|CRE Permit LNG Offshore Terminal Jan 2005|
Port Clean Energy Terminal
Gets OK for Louisiana Facility
FERC approve Texas terminal April 2005
||Sakhalin II 9.6||S. A Cent 15||
GAS RESERVES Bcf
||2 North Slope||
|ExxonMobil||El Paso 04||Mexico
|Indonesia new||LNG 2003||Peru LNG|
||LNG History||LNG Plants|| Costa
||Plant Capacity||CONVERSION TABLES
GAS RESERVES Bcf
Trinidad Tobago 23,450
|Beacon Port Clean Energy Terminal
Offshore LNG terminal
ConocoPhillips has submitted an application to the US Coast Guard for the construction of a new offshore LNG regasification facility in the GoM. The proposed Beacon Port Clean Energy Terminal will be in federal waters 56 mi south of the Louisiana mainland.
The facility will offload, store, and regasify the LNG, then make the natural gas available through a system of pipelines for delivery. This facility will have a throughput capacity of 1.5 bcf/d and will serve ars a source of clean energy for the US and the Gulf Coast region.
ConocoPhillips plans for Beacon Port to consist of two concrete gravity-based LNG storage tanks, regasification equipment docking platforms, and other unloading and operational equipment. A separate platform adjacent to the tanks will house terminal crew and other related equipment and non-operational facilities. Beacon Port will send gas to the mainland through 46 mi of new pipeline and a riser platform that will connect to existing pipelines 29 mi south-southeast of Johnson's Bayou, Louisiana. Existing pipelines will bring the gas to shore.
Construction could begin in late 2006 and will take four years.
ConocoPhillips anticipates that the first shipment of LNG to the facility could be delivered in 2010.
|FERC approves new Texas
WASHINGTON, April 13 2005 (UPI)
Federal regulators Wednesday approved plans to build a liquefied natural gas terminal along the south Texas coast in Corpus Christi. The terminal will be able to process and store about 2.6 billion cubic feet of gas daily and will link with a 23-mile pipeline that will connect with a major interstate pipeline in Texas' San Patricio County.
The Federal Energy Regulatory Commission gave the green light to both the terminal and the related pipeline project during its meeting Wednesday in Washington.
The Corpus Christi LNG project will have two tanker berths and three 160,000-cubic meter storage tanks. The FERC ordered the terminal be ready for operation within three years
|LNG Import Facility in
California BHP Proposal
BHP 8/15/2003 URL: http://www.rigzone.com/news/article.asp?a_id=7956
Looking to meet the growing demand for natural gas, BHP Billiton announced that following preliminary discussions it intends to file applications with the United States Coast Guard/Maritime Administration (MARAD) and the California State Lands Commission to construct and operate a liquefied natural gas (LNG) regasification facility. The facility would be located more than 20 miles from Oxnard off the Ventura County coast and would be developed by BHP Billiton LNG International, Inc., a wholly owned subsidiary of BHP Billiton.
This deepwater facility -- named Cabrillo Port -- would be the receiving point for shipments of 'California-bound' LNG. Cabrillo Port would be a permanently moored facility -- a floating storage and regasification unit, or FSRU. LNG will be stored onboard in traditional LNG storage tanks and will be converted to natural gas through a heat exchange system, and then transported by an undersea natural gas pipeline into the existing pipeline system of the local gas utility.
The applications will seek to obtain a deepwater port license for the right to operate the FSRU in U.S. coastal waters and a land lease from the California State Lands Commission for the right to construct an undersea pipeline to the shore to deliver the natural gas into the local utility system. The deepwater port license would be issued by MARAD, who is authorized by the Secretary of Transportation to make a decision on the license after processing by the Coast Guard and MARAD.
"We've taken BHP Billiton's long-held expertise in operating offshore floating production facilities and merged it with state of the art LNG carrier, storage and regasification technology, in order to be able to site an FSRU offshore that can deliver much needed natural gas directly into California," said Stephen Billiot, Vice President of BHP Billiton LNG International, Inc.
"We understand California's concern for its coastline and its communities. Although LNG's excellent safety record is well documented, we are siting this much needed LNG facility far offshore and away from population centers to ensure the highest level of protection for the California coast and public safety," Mr. Billiot said.
Cabrillo Port will be based 21.5 miles offshore of the City of Oxnard -- outside the existing shipping lanes and marine mammal migratory patterns, as well as away from the Point Mugu U.S. naval testing area and the Channel Island Marine Sanctuary. The FSRU will be permanently moored to the ocean floor and connected to the shore via a traditional natural gas pipeline. The natural gas pipeline will come ashore in Ventura County, near Ormond Beach, and connect directly into the local gas utility's pipeline system.
The FSRU design features three "Spherical Tanks" -- state of the art LNG storage tanks -- with the capacity to store the equivalent of 6 billion cubic feet of natural gas. The FSRU will contain eight vaporizers to enable the conversion -- or regasification -- of up to 1.5 billion cubic feet of natural gas per day. Anticipated average send-out will be approximately 800 million cubic feet per day, or almost 15% of what California requires every day.
Following the filing of the applications with the Coast Guard and State Lands Commission, BHP Billiton anticipates that both agencies will take the lead, pursuant to federal and state environmental laws, and undertake a joint and cooperative environmental and public review process. Following public review and approval, BHP Billiton expects the design, fabrication and installation of necessary facilities to allow for operations to commence by 2008.
BHP Billiton's Cabrillo Port provides a unique and environmentally friendly alternative to meeting the energy and environmental demands of California. Natural gas is a more efficient and cleaner burning fuel than coal or oil, and the FSRU's offshore location minimizes social and environmental impacts while providing a safer and less intrusive locale for its operations.
BHP Billiton's applications for a deepwater port license and land lease are the first step in a lengthy process that will include other relevant permit applications, significant environmental review, public hearings and community meetings. As part of BHP Billiton's health, safety, environmental and community operating practices, meetings will be held in appropriate public forums to discuss this project with a wide variety of stakeholders in the region. These will be set, disclosed and in compliance with all applicable regulations.
Fairwinds LNG terminal JV ConocoPhillips Co. TransCanada Pipelines LtdFishermen trying to sink gas terminal; "They're going after our way of life," says a leader of Fish...
Fairwinds Suspends Harpswell LNG Project
Jan 22, 2004 - Portland Press Herald Author(s): Ted Cohen Staff Writer
A group of fishermen in Harpswell has launched an aggressive door- to-door campaign to try to prevent the town from leasing a former fuel depot for use as a liquefied natural gas terminal. Fishing Families for Harpswell, which outlined its campaign Wednesday before the editorial board of the Portland Press Herald/ Maine Sunday Telegram, argues that the project would devastate the lobster industry. The group is urging the town to reject the project when it comes to a vote, possibly in early March.
"Fishermen have worked for decades to preserve our way of life," said Jim Merryman, co-President of Fishing Families for Harpswell. "This project would be devastating to the lobster habitat." Merryman said that the laying of a pipeline and the movement of huge ships carrying the gas would wreak havoc with lobster migration patterns, and that the lobster supplies would eventually decline.
Officials for Fairwinds, which is a joint venture of ConocoPhillips Co. and TransCanada Pipelines Ltd., said all necessary steps are being taken to ensure that the fishing industry is protected. Fairwinds came to the town in September for permission to build and operate a gas terminal and pipeline on a 7-acre parcel at the former Navy fuel depot off Route 123.
The debate about the possible lease by the town will resume tonight when selectmen provide an update on their talks with Fairwinds. A date for a town meeting vote on a proposed lease could be set tonight, said Town Administrator Kristi Eiane.
Ron Lapointe, co-President of Fishing Families for Harpswell, said lobstermen "are being sacrificed" for the project. "They're going after our way of life," he said. "We're small businessmen."
Peter Micciche, spokesman for Fairwinds, said the project "was specifically designed around the needs of Casco Bay/Middle Bay fishermen." Micciche said that ships would not be operating when lobstermen are fishing, and that the channel would be marked to clarify where the ships would operate. He also said that a $1 million mitigation plan would protect against possible damage to lobster gear, and that extensive environmental studies would be done "in order not to impact the lobster fishery."
Fairwinds has said it would restrict the tankers' passage to a 400-foot area. Ships would be allowed to dock in Harpswell only after 1 p.m. They would make one trip every four to nine days. The $350 million project would enable Fairwinds to receive gas shipments in Harpswell at a new dock and jetty. Liquefied natural gas would be reverted to natural gas on the site before being sent through a new underwater pipeline that would traverse Casco Bay. In early December, selectmen canceled a Jan. 27 vote in which residents would have decided whether to approve a lease that would last 30 to 50 years. Fairwinds had agreed to pay the town about $8 million a year in annual lease fees. Town officials identified discrepancies in the lease proposal and accused Fairwinds of trying to take advantage of the town. Selectmen agreed to resume negotiations provided they could deal with Fairwinds' top officials and present the venture with a list of demands. Negotiations resumed recently.
A group called FairPlay for Harpswell is also opposing the proposed lease. It members claim that neighbors of the site would be forced to move, property values on Harpswell Neck would decrease, and fishing would be jeopardized by the tankers and the underwater pipeline. Staff Writer Ted Cohen can be contacted at 282-8225 or at: firstname.lastname@example.org
Fairwinds Suspends Harpswell LNG Project
Fairwinds 3/10/2004 URL: http://www.rigzone.com/news/article.asp?a_id=11495
TransCanada and ConocoPhillips will suspend further work in Harpswell, Maine on the Fairwinds liquefied natural gas (LNG) project. Yesterday, the residents of Harpswell voted against leasing the former U.S. Navy Fuel Depot site in the community for the purpose of building an LNG regasification facility.
Despite the outcome of this vote, there remains a critical need for reliable, new sources of natural gas in the northeast United States. Both companies are committed to pursuing opportunities to deliver clean and safe LNG supply to the northeast United States. "Although we are disappointed with the results, we respect the choice of the people of Harpswell regarding their decision," said Peter Micciche, Fairwinds Stakeholder Relations Manager. "Over the past six months we were committed to listening to those affected by the project and felt we developed a lease that addressed their major concerns.
"We've enjoyed the opportunity to spend the past few months becoming acquainted with so many good people in Harpswell," Micciche continued. "We'd like to extend a heartfelt thanks for their New England hospitality. We have also grown to appreciate the unique qualities of the town and wish the community of Harpswell success in the future," said Micciche.
On September 18, 2003, TransCanada and ConocoPhillips presented plans for the Fairwinds LNG project to the Board of Selectmen at a public meeting. A detailed public information program to inform Harpswell residents and to solicit their views about the Fairwinds project followed.
El Paso's plans to build on offshore liquefied natural gas port won approval last Thursday from federal regulators. The U.S. Maritime Administration, part of the Department of Transportation, gave the go-ahead for El Paso to build its natural gas deep-water port 116 miles off Louisiana. The facility will basically be a buoy attached to a flexible steel pipe. When it's not in use, it will rest near the floor of the Gulf of Mexico. But after a tanker approaches, the device will rise to the surface. Once the tanker is docked, the liquid natural gas it is carrying will be converted into gas on the ship and pumped through the buoy into subsea pipelines.
"This new facility will improve efficiency by eliminating the need for a carrier to come all the way into a shore-side port and save money in the process," U.S. Transportation Secretary Norman Mineta, said in a prepared statement.
Houston-based El Paso is the owner and operator.
"We are pleased with today's announcement, and we look forward to completing the final stages of this project," El Paso spokesman Aaron Woods said. El Paso expects to begin constructing the port during the second half of the year, with the facility expected to be running by December. Its capacity, which represents an outflow of gas, is expected to be 400 million cubic feet to 500 million cubic feet a day.
Excelerate Energy, based in the The Woodlands, is providing funding the project and will own its capacity. Excelerate has also already charted two tankers, which are now being built.
Various companies have proposed a number of LNG projects, both onshore and offshore.
On Thursday, Exxon Mobil Corp. said it had filed for a permit with the Federal Energy Regulatory Commission for an LNG terminal in San Patricio County. The terminal would have a processing capacity of 1 billion cubic feet of gas per day.
An ExxonMobil affiliate, Vista del Sol LNG Terminal LP, has announced plans to develop a $600 million Liquefied Natural Gas (LNG) receiving terminal along the Gulf Coast of Texas. The proposed project, to be located in San Patricio County about two miles west of Ingleside, Texas, was announced today at an event attended by Texas Governor Rick Perry, Consul General of the State of Qatar Mohamed Al-Hayki, local business and government officials, and representatives of ExxonMobil.
The terminal, which will process imported LNG for distribution throughout Texas and the United States, should take about three years to build and involve employment for some 600 workers during peak construction. The facility is expected to be operational in the 2008/09 timeframe, with a processing capacity of 1 billion cubic feet per day (bcfd) of LNG.
Late last year, ExxonMobil initiated the permitting process for the Vista del Sol project with the Federal Energy Regulatory Commission (FERC), an undertaking that involves numerous engineering design, safety, environmental and other studies that typically lasts about 18 months. Prior to the initiation of the permitting process, the Port of Corpus Christi Board of Commissioners voted unanimously to support the project.
In November, the company via an affiliate, Golden Pass LNG Terminal LP, entered the FERC permitting process at another Texas site, Sabine Pass, located 10 miles south of Port Arthur.
"Texas and the United States need secure supplies of natural gas to attract industries, assure development and to continue the strong economic growth we're experiencing in our state and throughout the nation," said Governor Rick Perry speaking at today's event. "This project will bring jobs and other economic benefits to San Patricio County and the greater Corpus Christi area, and will provide long-term supplies of natural gas for our industries, power plants and homes. We support ExxonMobil's efforts to bring another important LNG project to Texas."
Philip Dingle, president of ExxonMobil Gas and Power Marketing Company, said, "This is another important step in our plans to develop LNG receiving terminals on the U.S. Gulf Coast. There is strong growth in natural gas demand projected in the future, and the import of LNG will be an important component of the supply mix. We appreciate the continued commitment of Governor Perry, Texas Railroad Commission Chairman Victor Carrillo, State Senator Judith Zaffrini, State Representative Gene Seaman, San Patricio County Judge Simpson, the Port of Corpus Christi Board of Commissioners and other state, local and civic leaders who are working with us to bring this LNG project to San Patricio County. This project will help support economic development in South Texas and the U.S."
In October, ExxonMobil and Qatar Petroleum announced a Heads of Agreement to supply 15.6 million tons a year of LNG (2 bcfd) from Qatar to the United States for an expected period of 25 years.
DKRW purchases land for By OGJ editors HOUSTON, Aug. 17 2004
Houston-based DKRW Energy LLC's subsidiary Sonora Pacific Mexico has purchased from the state of Sonora, Mex., 1,500 acres of property at Puerto Libertad on the Gulf of California for its planned 1.3 bcfd LNG regasification and storage terminal and pipelines (OGJ Online, May 26, 2004).
El Paso Corp. will install pipeline infrastructure to deliver 500 MMcfd of gas from the terminal to Sonora and Sinaloa states—primarily for electric power generation—and 800 MMcfd to Arizona and California through Nogales to its existing system in the western US. The LNG site is 200 miles from the large Tucson-Phoenix gas market.
Sonora Pacific plans to start construction in mid-2005 and to begin operations in mid-2008, assuming government approvals.
Bechtel Corp. and Chicago Bridge & Iron, The Woodlands, Tex., will manage engineering and construction, and Houston firm Andrews & Kurth LLP will provide legal support.
In the next few months Sonora Pacific will work to secure permits and to market throughput capacity and equity in the terminal and pipeline to Pacific Rim gas suppliers and other investors.
|ChevronTexaco de Mexico Awarded
Winner in SCT Public Licensing Round for the Construction of an Offshore Natural Gas Import Terminal in Baja California
SAN RAMON, Calif. and TIJUANA, B.C., Mexico, Jan. 6 -- ChevronTexaco de Mexico today announced that it was awarded a permit from the Regulatory Energy Commission (CRE) for a proposed natural gas import terminal off the coast of Baja California, Mexico, moving the company forward in its aim to deliver natural gas to Mexico. In addition, ChevronTexaco received notice from the Communication and Transport Secretariat (SCT), through its Port Authority, that the company is the winner of the public licensing round for an offshore concession to construct and operate its offshore natural gas import terminal.
"We are pleased to be awarded these authorizations from the Mexican federal government after participating in a comprehensive and rigorous permitting process," said John Gass, president of ChevronTexaco Global Gas. "These important new milestones, together with the previously received environmental authorization from the Environment and Natural Resources Secretariat, move us a step closer to being able to import essential supplies of natural gas to help meet Mexico's long-term energy needs. It also provides a potential outlet to supply neighboring markets with any excess capacity."
Carlos Atallah, president of ChevronTexaco de Mexico, said, "We are pleased with our progress in the terminal permitting process. This is an important project for Baja California and the whole region to be able to meet the growing demand for clean energy."
Atallah added, "The terminal will be designed to have an initial capacity of 700 million cubic feet of natural gas per day and can be expanded based on future demand. ChevronTexaco's project is expected to bring additional investments and jobs to Baja California and, by diversifying the state's natural gas sources, contribute to more stable energy supplies and prices."
ChevronTexaco's terminal will be located more than 13 kilometers (8 miles) offshore and will be designed with state-of-the-art safety and environmental standards. ChevronTexaco is committed to an open dialogue with the various representative groups of the Baja California community and welcomes their interest in learning more about the project.
To learn more about ChevronTexaco's project in Baja California, please visit www.gnlbaja.com.
Cautionary Statement Relevant to Forward-Looking Information for the Purpose of "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995.
This news release contains forward-looking statements about ChevronTexaco's plans for a liquefied natural gas receiving and regasification terminal offshore Baja California. The statements are based on management's current expectations, estimates and projections; are not guarantees of future performance; and are subject to certain risks, uncertainties and other factors, some of which are beyond the company's control and are difficult to predict. Among the factors that could cause actual results to differ materially are the success and timing of securing additional necessary approvals and permits for the construction and operation of the terminal, actual future demand for natural gas demand in Mexico and North America, timely construction and start-up of the terminal offshore Baja California, and local and general economic conditions. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, ChevronTexaco undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
SOURCE ChevronTexaco Corp.
Oil majors are trying to setup deals by the end of 2003 due to LNG imports to the US will doubled by 2025 to nearly 5-trillion cu ft. according to the forecast of the US government's Energy Information Administration (EIA).
Shell and US Sempra have teamed up in Mexico, to build the first LNG import facility in Baja California. UK BG, the leading LNG importer to the US, has pick up more capacity and setting deals with suppliers such a Trinidad. ConocoPhillips has given a major boost to a Texas project, BP, has lined up a deal to supply Sempra with LNG from Indonesia's Tangguh project. Sempra it is also developing an LNG reception terminal - Cameron LNG - near Lake Charles, Louisiana.
Sempra, Shell on Course for LNG Land Permit
Sempra Costa Azul May 05 2005
BNAmericas 3/18/2004 URL: http://www.rigzone.com/news/article.asp?a_id=11644
It is "practically a fact" that energy companies Shell and Sempra will receive a land permit for their proposed liquefied natural gas (LNG) terminal at Costa Azul in Mexico's Baja California state, the state's minister for economic development, Sergio Tagliapietra, told BNamericas.
Tagliapietra addressed a letter to "the international community" on March 12 saying that the state supports companies "that have met all the legal and technical requirements associated with LNG projects in Baja California." The move reflected concern about the possible negative fallout in the international business community when US company Marathon abandoned a US$1.5bn energy complex after the state government expropriated the land where the project was planned.
The state government maintains that Marathon did not follow the proper procedure because the company never applied for permission from the state and Tijuana municipal authorities although it obtained a permit from national energy regulator CRE in 2003. "Companies know that it is necessary to comply with the regulations as well as responding to the market demands. Sticking to the law guarantees and gives certainty to investments," Tagliapietra said. "We are a state that promotes investment and aim to provide the best information possible for companies to make decisions.
On the other hand, companies should act in accordance with the regulations that apply in each case," he added.
Apart from the Sempra-Shell project, ChevronTexaco plans a regasification terminal 13km offshore from Tijuana. "Both projects will generate benefits and contribute to the strengthening of our state's infrastructure, making us more attractive to investment. However, it is not the state government alone that determines whether these plants get built," Tagliapietra said.
Shell and Sempra have received a permit from the CRE and ChevronTexaco expects to receive one sometime this year, but the latter's project has attracted negative press because of its location near the environmentally-sensitive Coronado Island.
While ExxonMobil is counting on a US east coast LNG import project, the company has begun the pre-filing process for a liquefied natural gas import facility in Corpus Christi, Texas, the company announced Thursday. Houston-based Cheniere Energy, in December filed a permit with FERC to build a 2.5 Bcf/d LNG import terminal in Corpus Christi, as well as a permit to build a similar terminal in Sabine Pass, Louisiana. ExxonMobil also holds an option on an LNG terminal site across the river from the Cheniere site in Sabine Pass, Texas.
Cheniere Gets OK for Louisiana Facility
Cheniere Energy Inc. said Wednesday that government regulators approved its plan to build a liquid natural gas receiving terminal in Cameron Parish, La.
The oil and gas producer said the approval by the Federal Energy Regulatory Commission allows the company's Sabine Pass LNG limited partnership to construct and operate the terminal and an associated pipeline. The approval is subject to specific conditions that Cheniere expects to satisfy and construction is set to begin in the first quarter.
Cheniere said the facility will have an initial processing capacity of 2.6 billion cubic feet of liquid natural gas per day.
Late Monday, ChevronTexaco Corp. said it entered to a 20-year agreement reserving 700 million cubic feet of gas capacity at the Sabine Pass terminal, after backing out of a deal to buy a stake in the partnership last week. Cheniere stock opened 14 percent higher at $61 per share on Tuesday after ChevronTexaco's announcement.
Cheniere shares rose $1.20, or 1.9 percent, at $63 in afternoon trading on the American Stock Exchange. Shares of San Ramon, Calif.-based ChevronTexaco fell 25 cents, or 0.5 percent, to $52.83 on the New York Stock Exchange.
Marathon Oil has announced plans for a terminal that would form part of a "regional energy park," including a 1,000MW power plant, at La Joya outside Tijuana, Mexico.
ChevronTexaco is looking at an offshore terminal in Mexico, while Shell already has a 75% stake in a joint venture with France's Total to build an LNG terminal at Altamira on the Gulf Coast for supply to power plants of state owned Federal Electricity Commission (CFE). Announcing the deal just before Christmas, the companies said their JV would build, own and operate a terminal at Costa Azul, some 14 miles north of Ensenada, able to supply 1-bil cu ft/d of gas both locally and in the US southwest.
About 500-mil cu ft/d would be used to meet growing demand in western Mexico, with any surplus providing new supplies for the southwest US. Construction is due to start by mid-2004, with the terminal going on-stream in 2007.
The partners said combining their proposed terminals into a single project would significantly cut the impact on the local environment. Shell and Sempra have long track records in Mexico. Shell already has a 75% stake in a joint venture with France's Total to build an LNG terminal at Altamira on the Gulf Coast for supply to power plants of state owned Federal Electricity Commission (CFE).
ConocoPhillips gave a proposed LNG reception terminal at Freeport a major boost just ahead of Christmas when it announced it would obtain a 50% interest in the general partner of Freeport LNG Development and provide construction funding estimated at $400-500-mil for the LNG reception terminal at Freeport.
Freeport Closes ConocoPhillips Deal
Cheniere Energy Inc. said Tuesday that Freeport LNG Development LP closed a deal in which ConocoPhillips will build and use a liquefied natural gas receiving terminal on Quintana Island near Freeport, Texas. Cheniere, a producer of oil and gas as well as a developer of natural gas terminals, holds a 30 percent limited partnership interest in Freeport LNG.
ConocoPhillips acquired one billion cubic feet per day of re-gasification capacity in the terminal and obtained a 50 percent interest in the general partner that is managing the venture. The Houston-based oil and gas company also will provide a majority of the construction funding, Cheniere said.
Dow Chemical Co., based in Midland, Mich., has contracted for the remaining 0.5 billion cubic feet per day, Cheniere said.
Freeport received approval from the Federal Energy Regulatory Commission last month to build and operate a facility to produce 1.5 billion cubic feet of gas per day. The company said it expects to receive the remaining federal, state and local approvals in the third quarter. Cheniere said the companies plan to start construction in the fourth quarter and begin operations in the second half of 2007.
Freeport chairman and chief executive Michael S. Smith said the Quintana facility will be the first liquid natural gas receiving terminal built in the continental United States in 20 years. "The capacity of the facility is equivalent to about 3 percent of the current U.S. gas production," Smith said in a statement.
In addition to Cheniere's 30 percent stake, Contango Oil & Gas Co. owns 10 percent of Freeport.
Iraq 109,800 Indonesia 92,500 Australia 90,000 Norway 77,300 Malaysia 75,000 Turkmenistan 71,000 Uzbekistan 66,200 Kazakhstan 65,000
Netherlands 62,000 Canada 60,118 Egypt 58,500 China 53,325 Kuwait 52,200 Libya 46,400 Ukraine 39,600 Azerbaijan 30,000 Oman 29,280
Bolivia 24,000 Trinidad and Tobago 23,450
Total world 5,501,424 Jan. 1, 2003 OGJ, Dec. 23, 2002, p. 114
Colleen Taylor Sen Gas Technology Institute Des Plaines, Ill Oil & Gas Journal June 23, 2003
Despite marginal gas production growth for natural
gas in 2002, LNG's share of the world's trade in natural gas set records.
Last year, marketed world gas production edged up only 1% to 2,580 billion
cu m (bcm; 1bcm = 37.3 Bcf and 0. 73 million tonnes of LNG), reflecting the
continued economic slowdown in many parts of the world.
In the first half of 2002, demand for LNG was stagnant
but raised more than 8% in the second half. Spot and short-term LNG sales
accounted for a record 9% of the total.
Today, one of the major forces driving the global LNG industry is the desire of producers and resource owners to commercialize reserves they have already discovered. ExxonMobil Corp., Royal Dutch/Shell Group, TotalFinaElf SA, ChevronTexaco Inc., ConocoPhillips, Petroliam Nasional Bhd. (Petronas), Statoil ASA, Qatar Petroleum General Corp., and other private and state owned companies with substantial reserves are seeking to develop markets by building their own terminals, buying interests in other companies' receiving terminals, or acquiring access in open-access terminals. At the same time, LNG buyers such as Tokyo Gas Co., Tokyo Electric Co., and Korea Gas Corp. are acquiring shares in upstream reserves and liquefaction plants and buying their own ships in order to maximize their investments.
There is no necessary correlation between size of reserves and LNG production capacity despite its enormous reserves, Iran for political reasons, has never become an LNG exporter, although several projects are now being developed or proposed.
Apart from Abu Dhabi, the Middle East was not a participant in -the LNG industry until the 1990s, in part because of policy decisions to develop gas resources for chemicals and other uses. Trinidad, on the other hand, became a major exporter because of its proximity to major markets and government support despite its much smaller reserve base.
As a rule of thumb, it takes 1 Tcf of proved gas
reserves to produce 1 million tpy of LNG for 20 years plus a tailgas requirement
of 1 to 3 Tcf.
The cost of production can range from effectively zero when the resources are large and rich in condensates to $1 /Mcf or even higher. Typically the government of the producing country charges a royalty and gets revenue from owning a share in the production and liquefaction plant.
Over the past decade there has been a 35% to 50% decline in LNG production and transportation costs. The average cost of I tpy production capacity is now around $250/tonne for a greenfield plant and $175 for an expansion train, compared with more than $500 in 1965-70 and $300$400 throughout the 1970s and 1980s.
Economies of scale clearly play a role in bring costs down. The average train size has grown from around 1 million tpy in the 1960s to 3 million tpy in 2000, while the number of tariffs per project declines. Today trains in the 4-4.8-million tpy range are becoming the standard for new construction (e.g., Nigeria LNG Trains 4 and 5, Northwest Shelf Train 4, Ras Laffan Train 3), and ExxonMobil is looking at 7-million-tpy trains for a new project in Qatar.
Also contributing to lower costs is:
LNG prices are falling
Ship costs are also coming down from a peak of more
than $250 million in 1991 to around $160-$170 million today. Nine new ships
were delivered in 2002, bringing the total fleet to 140 at yearend.
Indonesia's state electricity firm PT Perusahaan Listrik Negara (PLN) plans to build a $300 million liquefied natural gas (LNG) terminal in West Java to supply local power plants, a company official said on Friday. "PLN needs more natural gas and needs to secure future supply for power
plants. Therefore, we plan to build the LNG terminal," PLN director Ali Herman Ibrahim told reporters. He said under the plan the terminal would initially have a capacity of turning out 400 million cubic feet of natural gas per day from LNG supplies, with the potential to rise to 800 million cubic feet per day. Some PLN power plants in West Java province were using fuel oil, which was more expensive than gas, Ibrahim said. He said PLN had also extended a gas supply deal of 120 million cubic feet per day with BP Plc to feed two power generators in Jakarta with total combined capacity of around 1,750 megawatts (MW).
"PLN has signed an extension gas supply deal with BP for another ten years from January 2004," Ibrahim said, adding BP would supply gas from offshore West Java, in the Java sea. PLN also has a 950 MW capacity power plant at Muara Tawar in West Java. PLN needs to increase electricity supply to avoid shortages in the world's fourth most populous country, where annual demand is estimated to be growing by around 10 percent a year.
Indonesia averages production of 2.8 trillion cubic feet of natural gas.
Some 1.5 trillion cubic feet are exported via pipeline, LNG and liquefied petroleum gas (LPG), with the remainder flowing to the domestic market.
Since the first LNG export to Japan in 1977, Indonesian LNG export to international markets such as Japan, Korea, and Taiwan (the traditional LNG markets) continues to increase, and reached 4.98 BCFD in 1999.
Nevertheless, the LNG supply was down significantly by 4.3 BCFD in 2000, and 4.0 BGFD in 2001 due to decreasing demand for LNG by Japan following the economic growth slowdown of the country. The following article explains about the challenges and opportunities faced by Indonesian natural gas/LNG industry amidst the tight competition in international market.
The world's biggest producer and exporter of gas is inexorably losing its grip on the market. Indonesia pioneered and dominated the regional market for 25 years through its state-owned energy company, Pertamina.
Indonesia seeking bigger LNG supply to China's Fujian
In earlier days Pertamina was Southeast Asia's only supplier on the market and had the power to dictate prices. But the entry of new players from Malaysia, Australia, Brunei and Qatar in the late 1980s heralded a new buyer's market that remains to this day. Pertamina lost its monopoly for handling the marketing of Indonesian liquefied natural gas (LNG) overseas in 2001.
Now Malaysia, Australia, Qatar and Russia all threaten Indonesia's regional LNG export markets. Qatar, with its huge gas reserves, has been able to lower LNG production costs, making its gas cheaper than other countries'. Qatar offered a price for a Taiwanese contract that was even lower than the Indonesian domestic price, said Minister of Energy and Mineral Resources Purnomo Yusgiantoro.
China, bent on enhancing its own energy security, started to change
the equation in Asia's regional energy market when it awarded a highly contested
tender to supply liquefied natural gas to Guangdong province to a consortium
led by Australian energy giant Woodside Petroleum Ltd. China did follow up
with a second contract for Fujian province to Tangguh LNG, an Indonesian
project in Papua.
Golkar, now in opposition after having ruled Indonesia during the entire length of former president Suharto's reign, castigated the government of President Megawati Sukarnoputri for weak lobbying and sending a delegation headed by Megawati's husband Taufik Kiemas to Beijing to push for the Guangdong contract, China's first deal to import foreign natural gas.
The shock waves have reverberated through Indonesia's gas industry, prompting Resources Minister Purnomo to warn that Indonesia could no longer rely on its old paradigms for selling LNG. The warning has not been ignored and, 12 months later, amid a stream of bad news for the country's LNG exports, the government has prepared to bite the bullet, face the loss of part of its traditional markets, and focus on domestic demand.
There could be more bad news coming. Japan, the world's largest LNG importer, Taiwan and South Korea have been buyers for Indonesian LNG for decades. Combined demand in the three countries is likely to increase by some 35 million tonnes by 2010. Though they still take most of Indonesia's LNG exports under long-term contracts of between 20 and 30 years, these will expire in the next few years.
One 8.4-million-tonne contract with Japan expires in 2010 and another, of 3.6 million tonnes, in 2011. Sales contracts with Kansai Electric, Kyushu Electric, Nippon Steel, Tohoku and Tepko, amounting to a total of 10.15 million tonnes per year, are set to expire in 2010.
Also, Japan's Tohoku Electric Power Co moved the goalposts this month by shortening a long-term LNG import contract with Pertamina and slashing the volume from 3 million tonnes to 830,000 a year. Megawati herself, on an official visit to Tokyo, vainly lobbied the Japanese government to urge Japanese buyers to extend their purchase contracts.
A week earlier Taiwan's state-owned Taiwan Power Co (Taipower) had awarded an $8.6 billion contract to its state-owned Chinese Petroleum Corp (CPP) to supply LNG to its Tatan power plant. The LNG will come from Qatar's Ras Laffan (Rasgas) project. United Resources, which lost the bid, would have sourced LNG from Tangguh.
Tangguh's gas fields contain 14.4 trillion cubic feet of proved
and certified natural-gas reserves.
The project includes development of gas fields and construction of the LNG plant, tankers, related infrastructure and pipelines, but delivery of gas from Tangguh will not be before early 2007, coinciding with completion of China's Fujian gas terminal. This left the plant, where construction is expected to get under way next year, with only the one confirmed order, although a new deal, still being negotiated with Japan's Western Buyer, may give Tangguh a 2.6-million-tonnes-a-year LNG supply contract starting from 2010. Japan, to guarantee stable supply, wants the 6.0-million-tonne-a-year contract to stipulate that LNG will be supplied by two producers - Bontang and Tangguh. The whole deal would bring Indonesia $8.5 billion over 25 years.
The Bontang plant uses a pool of natural gas piped from the offshore East Kalimantan fields operated by Total, Unocal and Vico. It is owned 55 percent by Pertamina, 20 percent Vico, 10 percent Total and 15 percent by Japan Indonesia LNG Co (JILCO).
The two major facilities, Arun at Lhokseumawe, in Aceh, and Badak, in Bontang, condense natural gas by refrigerating it to one-six-hundredth of its volume for shipment in tankers. Both plants were built in the late 1970s under supply contracts to Japan, although excess production was sold to other buyers. They have combined production capacity of 31.6 million tonnes. Bontang accounts for 22.25 million tonnes of that, and this output alone accounts for some 25 percent of the Asian LNG market.
However, neighboring Malaysia is expanding output this year from
its third LNG venture at Bintulu in the north of Borneo that could boost its
capacity to 23 million tonnes a year, leaving Bontang in second place.
Total, the world's fourth-largest energy firm, has said the future of its business in Indonesia would depend on Japanese buyers' readiness to extend their LNG purchase contracts from the Bontang plant. Total supplies 65 % of the feed gas to the eight refineries at Bontang. LNG and LPG products are exported and the condensate is returned to Unocal facilities in Santan, East Kalimantan.
Pertamina plans a ninth production line, Train-I at Bontang, to
compensate for falling output from the Arun plant, which liquefies gas supplied
by Exxon Mobil Corp. But Total chief executive officer Thierry Desmarest has
said the company is unlikely to build the new train until it can confirm that
Japanese buyers would extend their contracts. "It is more important for us
to confirm that our existing trains have a market," he warned. This ninth
train, if it goes ahead, would add 3 million tonnes' capacity and cost about
$550 million to build.
All the signs are that the government is fundamentally rethinking
its domestic energy strategy.
State-owned gas-distribution company Perusahaan Gas Negara (PGN) and state-owned power utility Perusahaan Listrik Negara (PLN) will join the consortium to build the terminals, one near Jakarta and the other at Surabaya, the country's second-largest city and industrial area.
LNG could not compete with oil-based fuels for years in the local market because of the government's subsidy policy. International Monetary Fund insistence on the gradual scrapping of the fuel subsidies has also helped to bring the domestic gas market into planner's radar screens.
Major customers include PGN, the state fertilizer producer, which processes it into ammonia and urea, and scores of large industrial users throughout Java. PLN has now been persuaded to look on natural gas as the fuel of choice for several of its power plants. Increasing the amount of LNG and piped gas sold in Java and other areas of the country that face energy shortages makes real sense, with annual power demand estimated to be growing by about 10 percent annually.
Proper development of the country's domestic gas market would not only produce enormous savings, but would also deliver an environmentally clean fuel.
Malaysia LNG (MLNG) Sdn Bhd produces and exports liquefied natural gas to various countries across Asia. Based in Bintulu, Sarawak, MLNG is the world's largest producer of liquefied natural gas in a single location, producing 22.8 million metric tonnes per year.
Brunei is the world's fourth largest producer of liquefied natural gas (LNG). The current gas production is approximately 27 million cubic metres per day, and 90 per cent of it is exported to Japan, namely the Tokyo Electric, Tokyo Gas and Osaka Gas Companies. The Japanese companies and Brunei Coldgas of Brunei LNG signed a further 20-year contract in 1993. The new contract is believed to have raised the quantity and price of gas.
The Brunei Liquefied Natural Gas plant in Lumut, one of the largest in the world, was upgraded and expanded at a cost of around B$100 million in 1993. LNG from the plant is transported to Japan by a fleet of seven specially-designed 100,000-tonne tankers with a capacity of 73,000 cubic metres of LNG each. The sale of LNG has grown to be as important a revenue earner as oil exports. Domestic market takes up only 2 per cent of the LNG produced.
At the current rate of production, the proven reserves of natural gas is estimated to last another 40 years. However, the discoveries of new gas fields and the possiblity of more finds will enable Brunei to benefit from the growing demand for LNG in Asia, which is needed primarily for power generation.
North Asia is seen as the world's largest LNG market over the next twenty years, and Australia, like its competitors, is looking to supply the growing regional and global demand for LNG. India, too, presents significant market opportunities. Australia - again, like its competitors - is fortunate in having huge uncommitted gas reserves and close proximity to potential new markets in Asia. And - of great importance - Australia is seen across the world as a reliable and secure supplier.
Expansion plans for the North West Shelf LNG Project in Western
Australia, the planned Gorgon field development - and other projects in the
Northern Territory - have the capacity to expand the industry and add considerably
to LNG trade worldwide, especially in the Asia Pacific. The North West Shelf
Project is the largest single resource project in Australia, and represents
a AUD 12 billion investment in off-shore production and onshore processing
facilities. The Joint Venture Participants' expansion of facilities at Karratha
will potentially double Australia's LNG production to 14.5 million tonnes
Entire 3.6 mtpa output of Egyptian LNG Train 2 to Lake Charles for approximately one year with some volumes to be switched to Brindisi thereafter
Lake Charles The LNG Terminalling Service Agreement enables BGLS to control approximately 81% of the capacity of the Lake Charles LNG importation terminal from 1 January 2002 until 31 August 2005. From 1 September 2005, BGLS will control 100% of the capacity. The terminal currently has the capability to receive, store, vaporise and deliver an average daily send-out of 630 mmscfd of gas on a sustainable basis, and 1 bcf per day on a peaking basis. The terminal has access to 15 major intrastate and interstate natural gas pipelines, as well as to Henry Hub, through the Trunkline Gas Pipeline system. In October 2001, CMS Energy Corp, then owners of the Lake Charles LNG terminal, announced a planned expansion of their facility. This expansion is scheduled to be completed by the start of 2006. The sustainable throughput capacity will be expanded to 1.2 bcfpd, storage increased from 6.3 bcf to 9 bcf, and a layberth and ancillary services constructed. All of the capacity of the expansion is committed to BGLS.
BGLS is pursuing a number of options to create a diversified supply portfolio for the Lake Charles terminal. These include buying LNG from a variety of suppliers, including third-parties as well as BG equity LNG production, building a portfolio of LNG supply with a variety of tenures, including short-term and long-term contracts, and purchasing LNG on both a Free on Board (FOB) basis using BG’s own or acquired shipping resources, and on an ex-ship or Carriage, Insurance and Freight (CIF) basis whereby the supplier provides shipping.
On 13 May 2003, BG announced the signing of the following two long-term
LNG purchase arrangements:
initial deliveries of 3.6 mtpa, starting 2006, representing the
entire output of Train 2 of the Egyptian LNG project (ELNG), in which BG
is a partner (see page 34). The purchase agreement will cover the entire output
of ELNG Train 2 but will provide for volumes to be switched to BG’s Brindisi
LNG terminal in Italy, approximately one year after Train 2 commercial operations
start. In addition, BGLS is planning to purchase volumes from BG’s interest
in Atlantic LNG Train 4, which is anticipated to commence operations in the
first quarter of 2006.
Source: Al Nisr Publishing LLC http://www.gasandoil.com 09-02-01
South Korea is expected to import larger quantities of gas and oil from Oman, according to Shin Kook Hwan, South Korean Minister of Commerce, Industry and Energy. "The demand for oil and gas is increasing in South Korea, which means we are going to import more gas and oil from Oman, our steadfast partner," he said. South Korea is the biggest buyer of Oman's LNG. The first shipment was sent last April. The agreement requires Korea Gas Corp (Kogas) to import 4.1 mm tpy of LNG annually for 25 years. Since then, 19 cargoes of LNG have been exported, of which 15 have been to Kogas. Oman supplies 10 % of South Korea's LNG needs.
Hwan said South Korea is involved in the offshore Bukha Hanjam gas project in Musandam near the Strait of Hormuz. "Given the opportunity, we will go for more joint ventures." He was optimistic about winning the $ 750 mm Sohar Refinery contract. "Our companies have won contracts in Oman before and we expect to win more," said the minister, referring to Daewoo's $ 65.5 mm deal to build a reef at Sohar port and Hyundai's $ 25.5 mm dredging and reclamation contract for the port due for completion by 2002. Samsung and Hyundai are bidders for the construction of the Sohar Refinery with a planned capacity of 75,000 bpd. Hwan said talks with Maqbool bin Ali Sultan, Oman's Minister of Commerce and Industry, were very fruitful, marked by the signing of an MoU to promote exports, investment and training. He also met with Ahmed bin Abdulnabi Macki, Minister of National Economy. "The visit has brought us still closer." Maqbool bin Ali Sultan said the two sides discussed the possibility of joint ventures in tourism and information technology, with both laying increasing emphasis on trade contacts. "We want to benefit from the South Korean experience in the development of small and medium-sized businesses," the Omani minister said. The Korean minister voiced concern over rising oil prices, hoping the GCC states would impress upon OPEC to stabilise energy supplies.
Oman, an independent oil producer, exported more than 150,000 bpd
to South Korea last year.
Indonesia seeking bigger LNG supply to China's Fujian
JAKARTA, Dec. 9 2003 (Xinhua)
The Indonesian government is expecting to raise its liquefied natural
gas (LNG) supply to Fujian Province of China to 5 million tons a year, an
official said here Tuesday. The two sides agreed to deepen cooperation in
energy sector during a meeting held Monday evening, said Iin Arifin Takhyan,
director general of oil and gas under the Ministry of Energy and
Indonesia and China signed an LNG supply contract in 2002 under
which Indonesia pledged to supply Fujian with 2.6 million tons of LNG a year
starting from 2007. Iin told reporters at the parliament building that Indonesia
is making efforts to obtain an LNG supply of 5 million tons a year in line
with growing demand for LNG in Fujian. Iin said both sides "have been preparing
an LNG terminal in Fujian. "
Source: HUGIN Online http://www.gasandoil.com 13-11-03
Petroplus International and BG Energy Holdings, a subsidiary of BG Group, have announced that they plan to work together on the continuing development of Petroplus' proposed LNG import terminal at Milford Haven in Wales. The terminal, which has already received planning permission, will bring jobs to Wales and gas to help to meet the expected UK supply shortfall from 2007 when the new facility is expected to become operational.
Under the terms of a Memorandum of Understanding (MoU) signed, BG intends to purchase a 50 % equity stake in Dragon LNG, a special purpose project company already established by Petroplus to develop the project. In addition to this equity position, BG intends initially to contract for the use of 2.2 mm tpy of capacity at the facility. This represents half of the initial planned throughput capacity. Dragon LNG's sale of the remaining 2.2 mm tpy throughput capacity of the terminal is ongoing.
The existing Milford Haven site includes marine docking and unloading facilities at three berths. The development proposal provides for the adaptation of these facilities for use as an LNG tanker berth, with pipelines and other facilities as necessary for unloading LNG and transporting it to storage tanks onshore within the existing area.
Paul van Poecke, CEO, Petroplus Logistics, said: "We are very pleased to announce the successful conclusion of an MoU with BG. We are looking forward to working closely with our new partner, whose experience and leading role in the global LNG market will help us to develop further the work we have done over the past two years at our Milford Haven site. The transaction is a significant step forward in Petroplus' strategy of rebalancing activities and is consistent with our broader strategic agenda." Martin Houston, Executive Vice President and Managing Director, North America, Caribbean and Global LNG, said: "BG is already a major supplier of gas to the UK and is committed to continuing to seek new ways to serve this growing market.
The development of this facility with our partner, Petroplus, will allow us to deliver competitively priced natural gas to meet expected market requirements. This project will extend our position in the UK and strengthen our LNG leadership position in the Atlantic Basin." The Petroplus Milford Haven facility, located in Wales, United Kingdom, was acquired by Petroplus from Chevron in 1998. The complex comprises 1,550,000 cm of storage capacity, deepwater jetties and a mothballed refinery including a cogeneration facility. Petroplus Tankstorage, a wholly owned subsidiary of Petroplus International, currently operates the site as a commercial tank farm for petroleum products.
Petroplus International was established 10 years ago and is a leading player in the European midstream oil market. The midstream sector encompasses refining, marketing and logistics (predominantly tank storage). Petroplus is the owner of refineries in Antwerp (Belgium), Cressier (Switzerland) and Teesside (United Kingdom) with a total capacity of 270 000 bpd. Petroplus has a sales volume in excess of 20 mm tpy of oil products and a storage capacity of almost 5 mm cm throughout Western Europe. Petroplus International is publicly listed in the NextPrime segment of Euronext, Amsterdam. LNG represents one of BG Group's core business segments. The company is involved in developing LNG projects in Trinidad & Tobago, Egypt, Italy, India, Indonesia, Bolivia and Iran.
In January 2002, BG LNG Services (BGLS), a wholly owned subsidiary of BG Group, took 81 % of the capacity at North America's largest operating import terminal, Lake Charles in Louisiana, which has the capability to receive, store, vaporise and deliver 4.7 mm tpy. From September 2005, BGLS will take 100 % of the capacity. In March 2003, the Federal Energy Regulatory Commission gave approval for expansion of the terminal to 8.9 mm tpy. Construction of the expansion plant is expected to be completed by the beginning of 2006.
BG has four business segments -- Exploration & Production, LNG, Transmission & Distribution and Power Generation. Active in some 20 countries on five continents, its core geographical areas are the UK, Kazakhstan, Egypt, Trinidad and Tobago, South America and India.
PARTNERS in the Sakhalin 11 LNG project on Russia's Sakhalin island have awarded $95 million in lump sum contracts for the construction of two LNG storage tanks at a planned natural gas liquefaction plant at Prigorodnoye on Aniva Bay, Sakhalin Island (see map, OGJ, Oct. 1, 2001, p. 58).
The contracts were awarded to CB&I Europe BV and CMP Holdings BV, both units of The Woodlands, Tex.-based Chicago Bridge & Iron Co. NV (CB&I).
The CB&I units will handle the engineering, procurement, and construction (EPC) of two 100,000 cu m LNG storage tanks, which will be the first LNG tanks designed and constructed in Russia, according to CB&I.
The CB&I units were selected to construct the tanks by Chiyotec Ltd. and CTSD Ltd., both of which were awarded contracts along with their Russian partners, NIPIgasperabotka and Khimenergo Consortium, for the implementation of the overall LNG project by the project's owner, Sakhalin Energy Investment Co. Ltd. (SEIC). SEIC shareholders are Shell Sakhalin Holdings BV, Mitsui Sakhalin Holdings BV, and Diamond Gas Sakhalin BV.
CB&I said that completion of the tanks is anticipated in spring of 2OQ7 and first LNG is expected to be delivered from the terminal during 2007.
Qatar will spend $25 billion over the next six years to more than quadruple its LNG export capacity to 63.5 million t annually, said Faisal Mohamed al-Suweldy, vice chairman of Qatar Liquefied Gas Co. (Qatargas).
He noted that Qatargas already has heads of agreement signed with ExxonMobil for exporting 15 million t per annum to the UK market and with ConocoPhillips for sending 7.5 million t per year to the US.
The country this year is already exporting about 15 million t to
Japan, South Korea and Spain, with a small amount to the US.
Repsol YPF to Build an LNG Terminal in Mexico
Repsol YPF 2/18/2004 URL: http://www.rigzone.com/news/article.asp?a_id=11057
The Mexican authorities have awarded Repsol YPF land for the construction of a regasification plant in Port Lazaro Cardenas, on the Pacific coast of Mexico.
The Lazaro Cardenas LNG (liquefied natural gas) terminal will be the first to be sited in West Mexico, and will play an essential role in energy development on that Pacific coast since gas will be supplied from this facility to the gas markets in the area.
The Lazaro Cardenas Integral Port Administration (API) granted Repsol YPF the land on which the terminal will be built for $10.1 million. The plant will have an initial capacity of over 4 billion cubic meters (bcm) per annum, with a revamp potential of up to 10 bcm per annum. The initial investment is budgeted at around $350 million dollars and the facility is expected to go on stream in 2008.
Port Lazaro Cardenas is one of Mexico's largest industrial ports, and the only port on the Pacific Coast with access facilities to the national gas grid, making it an optimal location for a terminal of this kind.
Winning this project is core to Repsol YPF's strategy for profitable growth in the LNG business, and marks the company's entry in the American Pacific area, thus complementing its current activities in the Atlantic Basin through Atlantic LNG and the sale of LNG on the East Coast of the U.S.A.
Shell, Sempra to build $600 mln LNG terminal in Mexico
Dec 22 (Reuters)
Royal Dutch/Shell Group , the world's No. 2 oil company, and Sempra Energy , a U.S. power company, said Monday they have agreed to build a $600 million liquefied natural gas terminal in Mexico to take advantage of more demand and higher prices. The companies will form a 50-50 joint venture to build, own and operate the LNG receiving terminal in Baja California, Mexico. Both will pay an equal share of the investment costs and take half of the terminal's capacity.
The project is among the first to begin construction of the more than 30 North American LNG projects proposed to help cover an expected supply shortfall in the coming years. "Sempra saw that (gas demand growth) well in advance and we positioned ourselves for it," Darcel Hulse, president of Sempra Energy LNG Corp, told Reuters. Construction on the Baja California terminal will begin in mid-2004 and operations will begin in early 2007, the companies said in a statement.
The terminal, to be located in Costa Azul on Mexico's west coast, will be able to supply 1 billion cubic feet of natural gas per day. About 500 million cubic feet per day of gas from the terminal will be used to meet demand in western Mexico, while surplus gas will be used to meet demand in the southwestern United States. Sempra announced last week it had signed an agreement with BP Plc to buy 3.7 million tons of LNG annually for 15 years from Indonesia's Tangguh fields to supply to terminal. Shell is the world's largest private producer of LNG with six projects around the world. Until recently, LNG had few backers because of the high up-front costs of plants required to cool the gas to its more compact liquid form and the ships to carry it, as well as the low price of North American gas.
Now as prices have risen, and demand is greater, companies believe LNG can be profitable.
Calpine Withdraws Plans for LNG Project in Eureka, Calif.
Calpine 3/18/2004 URL: http://www.rigzone.com/news/article.asp?a_id=11658
Calpine has withdrawn its plans to proceed with a liquefied natural gas terminal at Samoa Point, in Eureka, Calif., and is ceasing development activities. "Based on feedback from the local community and public officials, we believe this decision is best for all parties," said Calpine Vice President Ken Koye.
Calpine values its relationships with the communities where its plants are located. While there can be differences of opinion, Calpine seeks a clear majority of support for proposed projects. "The Eureka City Council, the city staff and community leaders are to be commended for their time and effort in considering the project," continued Koye. "We appreciate those who worked with us to explore the potential for the project."
http://www.gasandoil.com 17-11-03 Source: Enatres
Brazil has discovered giant gas reserves with an unimaginable impact
in the future, since they are just a hundred miles away from the country's
main industrial concentration, Sao Paulo which is equivalent to 40 % of the
country's GDP. The enormous "bubble" off-shore Santos port could hold reserves
equivalent to 40 tcf. This compares with Argentina's total reserves of 34
tcf and Bolivia's 54 tcf, according to Oscar Prieto head of Comgas, the gas
consortium of Shell and British Petroleum in Brazil.
The state of Rio de Janeiro is studying proposals that could lead to development of a $ 5 bn LNG and petrochemical complex at a key port area. LNG and petrochemical exports from the complex would target the US. The complex would fed by natural gas-both the vast reserves recently discovered off the state and growing supplies imported from neighbouring Bolivia. Rio de Janeiro State Energy, Shipbuilding, and Oil Sec. Wagner Victer told that there are advanced studies evaluating the construction of LNG plant and an industrial complex in an area of Sepetiba Port, south of the city of Rio de Janeiro. "Around $ 2 bn has been allocated to start the LNG project; however, depending on the number of trains set for the liquefaction plant and the dimensions of the export terminal, plus other plants, costs will most probably increase to $ 5 bn."
Other investments envisaged involve units for gas processing/NGL recovery, ammonia-urea, and olefins (namely ethylene and propylene) with possible intermediates such as polyethylene, high-density polyethylene, and polypropylene also under consideration, Victer confirmed. The project will be financed by the National Economic and Social Development Bank (BNDES). The draught Sepetiba port is strategically located near the country's main consumer markets, Sao Paulo and Rio de Janeiro, and available infrastructure includes a Petroleos Brasileiro (Petrobras) pipeline network already in place. "The Sepetiba port was included by the federal government in the export processing zone (ZPE), so it is entitled to fiscal benefits for exports. And furthermore the ICMS sales tax over assets usually charged by the state government will be scrapped for this project," Victer said. "Sepetiba is a developed port complex, and its geographical position is also privileged in relation to recent discoveries of estimated reserves of 420 bn cm of natural gas on the BS-400 block in the Santos basin by [Petrobras]. Furthermore, Petrobras owns land at the port for its PetroRio petrochemical hub, which was never developed."
According to Victer, this will help to expand the gas liquids-based olefins complex under construction in the same region, where plans call for production of 515,000 tpy of PE, an ammonia-urea plant, and a gas processing/NGL recovery unit. "Besides exporting LNG, the gas available from Brazilian reserves and by the take-or-pay contract with Bolivia can be used to implement other petrochemical installation projects, such as a first-separation phase of ethane and the supply of the residential and automotive markets with natural gas, plus the generation of [electric power]."
The secretary confirmed that the natural market for exporting Brazilian LNG would be the US and his plans for the developing the project call for participation in a joint venture with multinational oil and gas companies. At the top of his list of multinationals are Houston-base El Paso and Norwegian state oil company Statoil. El Paso operates one of the largest natural gas pipeline systems in North America and is heavily involved in LNG import schemes. Statoil's US unit is a trading and marketing business that delivers 600,000 bpd of crude oil, gasoline, butane, and propane into the US. Victer also said that other companies are welcome to participate. Jacob Sannes, director of Statoil in Brazil, told the project is "very interesting, but the company will not make a formal decision about the project before having more details and negotiating with Petrobras and the government."
Victer, formerly head of Petrobras's exploration and production division, also noted that "the goal of the joint venture is to take advantage of the estimated 420 bn cm of natural gas reserves recently discovered by Petrobras off the coast in the Santos basin. This great potential could add supplies to the domestic and foreign markets and boost the petrochemical sector." The secretary also said the state's strategy is to back out imported petrochemical feedstocks such as LPG with domestic natural gas andto substitute in power generation schemes natural gas for low-value-added refined products such as fuel oil, which could be further refined into higher-value products. Another consideration would be the environmental benefits from the replacement of gasoline with vehicular natural gas.
Victer also noted that the project would contribute to the government's policy of generating more jobs and improving the trade balance, being negatively affected by Brazil's imports of natural gas from Bolivia under a take-or-pay contract paid in dollars. The Brazilian government until recently had been negotiating with Bolivia for greater flexibility in the take-or-pay contract that calls for payment for a minimum of 14 mm cmpd even if actual volumes fall below that level. In 2004, this minimum will rise to 18 mm cmpd, but Brazil's consumption currently is only 13 mm cmpd, said the mines and energy ministry.
Negotiations were halted prior to the recent ouster of Bolivian President Gonzalo Sanchez de Lozada due to massive and bloody protests sparked by a project proposed to export Bolivian gas as LNG via Chile to Mexico and the US. Lozada was replaced as president by his vice-president, Carlos Mesa, who promised to call upon the Bolivian people to vote in a referendum as to whether they wanted this project to go ahead or not. After Mesa took office, Marco Aurelio Garcia, an international aide to Brazilian president Luiz Inacio Lula da Silva, told that the referendum will probably also include the natural gas sales to Brazil. "I do not believe that Bolivia is hostile in relation to gas exports to Brazil, but the country is a historical enemy of Chile and Peru through which the natural gas would be exported to the US." Garcia was on an official mission in Bolivia to try to mediate the trade conflict before Lozada resigned.
The shortfall of Brazilian gas demand vs. Bolivia's takeaway capacity has been blamed on a projected flurry of gas-fired power plant construction in Brazil that has yet to materialize. But Victer says he does not believe that the gas-fired electric power plant boom projected for Brazil has failed yet. "In my opinion market conditions did not correspond to the expectation, and this led to a contraction of these projects. Due to the [government's] new energy model, which is more attractive to private investors, and to adjustments in the natural gas market being proposed by the mines and energy ministry, a new impetus for the development of gas-fired thermoelectric plants may take place for joint [development] with other projects."
Victer said that the LNG export facility will probably come on stream within 4-5 years, depending upon environmental licensing and agreements with the market players that would concur in purchasing its output. "Brazil's 20-year contract with Bolivia calls for eventually importing 30 mm cmpd of natural gas, and this figure is currently being used as a parameter for the LNG export project to the US.” However, the secretary stressed that this and the number of trains to be built for the project depend on how much firm interest is shown by foreign companies to import LNG from Rio de Janeiro. "The final project will be defined only by the first quarter of 2004," he added.
Peru LNG has called for bids for construction of a $1 billion liquefaction plant with an initial capacity of 4.4 million tonnes/year of LNG-600 MMcfd of natural gas-at Pampa Melchorita near Caiiete, 169 km south of Lima. It later will spend another $800 million for additional wells, pipelines, and other facilities. Tractebel will ship the LNG from the plant and regasify it in Mexico.
Botivia's new president Carlos Mesa promised to hold a national referendum on the question of gas exports to mollify protestors who opposed the idea. Bolivia's Margarita Field has some 13 tcf but a pipeline would need to cross Chile to a proposed LNG plant on the Pacific.
Sempra signed a memorandum of understanding with Pacific LNG in
1991 to enter into exclusive negotiations for Bolivian gas but the pact expired
in August of last year, Sempra said. The parent firm owns Southern California
Gas, America's largest gas distributor and is talking to Pacific rim nations
looking for supply and is exploring Alaska as a possible gas source. Sempra
won't start building the Baja terminal until it lands long-term contracts
with shippers, Baum assured investors. The fmn doesn't have any such agreements
http://www.gasandoil.com 17-11-03 Source: United Press International
Egyptian Oil Minister Sameh Fahmy announced his country will rise
to sixth position in the world in terms of exporting LNG. "The latest discoveries
of gas fields will enable Egypt to reach that position by 2006," Fahmy told.
He said Egypt signed an agreement to supply Jordan with gas and was seeking
similar arrangements with Syria, Lebanon, Turkey and Israel. Egypt said
its gas reserves exceeded 55 tcm and were expected to increase to 65 tcm
in a short while. Reports since have put the gas reserves at between 100
tcm and 120 tcm.
Apache Inks 25-Year
Deal to Sell Egyptian Gas
New Liquefied Natural Gas Projects Include Two North Slope Producers
The Alaska Oil & Gas Reporter, Anchorage, Alaska 1/7/2004 URL: http://www.rigzone.com/news/article.asp?a_id=10306
Major oil and gas companies, including several active on the North Slope, are rushing to sign up new deals to import liquefied natural gas, or LNG, into the U.S. and Baja California.
Meanwhile, the U.S. Energy Information Administration has sharply increased its estimates of future LNG imports into the U.S. The latest EIA forecast, released Dec. 16, estimated that LNG imports in 2003 will be twice as high as estimated earlier and will increase by 16 per cent annually to 2025.
Imported LNG is a strong competitor for an Alaska natural gas pipeline because the costs of delivering new gas to the domestic market are expected to be about the same as for the pipeline from Alaska, according to Cambridge Energy Research Associates, a consultant to the state of Alaska. The competitive threat of LNG is enhanced by the fact that the receiving terminals can be built over time so that LNG's share of the market increases gradually, nibbling away at the potential market for an Alaska project, CERA said. A pipeline from Alaska will not be complete until at least 2012.
In its report, the EIA said there are at least "two dozen" proposals to build new LNG import terminals on the U.S. coast by companies rushing to position themselves. BP signed a 20-year agreement Dec. 18 to supply 3.7 million tons of LNG per year to Sempra International Inc. for its planned regasification facility in Baja California. The contract covers a 15-year period.
The Alaska Natural Gas Development Authority had hopes of eventually signing up Sempra as a customer for a new Alaska project, but LNG from Alaska cannot be delivered in time to meet Sempra's timetable. BP will supply LNG from its Tangguh gas field in Indonesia. Sempra hopes to have its plant in operation by 2007.
In another development, BP announced plans in early December to build an LNG regasification facility on the east coast to supply gas to New Jersey, Pennsylvania and Delaware. The LNG would be supplied from Trinidad, where BP owns and operates a large LNG production plant. BP is a major owner of oil and gas properties on the North Slope, and is engaged in studies of a long-distance natural gas pipeline from Alaska to the Lower 48 states.
Another North Slope producer, ConocoPhillips, signed an agreement Dec. 21 to participate in a planned LNG receiving terminal in Quintana, Texas. The company will acquire capacity in the plant sufficient to process 1 billion cubic of gas. The project is expected to start up in 2007.
The EIA said in its Dec. 16 report that the U.S. could be importing 2.2 trillion cubic feet of gas per year in the form of LNG by 2010, in its latest assessment. By 2025 imports of LNG are expected to grow to 4.8 trillion cubic feet per year, enough to meet 8 percent of projected U.S. gas consumption. Strong U.S. demand for natural gas and a drop in the cost of producing LNG will fuel the coming boom in U.S. LNG imports, the EIA said in its report.
Liquefaction costs have dropped 35 to 50 percent over the last 10 years due to improved technology, according to the EIA.
BP LNG terminal New Jersey
Dec 4, 2003 - Reuters Power News SAN FRANCISCO
Global energy giant BP on Thursday said it proposed to build a $500 mln liquefied natural gas terminal (LNG) in New Jersey in an effort to boost its position in the fast-growing U.S. LNG market. BP said it planned to initiate regulatory filings with federal officials later this month.
The termiinal is scheduled to begin service around 2008, spokesman
Howard Miller said.
Around 30 proposals to build LNG terminals have been announced in
the past two years.
He declined comment on what regions BP was considering. Howard said the company had not put an exact price tag on the proposed terminal but said parties familiar with the project, in Gloucester County in southern New Jersey, put the cost estimate at about $500 million.
New Jersey is a major hub for interstate natural gas pipelines serving the populous Northeast, one of the biggest gas consuming regions in the United States.
Four continental U.S. LNG terminals are in operation in Louisiana,
Georgia, Maryland and Massachusetts, with two others operating in Puerto
Rico and Alaska.
The facilities are the first LNG terminals approved in nearly two decades in the United States after once-abundant domestic gas supplies and low gas prices made LNG economically unfeasible for many operators.
LNG has traditionally met just about 1 percent of total U.S. gas
demand though analysts forecast LNG could meet up to 10 percent of total
U.S. gas use by the end of the decade.
Cove Point in the heart of the Chesapeake Bay
Despite the promise of an alternate energy source
on the heels of the mid1970s energy crisis, the demand for LNG never quite
materialized. Jump ahead nearly a quarter of a century, and the projected
demand v. supply numbers are far more impressive, and the production and
Transportation of LNG is booming.
Almost identical to their the two sister tugs built before them - Janet M. and Vicki M. McAllister - the Emily Anne and A.J. will have the ability to not only pump out I 1,000 gpm, but will also be among the first-privately owned tugs on the U.S. East Coast to hold FiFi I firefighting classification as awarded by ABS. Each measuring 96 ft., with a breadth of 34 ft. and depth of 14.9 ft., the tugs were constructed at Eastern Shipbuilding in Panama City, Fla. With the Emily Anne delivered I McAllister this past summer, the A.J which underwent successful sea trials tt end of October, is scheduled for deliver to McAllister in early November 20( where it will undergo a "try out" period various ports until its deployment at Cove Point at the start of the New Year. The fire fighting equipment four onboard this pair of technological]
"The engines for the firefighting equipment are almost as big as the mafin engines," according to Buckley. "Our new boats have roughly quadruple the firefighting of the Janet and Vicki in terms of gpm."
According to Glynn Grantham, president of In-Mar Systems, New Orleans, La., which is the distributor for SKUM products in the U.S. and Mexico, both fire pumps are driven by their own dedicated engines - unlike the traditional practice of driving the pumps off the main engines. "We can assure that with the (tugs') engines off that the monitors (dedicated engines) would push the tug at three knots without the main engines running; the fire monitors are similar to jet engines," Grantham says.
With each monitor able to expel 3,500 lbs. of force spraying streams of water that measure approximately 3.5 in. of diameter, this would not be a practice that would be heralded without caution. To protect against personnel onboard the vessel or tug in distress, the tugs' water cannons can be configured to resemble that of a duck bill, which squeezes the water flow via a device at the end of the nozzle to provide a fogging effect - rather than a highpowered, steady stream. This process, according to Grantham, is especially effective when trying to perform rescue operations on tankers or oil rigs - a logical solution for tugs working at the Cove Point Terminal.
Calling upon Jensen Maritime Consultants of Seattle, Wash. to design these technologically advanced tugs, McAllister enlisted the expertise of Jonathan Parrot, Jensen's director of engineering, who worked with the company to customize Jensen's design. "We used a plum bow (instead of raked) so that the tugs would be able to do barge assist work," according to Buckley.
McAllister also reduced the size of the tugs' pilot house on the Emily Anne and the A.J. so that they could get up close and personal anywhere on the ship.
Other modifications included the decision to use Schottel drives, which was an easy one for McAllister - the company's first Z-drive tug, the Brooklyn still runs successfully on Schottel equipment. Constructed in 1985, the tug, which currently operates out of Philadelphia, set a model for the company in terms of Z-drive tugs. "The initial changes on the tugs were the Schottel drives," Buckley said. "We've been very happy with them and have ended up with a great service record because of them."
When Dominion Energy decided to resurrect the Cove Point Terminal from El Paso Energy, the new operator then bid out the terminal's capacity to three shippers who would call there - BP, Shell and Statoil - who immediately enlisted a "Zero Tolerance Policy" in terms of safety. hence the FiFi I on all four tugs. "The reason they are (the tugs) FiFi I is because the shippers at Cove Point requested to have advanced firefighting tugs," Buckley said. "It's all part of the zero tolerance safety culture connected with the LNG terminals."
Until the Janet McAllister, which was introduced with much fanfare in New York Harbor in July 2001, McAllister had not constructed a Z-drive tug since the Brooklyn made its debut. Things changed however when the possibility of the Cove Point Terminal started to become a reality"From 1985 until about five years ago our customers did not put a premium on Z-drives," Buckley said. "The Cove Point Terminal shippers have put a premium on safety, and are willing to pay for custom built tugs."
Following the RFP that was issued by the shipping trio in the spring of 2002, the contract was awarded to McAllister and Moran who each bid on half the tug requirements at the terminal. According to Buckley, his company wasted no time in the construction process at Eastern Shipbuilding. "We started building the Emily Anne so that a FiFi I tug would be available from the first day of operation at the terminal - July 2003," he said.
With four tug companies trying to get piece of this contract, Brian McAllister, president of the company that bears his name, notes that the decision to choose his company's services is not based upon the tugs themselves. "We submitted our specs of our boats and our spec4s met all theiishipping requirements," he said. "But wh\ we were picked only the customer can tel for sure."
Brian also said that the shippers not only got involved in the bidding process, but with the training of both Moran's and McAllister's onboard and shoreside crews. "These shippers have extremely knowledgeable marine people who know and understand precise requirements' that they want from the tugs that are available," Brian said. "This includes escort capabilities, horsepower, bollard pull, firefighting and most importantly local, highly trained backup crews."
Both McAllister and Moran held crew training courses at MSI in Newport, R.I. on specially-designed simulators that recreate both the bridge of the ship and bridge of the tug in two separate rooms, which allows the docking pilots to interact easily with tug crews. According to Buckley, the docking pilots and tug masters took a three-day course curriculum that was part of the MSI training sessions, which included a presentation on the properties of LNG. "The shippers have been focused on getting docking pilots and tug crews to review policies and procedures for docking tankers and for overseeing exactly how ship docking services were going to be performed," Buckley said.
Brian McAllister was amazed at the extent of the terminal specific training that was offered to his crew and shoreside personnel - training, which went above and beyond the general legal requirements. "When you stop to think, we've been in the shipdocking business for over 100 years. We may meet with customers, such as Maersk, on certain occasions to review operations. Rarely have we had customers devote resources to such specialized training," he said. "The extent of the training was remarkable. But it is what can now be expected in zero tolerance conditions such as Cove Point."
American LNG imports are on the rise. Statoil delivered its first cargo of LNG, representing 80 MMcm of regassified natural gas, to the Cove Point, Maryland, terminal in early September. A second shipment was scheduled from another supplier for later the same month.
Final negotiations are underway on long-term LNG deliveries to Cove Point. According to Statoil, that step will secure supplies until the Snohvit field in the Barents Sea comes onstream in 2006.
Statoil signed an agreement with El Paso Merchant Energy last year, securing the right to one-third of Cove Points import capacity over 20 years.
Long-term Solution Needed To Embrace Imports with
(Editor's note. Last month's article outlined a number of the pending issues and challenges relating to the ability of U.S. LLVG imports to import a wide variety of LNG cargoes, many that a gross beating value (GHV) that exceeds the present GHV specifications for domestic pipeline gas. With that discussion providing the background, this month's article will explore some of the recent experiences of U.S. GHG import terminal outlets and operators in dealing with high GHV issue.)
The Elba Island Experience
Concerning this effort, SLNG submitted a pro forma
gas tariff that included a requirement that, among other things, LNG tendered
to the terminal must be merchantable. It must have a gross heating value that
is not less than 1,000 Btu/cf and not greater than 1,075 Btu/cf.
The tariff further provided that LNG may not be tendered if, on sendout, the revaporized LNG would cause the composite sendout gas stream to fail requirements of the downstream pipeline. This specification was in part designed to facilitate LNG imports by a British Gas subsidiary from an LNG production facility located in the Republic of Trinidad and Tobago. It should be borne in mind that Southern Natural Gas, owner of the main pipeline system served by the Elba Island terminal, did not at the time (and still does not) have a maximum Btu content specification in its pipeline tariff.
Furthermore, when the SLNG facilities were originally
commissioned, the Federal Power Commission, the predecessor to FERC, noted
that the expected Btu content of LNG to be imported from Algeria was 1,139
A spurned capacity bidder filed protest with FERC that challenged SLNG's allocation of long-term firm terminal services to a marketing affiliate. Concerning the settlement of that dispute, SLNG made an application to FERC for the installation and operation of certain upgraded vaporizer equipment. Also, to install either air or nitrogen injection facilities at the tailgate of the terminal. That would allow SLNG to reduce the content of certain LNG tendered by such capacity bidder to the terminal to 1,075 Btu/cf in order to meet SLNG's tariff specification for maximum GHV.
Later in the proceeding, SLNG also explored with all interested parties whether the issue surrounding high GHV LNG could be resolved by developing a mechanism whereby SLNG would be required to waive the maximum Btu specification in its tariff under certain agreed circumstances.
Two customers of Southern Natural, operator of the main pipeline connected to the Elba Island facility promptly filed objections to the air and nitrogen injection proposals, especially to the proposal to inject air. One customer claimed that either of the proposed Btu stabilization methods would cause problems for its downstream industrial customers due to the effect that an increase in carbon content allegedly present in higher GHV gas would have on catalysts used in the production of steel.
That customer also cited the potential for fluctuation in Btu content that could interfere with customer uses that require a stable furnace temperature over long periods. This includes the production of glass fiber products, the potential for reduced industrial boiler efficiency due to changes in fuel Btu content, and the potential for incomplete combustion to cause excess soot production that would discolor tile and brick products during the manufacturing process.
The other customer, a fertilizer manufacturer, claimed that air injection should not be permitted since the resulting oxygen would impair its production capabilities by causing carbon formation on its hydrodesulphurization catalyst.
Two other Southern Natural customers filed comments indicating that they could not determine how SLNG's proposals would affect their interests. They asked FERC to require SLNG to provide additional information in order to allow them to best evaluate the impact of SLNG's proposal.
To support its air and nitrogen injection proposals, SLNG retained an independent engineering firm. After extensive study and testing, concluded LNG with a gross heating value of 1.17 Btu/cf could be effectively diluted to 1,075 Btu/cf, using the 3.8 percent air injection method. In addition, LNG with a gross heating value of 1,097 Btu/cf could be effectively diluted to 1,075 Btu/cf using the 2 percent nitrogen injection method.
Later technical commentators pointed out that permissible
inlet LNG heating values may actually be higher under the 3.8 percent air
injection method since the dilution with air also reduces the specific gravity
of the sendout gas stream.
SLNG's independent engineers estimated that installation of the air injection facilities would cost approximately $18.5 million, while installation or nitrogen injection facilities by reporting that the cost of installing stripping facilities to remove higher Btu content NGLs, such as ethane, propane and butane, would be approximately $40 million, exclusive of the additional costs required to transport (by pipeline, truck, barge or rail) and market the resulting liquids products.
Concerning the FERC proceeding, one of SLNG's indirect LNG suppliers responded to indirect downstream gas customer preferences for the installation of stripping facilities by reporting that the cost of installing stripping facilities to remove higher Btu content NGLs, such as ethane, propane and butane, would be approximately 40 million, exclusive of the additional costs required to transport (by pipeline, truck, barge or rail) and market the resulting liquids products.
This same supplier calculated that because of the lack of any meaningful market for NGLs on the U.S. East Coast, the stripped liquids would have to be sold into the U.S. Gulf Coast petrochemicals market, which after barge transportation from Elba Island, would result in a net penalty of $0.04 to $0.05 on each MMBtu of high heat content LNG delivered into the Elba island terminal.
After these engineering studies were completed and it appeared to at least one interested party, that 3.8% air injection was the more efficient means to stabilize the variety of high Btu LNG imports. SLNG declined to further pursue either injection method, stating in a FERC filing that, "[n]either the 3.8 percent air nor the 2 percent nitrogen proposal for Btu stabilization will cause flowing gas to exceed the quantitative specifications for nitrogen or oxygen in Southern LNG's and Southern Natural's tariffs. However, both tariffs impose a further specification that the natural gas be 'merchantable.' Southern LNG's injection of 3.8 percent air or 2% nitrogen would cause flowing gas to contain inerts that exceed historical levels on Southern Natural's system."
In other words, both air and nitrogen injection would result in sendout gas that would meet the applicable terminal and pipeline tariff quantitative composition specifications. Nevertheless SLNG would not pursue either injection method due to concerns that its ultimate downstream customers would reject tendered gas on the basis that it is not merchantable due to the presence of inerts that. While not outside the range of any tariff requirement, were in greater concentration than had previously been found in the Southern Natural pipeline system.
SLNG, or rather SLNG's customers, took the position that the merchantability standard is independent from the quantitative tariff specifications and could be used as a form of 'trump card' to override these quantitative specifications. One downstream gas customer succinctly phrased the position as follows: "Gas that may cause reliability problems is simply not merchantable."
The difficulty that U.S. LNG importers to Elba Island will likely have with this position is that the term 'merchantable' is not defined in either the SLNG or the Southern Natural tariffs. Furthermore, it appears that although there are a few FERC orders that discuss the concept of merchantability, it appears that FERC has never precisely defined the meaning of the term. Likewise, it does not appear that FERC has ever applied a general tariff merchantability requirement to override a more specific tariff quality specification, or vice versa.
A search of published federal court decisions at the time likewise did not reveal any case in which the term merchantable was defined in the context of interpreting a gas terminal or pipeline tariff. Some have suggested that the use of an undefined merchantability standard to override a specific tariff quality specification raises questions as to whether the rejection of gas based on a vague and subjective merchantability provision is, on its face, discriminatory or allows the potential for unlawful preferences.
This issue is by no means resolved, and unfortunately until it is in a way that gives potential LNG importers and gas customers some level of certainty as to its application, it could continue to present an impediment to FERC's recently announced policy objective of maximizing the importation of 1NG in order to help address the growing domestic natural gas supply-demand imbalance.
Since the 1980s, the LNG facilities at Cove Point, MD have been operated as a peak shaving liquefaction and gas storage facility, with the marine import terminal facilities being mothballed after early LNG supply arrangements with an Algerian supplier broke down over pricing issues. The existing Cove Point tariff governing receipt of domestic gas for such LNG peak shaving activities provides for the receipt of gas with a Btu content ranging from 967 Btu/cf to 1,065 Btu/cf.
Upon making its application with FERC to recommission the facilities for LNG import service in January 2001, Dominion Cove Point, the owner of the facility, filed a pro forma tariff that provided for the receipt of LNG with a Btu content that can range from 950 Btu/cf to 1, 1 50 Btu/cf, and a mechanism to waive the tariff requirement and permit the receipt of even higher GHV cargoes under certain circumstances. The new tariff also reduced the acceptable carbon dioxide content in delivered LNG from 1.5 percent to 1.0 percent and increased the permissible levels of nitrogen in delivered LNG from 0.75 percent to 4.0 percent.
As with SLNG's reactivation filing, it was not long before several challenges (and at least one lawsuit) to the- change in tariff specifications were lodged by downstream gas customers seeking to prevent the increase in maximum Btu content and to block the ability of Dominion Cove Point to waive maximum GHV tariff specifications in order to receive and treat even higher Btu content LNG. These objections were generally based upon a number of the same gas quality and merchantability issues that were previously raised in the Elba island terminal recommissioning proceedings.
After a year of negotiations with various interested parties, Dominion Cove Point filed a settlement proposal with FERC that would essentially preserve the increase in the tariffs maximum Btu content specification and could also allow Dominion Cove Point to waive the tariff requirement and permit the receipt of even higher GHV cargoes under certain circumstances where the quantity of on-specification gas available for pipeline sendout following nitrogen injection and LNG blending, would not be reduced below the quantity of such gas that would likely be scheduled by firm gas buyers. This settlement has now been accepted by all interested parties and awaits court approval in order to become effective.
Perhaps the most encouraging part of this saga is that the settlement also provided that Dominion Cove Point and the affected parties are required to commission and participate in an independent LNG-gas interchangeability study to investigate whether Dominion Cove Point's proposed nitrogen injection facilities, when coupled with "streaming," or routing certain quantities of high heat content vaporized LNG directly to a nearby power generation customer, would allow the receipt of LNG with a higher GHV content without jeopardizing the safe and efficient operations of the downstream natural gas customers.
The conclusions reached in this interchangeability study, as well as the acceptance of such conclusions, will no doubt have far-reaching implications for a number of future LNG import terminal developers.
The Everett (Boston) Experience
FERC rejected Algonquin's argument and declined to order DOMAC to install additional gas conditioning equipment. In part, based upon the fact that, even if air injection were to cause an increase in the oxygen and carbon dioxide content of the sendout gas, such gas would still comply with DOMAC's tariff specifications. Its tariff did not contain standards for acceptable levels of oxygen or water vapor. As for Btu content, DOMAC's filed tariff provides for the acceptance of LNG with a Btu content that ranges between 950 Btu/cf and 1,150 Btu/cf.
The interesting part of this proceeding is that at the same time it rejected any requirement that DOMAC must condition its sendout gas prior to delivery to Algonquin, FERC nevertheless pointed out its belief that Algonquin was able to adequately protect itself. Its pipeline tariff contained specifications for acceptable levels of oxygen and dioxide that would provide a basis for rejection if the vaporized LNG tendered by DOMAC failed to meet Algonquin's gas tariff quality specifications.
FERC then appears to endorse the idea that Algonquin could also refuse to accept gas onto its system based on a general, catchall tariff provision that purported to allow Algonquin to reject tendered gas. That is if, in its judgment, Algonquin believed that harm to its facilities or operations could reasonably be expected to occur if such gas, were to be received and transported.
To the extent that this catch-all provision can be equated with a general gas merchantability standard, albeit in a fairly subjective form, widespread acceptance of this decision could make efforts to explore various Btu stabilization alternatives more difficult. Fortunately for the LNG import community, this portion of FERC's analysis does not appear to have been necessary to its ultimate decision and therefore, it can be argued that it is of questionable precedential value.
The Lake Charles
At, a time when expanding the diversity of gas supplies is becoming increasingly necessary, it will be important for all participants in the U.S. natural gas markets to work more effectively and cooperatively toward more creative and flexible long term solutions that will in the end benefit everyone. The Btu stabilization mechanisms and gas/LNG interchangeability studies described herein is a good starting point, but more work certainly remains to be done.
Gas shortfall continues despite LNG permit activity Even as state-of-the-art LNG receiving terminals are installed, they'll incorporate new technology at a rapid pace, said Jim O'Sullivan, Technip Offshore's senior vice president for marketing, during the sixth annual Global Forum for Engineering and Construction at Rice University.
The fist LNG receiving terminals in the Gulf of Mexico could come onstream as early as 2005, but O'Sullivan expects 2007 as the more likely arrival time of the first receiving terminal in the Gulf.
Despite the number of terminals under consideration, not one final perrnit had been issued as of early September. Ten terminal permit requests have been filed for onshore US, in addition to the five offshore GoM permit requests. Of those, three are for onshore California and two offshore California. One is for onshore East Coast. Of the remaining nine, three are for offshore GoM and six are for onshore along the Gulf Coast. O'Sullivan doesn't expect any of the California terminals to be onstream before 2010.
One permit has been filed for the Bahamas, and five have been filed off Mexico, with four of those on the Baja California side. In the long run, O'Sullivan said, locating the terminals over the border will help but will not be a final solution because of infrastructure. The "not in my backyard" (Nimby) risk is a timing risk, just as technology is a timing risk that can likely be mitigated. Industry has tended toward manmade islands to serve as the receiving terminals. They provide flexibility because they don't require specialized carriers but do allow mid-ship loading, he said. There is no single point mooring, so the setup will allow alongside berthing. The downside, he said, is that there would be less than 80% accessibility in the Gulf. El Paso's Energy Bridge proposal is a bit different, he said, but it will require specialized vessels.
One technological advance that will "make a huge jump in annual availability" in the Gulf is a floating cryogenic hose, which is under development, O'Sullivan said. These hoses should be available in 2006-2007. The terminals now being designed will not likely include them as an initial feature but rather as an immediate upgrade on installation, he said. "Supply is the main driver" for the number of receiving terminals under consideration, he said. The concern for supply is tied directly to supply coming from the Gulf of Mexico, he said. "The shelf peaked in 1997 and has been in decline ever since," O'Sullivan said. "There's no coming back." Gas is now being found in the deepwater GoM, but lack of infrastructure for transportation could hamper development of those reserves, he said.
Combine a declining shelf with an increasing demand, and LNG receiving terminals make a lot of sense. The problem, he said, is even with a concentration on LNG import there will still be a shortfall of 1-Tcf/year through 2010.
ChevronTexaco gets approval for Gulf of Mexico LNG terminal
ChevronTexaco said that it has received federal approval to build Port Pelican, the nation's first offshore LNG terminal. The terminal will be in the Gulf of Mexico, about 40 miles off Louisiana, basically a big concrete structure sitting on the floor of the Gulf where LNG tankers can unload their cargoes. The Maritime Administration of the Department of Transportation granted the company a deep-water port license, which allows it to construct, own and operate the terminal.
Port Pelican will be the first deep-water port in the United States since the Louisiana Offshore Oil Port of 1976 and also the first natural gas deep-water port in the world. Until now LNG terminals have been built on land. Port Pelican will consist of a receiving terminal to handle the ships, facilities to store LNG, facilities to turn it from a ultra-cold liquid back into a gas, and pipeline connections to the interstate natural gas delivery system. Its capacity will be 1.6 bn cfpd of gas. "This is a positive example of industry and government working together to ensure the energy infrastructure is in place to meet the growing demand for natural gas in the United States," said Richard Lammons, vice president of Port Pelican, from company headquarters in San Ramon, California.
The company expects to start construction next year, with operation
projected to start in 2007. Major contracts for the front-end engineering
design were recently awarded, and ChevronTexaco is securing LNG supplies for
|The Bear Head LNG Terminal
Anadarko Petroleum buys out Access Northeast Energy's Bear Head LNG terminal 08 13 2004
The Bear Head LNG Terminal development would include marine off loading, LNG storage and re-gasification facilities to deliver gas into the Maritimes and Northeast Pipeline (M&NP), which services Eastern Canada and the Northeast U.S. gas markets. Pending receipt of appropriate permits, the proposed Bear Head LNG terminal would be in commercial operation with a send-out capacity of 1,000 million standard cubic feet per day (MMscfd) by November 2007.
TransCanada Corporation and ConocoPhillips have announced plans to build a new LNG receiving terminal at a site previously used as a U.S. Navy fuel depot and currently owned by the town of Harpswell, ME.
The companies recently presented plans for the project to the Town
Selectmen and asked them to initiate in detailed public review of the project
and to schedule a town meeting vote for a series of ballot initiatives that
would allow the project to go forward.
Freeport LNG Proposed Texas Receiving Terminal
Inks Deal with Freeport for TX LNG Terminal
AES Corp. is the "front-runner" in the competition to build a liquefied natural gas (LNG) terminal in the Bahamas to serve the nearby Florida market, Bahamas Trade Minister Leslie Miller said on Thursday. "All indications are that we should know by mid-January who the license is given to," Miller told a global LNG trade conference. AES has proposed building an LNG terminal in the Bahamas to supply more natural gas to the growing Florida market.
The Bahamian government has not yet officially decided whether to approve the AES plan. Another company, Suez of France's Tractebel unit, is also seeking to build an LNG facility in the Bahamas. "If the need arises, Tractebel would likely be given license to build a second LNG terminal," an aide to Miller said.
Both AES and Tractebel have won preliminary approval from the U.S. Federal Energy Regulatory Commission to build separate pipelines from the Bahamas to Florida.
AES proposed constructing a 54-mile pipeline, which would transport up to 842 million cubic feet of natural gas a day and connect to a Bahamas-jurisdiction pipeline owned by another AES affiliate that extends to Ocean Cay in the Bahamas. Ocean Cay, a 90-acre man-made industrial island, would be the site of an LNG import terminal to receive supplies from producers such as Trinidad or Algeria.
BG Group has today announced that its wholly-owned subsidiaries,
BG LNG Services, LLC (BGLS) and BG Gas Marketing Ltd (BGGM), have completed
an agreement with El Paso Merchant Energy (EPME) to acquire all of EPME's
capacity in the Elba Island liquefied natural gas (LNG) re-gasification terminal
near Savannah, Georgia, USA and related LNG purchase and gas sale agreements.
BG Group Acquires
LNG Capacity at Elba Island
Sabine Pass, La.,
and Corpus Christi, Tex.
Plans for LNG Project in Eureka, Calif.