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WTI Crude Trades Near Two-Week High on U.S. Gasoline Supply Drop

West Texas Intermediate traded near the highest price in two weeks after U.S. gasoline stockpiles tumbled and fuel demand in the world’s biggest crude consumer increased.

Futures were little changed in New York after jumping yesterday by the most since Dec. 26.Gasoline inventories shrank by 3.93 million barrels last week for the biggest decline in a year, data from the Energy Information Administration showed. Demand for the motor fuel increased 4.4 percent to 8.75 million barrels a day, the highest level since November.

WTI crude for June delivery was at $91.54 a barrel, up 11 cents, in electronic trading on the New York Mercantile Exchange at 8:30 a.m. Tokyo time. The volume of all futures traded was 68 percent below the 100-day average. The contract rose $2.25 to $91.43 a barrel yesterday, the highest settlement since April 11. Prices are down 0.3 percent this year.

Brent oil for June settlement advanced $1.42, or 1.4 percent, to end the session at $101.73 a barrel on the London- based ICE Futures Europe exchange yesterday.

The European benchmark grade traded at a premium of $10.30 to WTI, the narrowest differential since Jan. 18, 2012. The spread declined after Genscape Inc. said BP Plc (BP/)increased flows on the BP1 pipeline that links Cushing, Oklahoma, the delivery point for New York-traded futures, to its Whiting, Indiana, refinery to 172,000 barrels a day from about 86,000.

To contact the reporter on this story: Jacob Adelman in Tokyo at jadelman1@bloomberg.net

To contact the editor responsible for this story: Alexander Kwiatkowski atakwiatkowsk2@bloomberg.net

Diesel to Climb as Record Planting Eats at Inventories

Diesel prices are surging in the U.S. Midwest as farmers prepare to plant a record amount of crops this season, eating into below-average fuel supplies.

Farmers may sow 174.4 million acres of corn and soybeans this year, boosting output by 30 percent, the Agriculture Department forecast. Midwest prices are at the highest seasonal premium to the Gulf Coast since 2007. The Energy Information Administration estimated agricultural distillate fuel use will rise 5.1 percent in 2013 to the most since 2010.

Demand for fuel to run tractors and combines is growing as the U.S. attempts to recover from last year’s drought, the worst since the 1930s. Photographer: Victor J. Blue/Bloomberg

April 24 (Bloomberg) -- U.S. Federal Energy Regulatory Commission Chairman Jon Wellinghoff talks about the U.S. power grid and potential threats facing it. He speaks with Tom Keene and Scarlet Fu on Bloomberg Television's "Surveillance." Sarat Sethi, a principal and portfolio manager at Douglas C. Lane & Associates, also speaks. (Source: Bloomberg)

Demand for fuel to run tractors and combines is growing as the U.S. attempts to recover from last year’s drought, the worst since the 1930s. At the same time, refinery maintenance may limit local production, pushing prices higher to entice suppliers to ship diesel north by pipeline from the Gulf Coast rather than send it abroad.

“Farmers are going to be planting fence to fence this year,” Steve Mosby, vice president of supply consultant ADMO Energy LLC, said in a phone interview from Kansas City,Missouri. “We’re looking at huge demand in a year that supply is really off. Prices are going to explode.”

Ultra-low-sulfur diesel in the Midwest, or the Group 3 spot market, was 4.63 cents a gallon above futures on the New York Mercantile Exchange yesterday, compared with a 2.75-cent discount in the Gulf Coast, data compiled by Bloomberg show. The Group 3 includes states north of Tulsa, Oklahoma, to Minnesota and North Dakota along Magellan Midstream Partners LP (MMP)’s pipeline system. ULSD futures increased 1 percent to $2.8403 a gallon at 1:08 p.m. in New York.

Record Acres

Fuel demand may surge as early as May, when many Midwest farmers begin to sow fields for the September and October harvest season. Growers intend to plant 97.3 million acres of corn, the most since 1936, and 77.1 million acres of soybeans, the Agriculture Department reportedMarch 28.

The agricultural sector will probably use about 141,572 barrels of distillate fuel a day, compared with 134,752 barrels in 2012, EIA data show. U.S. farms and ranches typically use this fuel to power tractors, combines and other equipment.

Farms’ cash expenses may rise to $316.6 billion, with fuel accounting for 5 percent of spending, or $15.7 billion. Costs have averaged $14.4 billion a year since 2009, the data show.

“We should see an increase in planted acreage this year and that’s the biggest factor in fuel spending,” Chris McGath, an agricultural economist of the economic research service at the Agriculture Department, said by phone from Washington. “There will be a lot of consumption.”

IllinoisIowaNebraska and Minnesota may consume the most fuel as the states are expected by the government to plant the largest number of corn and soybean acres this season.

Wide Differential

“Once planting begins in the Midwest, we expect those prices are definitely going to rise and the differential to the Gulf Coast will stay wide,” Ed Malloy, president of Danaher Oil Co., said in a phone interview from Fairfield, Iowa.

Planting was slowed as heavy rain last week spurred flooding along rivers. Storms on April 17 and April 18 in the northern Midwest dropped 5.4 inches (14 centimeters) of rain on Chicago and as much as 6 inches on part of Eastern Iowa, according to AccuWeather.com.

Corn planting in the largest U.S. producing states was 2 percent complete as of April 14, compared with last year’s pace of 16 percent, Agriculture Department data showed. No corn was seeded in Iowa, the biggest producing state.

Refinery Turnarounds

Inventories of distillate fuel in Petroleum Administration Defense District 2, which covers an area from Oklahoma north through North Dakota and east through Ohio, were 28.8 million barrels as of April 19, 8.3 percent less than a year earlier, EIA data show. PADD 2 refiners processed 3.14 million barrels a day of crude, the fewest in two years.

Phillips 66 (PSX)’s Wood River, Illinois, and BP Plc (BP)’s Whiting, Indiana, plants, the two largest in PADD 2, have had units shut for maintenance. HollyFrontier Corp. (HFC)’s Tulsa, Oklahoma, refinery plans work this quarter, joining Calumet Specialty Products Partners LP’s Superior, Wisconsin, plant and Exxon Mobil Corp.’s Joliet, Illinois, site that have begun turnarounds.

“There has been a lot of turnaround going on in the PADD 2 region and it’s still unclear as to when we’ll see Whiting producing at full rates again,” Chris Barber, a senior analyst at Energy Security Analysis, Inc. in Wakefield, Massachusetts, said by phone. “That’s definitely going to make a difference and continue to take supply offline.”

Chicago Premium

The spread between diesel in Chicago and the Gulf Coast was about 16.75 cents a gallon, the highest level for this time of year since at least 2006. Chicago ULSD has averaged 0.84 cent a gallon over the Gulf Coast around this time of year since 2008, compared with 1.21 cents a gallon for Group 3, according to data compiled by Bloomberg.

It costs about 4 cents a gallon to ship diesel from the Houston area to Tulsa and about 7 cents to ship it to Chicago on the Explorer pipeline, based on tariff data on Explorer Pipeline Co.’s website.

Chicago was 8.19 cents over Group 3, making it a more attractive destination for supplies shipped north from the Gulf.

“The turnarounds in Chicago have driven the supply side of the picture and pushed prices higher in the region,” Malloy said. “There’s a big arbitrage between Chicago and the Group 3 in distillate.”

Refineries on the Gulf Coast sent 2.7 million barrels of distillate to the Midwest by pipeline, tanker or barge in January, according to EIA data. In the same month, 19.8 million barrels were exported from the Gulf.

Latin Competition

“The Midwest is really going to have to compete on price if they want those barrels because Latin America needs that fuel and the Gulf generally exports most diesel,” Barber said.

Latin America is likely to use 7.01 million barrels a day of fuel in the second quarter, 4 percent more than a year earlier, the EIA estimated April 9.

“We should have enough distillates on the Gulf Coast to satisfy foreign demand and Midwest demand,” said John Auers, senior vice president of Tuner Mason & Co., a petroleum and refining consulting firm in Dallas. “If we’re short diesel and there’s demand, the reaction will be an increase in diesel prices and the barrels will come up from the Gulf.”

To contact the reporter on this story: Christine Harvey in New York atcharvey32@bloomberg.net

To contact the editor responsible for this story: Dan Stets at dstets@bloomberg.net

Vanco and LUKOIL Discover Gas-Condensate and Oil at Dzata-1

ACCRA
, Ghana--Vanco Ghana Ltd. (Vanco), together with LUKOIL Overseas Ghana Ltd. and GNPC, announces that the Dzata-1 exploration well drilled on the Cape Three Points Deep Water Block located offshore the Republic of Ghana has discovered a significant hydrocarbon accumulation based on the results of drilling, wireline logs and samples of reservoir fluid.

Dzata-1 is situated in a water depth of 1,878 meters, approximately 75 kilometers (45 miles) south of Cape Three Points, and represents the deepest water exploration well drilled to date in the Ghanaian Tano Basin. The well was drilled to a total depth of 4,433 meters and at 3,653 meters encountered a gross hydrocarbon column of 94 meters with 25 meters of net stacked oil and gas pay. The primary reservoir sandstone between the depths of 3,663 and 3,690 meters contains gas and light oil. Volatile black oil was recovered from a zone between 3,701 and 3,709 meters. The well has been plugged and temporarily abandoned pending further evaluation.

The Dzata discovery, in a Cenomanian/Albian faulted anticlinal trap, opens a new prospective trend in the eastern part of the prolific Tano Basin. Dzata continues the series of recent exploration successes, which include discoveries at Jubilee, Tweneboa, Odum and Sankofa. In addition to the 1,500 square kilometer 3D survey acquired in 2005 which was used to define the Dzata Prospect, Vanco and LUKOIL are currently acquiring a new 1,664 square kilometer 3D program to identify prospective features in the northern and western parts of the block.

The Dzata-1 well was drilled using the “Sedco 702” - a dynamically positioned fifth-generation deepwater semi-submersible drilling unit. This is the first exploration well to be drilled in the Cape Three Points Deep Water Petroleum Agreement Area, which encompasses an area of 5,164 square kilometers (1.27 million acres) in water depths ranging from 200 to 3,000 meters in the Tano Basin.

On April 1, 2009, the Government of the Republic of Ghana, the Ghana National Petroleum Corporation (GNPC), Vanco Ghana Ltd. and LUKOIL Overseas Ghana Ltd. signed a new Petroleum Agreement covering the Cape Three Points Deep Water Block and the new agreement was ratified by Parliament on June 30, 2009.

Vanco (Operator) holds a 28.34% participating interest with LUKOIL holding a 56.66% participating interest. GNPC, the state oil company, holds a 15% carried interest, with the option to acquire up to an additional 5% in any commercial discovery.

 

Crude oil price spike makes its way to the pump
Published: Sunday, February 28, 2010 7:58 AM CST
Although gas prices have stayed within a 15-cent band for the first two months of 2010 (between $2.61 and $2.76), recent increases in crude oil prices have hit prices at the pump. Gas prices have begun to creep back up, with the national average price of regular grade jumping 8 cents last week to $2.70 on Friday.

In the Newark area, prices rose by as much as 15 cents a gallon, almost overnight earlier last week.

Small business social media event slated
Published: Thursday, February 18, 2010 6:43 PM CST
Delaware Small Business Social Media Train is slated for Fri., Feb. 19, from 12 p.m. to 3 p.m.
The event is aimed at small Delaware business with an interest in being visible and communicating on Social Media, but not sure where to start.

 

 

Controversy continues as U.S. LNG imports set to rise

21 May 2009 No Comment

 
LNG HOUSTON, TEXAS: Proposals to build and operate liquefied natural gas (LNG) terminals worldwide continue to face opposition from government officials, citizens and environmental groups.

In the U.S., projects in the Pacific Northwest and the U.S. East Coast continue to stir controversy over environmental and security risk concerns, as does the Federal Energy Regulatory Commission’s (FERC’s) handling of the LNG facility review and licensing process.

A number of LNG terminals were originally proposed as a means to bring natural gas, which was anticipated to be in short supply, to the U.S. However, technological breakthroughs have allowed for the exploration and production of gas from unconventional plays in the U.S. and Canada, increasing supply, leaving doubt as to whether all the proposed LNG terminals will be needed.

Historically, shipments of LNG have been directed away from the U.S. to Asia, where greater demand could command higher prices. However, with Asian and European demand falling due to the global economic recession, LNG imports to the U.S. are expected to increase this year.

Varied projects proceed around the globe


New projects such as AGA Gas AB’s LNG terminal at Brunnsviksholme outside Nynäshamn, Sweden, have been announced. It will be the first of its kind in Sweden.

The LNG tank will be 33 meters (108 ft) high and 38 meters (124 ft) in diameter and will be constructed in slip form in August 2009 and completed during the first half of 2010 by NCC Construction Sweden AB.

NCC will also construct a harbor able to receive tankers with a maximum length of 160 meters (524 ft) and a depth of nine meters (29 ft). An approximately 100-meter-long (328-ft-long) bridge will connect Brunnsviksholme with the mainland. NCC also will construct of a service building, an access road to Norviksvägen, a vehicle bay for receipt of LNG and some ground work.

LNG projects such as Qatargas 2 and Sakhalin 2 have come online. In Qatar, Qatargas has inaugurated Qatargas 2, which it says is the world’s first fully integrated value chain LNG venture.

Combined, Qatargas 2 consists of three offshore unmanned platforms, two world class LNG trains, five storage tanks, two loading berths and a fleet of 14 state of the art LNG ships. The main destination for the LNG will be the South Hook terminal in the deepwater port of Milford Haven, Wales.

Qatargas 2 is capable of providing up to 20 percent of Britain’s natural gas needs.

The South Hook LNG Terminal is the largest LNG receiving terminal in Europe with a capacity of 15.6 million tonnes (17.2 million tons) per annum. The terminal features the largest diameter storage tanks in the world.

A tanker carrying about 67,000 tons of liquefied natural gas docked last month at an LNG receiving terminal in Sodegaura, Chiba Prefecture, Japan, marking the arrival of the first shipment of LNG from Russia’s Sakhalin-2 project.

Tokyo Gas Co. and Tokyo Electric Power Co., which jointly operate the LNG storage facility southeast of Tokyo, will share in shipments equally, with the gas company supplying the LNG as town gas and the electricity firm using it as fuel for its thermal power plants.

With Russia’s LNG project, Tokyo is hoping to reduce its energy dependence on the Middle East while Moscow is aiming to boost natural gas sales in the Asia-Pacific region in addition to Europe.

However, Tokyo Gas anticipates it will purchase less LNG in fiscal year 2009 versus 2008. In fiscal year 2009, Tokyo Gas expects its volume of gas production and purchasing, including LNG, will be 12.3 Bcm (434.3 Bcf), down from 13.1 Bcm (462.6 Bcf) in fiscal year 2008.

LNG market outlook

The U.S. Energy Information Administration (EIA) reports that U.S. LNG imports are expected to increase to about 480 Bcf in 2009, up from 352 Bcf in 2008, because of lower global economic activity and the start up of new liquefaction capacity in the Middle East and other parts of the world.

In its monthly Short-Term Energy Outlook for April, EIA reports that depressed LNG demand in Asia and Europe should tend to increase the amount of LNG available to the United States.  However, the projection is subject to considerable uncertainty. 

Initial production from new liquefaction capacity has been slowed or delayed for extended periods, and U.S. natural gas demand is also projected to be lower in 2009.  As a result, expanded LNG flows into the U.S. likely would depend on there being less domestic natural gas production or imports from Canada than forecast.  U.S. pipeline imports are expected to decline by about 11 percent in 2009. 

Recently, Europe has been seeing an increase in LNG imports, especially into France and the UK, partly because prices for LNG have come down and now are competitive with European prices. Right now, Europe has extra capacity to take in LNG after stores were depleted during last winter’s Russian/Ukrainian dispute, in which gas shipments were curtailed, forcing European countries to draw more gas from storage. Norway and Russia have lately been pushing more gas into the market, unwilling to give up their market share for LNG, said Zach Allen, president of PanEurasian Enterprises.

However, the global recession has hurt electricity demand, and Spain, Japan and South Korea, which last year accounted for over 60 percent of the total world LNG market, have curtailed their LNG buying. “These countries have a tremendous impact on LNG. If they need it and they’re buying aggressively, there’s not much left over. If they’re not buying, that means there’s a lot more LNG available in the market,” Allen said.

While LNG has been heading for Europe in recent months, cargoes will begin bringing LNG to the U.S. as temperatures rise and demand slips in Europe. Typically, the U.S. has been the destination for LNG in the summer as European demand wanes.

Steve Johnson, president of Houston-based Waterborne Energy, reports seeing a 28 percent increase in LNG imports during the first quarter of 2009 versus first quarter 2008, and expects LNG imports in the second quarter of this year to increase.

The global economic crisis, which has hampered energy demand, has resulted in LNG supply being backed out of Asia, and then Europe. The U.S., which has traditionally been a market of last resort, will see a significant influx of LNG imports this year, Johnson noted. “We’re seeing the beginning of a short-term global oversupply. Global supply by mid-2010 is likely to increase by 30 percent, which is enormous by any industry standards.

“Production has been bleeding slowly into the markets, and with seven new plants starting operations this year alone, the U.S. will see its first large incremental increase in imports, maybe 80 Bcf by May or June,” Johnson said.

A significant amount of LNG is likely to be headed to the U.S. from Nigeria and Algeria, where outages at LNG terminals have kept about 50 Bcf of supply off the market. That supply will likely be pushed to the U.S. when these plants come back online. 

“We have a perfect storm brewing, even though we’ll be stirring US$2.50/Mcf gas by this summer. We’re running into a situation where it’s more about storage capacity as opposed to price. There are a lot of the capacity holders in U.S. who are the primary spot players in market. It’s likely these capacity holders will start bringing in this product,” Johnson said.

The economic recovery will likely cause “an enormous whiplash” in the LNG business. A demand increase of five percent in Japan is a huge amount, and when the market turns around, demand for LNG will cause prices to take a severe hit. “It won’t be in five years or six months, but perhaps a year, a year and a half,” said Allen.

Import fears hit U.S. producers

Some industry associations, such as Denver-based Independent Petroleum Association of Mountain States (IPAMS), warned that the influx of foreign gas, in particular the agreement between Shell and the state-run Russian natural gas company Gazprom to import 20 million tons of Russian LNG to the Costa Azul LNG terminal in Baja California, could have devastating effects on independent natural gas producers in the Western United States.

The Gazprom-Shell agreement marks the entry of Gazprom into the North American market. As part of the transaction, Gazprom affiliates, under long-term assignment from Shell, will take capacity in Sempra’s Energia Costa Azul LNG import terminal in Baja California, Mexico, and pipeline capacity to enable gas to be transported to Southern California.

“America is currently awash with American-produced natural gas,” said John Harpole, president of Mercator Energy and member of the IPAMS board of directors. “In fact, due to recent technological advances, our proved reserves have increased dramatically in the past few years, placing the U.S. in an elite group of the world’s most natural-gas rich nations. We have no need for Russian natural gas, and the result will be a loss of American energy jobs.”

The short and medium-term impact of potential LNG imports to the U.S. on U.S. gas prices remains to be seen, according to the FERC’s State of the Market report. During 2008, the U.S. received less than 1 Bcf/d of LNG as prices in the rest of the LNG-importing world were higher than U.S. prices, Asian and European demand was high, and there were occasionally supply shortfalls.

However, world LNG prices have fallen substantially since the end of 2008, to the point that prices for natural gas were on par with the rest of the world by the end of March 2009.

In addition, additional LNG supplies are coming online and Asian and European demand continue to fall. Some analysts forecast U.S. imports greater than 3 Bcf/d by the third quarter of this year. A large inflow of LNG could put substantial downward pressure on natural gas prices, especially if U.S. demand does not rebound or production growth does not slow.

Many U.S. East Coast projects face opposition

While FERC has approved a number of projects, construction on several has been postponed because they lack necessary permits from state agencies.

In the past, critics have said that FERC was too easily green lighting projects, a trend seen by some as likely to change with the appointment of a new FERC chairman, Jon Wellinghoff.

However, Allen said he can’t see FERC behaving differently now that a new chairman is in office. “They may tighten up and be more rigorous in environmental examinations, but they’ve been very rigorous already, I think. The law is pretty specific as to what FERC can or can’t say. FERC is in a box, and they have to determine whether or not a facility is environmentally acceptable.”

Controversy continues to surround a number of proposed projects. Last month, the U.S. Department of Commerce upheld the state of New York’s objection to the proposed construction and operation of a floating LNG terminal and subsea pipeline that would be located in Long Island Sound.

Broadwater Energy LLC and Broadwater Pipeline LLC proposed constructing the terminal, which would have delivered up to 1.25 Bcf/d of gas to fuel electric generating plants and heat homes. The floating storage and regasification unit would have measured about 1,215 feet (370 m) long and 200 feet (61 m) wide, rising 80 feet (24 m) above the water line.

New York asserted that the proposal was inconsistent with the Long Island Sound Coastal Management Program.

BP, which has proposed the Crown Landing LNG facility for construction in Gloucester County, N.J., has had its request to FERC granted to extend the time to construct the terminal and associated pipelines.

BP subsidiary Crown Landing said that current market conditions are severely hampering the construction and development of LNG terminals in the U.S. and that a reconfiguration of the project must be developed, filed with, and approved by FERC before construction can begin.

The project has faced opposition from the state of Delaware over safety concerns. The U.S. Supreme Court in 2008 ruled that Delaware can block New Jersey industrial projects that jut into the state under the Delaware River, including BP’s Crown Landing LNG project.

BP’s proposed project would deliver up to 1.2 Bcf/d of gas to the Mid-Atlantic region.

President Barack Obama on March 30 signed into law H.R. 146, the Omnibus Public Lands Management Act of 2009, which designates about 2 million acres of new wilderness areas. The passage of the bill has been viewed by some as an attempt to block development of the proposed Weaver’s Cove LNG terminal in Fall River, Mass.

Under the bill, the Taunton River in Massachusetts will become part of the Wild & Scenic River system. The “Wild and Scenic” designation would cover the main stem of the Taunton River from its headwaters at the confluence of the Town and Matfield Rivers in the town of Bridgewater downstream 40 miles (64 km) to the confluence with the Quequechan River at the Route 195 Bridge in the city of Fall River.

Critics of the bill say that the lower segment of the Taunton River has been a highly developed, industrialized river for a long time and does not  possess the “remarkable scenic, recreational, geologic, fish and wildlife, historic, cultural or similar values” that qualify a river for wild and scenic designation.

Many LNG projects proposed for the U.S. East Coast face opposition from local officials, but not all. In Maine, Gov. John Baldacci and local industry has urged the Canadian province of New Brunswick to approve the development of LNG facilities in Maine in exchange for the state’s support of an energy corridor that would pass through New Brunswick and Maine.

The current economic environment is affecting the progress of some LNG projects. Earlier this month, FERC approved Cameron LNG LLC’s request for an extension of time until Dec. 31, 2009, to place the Cameron LNG terminal near Hackberry, La., in service.

Cameron LNG said in a March 16, 2008, filing that it has experienced construction delays and will be unable to complete construction of all its facilities within the time originally required. Cameron LNG expects to complete all construction activities and make the facilities available for service by Dec. 31 of this year.

Construction costs for LNG projects rose substantially in the past few years, in some cases doubling and tripling. Given the fall in LNG demand and gas prices, companies will likely begin aggressive cost cutting in the next six months, according to Steven Miles, head of the project development and finance section, as well as the LNG practice, at the international law firm of Baker Botts.

U.S. Gulf of Mexico - too many terminals?

The U.S. Coast Guard issued letters of recommendation on April 10 for eight LNG facilities located throughout the Gulf Coast, including four in Texas, two in Louisiana and two in Mississippi.

The letters indicate that the waterways associated with Calhoun LNG, Point Comfort, Texas; Freeport LNG Phase II, Freeport, Texas; Golden Pass LNG, Sabine Pass, Texas; Port Arthur LNG, Port Arthur, Texas; Creole Trail LNG, Cameron, La.; Sabine Pass LNG Phase II, Cameron Parish, La.; Casotte Landing LNG, Pascagoula, Miss.; and Gulf LNG Clean Energy, Pascagoula, Miss., are suitable for the expected vessel traffic at the facilities.

FERC earlier this year concluded that Sabine Pass LNG’s proposal to export LNG from the Sabine Pass LNG import terminal in Louisiana, with appropriate mitigating measures, would not constitute a major federal action significantly affecting the quality of the human environment.

Sabine Pass said its proposal would provide customers of the Sabine Pass terminal the opportunity to purchase cargoes of LNG at current LNG world market prices that may be higher than prices in U.S. markets, with the intent that such LNG subsequently could be exported for redelivery to a foreign market at a later date.

To export LNG from its facility, Sabine Pass will modify four 24-inch diameter check valves located on Transfer Arms A and D on the East and West Jetty Platforms.

The first phase of Sabine Pass LNG commenced service in April 2008, with 10.1 Bcf of LNG storage in three tanks, each with an LNG capacity of 160,000 cubic meters (5.6 MMcf), and a maximum continuous regasification rate of 2.6 Bcf/d. The first stage of Phase 2 will include the addition of a fourth and fifth storage tank, additional vaporizers that will bring the maximum continuous regasification rate up to 4.0 Bcf/d with a peak send out capacity of 4.3 Bcf/d. In the future stages of Phase 2, Cheniere may add a sixth storage tank and related facilities to bring the total LNG storage volume to 20.2 Bcf.

ExxonMobil’s Golden Pass LNG terminal is expected to begin operations in mid-2009. The LNG terminal will be located approximately 10 miles south (16 km) of Port Arthur and two miles (3.2 km) northwest of Sabine Pass, Texas, in an area zoned for industrial use on the Sabine-Neches Waterway.

In August 2007, FERC concluded that construction of Calhoun Point Comfort’s proposed Calhoun LNG project with appropriate mitigating measures, as recommended, would have limited adverse environmental impact.

The proposed Calhoun LNG facility will be capable of receiving, storing and regasifying up to 1 Bcf/d of LNG.  The project would ultimately consist of two 5.6 MMcf storage tanks with appropriately sized separation and vaporization facilities.  The project will be located near Port Lavaca, Texas. The facility could be operational in late 2009 or early 2010.

Sempra Energy’s Port Arthur LNG project has been permitted, but construction has not begun as the company is waiting on capacity supply contracts to be put into place first.

West Coast projects remain controversial

Three LNG projects proposed for construction in Oregon, Oregon LNG, Bradwood Landing LNG and Jordan Cove LNG, have sparked concerns among state and local officials, environmental groups and local residents over the projects’ impact on the local environment and wildlife, safety risks and impact on local industries such as forestry.

Some critics also view the projects as a means of using Oregon as a backdoor to supply more energy to California, and have criticized FERC’s handling of the LNG facility review and license process.

Both Allen and Johnson think it’s unlikely that LNG projects proposed for construction on the U.S. West Coast will be commercially viable. “It’s counterproductive and expensive to try and push through projects there,” Johnson said.

In a bid to regulate how and whether LNG projects are approved for construction and operation in Oregon, a bill was submitted to the Oregon Legislative Assembly that would establish certain requirements before applicants seeking to construct LNG terminals or related pipelines may be issued specified permits and authorizations. However, the bill died in committee.

Despite local opposition, FERC has concluded that the proposed Jordan Cove LNG project and associated Pacific Connector pipeline project would have limited adverse environmental impacts if constructed.

The U.S. Coast Guard also has issued a letter of recommendation for the Oregon LNG receiving terminal proposed for construction on the Skipanon Peninsula in Warrenton, Ore.

The Coast Guard has determined that, while portions of the Columbia River and its approaches are not currently suitable for the proposed traffic, they could be made suitable for the type and frequency of LNG marine traffic associated with the project. “Additional measures are necessary to responsibly manage the maritime safety and security risks,” the Coast Guard said.

Specific risk mitigation measures recommended to manage the safety and security risks of the project include a moving safety-security zone to be established around the LNG vessel extending 500 yards around the vessel but ending at the shoreline.

Construction of the import facility and an associated pipeline is anticipated to begin in 2010. The project is expected to begin serving customers in 2013.

The Oregon LNG receiving terminal will be designed with a natural gas send out capacity of 1.0 Bcf/d and a peak of up to 1.5 Bcf/d. The project will be designed to receive LNG from oceangoing LNG carriers up to 266,000 cubic meters (9.4 MMcf) in size and will feature three 160,000 cubic meters (5.6 MMcf) aboveground, full containment LNG storage tanks.

The Coast Guard also issued letters of recommendation for the other two proposed Oregon LNG terminals, Bradwood Landing and Jordan Cove.

FERC has granted a rehearing of the Bradwood Landing LNG project proposed for siting and operation near Astoria, Ore. to allow for additional time for consideration of matters related to the facilities.

Oregon Governor Ted Kulongoski had said in January the state would appeal FERC’s decision to license the proposed Bradwood Landing LNG terminal before environmental mitigation plans were fully evaluated and approved and the state permitting process was complete.

“I have been clear that FERC should not issue a license until all environmental issues are appropriately addressed and not before state permit decisions have been rendered,” Kulongoski said. “I am deeply disappointed that FERC has chosen to ignore Oregon’s concerns in this matter and have asked the Attorney General to seek prompt judicial review.”

Long Beach happy to use LNG

While opposition to LNG terminals along the U.S. West Coast has been strong, LNG is finding a foothold as an alternative fuel for trucks. The city of Long Beach last month unveiled a new LNG fueling station for the city’s growing feet of alternative fuel vehicles. The 32,000-gallon fueling station handles a two-week supply of LNG for the city’s 79 LNG vehicles, including the only LNG-powered street-sweeping fleet in the United States.

Mayor Bob Foster said, “Creating a world-class green fleet is one of the many sustainable programs that the city has implemented.  This LNG fueling station will save costs, and burns much cleaner than diesel fuel.”

The LNG fueling station will soon be publicly accessible for use by other LNG vehicles, and was partially funded by the South Coast Air Quality Management District.

By using LNG vehicles and retrofitting diesel vehicles with particulate traps, the city of Long Beach has removed more than 2.8 metric tons (3.1 tons) of particulate matter from the atmosphere.

Additionally, the conversion of a large portion of the city’s solid waste fleet to LNG powered vehicles has reduced carbon dioxide emissions by 19.54 metric tons (21.5 tons) per year, significantly reducing greenhouse gases that contribute to global warming.

The LNG is produced and supplied to Long Beach by Topock, Ariz.-based Applied LNG Technologies.

Australia develops as LNG hub

Australia is rapidly becoming a hub for LNG activity, albeit with environmental concerns by at least one government agency.

The Environmental Protection Authority (EPA) of Western Australia on April 30 conditionally approved Chevron Corp.’s proposal to revise and expand the Gorgon LNG development on the Barrow Island nature reserve.

Despite its conditional approval, EPA Chairman Paul Vogel said the agency still opposes the location of industry on Barrow Island, a Class A nature reserve. Vogel stated, “Given the very high environmental and unique conservation values of Barrow Island, which are reflected in its status as a class A Nature Reserve, it is the view of the EPA that, as a matter of principle, industry should not be located on a nature reserve and specifically not on Barrow Island.”

However, the EPA “recognizes that Government approved construction of a smaller gas processing plant on Barrow Island in 2007, and has therefore assessed the revised and expanded proposal for new and, or additional risks and impacts to significant environmental assets,” Vogel said.

The EPA has concluded that the proposal could meet the EPA’s objectives provided stringent conditions are imposed.

EPA has recommended that the Minister for Environment seek advice from the Marine Turtle Expert Panel on mitigating potential impacts on one of the most significant flatback turtle rookeries in Western Australia.

The EPA also regards the increased potential impacts of dredging and marine infrastructure construction on the high value coral dominated habitat of the Lowendal Shelf as an important issue.

Corrective action, including stopping dredging when required, would need to be set out in conditions, following advice to the Minister for Environment by the Construction Dredging Environmental Expert Panel.

Gas from the Gorgon field is high in carbon dioxide. A fundamental justification by the proponent for using Barrow Island was the need for access to a suitable aquifer beneath the island for long term carbon dioxide storage. If injection and long term storage of the carbon dioxide produced with the gas that is processed at the Gorgon plant is not achieved, then the decision to permit gas processing on Barrow Island nature reserve should be reconsidered, in the EPA’s view.

Chevron officials welcomed the EPA’s decision to conditionally approve the revised and expanded proposal, which would add a third 5 million metric ton (5.5 million ton) per year LNG train to the original two-train proposal already approved for Barrow Island.

“The EPA’s decision is an important step in the regulatory process. Chevron can now continue to assess the conditions as it works toward a final investment decision in the second half of this year,” Chevron said.

Chevron is operator of the Gorgon project with 50 percent interest. Partners in the joint venture include ExxonMobil with 25 percent and Shell with 25 percent.

Elsewhere in Australia, LNG projects are in various stages of planning. Woodside Petroleum Ltd. signed and executed a Heads of Agreement with the state of Western Australia and the Kimberley Land Council on behalf of Traditional Owners related to the establishment of a Kimberley LNG precinct.

Woodside’s decision follows the broad agreement reached by the Western Australian government with the Kimberley Land Council and Woodside about the establishment of a site for an LNG precinct at James Price Point on the Kimberley coast. Traditional owners voted to endorse the project on April 15.

State Premier Colin Barnett said the broad agreement provided a groundbreaking framework for comprehensive native title and cultural heritage agreements, land tenure arrangements and benefits to the community.

The precinct at James Price Point would occupy about 1,000 hectares (2,471 acres). With accommodation, ancillary services and an appropriate land and sea buffer, the total area may be up to 3,500 hectares (8,648 acres).

“The next step is the development of an Indigenous Land Use Agreement in negotiation with the Traditional Owners, registered by early 2010 and the environmental approvals process completed by late 2010,” Barnett said. 

The Australian state of Queensland also is becoming a hive of proposed LNG development, with four projects in the works.

The Australia Pacific LNG (APLNG) project, co-owned by Origin Energy and ConocoPhillips, reached a key milestone in April when the Queensland Co-ordinator General declared the project significant.

APLNG is proposing a large coal seam gas (CSG) to LNG project in Australia, which will result in investment in the order of A$35 billion (US$24.9 billion) in Queensland through to 2020.

The Co-ordinator General’s declaration will lead to a streamlined government approval process by allowing the draft Terms of Reference to be set for an Environmental Impact Statement for the project.

APLNG Project Director Todd Creeger said the declaration was an important milestone for the project. “Our CSG to LNG project is underpinned by a strong relationship between Origin and ConocoPhillips, which are both leaders in the production of CSG and, in the case of ConocoPhillips, a leader in the delivery of LNG projects.”

The project consists of the further development of APLNG’s CSG fields; a gas transmission pipeline to the Queensland coast; a gas processing plant and associated facilities where the gas will be cooled and liquefied for shipping overseas.

The project will consist of up to four trains. When all four trains are operational, the plant is expected to produce up to 14 million tonnes to 16 million tonnes (15.4 million tons to 17.6 million tons) of LNG a year.

Origin will be responsible for the development and management of the CSG facilities including the gas fields and pipeline on behalf of APLNG.

ConocoPhillips will be responsible for the construction and management of the LNG plant on behalf of APLNG. Discussions are continuing with relevant parties regarding the suitability of certain sites.

Production could begin in 2014 at 3.5 million tonnes (3.8 million tons) per annum, the Queensland government said in a statement.

Earlier this year, Santos Ltd. submitted a draft of the Environmental Impact Statement (EIS) for the CSG Gladstone liquefied natural gas (GLNG) project, also proposed for construction and operation in Queensland.

Santos said GLNG is set to become the world’s first major project to produce LNG sourced from CSG. Gas will be piped from fields near Roma via a 435-kilometer (270-mile) pipeline to Curtis Island, where will be cooled to minus 161 degrees Celsius in a liquefaction plant and shipped to global markets.

The EIS assesses major components of the project, including the CSG fields near Roma; transmission gas pipeline connecting Roma to Curtis Island; LNG liquefaction and export facility on Curtis Island; bridge, roads and service corridors to Curtis Island; and dredging in Gladstone Harbour.

The state government will examine the EIS against the Terms of Reference agreed for the project’s assessment before the document is made public. The Queensland community will then have an opportunity to review the EIS and make submissions.

Royal Dutch Shell Plc in February signed an agreement with Gladstone Port Corporation for an exclusive Right to Investigate a site on Curtis Island for construction of a possible LNG plant.

Shell intends to supply the plant with natural gas from Arrow Energy’s CSG acreage jointly owned by Shell and Arrow. A full integrated project plan is being formed.

Shell has closed on its acquisition of a 30 percent interest in Arrow’s CSG acreage in Queensland and a 10 percent stake in Arrow Energy subsidiary Arrow International, which holds Arrow’s international interests in CSG opportunities.

 

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