A consolidation of suppliers has led to a shortage of steel pipes, pushing prices up for oil and gas drillers. Along the way, steel surface casing prevents contamination of fresh water in the ground, steel tubing allows the oil or gas to travel to the surface, and steel production casing acts as a protective layer underground.

But the steel pipe used in these wells is becoming more expensive and harder to get for oil and gas companies, putting a drag on production and driving up the cost and time it takes to plan the wells.

And the effect on North Texas could be significant, particularly because gas drilling in the Barnett Shale requires the complex rigs that snake into the ground horizontally.

"When you've got something that costs that much money for each well, definitely it's making people think twice before they make the final decision to go ahead and drill," said Alex Mills, president of the Texas Alliance of Energy Producers.

The rising cost of materials and the consolidation of steel pipe suppliers have collided with growing drilling demand, which has been spurred by oil and gas price increases. And many new wells require more pipe than the ones before the recent boom.

"The deeper you go, the more drill pipe you need," said Michelle Michot Foss, chief economist and head of the University of Texas Center for Energy Economics. "Generally, as prices rise, people start going after the riskier stuff."

The riskier stuff includes methane coal beds and shale – layers of clay that are harder to extract gas from.

Projects in the Barnett Shale, one of the country's biggest natural gas plays, use horizontal drilling, in which drill pipes turn inside the rock to tap into natural gas.

The technique is what is making the Barnett Shale such a profitable resource.

Jeff Tillery, an analyst with Tudor, Pickering, Holt and Co., said supply of the steel pipe is the lowest he's ever seen.

Distributors are keeping less than four months' supply today, compared with six months in 2006.

Oil and gas companies buy steel pipe from distributors, which get their supply from steel mills.

The steel mills make the pipe using either scrap steel or iron ore, both of which have seen significant price increases, driven by demand from developing nations such as China.

And that's driven up the price of steel pipe for oil and gas rigs.

Additionally, manufacturers miscalculated the expansion in the number of rigs.

Roland Balkenende, U.S. commercial director for steel pipe manufacturer Tenaris, said distributors have been decreasing their inventories for two years. The Luxembourg-based company is one of the world's largest suppliers of the pipe.

Demand for the pipe has been so great that some suppliers are reporting backlogs in orders.

"When you look at the total demand, the manufacturers' supply may be what is needed," Mr. Balkenende said. "But unplanned activity is very hard to get because there's no inventory ... for emergencies."

Mr. Tillery said distributors also reduced inventories on fears of whether the level of drilling could be sustained.

Consolidation further reduced supply when a number of independent mills and suppliers were acquired by larger companies.

Bruce Bullock, director of Southern Methodist University Maguire Energy Institute, said, "Virtually all of the service and supply firms have faced capacity constraints in being able to produce the necessary equipment for the drillers to use."

Pampa, Texas-based Bourland and Leverich Supply Co., a steel pipe distributor, has seen a 50 percent decline in its inventory of the steel pipe, also known as tubulars, over the last year.

"We've had a difficulty in meeting all of our customers' demands because there is a shortage of tubulars," said Rick Leverich, president of Bourland and Leverich.

And capital costs related to building oil and gas projects have doubled since 2005, according to Cambridge Energy Research Associates' Capital Costs Index.

"As you begin to get shortages in those key areas, whether it's pipe or whether it's valves or other types of equipment, then you begin to raise the cost significantly," Mr. Bullock said.

The shortage also slows down gas projects in areas such as the Barnett Shale, where most of the returns arrive early in the life of the well.

"The main issue is not being able to get pipe quick enough in order to do hookups, which means in some companies they pull back on production because they can't get the product into pipe," said XTO Energy Inc. spokeswoman Nicki Northcutt.

The wells tend to produce a large amount of gas initially and decline rapidly, creating an incentive to drill more wells more quickly.

"We are scrambling to stay ahead of the rigs," Steve Dixon, chief operating officer of Chesapeake Energy Corp., said during the natural gas driller's second-quarter conference call.

Not all producers are in a pinch. Fort Worth's Quicksilver Resources Inc. anticipated the pipe shortage in February and expanded its steel pipe inventory, escaping the slowdown.

Oklahoma City-based Devon Energy, which acquired Barnett Shale pioneer Mitchell Energy, said it has avoided a shortage because of its long relationships with suppliers.

Newer gas plays such as the Haynesville Shale in Louisiana also may see an impact from the shortage.

"The idea of being able to get anything off of it [Haynesville] at this point is kind of up in the air," Ms. Northcutt said. "It's hard enough to get pipe installed in the Barnett Shale."

The situation differs significantly from about a decade ago, when energy prices were lower and producers were less active.

"When we had low prices, you couldn't give a drilling rig away and you couldn't give tubular goods away," said Mr. Mills of the Texas Alliance of Energy Producers. "At $140 oil and $13 gas, people are going to be paying premiums to make sure that their exploration program continues to flourish."

ARCTIC

90 Billion Barrels of Oil and 1,670 Trillion Cubic Feet of Natural Gas Assessed in the Arctic

The area north of the Arctic Circle has an estimated 90 billion barrels of undiscovered, technically recoverable oil, 1,670 trillion cubic feet of technically recoverable natural gas, and 44 billion barrels of technically recoverable natural gas liquids in 25 geologically defined areas thought to have potential for petroleum.

The U.S. Geological Survey assessment released recently is the first publicly available petroleum resource estimate of the entire area north of the Arctic Circle.

These resources account for about 22 percent of the undiscovered, technically recoverable resources in the world. The Arctic accounts for about 13 percent of the undiscovered oil, 30 percent of the undiscovered natural gas, and 20 percent of the undiscovered natural gas liquids in the world. About 84 percent of the estimated resources are expected to occur offshore.

"Before we can make decisions about our future use of oil and gas and related decisions about protecting endangered species, native communities and the health of our planet, we need to know what's out there," said USGS Director Mark Myers. "With this assessment, we're providing the same information to everyone in the world so that the global community can make those difficult decisions."

Of the estimated totals, more than half of the undiscovered oil resources are estimated to occur in just three geologic provinces - Arctic Alaska, the Amerasia Basin, and the East Greenland Rift Basins. On an oil-equivalency basis, undiscovered natural gas is estimated to be three times more abundant than oil in the Arctic. More than 70 percent of the undiscovered natural gas is estimated to occur in three provinces - the West Siberian Basin, the East Barents Basins, and Arctic Alaska.

The USGS Circum-Arctic Resource Appraisal is part of a project to assess the global petroleum basins using standardized and consistent methodology and protocol. This approach allows for an area's petroleum potential to be compared to other petroleum basins in the world. The USGS worked with a number of international organizations to conduct the geologic analyses of these Arctic provinces.

Technically recoverable resources are those producible using currently available technology and industry practices. For the purposes of this study, the USGS did not consider economic factors such as the effects of permanent sea ice or oceanic water depth in its assessment of undiscovered oil and gas resources. The USGS is the only provider of publicly available estimates of undiscovered, technically recoverable oil and gas resources.

Exploration for petroleum has already resulted in the discovery of more than 400 oil and gas fields north of the Arctic Circle. These fields account for approximately 40 billion barrels of oil, more than 1,100 trillion cubic feet of gas, and 8.5 billion barrels of natural gas liquids. Nevertheless, the Arctic, especially offshore, is essentially unexplored with respect to petroleum.

AMERICAS

U.S.

United States Oil and Gas Files Patent Pending for a Simple Fiber-Optic Seismometer

United States Oil and Gas Corp announced it has a patent pending on a simple fiber-optic seismometer for rugged environments that will dramatically reduce the cost of seismic sensor arrays having the fidelity and reliability necessary for permanent down-hole and seafloor installations. The advancement promises to make big oil techniques for oilfield production management and exploration techniques available to the middle market players.

USOG plans to revolutionize "Green" oil and gas technologies with the smallest footprint. Most heavy oil recovery schemes depend on formation feedback information to make decisions about inputs and production rates to optimize the oil field. Correct management of costly secondary recovery methods could double the financial returns on these projects. Affordable sensors are the key to bringing modern production techniques to the oil patch.

Offshore, a seismic sensor array has to be reliable enough to be deployed once and not need maintenance. This invention transcends the intrinsic limitation of existing sensing seismic sensing technology by the elimination of physical connections to remote optical fibers in addition to a non-electric solution. The simplicity of this new device raises opportunities for seismic sensors that have lifetimes exceeding ten years in deepwater applications.

Advantages

· Rapid data acquisition

· Immediate data availability

· Detailed subsurface information

Capabilities

· Shear-wave-velocity measurement

· Detailed oil and gas stratigraphic profiling

· Evaluation of liquefaction potential

· Vane-shear measurement

· Conductivity/resistivity measurements

· Discrete-gas sampling

· Regional and site-specific stratigraphy

Applications

· Seismic-positioning of deep sea exploration

· Oil and Gas exploration drilling

· Environmental-contamination prevention studies

Dresser-Rand to Acquire Arrow Industries and Completes Acquisition of Enginuity LLC Assets

Dresser-Rand Group Inc., a global supplier of rotating equipment to the oil, gas, petrochemical, and process industries, announced that its affiliates have entered into two acquisition agreements. Each is consistent with the company's strategy of acquiring products, services, and technologies that offer access to new markets or enhance current market positions, and each will enable Dresser-Rand to expand services to its clients.

The acquisitions are expected to be neutral to earnings in the first year and accretive thereafter. Terms of the agreements were not disclosed.

Dresser-Rand Services, LLC has signed an agreement to acquire all of the stock of Arrow Industries, Inc. ("Arrow Industries" or "Arrow"). The agreement is expected to close in late August.

Established in 1982, Arrow Industries is a premier provider of foundation and mechanical services for reciprocating engines and compressors used in the North American pipeline industry. With four facilities in the U.S., Arrow is a Dresser-Rand foundation services provider, and is experienced in implementing and servicing Dresser-Rand and similar OEM equipment. In 2007, Arrow reported sales of approximately $30M.

A significant portion of Arrow's sales is derived from servicing equipment from manufacturers other than Dresser-Rand. This diverse servicing expertise supports Dresser-Rand's Applied Technology strategy and will allow it to develop markets that are expected to increase earnings for the company.

"Dresser-Rand and Arrow Industries have worked together in the past, and each has decades of experience providing innovative solutions in the energy markets," said Vincent R. Volpe Jr., president and CEO of Dresser-Rand. "Both companies are known for quality, economy, and reliability that bring added value to their clients. The acquisition of Arrow Industries strengthens Dresser-Rand's business and will enhance our ability to better serve the pipeline industry and other markets."

Dresser-Rand Company also announced the closing of an agreement to acquire the assets of Enginuity LLC ("Enginuity") a private, U.S.-based provider of combustion and catalytic emissions technology solutions, controls and automation, and aftermarket services for reciprocating gas engines used in the gas transmission market. In 2007, Enginuity reported sales of approximately $16M.

Focused on the North American gas transmission market, Enginuity is the technology solutions leader for reducing gas-fired engine emissions and for engine and compressor controls and monitoring. In connection with this acquisition, Dresser-Rand will establish its Gas Engine Technology Center in Fort Collins, Colorado, which has served as Enginuity's headquarters since 1999.

"Enginuity will strengthen Dresser-Rand's engine technology position and value proposition in the gas transmission market, and enhance Dresser-Rand's Applied Technology capabilities," said Volpe. "Together, Dresser-Rand and Enginuity expect to play a leading role in the development and deployment of technology solutions to reduce CO2 emissions from compressor systems," he emphasized.

Solar Power Helps Protect Puget Sound Energy's Natural Gas System

Puget Sound Energy (utility subsidiary of Puget Energy) recently added two new solar-powered systems to dozens installed since 1984 that help protect the utility's underground natural gas system in Western Washington.

PSE's two newest solar-powered systems in Edmonds, Wash., use the sun to produce electric current along more than six miles of buried natural gas steel pipe to block corrosion caused by the electrochemical reaction between the metal pipe and the surrounding soil. The anticorrosion technique, called cathodic protection, uses a small amount of electric current to charge the pipe's surface and direct the rust to an anode. This in effect "fools" the pipe, targeting the corrosion elsewhere, increasing the longevity of the pipe and, long-term, decreasing the potential for natural gas leaks.

In total, the utility's nearly 85 solar-powered cathodic protection systems installed in six counties protect more than 250 miles of buried natural gas steel pipe.

Without needing to be positioned near a source of socket-ready power, PSE's solar units can be installed nearly anywhere. "While good for the environment, these solar installations give us the latitude to operate our natural gas protection systems in remote areas where other sources of power may be difficult to install or operate," said Sue McLain, PSE senior vice president of Operations. "It's fitting for PSE, which operates the Pacific Northwest's largest solar power-generating facility at our Wild Horse Wind and Solar Facility near Ellensburg to have also helped pioneer this technique to take advantage of solar energy to help protect our natural gas system."

With approximately a quarter of PSE's 300 cathodic protection systems operating on solar power, PSE is the only Washington state utility using solar technology to protect its natural gas system, and one of the largest users in the U.S. PSE installed its first solar powered cathodic protection system in 1984.

Enterprise Announces JV Texas Offshore Oil Port, Pipeline System

Enterprise Products Partners L.P. and Oiltanking Holding Americas, Inc. on August 18 announced they have formed a joint venture to design, construct, own and operate a new Texas offshore crude oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers along the upper Texas Gulf Coast. The initiative will provide an efficient alternative to offshore lightering and inland dock operations.

The Texas Offshore Port System ("TOPS") project would include an offshore port, two onshore storage facilities with approximately 5.1 million barrels of total crude oil storage capacity, and an associated 160-mile pipeline system with the capacity to deliver up to 1.8 million barrels per day (BPD) of crude oil. System capacity could be expanded with construction of additional offshore facilities. Development of the offshore port system and onshore infrastructure is supported by long-term contracts with Motiva Enterprises LLC and an affiliate of Exxon Mobil Corporation, which together have committed a total volume of approximately 725,000 BPD.

Demand for TOPS is being driven by planned and expected refinery expansions along the upper Texas Gulf Coast that are anticipated to add approximately 425,000 BPD of capacity beginning in 2010, as well as expected increases in general ship traffic at onshore ports. According to data from the federal Energy Information Administration, the Texas Gulf Coast is home to refineries with aggregate crude oil capacity of 3.9 million BPD (including planned and announced expansions), 2.5 million BPD of which are imported on vessels that require lightering services. Given the forecasted increased shipping traffic resulting from incoming crude oil supplies and operating limitations of ship channels, TOPS would offer refiners another delivery option that would provide added flexibility and enhanced reliability.

TOPS is designed to allow operations 24 hours per day without restrictions on movements and vessel size that limit most ship channels. TOPS would be able to accommodate the largest vessels which can carry approximately 3 million barrels of crude oil. The location of TOPS is also designed to avoid delays and risks related to fog, navigation hazards and channel closures on coastal waterways. Over the next several years, key port locations along the Texas Gulf Coast are expected to see a sharp increase in total traffic for all types of cargo, and TOPS would be well-positioned to play an important role in relieving potential congestion.

"With refining capacity along the upper Texas coast continuing to expand, TOPS offers a comprehensive solution for ensuring reliable access to supplies of crude oil," said Michael A. Creel, president and chief executive officer of Enterprise. "This project should provide refiners with cost savings, operating efficiencies and access to additional supplies beyond the Gulf Coast region."

Jerry E. Thompson, president and chief executive officer of the general partner of TEPPCO said, "The deepwater port is an integral part of our strategic plan for growing the partnership, which includes pursuing attractive infrastructure projects that provide facilities to meet the growing demand for imported crude oil coming into the Gulf Coast refining centers."

Carlin G. Conner, chairman of the new joint venture's Management Committee and president and chief executive officer of Oiltanking's North American subsidiaries, said, "TOPS is a key U.S. Gulf Coast infrastructure project that would enhance delivery of crude oil to the western gulf coast refiners. We are pleased to be a partner in TOPS. Each of the partners brings experience and know-how to this project, which is a necessary development to further drive Gulf Coast refining efficiencies. The project would also provide our customers with access to an efficient and reliable crude oil delivery system for years to come."

The TOPS project involves construction of a deepwater port located approximately 36 miles offshore from Freeport, Texas, and an onshore distribution and storage system. As designed, the deepwater port will feature two single-point mooring buoys that will essentially serve as floating docks for the vessels. Located in about 115 feet of water, the buoys will be able to offload crude oil at rates up to 100,000 barrels per hour. A subsea pipeline will connect the buoys to the onshore distribution system near Freeport. Utilizing directional drilling techniques to minimize beach impact, the TOPS pipeline system would run from the offshore port shore crossing to Freeport and extend along the Texas Gulf Coast to Texas City, Texas, connecting to a 3.9 million barrel crude oil storage facility. From there, the pipeline would connect to existing crude oil pipeline systems currently serving the Texas City and Houston Ship Channel refineries.

A separate but complementary component of TOPS would involve construction of a 75-mile pipeline extending from Texas City to its terminus at a planned storage facility with 1.2 million barrels of crude oil capacity near Port Arthur, Texas. The storage tanks are designed to connect to various refineries and other facilities via pipelines. This pipeline system would have the added capability of delivering waterborne and offshore crude oil from existing Texas City docks and storage facilities to all Port Arthur/Beaumont area refineries.

Affiliates of Enterprise, TEPPCO and Oiltanking each have a one-third ownership in the new joint venture and expect to invest approximately $600 million each in the initiative, which, subject to obtaining certain regulatory approvals and permits, is scheduled to begin service in the fourth quarter of 2010.

Oil Purification Systems and Felderhoff Brothers Drilling Develop New Fluid Cleaning Technology

Fluid cleaning technology helps eliminate equipment downtime and protect against expensive, time-consuming breakdowns in oil and gas industry

Oil Purification Systems (OPS), developer and manufacturer of the OPS-1(TM) on-board oil refining system, has announced a collaboration with Felderhoff Brothers Drilling to implement the Enviro-Pur fluid cleaning system. The new Enviro-Pur system helps lower overall maintenance costs by maintaining the quality of lubricating fluids used by all types of drill rig equipment, and by reducing the overall consumption of those fluids. Developed specifically for the oil and gas industry, the Enviro-Pur system helps to significantly reduce equipment downtime, a critical challenge faced by Felderhoff and other companies in the industry.

The Enviro-Pur system provides a comprehensive enhancement to Felderhoff's preventive maintenance program. Tom Burke, president of Felderhoff Brothers Drilling, said, "In the oil and gas industry, it is extremely important to get in and out of a drilling location very quickly. The OPS Enviro-Pur system allows us to basically eliminate oil changes to keep our equipment up and running almost constantly. We expect to save more than $500,000 annually per rig in repair and rebuilding costs alone. This is in addition to the savings we will see in the cost of lube."

The OPS Enviro-Pur system cleans gear lube while the rig is running, helping maximize uptime and reduce equipment breakdown. During the evaluation process, OPS worked extensively with Felderhoff to collect and provide written analysis of lubrication sample results to ensure that oil was running clean. By keeping gear lube and lube oil clean, scheduled maintenance can be eliminated, allowing Felderhoff to maintain operating performance at the highest level possible.

Additionally, the Enviro-Pur system helps to reduce oil consumption, saving hundreds of thousands of gallons of waste lube each year and minimizing waste for a cleaner environment. Felderhoff has already installed and tested the Enviro-Pur system on multiple rigs, and expects to save more than $600,000 in its first year of use from reduced lube oil changes making its total annual savings over $1 million.

"Felderhoff is a company that has proven to be a leader in the oil and gas industry in recognizing the importance of preventive maintenance instead of crisis maintenance," said Mitch Weseley, OPS president and CEO. "We view our collaboration with Felderhoff as a critical step in helping keep equipment up and running all the time to better serve customers in this industry."

Tres Palacios Gas Storage Gets Green Light from FERC

Tres Palacios Gas Storage LLC, a wholly owned subsidiary of Westport, CT-based NGS Energy LP, has announced the receipt of its first approval from the Federal Energy Regulatory Commission (FERC) to commence service of the first cavern of the facility.

The FERC notice will allow Tres Palacios to start limited operations on a portion of the system. Tres Palacios anticipates receiving FERC permission to commence operations on the rest of the system by the end of August, 2008 so that commercial activities may begin in September.

The new high performance salt dome storage facility located in Matagorda County, Texas will be interconnected with 10 interstate and intrastate pipelines, including: Florida Gas, Transco (near Sta 30), Tennessee, NGPL, CTGS (Transco/Tennessee), HPL, TETCO, Enterprise Texas, Enterprise Texas Intrastate and Kinder Morgan Tejas.

When all three caverns are placed into service, the facility will offer 36 BCF of working gas capacity to storage customers. The Project has been authorized to inject up to 1 BCF/d and withdrawal up to 2.5 BCF/d.

The company is also holding a binding open season for firm storage capacity that is available April 1, 2009. The deadline for submitting bids is September 4th.

John Crane and Siemens Announce Gas Seal Agreement

John Crane, part of the global technology business Smiths Group, has announced a major new supplier frame agreement with Siemens AG that is expected to secure business worth some EUR 10 million over the next two years.

With the potential for future extensions, the deal provides for John Crane gas seal equipment to be supplied via Siemens to a range of turbo-machinery applications in the Middle East, Caspian, Asia Pacific and South American regions.

It also includes the supply of aftermarket services. John Crane has underlined its commitment to the agreement by developing a new standard gas seal product designed to meet Siemens' specific operating parameters with the added benefit of service support from John Crane's unparalleled international network of customer support centers.

The agreement will also allow John Crane and Siemens to collaborate more closely than previously, leading to the development of innovative new solutions to market requirements.

Environmental considerations are expected to play a key role, especially in such areas as the current energy market demand for greater efficiency with lower emissions. John Crane has also extended the scope of the offering it makes to Siemens to cover other areas of turbo-machinery equipment such as speciality engineered bearings and filters.

Canada’s Precision Drilling to Buy Grey Wolf for $2 Billion

Precision Drilling Trust, Canada's largest driller, agreed to buy Grey Wolf Inc. for $2 billion to add customers, equipment and crews in fast-growing U.S. natural-gas basins in states such as Texas and Colorado.

Stockholders of Grey Wolf, based in Houston, will get $5 and 0.1883 trust unit per share, the companies said in a statement. At the Aug. 22 closing prices, that represents a premium of 4.8 percent.

Calgary-based Precision began publicly pursuing Grey Wolf June 10 as record oil and gas prices raised demand for rigs and support equipment. Grey Wolf agreed to take $1 a share less than a bid it spurned June 27. Since then, gas prices have slipped 42 percent and Grey Wolf shareholders rejected a competing deal.

``The premium is underwhelming,'' said Jud Bailey, an analyst for Jefferies & Co. in Houston who rates Grey Wolf shares at ``buy'' and owns none. ``This is clearly an inferior offer.'' Precision is getting Grey Wolf cheaply ``because there were no other takers,'' he said.

Precision Drilling dropped C$1.43, or 6.4 percent, to C$20.80 as of 11:03 a.m. in trading in Toronto. Grey Wolf fell 16 cents, or 1.9 percent, to $8.43 in composite trading on the New York Stock Exchange.

Precision guaranteed Grey Wolf holders $5 a share, slightly ``sweeter'' than the $10 offer, which was to consist of no more than $5 in cash, said David Rewcastle, an analyst in Stamford, Connecticut, with Argus Research who had recommended clients hold Grey Wolf shares to capture the acquisition premium.

Precision will gain 121 rigs, mostly drilling for natural gas in the U.S., where those in operation have risen 13 percent this year to a record 1,998, according to weekly counts by Baker Hughes Inc. Canadian rigs have fallen 13 percent since a high of 457 were operating in February.

The combination will make Precision among the largest North American gas drillers, analysts said.

``It will provide a nice platform for expansion, particularly further into Mexico, because in North American drilling, size and scope matter,'' Bailey said.

Precision builds its own mobile, fast-drilling rigs used to exploit oil- and gas-shale deposits that may be in demand by Grey Wolf's U.S. clients, said Chris Gindl, an analyst in Calgary for Dundee Securities Corp. who rates Precision at ``buy'' and owns fewer than 100 of its trust units. The company also may be able to augment Grey Wolf crews when Canada's mud season idles drilling for as long as 90 days, he said.

Grey Wolf shareholders opened the door to Precision by rejecting in July management's plan to buy Basic Energy Services for $1.4 billion. Precision Chief Executive Officer Kevin Neveu said then he would immediately revive his offer to buy Grey Wolf.

Since then, natural-gas prices have tumbled, dragging down the value of Precision's trust units by 12 percent. Grey Wolf has dropped 11 percent from a high of $9.50 a share on June 23. Precision said August 25 it will issue about 42 million new units to Grey Wolf shareholders, 4.5 percent more than in the June offer.

Grey Wolf shareholders will own 25 percent of the combined company and three of its directors will join the Precision board at closing. A vote of Grey Wolf shareholders on the deal will be held by year-end, the companies said.

Enterprise Announces North Texas Pipeline Expansion

Enterprise Products Partners L.P. have announced that its affiliates have signed new long-term agreements with major producers in the Barnett Shale region that will utilize approximately 900 million cubic feet per day of capacity on the partnership's 1.1 billion cubic feet per day ("Bcfd") Sherman Extension natural gas pipeline. The partnership also announced that it will construct a pipeline that will transport new supplies of natural gas produced from the Barnett Shale in Tarrant and Denton Counties, Texas to the Sherman Extension pipeline.

The 178-mile Sherman Extension is a major expansion of Enterprise's Texas intrastate natural gas pipeline system that provides additional transportation capacity for production from the Barnett Shale and North Texas region. The Sherman Extension traverses from an interconnect with a major pipeline segment of Enterprise's Texas intrastate system in Erath County, Texas, to Grayson County, Texas, where it will connect to the Gulf Crossing interstate pipeline.

Producers can utilize the Sherman Extension to reach natural gas markets in the Southeast United States and to markets in the Midwest and Northeast through connections with other interstate pipelines. Producers can also utilize the Sherman Extension to access Texas markets and, through connections with interstate pipelines, to natural gas markets in the western United States. The Sherman Extension is expected to be completed in the fourth quarter of 2008.

To accommodate growing natural gas production from the Barnett Shale, Enterprise will build a new 40-mile supply lateral that will extend from the Trinity River Basin north of Arlington to an interconnect with the Sherman Extension pipeline near Justin, Texas. This new pipeline will consist of 30-inch and 36-inch diameter pipeline designed to provide up to 1 Bcfd of natural gas takeaway capacity for producers in Tarrant and Denton counties. This new pipeline will also have a lateral to provide transportation services for natural gas produced from the Newark East field in Wise County. These new pipelines are anchored by long-term agreements with major producers and are expected to be in service in the third quarter of 2009.

"We are pleased to announce these latest developments," said Michael A. Creel, president and chief executive officer of Enterprise. "The Barnett Shale continues to exceed expectations. Production from the Barnett Shale currently exceeds 4 Bcfd and is expected to increase to approximately 6 Bcfd by 2011. We believe the Sherman Extension and the pipeline lateral into the Trinity River Basin will provide producers valuable transportation capacity for their production. Given the expected growth in the region, we are evaluating the need to expand the Sherman Extension beyond its current planned capacity of 1.1 Bcfd."

In August 2008, Enterprise completed a 42-mile section of the Sherman Extension from Erath County to Parker County, Texas, and commenced interim transportation service on the Sherman Extension to markets utilizing Enterprise's Texas intrastate system.

Oil Industry Tallies up Damage from Gustav

Oil companies, rig and pipeline owners and refiners spread out across the Gulf Coast to look for damage from Hurricane Gustav on September 2, and some were already putting equipment and people back in place to resume operations.

Early indications were that Gustav caused little damage to onshore and offshore facilities, though the full impact likely won't be known for a couple of days.

"Preliminarily, we don't know of any major damages at this time," John Rodi, deputy regional director of the U.S. Minerals Management Service, said.

The approach of Gustav had been one of the last remaining pillars of support for oil prices, which tumbled September 2 by more than $6 a barrel on the New York Mercantile Exchange, a decline of 26 percent from record highs of more than $147 in July.

Many companies were flying over offshore sites in airplanes, checking for any obvious damage. One of the next steps will be getting people aboard the offshore facilities for more detailed inspections, including checks of subsea equipment.

Rodi, whose agency oversees offshore activity, said it was too early to say when production might resume, though some companies already were gearing up. One of the tasks is getting the thousands of offshore workers evacuated before Gustav back to their positions.

In a note to clients, analysts at Tudor Pickering Holt & Co. said absent any serious damage, production should be back to near full capacity by week's end at the latest. It also said pipelines in the region, which were mangled during hurricanes Katrina and Rita, aren't "going to be nearly as messy as 2005."

One major unknown remained September 2 — the fate of the Louisiana Offshore Oil Port, which shut down over the weekend.

Gustav appeared to roll directly over the facility, which handles about 12 percent of the nation's crude imports and is tied by pipeline to about half the nation's refining capacity, much of it along the Mississippi River from the New Orleans area north to Baton Rouge.

Any prolonged closure of LOOP, as it's called, could severely disrupt crude imports and their shipment to refineries. LOOP is located about 18 miles south of Grand Isle, La.

Technicians were expected to assess any damage, but managers said it was premature to comment.

ConocoPhillips said remote monitoring of its Magnolia production platform about 165 miles off the Louisiana coast indicated it had not sustained significant damage.

"As weather conditions permit, we'll conduct a fly-over of the platform and south Louisiana assets to further assess their conditions," ConocoPhillips said in a statement.

The Houston-based oil giant also has two refineries in Louisiana — one near New Orleans, one near Lake Charles — and they both remained shut down.

Royal Dutch Shell said it would send a small number of staff back to installations in the Gulf that were out of the hurricane's path, though it noted it could take three to five days to resume full production in the Gulf.

In the days preceding Gustav, oil companies shut down virtually all oil and natural gas production in the Gulf, and the storm's threat halted about 15 percent of the nation's refining capacity based in the region.

The U.S. Gulf Coast is home to nearly half the nation's refining capacity, while offshore, the Gulf accounts for about 25 percent of domestic oil production and 15 percent of natural gas output.

Like ConocoPhillips, Anadarko Petroleum Corp., the largest independent deep-water producer in the Gulf of Mexico, said remote monitoring also indicated its offshore assets remained in placed as Gustav passed through the region September 1.

Exxon Mobil Corp. said it couldn't say when it would restart its Louisiana refineries in Chalmette and Baton Rouge, both of which were shut down as Gustav's approach.

But, Valero Energy Corp. said an initial assessment of its St. Charles, La., refinery, which turns 250,000 barrels a day of crude oil into gasoline and other fuels, found "no significant structural damage," although it was too soon to say when the plant's operations would restart.

Transocean Inc., the world's largest offshore drilling contractor, said September 1 it appeared its three moored, semisubmersible rigs in the Gulf remained anchored in position during the storm.

Transocean said eight other rigs that used thrusters to move out of the storm's path also were safe and were moving back to their drilling locations.

Rowan Inks $160 Million Rig Deal with McMoRan

Offshore contract drilling services company Rowan Cos. said September 2 it has inked a two-year, $160 million deal with McMoRan Oil & Gas LLC.

As part of the contract, Rowan will supply its news 240C class jack-up, called the Rowan-Mississippi, to drill one or more ultra-deep gas wells in the Gulf of Mexico.

The Rowan-Mississippi is set to be christened on November 1, and should be in use "immediately thereafter," the company said.

Chevron Plans Base Oil Plant at Pascagoula, MS

Chevron Corp. has applied to the Mississippi Department of Environmental Quality for an environmental permit to build a premium base oil facility at the company's 330,000 b/d refinery in Pascagoula, Miss. The refinery produces gasoline, jet fuel, diesel, and other products.

The base oil facility is expected to produce about 25,000 b/d of premium base oil for use in manufacturing high-performance lubricants such as motor oils for consumer and commercial uses. The facility will use Chevron's proprietary isodewaxing technology, which results in higher yields and enables use of a broader range of crude oil feedstocks.

Chevron expects to begin construction in early 2009 and to complete in 2011.

"These oils are the primary ingredients in the production of top-tier motor oils needed to improve fuel economy, lower tail-pipe emissions, and extend the period between oil changes," said Dale Walsh, president, Chevron global lubricants.

BP Awards $3.8 Billion Whiting Refinery Delayed Coker Contract to Foster Wheeler

BP Products North America awarded a contract to Foster Wheeler Ltd. for the engineering, procurement, and fabrication of a 102,000 b/sd, 6-drum delayed coking unit and gas plant facilities at BP's 405,000-b/d Whiting refinery in northwest Indiana.

The delayed coking unit is part of the BP Whiting Refinery modernization project, which will increase the refinery's gasoline production by 1.7 million gal/day and allow it to process more Canadian crude. Terms of the award were not announced. Foster Wheeler USA has been working on the project since 2005.

BP has awarded contracts for the project in stages. Previous contracts were awarded to Fluor Corp. for work that includes a crude distillation unit and a new gas oil hydrotreater and to Jacobs Engineering Group Inc. for the sulfur-recovery facilities.

BP expects to finish the $3.8 billion project in 2011. Foster Wheeler is using its Sydec process for the delayed coking units.

Oil Industry Sums up Preliminary Damage from Gustav

Oil companies, rig and pipeline owners and refiners spread out across the Gulf Coast to look for damage from Hurricane Gustav September 2, and some were already putting equipment and people back in place to resume operations.

Early indications were that Gustav caused little damage to onshore and offshore facilities, though the full impact likely won't be known for a couple of days.

"Preliminarily, we don't know of any major damages at this time," John Rodi, deputy regional director of the U.S. Minerals Management Service, said September 2.

Rodi, whose agency oversees offshore activity, said it was too early to say when production might resume, though some companies already were gearing up September 2. One of the tasks is getting the thousands of offshore workers evacuated before Gustav back to their positions.

One major unknown remained — the fate of the Louisiana Offshore Oil Port, which shut down over the weekend.

Any prolonged closure of LOOP, as it's called, could severely disrupt crude imports and their shipment to refineries. LOOP is located about 18 miles south of Grand Isle, La.

Technicians were expected to assess any damage by September 2, but managers said it was premature to comment.

ConocoPhillips said remote monitoring of its Magnolia production platform about 165 miles off the Louisiana coast indicated it had not sustained significant damage.

"As weather conditions permit, we'll conduct a fly-over of the platform and south Louisiana assets to further assess their conditions," ConocoPhillips said in a statement.

The Houston-based oil giant also has two refineries in Louisiana — one near New Orleans, one near Lake Charles — and they both remained shut down.

Royal Dutch Shell said it would send a small number of staff to installations in the Gulf that were out of the hurricane's path, though it noted it could take three to five days to resume full production in the Gulf.

The U.S. Gulf Coast is home to nearly half the nation's refining capacity, while offshore, the Gulf accounts for about 25 percent of domestic oil production and 15 percent of natural gas output.

Exxon Mobil Corp. said it couldn't say when it would restart its Louisiana refineries in Chalmette and Baton Rouge, both of which were shut down as Gustav's approach.

Valero Energy Corp. said an initial assessment of its St. Charles, La., refinery, which turns 250,000 barrels a day of crude oil into gasoline and other fuels, found "no significant structural damage," although it was too soon to say when the plant's operations would restart.

Transocean Inc., the world's largest offshore drilling contractor, said September 1 it appeared its three moored, semisubmersible rigs in the Gulf remained anchored in position during the storm.

Transocean said eight other rigs that used thrusters to move out of the storm's path also were safe and were moving back to their drilling locations.

Enbridge and BP Plan up to $2 Billion Pipeline Expansions to Get Canada Oil to Gulf

Enbridge Inc) and BP Plc plan to spend up to $2 billion expanding their pipeline systems to ship growing volumes of Canadian crude oil to the U.S. Gulf Coast, they said on August 29.

Enbridge, best known as operator of the main artery for Canadian oil exports, and BP, the British oil major, said they aim to develop a system to ship 250,000 barrels of oil a day to Texas City, Texas, from Flanagan, Illinois, by 2012.

The project would entail building new pipelines as well as using some already in service.

For Enbridge, it would coincide with its plans to get Western Canadian crude to Gulf Coast refineries by reversing the flow of two lines, allowing access to the Atlantic Seaboard. From there, it could be shipped to the Gulf by tanker.

That plan, called Trailbreaker, would cost about $333 million (C$350) and be in service in 2010.

With massive investments in Alberta's oil sands, production of that unconventional resource is forecast to nearly triple to 3.4 million barrels a day by 2015, and the industry is working to expand its markets.

For the new pipeline plan, the companies intend to use the BP 1 System and other pipelines north of the Cushing, Oklahoma, oil hub and build some new pipeline south of Cushing. There it would connect to markets in Houston and possibly Nederland, Texas, they said.

The system would link up at Flanagan with Enbridge's Southern Access pipeline, where about 140,000 barrels a day would be injected. The remaining 110,000 would come from interconnecting lines at Cushing.

U.S. / CANADA

Vector Plans Open Season for Proposed Third Pipeline Expansion

Vector Pipeline L.P. and Vector Pipeline Limited Partnership on August 27 announced plans to hold a binding Open Season in September 2008 to secure shipper interest in a third expansion of the Vector Pipeline System.

The 2010 Expansion proposes to add longhaul capacity of up to 120 million cubic feet per day (MMcf/d) by adding two new compressors and upgrades to the U.S. portion of the system. The expansion could also include up to 700 MMcf/d of shorthaul capacity (from Belle River, Mich., to Dawn, Ontario) by adding a loop to the Canadian side of the pipeline system.

"If shipper support for growth continues at its brisk pace, this will be our third expansion," said John Donaldson, Vector Pipeline vice president of marketing. "We still see increasing demand from downstream expansions on connecting pipeline systems, Millennium Pipeline shippers at Dawn, and storage expansions in southeastern Michigan and southwestern Ontario. Supply access is also on the upswing, particularly in the Midwest, with the recently constructed and announced pipelines from the Rockies. We're holding this Open Season now to ensure we keep meeting the growing need for secure, reliable natural gas that Vector Pipeline delivers. If justified by shipper support, we would target an in-service date of November 2010, given timely regulatory approvals."

Binding bids for firm capacity will be accepted from September 2, 2008, until September 30, 2008. Vector will make a final determination of incremental capacity following the conclusion of the binding Open Season. Open Season materials will be available on the Vector website (www.vector-pipeline.com). Additional shipper information about this proposed expansion is available by contacting John Donaldson at (734) 462-0238 or Matt Malinowski at (734) 462-0236.

Vector Pipeline's 2009 Expansion was approved earlier this year by the Federal Energy Regulatory Commission to increase nominal capacity of the Vector Pipeline from approximately 1.2 billion cubic feet per day (Bcf/d) to approximately 1.3 Bcf/d. Vector Pipeline will complete this expansion by building a new compressor station in Athens Township, Mich. It is projected to be in service in late 2009.

Last year Vector Pipeline completed its first expansion by installing compressor stations in Joliet, Ill., and Washington Township, Mich.

The Vector Pipeline System -- constructed in 2000 -- consists of 349 miles of mainline natural gas transmission pipeline between the Chicago Hub and the storage complex at Dawn, Ontario. Vector Pipeline L.P.'s system begins in Joliet, Ill., and terminates at the international border at St. Clair, Mich., where it interconnects with the Vector Pipeline Limited Partnership system, which provides service to the Dawn storage facilities. The system has multiple interconnections, which include Alliance, Northern Border, Guardian, ANR, NIPSCO, Crossroads, Consumers Energy, MichCon, DTE Washington 10 Storage, Bluewater Gas Storage, Enbridge Gas Distribution and Union Gas. Three power plants also are tied into the Vector system: Crete Energy Ventures, Kinder Morgan-Jackson and Greenfield Energy Centre.

U.S. Review Clears Pemex Pipeline on its Environmental Assessment

The U.S. State Department has determined a proposed multimillion-dollar Pemex gasoline pipeline from El Paso to Juarez would have no significant impact on the environment.

A presidential permit to allow the pipeline to cross the U.S.-Mexico border could be issued in early September if no federal agencies object to the issuance of the permit, said Elizabeth Orlando, a State Department official in Washington, D.C., who oversaw the project's environmental assessment.

A Pemex subsidiary, PMI Services North America, expects construction to take about six months once the presidential permit is issued, according to the environmental assessment. Orlando said the pipeline also needs other local and federal permits for construction.

Darryn Tollefson, vice president of business development for PMI in Houston, said the company had no comment on the State Department's finding, or the project's next steps.

The environmental assessment was prepared by Raba-Kistner Consultants and Mustang Engineering for PMI and reviewed by State Department officials before the agency issued its finding August 21.

Twenty-eight miles of the pipeline will run through El Paso County, mostly in the Lower Valley, and 21 miles will go through Juarez.

State Rep. Chente Quintanilla, D-El Paso, who is against the pipeline, said he and others will contact several federal agencies in hopes of convincing at least one of them to object to the presidential permit for the pipeline.

The State Department received no objections from federal agencies during the review and comment period for the assessment.

Quintanilla said he would talk to Lower Valley residents about the possibility of taking legal action to try to stop the pipeline.

El Paso County Judge Anthony Cobos, who has opposed the pipeline with other members of Commissioners Court, said, "The (State Department) decision is not in the best interest of the community. There were some significant environmental issues. It's next to a school, and through some populated areas."

Cobos said Commissioners Court would wait for an opinion from the county attorney's office before taking action.

PMI said the pipeline is safer than using trucks to haul fuel between El Paso and Juarez. The assessment estimated the pipeline would eliminate about 64,000 truck trips per year between the two cities.

The proposed Pemex pipeline would start at the Longhorn Partners Pipeline terminal at 13551 Montana near Zaragoza Road in far East El Paso County, go to the San Elizario area in the Lower Valley, and cross the Rio Grande into Juarez, where it will run an additional 21 miles to a Pemex terminal.

It would have the capacity to deliver 45,000 barrels of fuel per day to the Pemex terminal, the project's environmental assessment reported.
The fuel would come from Europe and be shipped from Houston through the Longhorn Partners Pipeline.

CANADA

Siemens Gasification Technology Selected for 270 MW Canada Power Plant

Siemens coal gasification technology has been selected for Canada's first low-CO2 IGCC power plant. EPCOR Power Generation is planning to build an integrated gasification combined-cycle power plant (IGCC) featuring carbon capture and storage in Genesee near Edmonton, Alberta, Canada. The demonstration plant, with an installed capacity of approximately 270 MW and is scheduled to come on line in 2015.

In the first project phase, Siemens will provide the technology license, as well as the process and basic engineering design for the coal gasification island based on the Siemens SFG-500 coal gasifier. Following the completion of the front-end engineering design of the plant, EPCOR intends to enter into an agreement with Siemens to supply the gasification reactor and components of the feed system.

The Siemens coal gasification technology is designed to produce clean syngas from coal that will be used to fire a gas turbine in the combined-cycle plant to provide electricity to the local grid. The emissions from IGCC plants are said to be significantly lower than those from today’s conventional coal-fired power plants. The plant in Genesee is designed to capture approximately 85% of the CO2 contained in the coal for enhanced oil recovery in existing oil fields.

Nexen Update on Canada’s Long Lake Project

Nexen Inc. has announced that Canada’s Long Lake project is proceeding well and the upgrader remains on track for start up and first production of Premium Synthetic Crude (PSC(TM)) this month. Commissioning is over 90% complete and the final major activity, testing of the gasifiers, is underway. Repairs are finished on the liquid oxygen storage tank and the air separation plant is producing oxygen and is fully operational. Other units in the upgrader, including the OrCrude(TM) unit, hydrocracker, and sulfur recovery unit are operationally ready to start up.

Based on commissioning activities and an evaluation of operational readiness, it has been determined that the upgrader can be started up with approximately 23,000 to 25,000 bbls/d of bitumen feedstock. Combined with the current SAGD production with externally sourced bitumen, there are sufficient volumes to start up this month. The upgrader is designed to produce approximately 60,000 bbls/d (30,000 bbls/d net to us) of PSC(TM). It is expected production of synthetic crude can be ramped up to full rates over a 12 to 18 month period following upgrader start up.

With respect to SAGD operations, the reservoir is performing well and well conversions to production are on track with 40 wells converted to date. However, the production ramp up schedule has been impacted by a number of surface issues. In late-June, an unexpected third-party transformer failure on the main electrical grid caused the shut down the SAGD facilities and wells for a period of time. In mid-July, transfer pumps failed on a third-party pipeline. As the storage tanks were full, it was necessary to temporarily ramp down production and shut in some wells.

In August, a number of valves controlling steam rates and pressure into the well pads failed. Start-up issues are not unusual. They are being solved and they are not recurring. For example, exposure to third-party power outages, have been mitigated. Recently, it was possible to successfully isolate and operate the co-gen units during a planned power outage. These units supply power to the site and any excess power generated is sold into the grid.

The start-up issues that were encountered limited the amount of steam that was possible to inject into the reservoir over the last two months and ability to consistently produce wells to their capability. Steam injection directly impacts bitumen production, therefore each time steam is interrupted, bitumen production temporarily decreases and takes time to ramp back up. These issues had a significant impact on average monthly production volumes in July and August, however, the reliability of the surface facilities is improving and gross bitumen production volumes have been increasing over the last three months as follows:

In June, bitumen production volumes averaged 7,200 bbls/d with demonstrated production performance of over 10,000 bbls/d;
In July, bitumen production volumes averaged 8,400 bbls/d with demonstrated production performance of over 13,000 bbls/d; and
In August, bitumen production volumes averaged 11,600 bbls/d with demonstrated production performance rates of over 15,000 bbls/d.

It is expected that bitumen production volumes will continue to increase as the surface issues previously identified have largely been dealt with and shut-in wells are being brought back on stream.

In light of the surface issues encountered over the last two months, steam injection rates were restricted. Because storage tanks were full and shipment could not be made, the bitumen production rates were restricted more than steam rates. This, combined with the conversion of new wells to SAGD operation, resulted in average steam-to-oil ratios (SOR) for the wells in SAGD operation to temporarily increase from three to four. This ratio is expected to decrease to long-term expectation of approximately three as SAGD volumes ramp up to full design rates of 72,000 bbls/d (36,000 bbls/d net to us).

The Long Lake project is being jointly developed by Nexen Inc. and OPTI Canada Inc.

Nexen is uniquely positioned for growth in the North Sea, Western Canada (including the Athabasca oil sands of Alberta and unconventional gas resource plays such as coalbed methane and shale gas), deep-water Gulf of Mexico, offshore West Africa and the Middle East. There is added value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity, governance and environmental protection.

MEXICO

Mexican Opposition Parties Submit Pemex Legislation

A group of Mexican political parties led by the Party of the Democratic Revolution submitted an energy bill to Congress that calls for lower taxes, more investment and limits on foreign investment in the industry.

The opposition parties' proposal, like a rival bill backed by President Felipe Calderon; aims to stem declining crude production at Petroleos Mexicanos, the state-run oil monopoly, and reduce imports of gasoline and petrochemicals.

The new proposal rejects an increase in private investment in the industry, a centerpiece of Calderon's bill, and calls for the state company to build more refineries, pipelines and chemical plants. The president's bill, introduced in April, would allow Pemex, as the company is known, to hire foreign companies to help it drill, refine and build pipelines.

``Without a doubt, there's a wide consensus on the urgency of a radical transformation of Petroleos Mexicanos,'' a document accompanying the bill said. The proposal seeks ``a Pemex for all Mexicans, without interference from foreigners.''

Mexico's Congress is set to discuss and vote on an energy bill after it begins its next session on Sept. 1. Progress on energy legislation has been delayed by a sit-in by the Party of the Democratic Revolution that shut Congress, as well as an agreement to hold a series of televised debates on energy.

Pemex's oil exploration is hampered by a lack of funds, even as crude trades near record prices, because its budget is sapped by repairs to crumbling infrastructure and taxes that take more than half of sales. The state oil company, formed from companies expropriated by the government in 1938, provides more than a third of Mexico's federal budget.

Guadalupe Acosta, president of the Party of the Democratic Revolution, said the new proposal would have the widest public support. Former presidential candidate Andres Manuel Lopez Obrador, a member of Acosta's party, has vowed to hold street protests nationwide if Congress approves Calderon's version of the bill.

The proposed bill would lower the hydrocarbon royalty Pemex pays to 65 percent from 74 percent and exempt from taxes profits that are re-invested in exploration, maintenance, pipelines, storage facilities and other infrastructure.

The proposal would place 60 percent of tax revenue from Pemex that's higher than budgeted in a fund to invest in energy projects. The investment would be used to build refineries, petrochemical plants, pipelines and to improve technology, the bill said.

The bill would order a congressional audit of all Pemex operations and create a special commission to report on the current relation between the company and its union.

It also calls on the government to assume interest payments on deferred debt that Pemex contracts for projects built by private companies, which is known as Pidiregas. The coalition of parties wants to scrap multiple-service contracts that Pemex awards to companies for complex work and replace them with cost-plus contracts.

Calderon's bill would allow Pemex to contract companies to build and operate refineries under an agreement in which the state-owned company would supply the crude oil and own the gasoline and chemicals produced by the refineries.

Proven oil reserves at Pemex cover nine years of production at current rates. For more than two decades, Mexico hasn't been able to replace oil at the rate it pumps crude out of the ground.

For the first seven months of the year, Pemex produced 2.845 million barrels a day, 10 percent less than a year earlier. Daily output at Cantarell, the world's largest offshore oil field, fell by more than half to 1.127 million barrels.

Pemex is the third-largest oil supplier to the U.S. Canada and Saudi Arabia are the first- and second-largest suppliers of crude to the U.S., Department of Energy figures show.

BOLIVIA

Bolivia to Pay Shell for Transredes Pipeline Stake

Bolivia and Royal Dutch Shell have signed a deal compensating the Anglo-Dutch energy group for its share in the nationalized gas pipeline company Transredes.

The accord was signed August 8 by Bolivian Energy Minister Carlos Villegas and Shell representative Jose Maria Linardi in the presence of President Evo Morales.

The amount of the deal for Shell's stake in Transredes, which was nationalized by Morales last year, was not divulged by officials.

Reports on August 9, however, put the sum at $120.57 million.

The accord lifts the share held by Bolivia's state-owned YPBF energy company in Transredes and gives the government a 98-percent stake, officials said. The other two percent is held by private partners.

"YPBF has become owner of Shell's share in Transredes at a price established by the national government," Villegas said.

The deal did not include another stake-holder in Transredes; U.S. company, Ashmore Energy International, which was demanding a $500 million pay-out from Bolivia in a case before the Arbitration Institude of Stockholm's Chamber of Commerce.

Shell and Ashmore together owned 50 percent of Transredes through a joint company, TR Holding, before it was nationalized.

Bolivia has the second-biggest gas fields in Latin America, after Venezuela, and the nationalization of the sector is one of the central policies of Morales's leftwing reforms.

CHILE

Petrobras Boosts Presence in Chilean Market

Petrobras on August 7 signed an agreement to purchase ExxonMobil's stakes in Esso Chile Petrolera and other associated Chilean companies. The director of Petrobras' International Area is Jorge Luiz Zelada.

The acquisition, worth $400 million, will give the Brazilian company a 16% share of the Chilean retail market in this segment, in addition to a 14% share in the industrial area. With the deal, Petrobras now owns a network of 8,315 points of sale in six South American Countries.

The agreement covers the fuels business in the retail, industrial, and aviation markets:

· 230 service stations, including 109 of which self-owned; about half of the total service stations have convenience stores

· Fuel distribution and sales at 11 airports

· Six fuel distribution terminals, two of which joint ventures

· 22% stakes in Sociedad Nacional de Oleoductos, and 33% stakes in Sociedad de Inversiones de Aviacion

· Sales volumes, in 2007, of approximately 74,000, 40,000, and 20,000 cubic meters per month in the retail, industrial, and aviation segments, respectively

· 16% and 14% of the retail and industrial market shares, respectively

"The operation is important as it consolidates Petrobras' position in the South American market. We had little participation in Chile, a country where the economy is stable. With this deal, Petrobras now holds significant assets there," said Petrobras' International Area's director, Jorge Luiz Zelada.

Change in control is expected to take place in the second quarter of 2009, together with the payment of some $400 million. Also according to the director, in the next five years, Petrobras plans to invest $90 million in Chile. "The intention is, as of this first deal, to discover new opportunities in the country," added Zelada. To the director, within a couple of years, all 320 service stations will be displaying the Petrobras brand.

With the acquisition of these distribution and logistics companies, Petrobras ensures high-quality services to consumers, accumulating the excellence in customer service and the technical qualifications of Esso Chile's 1,320-strong local workforce. ExxonMobil's chemical, lubricant, and special product businesses in Chile were not part of the agreement.

The deal reinforces Petrobras' image abroad, especially in Chile, a country to which the Company exported, in 2007, among other products, oil, LPG, natural gas, petrochemicals, and lubricants, with sales topping-out at nearly $1.5 billion. The main derivatives vendor and only refiner in the country is the national oil corporation ENAP, with which Petrobras has an excellent relationship.

This acquisition consolidates the Company's presence in the fuel distribution segment in Latin America, where, over and beyond in Brazil, it already operates in Argentina, Colombia, Paraguay, and Uruguay, with a network of nearly 1,000 service stations.

The agreement is aligned with Petrobras' Strategic Planning, which calls for expansion in regions such as Latin America.

COLOMBIA

Pacific Rubiales and Ecopetrol Award $320 Million Contract for Colombia’s Rubiales Oil Pipeline

Pacific Rubiales Energy Corp. recently announced that it has awarded, in conjunction with Ecopetrol S.A. (Ecopetrol), the construction of the Oleoducto de los Llanos Orientales Pipeline to the Consorcio Rubiales-Monterrey, a joint venture between Spiecapag and Ismocol (collectively, the Contractor).

This project will provide the company with a substantial reduction of transportation costs for Rubiales Crude to the export port of Covenas while ensuring that there will be adequate throughput capacity to bring the Rubiales Oil Field to its full production potential.

Under the terms of the Engineering, Procurement and Construction (EPC) contract, the Contractor will complete the construction of the 235 kilometer 24 inch pipeline between the Rubiales Oil Field, located in the Meta Province of Colombia, and the Monterrey Station, located in the Casanare Province, by September 30, 2009. The lump sum fixed price contract has a value of US$190 million and does not include construction of the pumping station at Rubiales Field, which will be awarded separately. Total capital commitments for the project so far exceed US$320 million, including the EPC contract, the pipe and procurement of long lead-time items.

Spiecapag, which leads the 60/40% consortium, is a highly regarded French international contractor, specialized in pipeline construction, as well as oil and gas production facilities and terminals. Spiecapag has executed significant worldwide projects for major oil and gas companies, as well as projects in Colombia. The local partner in the consortium is Ismocol de Colombia, a leading Colombian contractor, with approximately 20 years of experience in the Colombian oil and gas industry.

The pipeline company "Oleoducto de los Llanos Orientales S.A.", a special purpose vehicle organized for the pipeline project, is owned 35% by Pacific Rubiales and 65% by Ecopetrol. German bank WestLB will provide financing for up to 75% of total capital costs under a project financing structure.

This project is the key element of the Rubiales Oil Field master plan, which will allow field development to its maximum potential by 2010. Additionally, this pipeline will leverage the future development of the very prospective Los Llanos Heavy Oil Basin.

Pacific Rubiales, a Canadian-based company and producer of natural gas and heavy crude oil, owns 100 percent of Meta Petroleum Limited, a Colombian oil operator which operates the Rubiales and Piriri oil fields in the Llanos Basin in association with Ecopetrol S.A. the Colombian, national oil company. The Company is focused on identifying opportunities primarily within the eastern Llanos Basin of Colombia as well as in other areas in Colombia and northern Peru. Pacific Rubiales has a current net production of approximately 22,500 barrels of oil equivalent per day, with working interests in the Rubiales, Piriri and Quifa concessions and the Caguan, Dindal, Rio Seco, Puli B, La Creciente, Moriche, Guama, Arauca, Tacacho and Jagueyes blocks in Colombia and blocks 135, 137 and 138 in Peru.

VENEZUELA

PetroSA Qualifies to Explore Venezuela Off-shore Gas

South African state-owned oil firm PetroSA said on September 3 it had qualified as an operator for offshore gas exploration in Venezuela.

The company, which signed oil exploration and heavy crude oil production agreements with its Venezuelan counterpart PDVSA on September 2, said it had also agreed to study reserves in a section of the Orinoco Belt.

"PetroSA entered into an agreement for the study for the quantification and certification of reserves in "Boyaca 4" Block which covers an area of approximately 700 Km2, in the Orinoco Oil Belt," the company said in a statement.

ASIA

CHINA

PetroChina to Build 400,000 cbm Storage Tank in Changsha, Hunan Province

PetroChina will build an oil products storage tank in Changsha, central Hunan province, to link with its Lanzhou-Zhengzhou-Changsha oil products pipeline.

As one part of its 2,148.4-km Lanzhou-Zhengzhou-Changsha pipeline, the Changsha tank, to cost 800 million yuan, is designed to have storage capacity of 400,000 cbm and will come on stream before October 2009.

To feed on oil products pumped from northeast and northwest China, the tank is expected to act as a distribution center to supply Hunan and the provinces nearby.

INDONESIA

Indonesian $246 Million Combined-cycle Plant Contract for Alstom

Alstom has won a contract worth about US$246 million with the national electricity utility PT.PLN (Persero) in consortium with Marubeni Corporation for the construction of a combined cycle power plant in Indonesia. The power plant is located at Muara Tawar, 35 km from Jakarta, on the northern coast of Java. The project consists of extending the existing power plant with a fifth unit. The new unit will increase the total output of the plant by 235 MW from the current 1800 MW and will be operated with natural gas.

Under the terms of the contract, Alstom, as the consortium leader, will engineer, procure and commission a fully integrated power island, consisting of one GT13E2 gas turbine with one heat recovery steam generator, one COMAX steam turbine, two turbogenerators and the ALSPA control system. Alstom will engineer and manufacture the heat recovery steam generators at its local boiler facility in Surabaya, the capital of east Java. Marubeni Corporation will supply the balance of plant, high voltage switchyard, civil works and erection services.

At Least Twenty Oil, Gas Basins Found in E Indonesia

At least 20 new basins of oil and gas, mostly located in the eastern part of Indonesia were found and the country now has 87 basins in which 67 on the map previously released by the association in 1985, according to local media on August 27.

Experts of geology have discovered at least 20 new basins which are similar in the previous mapping, the Indonesian Business daily quoted secretary general of Indonesian geologist (IAGI) Ridwan Djamaludin as saying.

"Hopefully, the new mapping of basin can be used by the government and companies for references before an exploration on gas and oil," he said.

Indonesia has currently developed 17 basins which may be potential for the next phase of oil and gas production, he said, adding "other 33 basins are in an exploration level."

Besides in the eastern part, it has been said that some others basins are located in several areas in Sumatera, Papua, Java and also Bangka, South Natuna, Cendrawasih and Mentawai.

THAILAND / MALAYSIA

ASEAN Officials to Discuss Gas Pipeline Network Expansion

Energy ministers from Association of Southeast Asian Nations member countries planned to discuss the possibility of expanding a cross-border natural gas pipeline network as well as increasing cooperation on power grids during an annual meeting, a senior Thai official said August 4.

Senior energy officials planned to propose a plan to promote the Natuna gas field offshore Indonesia to be a key supply source for Asean nations in the future, with planned pipelines linking the field to Malaysia and Thailand. The pipeline links - approximately 1,000 kilometers long - will help implement the plan for a trans-Asean gas pipeline network, said Twarath Sutabutr, spokesman for Thailand's Energy Ministry.

A joint study on pipeline network expansion from the existing nine routes, with a combined length of 2,300 kilometers, would help increase natural gas trading in the region, Kurujit Nakornthap, deputy permanent secretary of the Thai Energy Ministry said.

The proposed Petroleum Security Agreement, which is aimed at helping member countries cope with shortages or oversupply of crude oil and petroleum products, would be finalized by senior Asean energy officials before being presented at ministerial level for signing, Twarath said.

"The key principle of the agreement has been agreed to. However, there are a few issues which need to be settled. If it isn't ready, the issue will have to be presented at the next meeting," said Twarath.

Under the draft agreement, oil exporters in Southeast Asia would supply petroleum products to countries suffering a shortage, so that they have supplies meeting up to 80% of their domestic demand. In the event of oversupply, net importers would purchase products from exporting countries.

The agreement also includes short-term measures to ensure that production isn't disrupted. It also covers medium-to-long-term measures to collaborate on renewable energy, energy conservation, and in building up oil stocks.

Senior Asean energy ministers planned to discuss the possibility of building up regional oil stocks August 5 with representatives from Japan's Ministry of Economy, Trade and Industry, said Twarath.

Asean member countries will also consider ways of increasing coal trading and building up coal reserves, Kurujit said.

Senior energy officials from Asean countries also planned tol discuss drafting an action plan on energy cooperation. The plan will cover oil and gas network, power grid expansion, clean coal development, energy efficiency and conservation, alternative energy and nuclear energy, said Twarath.

The action plan will be implemented from Jan. 1, 2010 to Dec. 31, 2015, instead of 2009-2014 as planned earlier, he added.

China, Japan, South Korea and the 10 members of Asean, a bloc known as Asean +3, together with Australia, New Zealand and India will participate in the annual discussions.

Asean comprises Brunei, Cambodia, Indonesia, Laos, Myanmar, Malaysia, the Philippines, Singapore, Thailand and Vietnam.

VIETNAM

Vietnam’s Big Oil and Gas Potential, Signs Agreement with Qatar for US$1 Billion Joint Fund Investments

Qatar and Vietnam have signed an agreement to set up a joint fund with a capital of US$1 billion to facilitate investments in both countries.

Vietnamese Ambassador in Doha Phung The Long said Qatar’s contribution to the fund, through Qatar Investment Authority (QIA), would be US$900 million and the balance would come from his country.

The two sides have discussed co-operation in oil & gas as well as agriculture.

Vietnam has the potential to become a regional oil and gas supplier. Ongoing explorations have led to several oil and gas discoveries in recent years. Consequently, the government highly prioritizes investments in both upstream and downstream production, which makes it an interesting market for Middle East companies.

Vietnam ranks the fourth in oil production among Asian countries, trailing China, Indonesia and Malaysia. Provided that the current rate of development continues, Vietnam will become the world's 30th largest oil-producing nation. And perhaps the most interesting aspect about Vietnam, its gas reserves seems even more promising than its oil reserves.

Vietnam’s oil and gas industry has undergone a significant development since the first oil was produced from the Bach Ho oil field in 1986. Until then, Vietnam’s economy relied heavily on imported petroleum products from the Soviet Union. Later on, as Vietnam started exploration of its reserves, The Soviet Union also provided the equipment and expertise in all areas of production.

To date, Vietnam has produced 220 million tons of crude oil and 37 billion cubic meters of natural gas bringing a turn over of US$53 billion and contributing US$30 billion to the state’s budget.

Up to December 2007, the industry has attracted approximately US$5.8 billion of foreign capital for exploration and production. Additionally, a large amount of capital has been invested in the downstream sector and related infrastructure. Having no refinery capacity of its own yet, Vietnam exports all of its crude production and imports fuels and petrochemical products. In 2007, Vietnam exported over US$8.8 billion of crude oil mostly to Australia, Singapore, US, Japan, Malaysia and Indonesia. Meanwhile, refined products imports are over US$7.7 billion, more than a half of which was from Singapore.

Overall, Vietnam’s oil and gas reserves seem attractive. Comparatively, the gas reserves are considered more promising than known oil reserves with large confirmed amounts of gas in Vietnamese waters. Oil and gas has been found in 60 fields, of which more than 20 commercial fields have been developed.

To date, 57 oil and gas contracts have been signed between the Vietnam National Oil and Gas Group (PVN) and its foreign counterparts. Foreign companies active on the market mostly operate under Product Sharing Contracts (PSCs) or Joint Operating Contracts/Companies (JOCs) or Business Co-operation Contracts (BCCs) with PVN with registered investment capital of more than USD 7 billion. The international players are companies such as Shell, Total, BP, Mobil, Conoco Phillip, Unocal, among others. At present, 22 of the 57 oil and gas contracts have been completed and the remaining 35 contracts are being implemented.

Vietnam has 3.1 billion barrels of proven oil reserves. However, the exploration in Vietnam continues to yield new discoveries and the reserves may amount to 4.5 billion barrels. Currently, Vietnam has seven operating oil fields; Bach Ho (White Tiger), Rong (Dragon), Rang Dong (Aurona), Hon Ngoc (Ruby), Dai Hung (Big Bear), Bunga and Kekwa. Most oil exploration and production activities occur offshore in the Cuu Long and Nam Con Son Basin.

In 2006, crude oil production averaged 390,000 barrels per days (bpd), of which the Bach Ho was account for more than a half (200,000 bpd). Despite the Su Tu Den (Black Lion) crude field in October 2003 founded and owned by PetroVietnam in the drilling process as well as new finds in 2005-2007 (such as Su Tu Trang, White Lion field; Su Tu Vang, Golden Lion field; and Su Tu Nau, Brown Lion field) provide long-term output potential, the country is, however, hard to maintain these higher production levels of crude oil in the coming years and unlikely to exceed 360,000 bpd by the end of 2011 as predicted by the Business Monitor International. The main reason of its limited production capacity is due to lack of technology and investment.

Currently, Vietnam has no operating refineries, and consequently most fuels and other oil products (lubricant, bitumen) consumed in the country have to be imported. However, PetroVietnam is in the process of building its first refinery, named Dung Quat refinery, and expected to be in operation in 2009. The US$ 1.5 billion refinery is located in Quang Ngai province. It will have a yearly capacity of 6.5 million tonnes of oil (130,000 bpd), producing an estimated 3 millionn tonnes of diesel, 1.8 millionn tonnes of gasoline, 400,000 tonnes of jet fuel, among other products such as liquefied petroleum gas (LPG) and propylene. PetroVietnam and Zarubezhneft of Russia each hold a 50% stake in the 25-year project.

In May 2005 Petro Vietnam and the French oil company Technip signed a contract for building the main part of the refinery. Other contractors in the consortium include the Japanese engineering company JGC and Spain's Technicas Reunidas.

Moreover, in October 2006 Petro Vietnam and its partner, Idenmitsu (Japan), completed an updated feasibility study on a setting up a Joint Venture for its second refinery project. The proposed US$ 5.25 billion Nghi Son petrochemical and oil refining complex will have a processing capacity of 180,000 bpd, and will be located in Thanh Hoa province, north of Hanoi. It should be operational by 2013. The refinery will use 100% imported crude oil from Kuwait.

This project is of great importance and it is expected to act as a catalyst for the Vietnamese economy in general and the northern Central provinces in particular, not only promoting the domestic petrochemical and commodity producing industries, but also ensuring energy security.

Finally, the government is approved for building a third refinery at Vung Ro in the southern Phu Yen province. The refinery will have a minimum capacity of 7 million tonnes per year and will be put into operation by 2015. The refinery will process mainly imported crude oil and only partly use oil domestically produced. Regarding the mode of investment, the Prime Minister of Vietnam, Nguyen Tan Dung, allowed a joint venture, a wholly foreign invested or a domestically invested entity to run the project.

In this context, it should also be noted that PetroVietnam has extended its focus beyond these huge projects. In terms of refineries, VTN-P Petrochemical Joint Venture Co is opening a small-scale refinery on a trial basis in the Mekong Delta City of Can Tho. The refinery may serve as a pilot-project for similar projects.

In addition, PetroVietnam’s business strategy includes oil-processing projects, which require smaller investment and shorter time for implementation. Moreover, as new refineries comes on-stream and begin consuming domestic crude supplies, crude oil exports is assumed to tumble to just 45,000 bpd in 2011 in comparison with 427,000 bpd in 2004.

In term of natural gas, Vietnam has proven gas reserves of 700 billion cubic meters (bcm), but it is expected to contain up to 3,000-4,000 bcm. Vietnam natural gas production is increasing steadily with further increases expected as additional fields come on-stream and in despite of current limited local demand as well as infrastructure. In 2007, Vietnam produced around 6.86 billion cubic meters (bcm) of natural gas. According to Business Monitor International’s forecast, the production is expected to reach 17 bcm by 2010.

The Cuu Long basin, a source of associated gas from oil production, is the largest Vietnamese production area of natural gas. Only two fields have been developed specifically for their natural gas potential: Tien Hai, with a potential output of 1.76 million cubic feet per day (mmcf/d) and Lan Tay/Lan Do of Nam Con Son with a production of 5 mmcf/d. Naturally, this strategy of raising gas production will require a substantial development of the infrastructure transporting the energy.

Pipelines are being built with surplus capacity to accommodate new discoveries and rising consumption later in the decade. The BP-operated Lan Tay gas fields are expected to produce for 15 years. Gas deliveries commenced in 2002 and rose sharply in the last few years. BP in 2005 increased its gas supplies from the Nam Con Son project to around 3bcm. The group is apparently considering a second Vietnamese gas pipeline to cope with increasing supply and demand.

In December 2002, a consortium headed by South Korea’s KNOC signed an agreement to install facilities to be used to pump and supply up to 3.7 millionn cubic meters per day (mcm/d) of gas, located in the Rong Doi and Rong Doi Tay fields. This gas will be purchased by PetroVietnam for 23 years. Sales commenced in 2005. PetroVietnam is in turn expected to sell the gas to Electricity of Vietnam (EVN).

Earlier this year, PetroVietnam announces that it will build and bring the US$70 million Phu My gas pipeline project from Phu My to Nhon Trach into operation in the first quarter of 2008. The pipeline was initially planned to transport associated gas from the Bach Ho and Rong fields for power generation.

The Vietnamese government controls both the oil and gas upstream and downstream sectors. PetroVietnam, now named the Vietnam National Oil and Gas Group (PVN), is the dominant player on the market. It has a full monopoly on all upstream exploration and exploitation and plays a significant role in downstream operations as well. Any foreign oil company working on upstream projects will have to deal with PVN in some capacity.

The central management of PVN is located in Hanoi. The group, as a parent company, will hold 100% of charter capital from six subsidiaries and half of the charter capital from 11 other affiliates in line with the current Prime Minister’s Decision stipulating the group’s organizational and operational regulations.

PVN is in the process of adding seven to ten new oil & gas fields from 2005 to 2010 in order to secure national energy demand. In the production sector, PVN aims at maintaining the oil production from current fields and to triple gas production from developing fields.

PVN also increases concentration on construction of infrastructure, especially to develop the gas market (power plants, petrochemical plants) to meet with potential gas supply. The refinery projects previously mentioned are explicit means to pursue this strategy.

For 2008, PVN plans to attain an output of 23.5 million tonnes of oil equivalent, including 16 million tonnes of crude oil, 7.5 billion cubic meters of gas, and 740,000 tonnes of fertilizer. The group also plans to supply enough gas to fuel electricity projects and people’s consumption.

Production wise, the strategy is to double volume of the Su Tu Den oil field, Vietnam's second largest oil field, and to keep the production at around 150 mmbo and 250 billion cubic feet of gas.

To exploit the gas and oil fields off the southwest coast of Vietnam, the group has set up the Southwest Gas Project, which is expected to supply gas to the national Ca Mau Gas-Power-Fertilizer Complex in the southernmost Ca Mau Province and to neighboring economic zones.

In order to implement its strategy, PVN expects to invest around US$15 billion to US$21 billion until the year 2020. With regards to foreign investment in the industry, international oil company upstream involvement is significant, in partnership with PVN. While Russian state company Zarubezhneft is the biggest foreign oil producer, in the Vietsovpetro JV with the group, BP is now the leading IOCs in terms of investment, followed by Petronas and ConocoPhillips.

Most of Vietnam’s crude oil is lifted from the Rong (Dragon) and Bach Ho (White Tiger) fields by the joint venture company Vietsovpetro. This is a 50-50 joint venture between PetroVietnam and Zarubezhneft, a company formed under the former Soviet Union. This is the sole joint venture company in upstream exploitation. It has been lifting oil in the Bach Ho field since 1986. It has the only operational gas pipeline and delivers roughly two to three million cubic feet of gas per day to Vung Tau.

Overall the Vietnamese oil and gas industry shows promising potential. There is a need for future investments in both upstream and downstream production in order to tap the country’s recourses effectively.

Regarding upstream operations, the opportunities appear large. The ongoing explorations continue to yield new discoveries of oil and gas reserves. PVN is increasingly aiming at attracting foreign investments for locating and tapping oil and gas reserves and to effectively implement contracts signed with foreign partners.

However, the field is competitive and contract-negotiations lengthy. Moreover, there is no separate petroleum authority, meaning that PVN determines the rules of the game, but is at the same time a commercial enterprise. Several foreign organizations have, however, lobbied heavily for improved operating conditions for oil and gas companies, and the efforts have resulted in some improvements of the business climate.

Regarding machinery and services, Vietnam has shown a strong demand for basic and less expensive products. Due to this strong and increasing demand, a substantial amount of imported oil and gas machineries is required. Moreover, given the country’s need to develop the oil & gas industry in the coming years, more sophisticated machinery and services will inevitable be required.

Thus, Middle East companies can find opportunities to provide machineries for platforms of various types and sizes, oil rigs, drilling equipment, operations and maintenance, fire-fighting, underwater tools, towing and rescue vessels, and so on.

Local production of oil and gas machinery in Vietnam includes primarily basic and low-end equipment of oilrigs, platforms and pipelines.

These machinery and services are mainly provided by subsidiaries of PetroVietnam such as PetroVietnam Exploration and Production Company (PVEP), Petroleum Technical Services Company (PTSC), PetroVietnam Engineering and Construction Company (PVECC).

It should be noted that Russia has established a strong base in exporting its offshore oil and gas machinery and services to Vietnam due to its long-established history in Vietnam. Korean, Japanese, Indian and U.S. companies are also active players on the market.

In terms of investment and financing capacity, PVN has an exceptionally large cash flow in comparison to other Vietnamese companies. Consequently, PVN has worked out measures to continue attracting foreign investments for locating and tapping oil gas in the offshore areas, and it also seeks to invest in oil and gas exploration and exploitation in the Middle East and other parts of the world.

EUROPE / AFRICA / MIDDLE EAST

MISCELLANEOUS

Foster Wheeler Announces Several Projects

Foster Wheeler Ltd has announced that its Madrid-based subsidiary Foster Wheeler Iberia SAU, part of its Global Engineering and Construction Group, has been awarded a project management consultancy contract by Gas Natural, for a new 400MW combined-cycle power plant in Málaga, Spain.

Foster Wheeler Ltd has announced that its Milan-based subsidiary Foster Wheeler Italiana SpA, part of its Global Engineering and Construction Group, has been awarded a contract for the supply of fired heaters for the Nizhnekamsk integrated refinery and petrochemicals complex in the Republic of Tatarstan, Russian Federation. Open Joint-Stock Co. "Taneco," a unit of the Russia-based oil company Tatneft, awarded the contract.

Foster Wheeler Italiana will engineer and supply the materials for two furnaces for the hydrocracking unit, and a charge heater and three interheaters for the continuous catalytic reformer unit. In addition, at the end of 2007, Foster Wheeler Italiana was also awarded a contract for the detailed engineering of two heaters for the new delayed coker.

Foster Wheeler Ltd has announced that a subsidiary of its Global Power Group has been awarded a contract by Hanwha Engineering & Construction Corp. (HENC) for the design and supply of two circulating fluidized-bed (CFB) steam generators to be located at the Gunjang National Industrial Complex (HENC GP Project), Gunsan City, Korea.

Construction of the two 50MWe (gross megawatt electric) CFB steam generators is expected to begin in the spring of 2009 with commercial operations scheduled for 2010.

MISCELLANEOUS OIL AND GAS COMPANY NEWS

Berry Petroleum Co. agreed to acquire interest in East Texas natural gas production from a consortium of private sellers for $620 million.

Berry Petroleum's transaction involves 4,500 net acres in Limestone and Harrison counties. The acquisition, which includes a $20 million gathering system, marks Berry Petroleum's entry into the East Texas basin.

Berry Petroleum of Bakersfield, Calif, will operate the properties upon closing, which was expected by July 15. The acquisition will add 32 MMcfd of gas equivalent to Berry's production from 100 producing wells.

Estimated proved reserves associated with the properties are 335 bcf of gas equivalent, with 29% being proved developed reserves.

Berry identified more than 100 drilling locations targeting stacked pay in various productive zones including the Pettit, Travis Peak, Cotton Valley Sands, Cotton Valley Lime, and Bossier sands.

Pacific Rubiales Energy Corp., Toronto, will buy Kappa Energy Holdings Ltd. of Colombia for $168 million.

Pacific Rubiales operates numerous blocks in Colombia and three blocks in Peru.

*Kappa Energy, operating since 1997, holds 747,000 gross acres in nine operating blocks in the Catatumbo, Llanos, and Lower, Middle, and Upper Magdalena basins.

Kappa Energy holds the following net working interests: Abanico block, 22.5% in the production area, 23.8% and 14.8%, respectively, in the Santana and Casablanca exploration areas, and 30.5% in the remaining exploration areas, Alhucema 50%, Arrendajo 32.5%, Cerrito average 75%, Chipalo 50%, Cicuco 100% for gas and oil, Guasimo 100%, Buganviles 49%, and Las Quinchas 50%.

The Abanico contract area includes the main oil producing field, Abanico, making 4,100 b/d, and Ventilador gas field making 4.3 MMcfd. Guasimo, Alhucema, and Arrendajo are in the drilling phase.

Kappa Energy had 9.3 million boe of proved and probable reserves as of May 31.

* Endeavour International Corp. has offered to buy Ithaca Energy Inc. for as much as $150 million in cash and shares to bolster its North Sea assets.

Endeavour sent a nonbinding letter to the Ithaca Energy board, setting out its proposal, which represents a premium of 44.2% on Ithaca's closing price on June 18. Endeavour, which already holds a 2.4% of Ithaca's current issued share capital, has offered an indicative price of $3.25/Ithaca share.

William Transier, Endeavour's president and chief executive, said: "Our two companies have similar strategic focus on the upstream business in the North Sea. With Endeavour's current cash flow and growing production profile, the risk of timely execution of Ithaca's development projects is reduced, and the ability to realize total value for shareholders is significantly increased."

Ithaca said it would review the unsolicited offer in light of its long-term strategic plan. It has interests in 30 blocks or partial blocks under 16 licenses covering more than 514,000 acres.

Endeavour estimates that its production in 2008 will average 8,600-9,000 boe/d. It plans to drill and appraise 15 North Sea exploration and appraisal wells later in 2008 and 2009.

Oklahoma City-based Quest Resources Corp. plans to buy private PetroEdge Resources LLC for $140 million, closing by mid-July

A Talisman Energy Inc. unit plans to invest as much as $125 million within 18 months to earn working interest in properties owned by Hallwood Energy LP.

Talisman-Hallwood Talisman Pres, and Chief Executive Officer John Manzoni said, "This agreement gives us exposure in a number of areas where we have not been active, including the deep Barnett and Fayetteville shales."

Previously, Manzoni said Talisman would spend $1.1-1.3 billion through 2009 evaluating its unconventional assets in Canada and the U.S.

Privately owned Hallwood Group Inc., a diversified holding company, owns 25% of Hallwood Energy of Dallas. Hallwood Energy's 2008 drilling program calls for 11 wells.

The Talisman agreement involves Hallwood's 40% working interest in more than 43,000 acres in the Barnett and Woodford shales in the West Texas counties of Reeves and Culberson. The agreement also involves Hallwood's 24,500 net acres in the Fayetteville shale in White and Faulkner counties in Arkansas.

In addition to the assets, the agreement includes a technical- services arrangement in which Hallwood's technical staff would assist Talisman for a year.

Manzoni said, "Hallwood has a proven track record in the early- stage development of shale programs, and we will use this to augment our experience in the piloting and development of our unconventional plays."

* Arrow Energy, Brisbane, has a major agreement with Shell Exploration Co. BV under which Shell will pay up to $776 million (Aus.) for interests in Arrow's Australian and international coal seam methane (CSM) projects.

Australian power retailer Origin Energy Ltd., Sydney, has formally rejected the unsolicited $13.8 billion (Aus.) takeover bid from BG Group. (see August 2008 Oil and Gas Updates)

Dutch Energy Firm Nuon Announced a €476.7 Million Deal to Acquire the Norwegian North Sea Energy Assets of ConocoPhillips

Nuon also will acquire Burlington Resources Nederland Petroleum BV, giving the company stakes in 35 gas fields in the Norwegian North Sea, gas pipelines, and processing facilities.

The transaction is key to Nuon's determination to become an integrated company across the gas and power value chain. It also adds the essential gas production capabilities to Nuon's existing gas trading, wholesale, and retail activities.

About 28 of the 35 fields are in the joint development area of the Dutch North Sea and Burlington holds interests in the Westgastransport Pipeline and Pipeline Extension, the onshore Den Helder facility with HiCal and LoCal gas processing plants, and the JDA LoCal pipeline. The assets are operated either by NAM or by Wintershall.

Nuon is keen to partner with a foreign company to strengthen its position in the European energy market and continue to acquire interests in gas fields or power plants. The search for a partner is expected to take at least 6 months.

* Canadian Imperial Venture Corp. has agreed to acquire 100%) of the assets of Encore Investments Ltd., including 25 sections of land in southern Alberta and interests in a number of producing oil and gas wells.

* ATP Oil & Gas Corp. acquired a 55% working interest in the Gulf of Mexico's Green Canyon Blocks 299 and 300, collectively known as Clipper.

ATP, which acquired the ownership interest from two independents, will operate both blocks. The value of the transaction was not disclosed.

ATP plans to complete one existing well and sidetrack and complete a second well first production scheduled for late 2009. Four wells drilled in 2005-06 in 3,400 ft of water.

InterOil, the CanadianC working in Papua New Guinea, Sold its Retention Leases in the Western Sector of the Country to Concentrate on its Potentially High Yielding Elk-Antelope Field in Eastern Papua New Guinea

The company also sold 43.13% of retention lease PRL4, which contains the undeveloped Stanley gas and condensate field, and 28.576% of PRL5, which contains the undeveloped Elevara and Ketu gas and condensate fields, to Horizon Oil Ltd. in Sydney.

InterOil retained first right of refusal to buy any condensate produced from both areas, which will be used as feedstock for the company's oil refinery in Port Moresby.

Horizon has increased its interests in both retention leases in recent few years and sees opportunity for commercial gas development as early as 2009, particularly in PRL4 at Stanley where the company will now have 100% interest.

Horizon's interest in PRL5 will become 49.647% if the transaction is approved.

The PRL4 deal is subject to government approval, while PRL5 is subject to pre-emptive rights from operator and major interest holder Santos Ltd of Adelaide.

InterOil said its move will allow it to concentrate on development of its potentially huge gas discoveries at Elk-Antelope. The recent Elk-4 well flowed at 14 MMefd. The company said the structure is potentially 13km long and 5km wide with gross reservoir thickness of 500m.

The Antelope- 1 appraisal will be drilled later this year

The company is a member of the Liquid Miugini Gas group with Merrill Lynch and Clarion Finanz AG and plans a 2-train LMG plant in Port Moresby capable of producing up to 9 million tonnes of LMG/ year from 2012 using the Elk-Antelope gas as feedstock.

* Wholly owned subsidiaries of Ute Energy LLC and Anadarko Petroleum Corp. formed Chipeta Processing LLC in the Unita basin of Utah.

* Eni SPA and Petroleo Brasileiro SA (Petrobras) renewed their commitment to work closely together on upstream and downstream operations, plus feasibility studies on renewables in Brazil and elsewhere.

OAO Gazprom Opened an Officei Algeria, Aimed at Developing Opportunities in Africa and in Particular with Sonatrach, The Nation's State Owned Oil Company.

Under a memorandum of understanding signed in 2006, both parties are committed to jointly developing oil and gas projects in Algeria, Russia, and third countries, including probable swaps of assets and operations, with exchanges of LNG and pipeline gas, for efficiency.

"Possibilities for cooperation in the area of joint acquisition of energy assets in the territory of third countries, engineering and construction of facilities of pipeline infrastructure were considered as well," Gazprom said.

This is the first time that Gazprom has established a representative in Africa. Deputy Chairman of the Management Committee of OAO Gazprom Alexander Medvedev added that cooperation would cover all parts of the oil and gas chain across Africa, including exploration and production, processing, sales, environmental protection, and energy efficiency. He said the office would help Gazprom raise its profile in becoming a global energy company.

Quicksilver is acquiring production, leaseholds, royalties, and midstream assets in Tarrant and Denton counties of Texas.

The properties have net production of 45 MMcfd of gas. Quicksilver estimates that these properties hold 350 bcf of proved gas reserves, of which 40% are proved developed. Quicksilver is paying $1 billion in cash and $307 million in common stock. The acquisitions are scheduled to close in August.

Upon closing, Quicksilver estimates that its total average 2008 production volume will increase to 275 MMcfd of gas equivalent, an 8% increase from earlier estimates.

Eni, the Italian Major will Offer its Exclusive Slurry Technology to Convert Residues and Heavy Oils, Typical of those Produced in Brazil.

Eni Chief Executive Paolo Scaroni and Jose Sergio Gabrielli, chief executive of Petrobras, signed the latest agreements at the World Petroleum Congress in Madrid. The first memorandum of understanding was signed in Brazil in early 2007.

Both companies will study the valorization of the natural gas reserves recently discovered by Eni off Brazil, particularly in the Santos oil basin.

Brazil has proven oil reserves of 11.5 billion bbl and proven natural gas reserves of 320 billion cu m. Hydrocarbon production, currently 2 million b/d and about 12 billion cu m/year of natural gas, will continue to grow due to encouraging exploration results, particularly offshore.

Eni has four offshore exploration blocks in Brazil along with a 30-year concession granted in 1999 to distribute natural gas in the northwest area of Sao Paulo state. Over the years, Saipem and Snamprogetti have jointly contributed to the building of numerous facilities in the oil sector, such as the refineries in Belo Horizonte, Porto Alegre, and Sao Jose dos Campos and some floating production systems.

NORWAY

Subsea 7 Wins $100 Million Contract from StatoilHydro for Troll B Gas Injection Facilities

StatoilHydro has let a US$100 million contract to Subsea 7 to design and install Troll B gas injection facilities to improve oil recovery at the country's largest gas field in the Norwegian North Sea. Troll field lies on the Norwegian Continental Shelf about 70km NW of Bergen in 300-340m of water.

The development is part of StatoilHydro's 10 billion-kroner plan to manage the resources and boost recovery of reserves at Troll by 17 million bbl. A single gas injection pipeline and a control umbilical will connect two separate subsea satellite wells to the Troll B platform-a floating process and accommodation platform with a concrete hull. One well will be 3.5km and another 6.5km south of the platform.

Subsea 7 will engineer, procure, fabricate, and install a 6.5km, 12in rigid pipeline, incorporating inline and end structures for connection to the satellite wells, in addition to the control umbilicals. It will use one of its new vessels to install two 200tn satellite structures.

Pipeline fabrication will be carried out in early 2009 at Subsea 7's new North Sea Spoolbase at Vigra on Norway's NW coast. Pipelaying operations are scheduled for 2009 with one of its specialized reeled pipelay vessels.

StatoilHydro's Lund Announces Oil and Gas Production Outlook and Recent Discovery

StatoilHydro ASA, the largest Nordic oil and gas producer, is on its way to meeting its output target for this year, Chief Executive Officer Helge Lund said.

``We are well under way to deliver on our production guidance for the year,'' Lund said August 25 in Stavanger, Norway. The company has an outlook for oil and gas production of 1.9 million barrels of oil equivalent a day for this year. Production rose 6 percent to 1,898 million barrels a day in the second quarter from a year earlier.

The company also announced an oil discovery near its Sleipner field in the North Sea. The find was estimated at 100 million to 125 million barrels of oil equivalent and was encountered in a well under the Dagny gas discovery.

``This is one of our most interesting oil discoveries in the North Sea for very many years,'' Lund said before a four-day conference in Stavanger that began August 26. The company is seeking to raise output from the Norwegian continental shelf to 1.55 million barrels of oil equivalent a day by 2012 from 1.4 million barrels a day, he said.

The company had recently reiterated its outlook for full-year output after having to shut its Kvitebjoern natural gas field because of a leak in a pipeline. Kvitebjoern produced about 13 million cubic meters a day of gas, on average, and about 40,000 barrels of oil a day, in the first six months of year, according to the Norwegian Petroleum Directorate.

The company also had to shut down its Arctic Snohvit liquefied natural-gas plant following a gas leak.

Snohvit has since resumed production and Kvitebjoern will be repaired next ``summer,'' Lund said. The company is looking at other options for Kvitebjoern, he said.

Separately, Lund also said that the company hasn't decided yet how to proceed with a Canadian oil sands project while a planned so-called upgrader is delayed. The executive also declined to say whether the company will take part in an oil licensing round in Iceland.

Aker Solutions wins $240 Million Order from Sevan Marine

Norwegian engineering group Aker Solutions will supply oil rig owner Sevan Marine with two drilling equipment packages worth about $240 million, Aker Solutions said on August 27.

The deal to provide drilling equipment for rigs being built by Sevan includes an option for a third package, Aker Solutions said in a statement.

The contracts will be booked as order intake in the third quarter, the company said.

Aker Solutions is now working on deliveries for Sevan's first rig, scheduled for delivery in 2009. The drilling equipment covered by the new contracts is for ultra-deepwater rigs due to be completed by the end of 2010 and end of 2011.

Det Norske Veritas, Partners Developing CO₂ Pipeline Standard

Det Norske Veritas (DNV), together with major industry partners, is developing a new standard for transportation of CO₂ in pipelines. The initiative is expected to remedy the lack of coverage in existing standards and regulations for issues relating to CO₂ in the dense, high-pressure phase.

"As Carbon Capture and Storage (CCS) projects could become an important mitigation option related to climate change, this broad cooperation is an important step forward," said DNV project manager Froeydis Eldevik. "This (the new standard) will apply for the oil and gas industry when it comes to the transmission part of a CCS industrial project."

According to Eldevik, it is necessary to address the novel issues of CO₂ in the dense, high-pressure phase when designing, engineering, operating, and maintaining the pipelines. "These issues are different in many aspects from transmission of hydrocarbons in pipelines," she explained. "This recommended practice (or standard) will give guidance on best practice -- that is, 'how to' questions will be answered here, based on the expert knowledge we have in the industry at the moment."

DNV stated that, in regard to CO₂ pipeline transmission, stakeholders demand a robust, traceable, and transparent approach that lends credence to the proper management of risks and uncertainties. "Some of the current standards do not address CO₂ in such a detail as the industry needs today," noted Eldevik.

Eldevik pointed out that the industry confronts a markedly different regulatory climate than it did in years past. These regulatory changes stem from public and governmental demands for a more stringent risk management regime related to CO₂ in dense, high-pressure phases. Hence the industry has had to become more aware of novel CO₂ issues.

DNV stated that the current pipeline standards do not take into account considerations related to the pipeline transmission of CO₂ from large-scale capture plants to suitable storage sites. The exclusion of such factors in turn hinders the effective large-scale deployment of CCS, the risk management provider added. "By following this recommended practice or standard, the industry will be in compliance with regulations," Eldevik said.

The DNV-led industrial collaboration aims to develop a standard reference guideline for the onshore and submarine pipeline transmission of dense, high pressure CO₂. The point of departure will be existing pipeline standards for the transmission of hydrocarbons, such as ISO 13623 and DNV OS-F101. DNV's partners include: StatoilHydro, BP, Shell, Petrobras, Vattenfall, Dong Energy, ArcelorMittal, Gassnova, Gassco, and ILF. The Technical Reference Group consists of government representatives from the UK, the Netherlands and Norway. The European Commission is also supporting this DNV initiative.

"The joint industry project is an important milestone for CCS and is absolutely timely since the industry really needs this recommended practice. It will be an important contribution to the development of large-scale CCS projects," emphasized Eldevik.

According to DNV, the guideline is intended to help designers and operators limit and manage uncertainties and risks related to the pipeline transmission of CO₂ by incorporating current knowledge related to both offshore and onshore operations. It will state rules for managing risks and uncertainties throughout the pipeline's lifetime, including the design, testing, inspection, operation, maintenance and de-commissioning phases. It will also incorporate the lessons learned from existing and previous projects.

"Due to the features lacking in the current industry standards, this project's scope of work is related to issues like safety, fast propagating ductile fractures, fatigue crack growth, pipeline operation conditions, flow assurance, corrosion and material compatibility," said Eldevik.

DNV stated the guideline will be ready within 18 months.

POLAND

Poland Plans 800MW Gas-Fired Plant with Germany’s RWE

Germany-based RWE is in talks with Poland-based gas group PGNiG to build an 800MW gas-fired power plant for up to USD 3.1 billion. The project would involve two 400MW units close to PGNiG's underground gas storage facilities in either Wielkopolska, western Poland or in Podkarpac, SE Poland.

In June, RWE agreed to build a coal-powered 800MW plant in Poland for EUR 1.5 billion in partnership with the country's largest miner Kompania Weglowa.

SCANDANAVIA

Gassco Awards Contracts to IKM Gruppen for Skanled Pipeline System

Gassco has awarded two contracts to IKM Gruppen for the design and development of the NOK 10 billion Skanled pipeline system. The 853km long Skanled pipe will transport gas between Norway, Sweden and Denmark, and provision will be made for possible spurs to Lista and Slagentangen in southern and SE Norway.

Gassco said an investment decision on the pipeline scheme is due in October 2009, with gas deliveries planned to start in December 2012. The Skanled project also involves spending on new facilities at Rafnes south of Oslo, where ethane will be extracted from the gas for local industrial use.

Under the latest contracts, IKM will pursue design activities related to the pipeline system with associated subsea structures, landfalls and receiving/metering stations. Most of this work will be done at IKM Ocean Design AS in Stavanger and Trondheim.

Phase one of the work will last for a year, with options for detailed engineering of the pipeline system.

LIBYA

U.S. Firms Find Doing Business with Libya Intimidating despite Better Relations

For U.S. companies long excluded from Libya, the announcement that Secretary of State Condoleezza Rice will visit Tripoli the first week in September is a green light for business.

But getting a toehold in Muammar Gaddafi's energy-rich North African country may be the easy part.

A strong bureaucracy, erratic decision making and suspicion built up over decades of isolation means foreign firms may struggle to benefit fully from a wealth of money-making opportunities in Libya, analysts say.

U.S.-Libyan ties have improved dramatically since 2003 when Libya gave up banned weapons programs, and both countries saw the benefits of lifting hurdles to trade and investment.

American companies got involved in Libyan oil and gas after the end of sanctions, but many have held back for fear U.S. courts might freeze their assets for doing business with Libya before terrorism compensation claims are settled.

Those fears receded this month after the two countries agreed to set up a fund to cover the claims.

"Once the fund is funded I think there will be a big impact on the expansion of U.S. business in Libya and Libyan business in the United States," said David Goldwyn, executive director of the U.S.-Libya Business Association in Washington.

Libya's investment authority, looking for new destinations for growing oil profits, will be able to invest in the United States or join U.S. companies to enter other markets, he said.

Washington raised the status of its Tripoli liaison office to an embassy in 2006 but its diplomatic presence remains small.

Rice's visit, the first by a U.S. secretary of state in over half a century, should smooth the way for an exchange of ambassadors, ease visa procedures and make it easier for U.S. firms to compete in trade and investment.

A succession of European leaders have visited Libya to drum up business. Italy agreed on August 29 to pay $5 billion in compensation for misdeeds during its colonial rule of Libya and was promised energy deals and other business in return.

"American companies will be in fierce competition with Europeans, Asians and others, so we need to get on the plane and go to Libya and build relationships face to face," said David Hamod, head of the National U.S.-Arab Chamber of Commerce.

U.S. government figures show trade with Libya grew from zero in 2003 to $3.9 billion last year, more than four times the figure for Libya's neighbor Tunisia which has a bigger population but far less oil.

Libya's energy industries earned over $40 billion in 2007 and the government wants to nearby double oil output capacity to 3 million barrels per day by 2012.

Part of the profits will be used to upgrade and rebuild roads, ports, schools and factories in the country of 6 million that fell into disrepair during the years of sanctions.

Top U.S. construction companies, drinks makers and software firms have made forays into Libya but had mixed results, said Rajeev Singh-Morales, a senior partner at Boston-based Monitor Group, which produced an economic strategy report for Libya.

"Foreign companies need to find local partners and people who understand the environment," he said. "Libya still requires dedication and perseverance but it's certainly well worth it."

The lure of lucrative contracts must be set against the risks of doing business in Libya, where powerful interest groups wage a nebulous battle for influence and patronage.

Many ministries and tribal groups have a say in policy, which could aid political stability but slows decision making.

Gaddafi has watered down his socialist system in recent years to allow more private sector activity but a culture of business transparency is absent, analysts say.

Policy confusion at the top echelons of power has also clouded the business outlook.

Gaddafi has said repeatedly that much of Libya's state bureaucracy, including key ministries, must be abolished, with decision making and oil wealth handed directly to the people.

His influential son Saif al-Islam has called for administrative reforms and a constitution but defended his father's unique system of rule by popular committee, which critics say is a fig leaf for authoritarianism.

"These statements lend an air of unpredictability to the entire scene there," said James Ketterer, an international relations expert at the State University of New York.

Some U.S. energy firms already decided the potential rewards outweigh the risks. ExxonMobil, Occidental, Chevron and Amerada Hess won acreage in bidding rounds for Libyan energy exploration leases in 2005.

Since then, Libya has strengthened terms for its main foreign oil partners. Analysts say the decision seemed to be motivated by a desire to allow Libya to benefit from higher world prices rather than discourage foreign players.

Until new fields start pumping oil, foreign firms see quicker profits in enhanced oil recovery -- raising output from existing wells that lacked equipment and care.

"U.S. companies have tremendous technical advantages over others in this area," said Goldwyn. "But the biggest risk will be decision making until we know whether and how Libya will pursue enhanced oil recovery."

MAURITANIA

Bloodless Coup Threatens Mauritania's Oil, Gas Industry

Mauritania's nascent oil and gas industry, already under threat from the al-Qaeda terrorist organization, is facing more uncertainty following a bloodless coup staged by Army commanders.

The coup began when President Sidi Ould Cheikh Abdallahi fired the country's top four military officials. According to reports, the officials had been suspected of supporting lawmakers who had accused the president of corruption and disagreed with his efforts to reach out to Islamic hard-liners.

Abdallahi was detained by presidential guard units and held against his will at the presidential palace compound. Meanwhile, a military junta, which took over state radio and television, announced the formation of a new "state council," led by Gen. Mohamed Ould Abdel Aziz, one of the four generals fired earlier in the day.

A U.S. spokesman issued a statement condemning "in the strongest possible terms" the Mauritanians' military's overthrow of the democratically elected government of Mauritania, while European Union Development Commissioner Louis Michel said the president should be quickly released and returned to his post.

In July, Malaysia's state-owned Petronas said it obtained positive results from its exploration program in Mauritania when a well drilled 2 km away from its original Banda-1 discovery confirmed the existence of "significant" quantities of oil and gas.

Petronas said further exploratory work will be necessary to determine the overall size of the reservoir, but gas resources could be in excess of 1 tcf.

Around the same time, al-Qaeda's North Africa network said it planned to attack interests held by the U.S., which it said was establishing military bases and seeking control of the region's energy sources.

NIGERIA

Shell Says, No Real Progress Fixing Nigeria Trunkline

Repairs to a damaged oil pipeline in Nigeria have been struggling to make significant progress, Royal Dutch Shell said on August 15.

Shell's Nembe Creek trunkline, located at Kula in Rivers state in the restive Niger Delta, was sabotaged in late-July.

The Anglo-Dutch oil major declared force majeure on Bonny Light crude exports to free itself from meeting its contractual obligations through to September.

"Repair work is not progressing as much as we want due to some security concerns. No real progress," a Shell spokesman said.

The Movement for the Emancipation of the Niger Delta (MEND), which has led a campaign of violence against the oil sector since early 2006, claimed responsibility for two pipeline attacks in July, including the Nembe Creek line.

Both pipelines are operated by Shell and are connected to the Bonny export terminal. Shell only confirmed the damage to the Nembe Creek line.

The spokesman said Bonny Light production has been unchanged at a low level but declined to specify the actual output volume.

Earlier, Shell said about 40,000 barrels per day of its equity production had been shut by the attacks. State run Nigerian National Petroleum Corp. (NNPC) said the total outage volume of Bonny Light was 175,000 bpd.

Bonny Light's normal production level is about 400,000 bpd, which should make it the largest stream from Nigeria.

Shell reiterated that the pipeline repair work has not been completed. Nigerian Oil Minister Odein Ajumogobia said earlier in August that all the pipelines damaged from the late-July attacks were fixed and some production had restarted.

Shell is the worst hit by militant sabotage in Nigeria. Repeated attacks to oil facilities have halted about a fifth of oil supplies from the world's eighth largest oil exporter, contributing to the rise in oil prices this year.

Militants Destroy Gas Pipeline in Nigeria’s Rivers State

Militants on August 12 destroyed a pipeline supplying gas to a key oil refinery in southern Rivers state. Two groups who are relatively unknown, Niger Delta Vigilante and Niger Delta Patriotic Force, claimed responsibility for the attack on the pipeline.

As at press time there was no official confirmation of the attack and it could also not be immediately determined if operations at the refinery had been halted.

The affected pipeline transports gas from the Alakiri gas flow-station to the Port Harcourt oil refinery. The attack was the latest to hit the volatile oil-rich Niger Delta in recent months.

Meanwhile, Shell said it is investigating whether one of its pumping facilities in Rivers state was attacked by militants.

The company is conducting a flyover of the Alakiri flow station to determine whether there has been any damage, Shell spokesman Precious Okolobo said.

Alakiri is about 5 kilometers (3 miles) from the Port Harcourt oil refinery.

GEORGIA

BP Says Testing Begins on BTC Pipeline through Georgia Ahead of Full Restart

British oil company BP PLC said that testing would begin August 20 on the closed Baku-Tbilisi-Ceyhan oil pipeline, which runs through conflict-stricken Georgia, ahead of a move to restart full operations.

BP spokeswoman Sheila Williams said that the "dynamic integrity testing" would involve "limited and intermediate flow" of oil through the BTC line, which usually provides some 1 million barrels per day of Caspian Sea crude to international markets.

The line, owned by a consortium of energy companies led by BP, had been closed for after a fire on its Turkish stretch. Kurdish rebels took responsibility for the blaze.

Williams said that the port in Ceyhan, Turkey, has been given orders to update its lifting program, which transports oil from the pipeline, to restart work, giving an indication of when the pipeline is likely to be fully operational again.

BP's options to export Caspian oil have been seriously curtailed by both the fire on the BTC line and the Russian military actions in Georgia.

The London-based company had already shut down its Baku-Supsa oil pipeline — which runs through the center of Georgia from Baku in Azerbaijan to Supsa on Georgia's Black Sea coast — because of security concerns. Williams said August 20 that the line, which has the capacity to pump up to 150,000 barrels a day, but had recently been pumping around 90,000 barrels a day, was closed.

She added that a railway line that exports Azeri oil through Georgia also remains out of action, following reports of damage to the line, which can carry between 50,000 and 70,000 barrels of Azeri oil to Batumi.

Georgian officials accused Russia of blowing up a key railway bridge on the line — running from the capital of Tbilisi through the city of Gori before splitting in three to head to the ports of Batumi and Poti on the Black Sea and a location just shy of the Turkish border — on August 16, severing the country's main east-west rail route. Officials later vowed to restore the link.

BP reduced its production in oil fields in the Caspian Sea because of the pipeline closures — analysts say it's likely been reduced by a third from the 800,000 barrels a day before the BTC line was damaged.

The EU had been trying to wean itself away from energy dependence on Moscow, which supplies a quarter of its oil and half of its natural gas, by developing routes for Central Asian resources that bypass Russia. A key to that strategy was the network of energy routes that run through Georgia.

BP has the biggest stake in the BTC line, owning 30.1 percent, followed by the State Oil Company of Azerbaijan with 25 percent. Chevron, Total and ConocoPhillips all have smaller stakes.

AZERBAIJAN

VP Cheney Looking to Secure Energy Links in Azerbaijan

U.S. Vice President Dick Cheney was looking to secure strategic energy corridors feeding oil and gas to the West during a visit the first week of September to the Azerbaijani capital Baku, analysts said.

Cheney arrives in Baku September 3 for the first leg of a tour that will also take him to Georgia, Ukraine and an economic forum in Italy.

The Georgia leg of the trip is being seen as a key sign of support for the U.S. ally following Russia’s invasion and occupation of parts of the country and its recognition of two pro-Moscow separatist regions.

But analysts said Cheney’s decision to first visit neighboring Azerbaijan reflects one of Washington’s key interests in the volatile Caucasus region: oil and gas.

"Dick Cheney’s visit is first of all connected with energy questions. Azerbaijan and Georgia are parts of a corridor supplying energy resources to Europe," said Azerbaijani political analyst Rasim Musabekov.

Dick Cheney was involved in lobbying for these projects. And so the United States is looking for assurances that Azerbaijan will continue oil and gas deliveries through Georgia," he said.

Georgia’s conflict with Russia has raised fears that oil and gas producers in the energy-rich Caspian Sea, such as Azerbaijan, could turn their backs on Georgia as a route for exporting to the West.

Backed by Western governments, international energy firms have invested heavily in building a corridor of oil and gas pipelines from Azerbaijan through Georgia to Turkey, and then on to energy hungry Western markets.

But analysts said Azerbaijan may now fear that making Georgia a key link in the chain was a mistake.

Georgia has accused Russia of attempting to bomb all three of the main pipelines through the country during the conflict: the Baku-Tbilisi-Ceyhan and Baku-Supsa oil pipelines and the South Caucasus Pipeline, which carries gas to Turkey.

"The U.S. is afraid that Azerbaijan will begin sending its energy resources through Russia instead of Georgia, and this question will be one of the main points of the visit," said Vafa Guluzade, a Baku-based political analyst and former presidential advisor.

Russia was already competing with the west for access to Azerbaijan’s substantial oil and gas reserves before the conflict with Georgia.

Russian gas giant Gazprom earlier this year made an offer to purchase large quantities of Azerbaijani gas.

On a visit to Baku in July, Russian President Dmitry Medvedev said he saw "prospects" for energy cooperation between the two countries and noted "we have no problems in the area of transportation" thanks to an existing pipeline network.

Analysts said Cheney will also be keen to ensure continued Azerbaijani support for the ambitious U.S. and EU-backed Nabucco gas pipeline.

Azerbaijan is seen as the key potential supplier for the project, a 3,300-kilometer (2,050-mile) pipeline that would run via Turkey and the Balkan states to Austria. Construction is scheduled to begin in 2009, with the completion date set for 2013.

Russia backs a rival pipeline, South Stream, being built by Gazprom and ENI of Italy. That project entails building a gas pipeline under the Black Sea from Russia to Bulgaria and then branches to Austria and Italy.

"There are other potential supply sources for Nabucco apart from Azerbaijan; Iran and Egypt have been mentioned," said Tanya Costello of the London-based Eurasia Group political consultancy.

"But there are huge questions on volumes for it and Azerbaijan has been seen as the biggest potential source. Big volumes going elsewhere could disable Nabucco."

RUSSIA

EU Sanctions against Russia as Key Fuel Furnisher in the Pipeline in Question

The European Union has narrowly avoided slapping sanctions on Russia, the country that provides the bloc with about one-third of its oil and 40 per cent of its gas, but the economic repercussions of the Georgia conflict worry Moscow as well as the West.

After a some talk of sanctions, EU leaders made it clear before their Brussels summit that it would be counter-productive, if not impossible, to economically isolate the world's largest gas exporter and second-biggest oil exporter.

But amid EU fears that the dispute over Moscow's intervention in Georgia could prompt a cut in energy supplies, Russia also knows that it needs western partners to sustain its economic boom.

The Kremlin has a tight grip on the provision of fuel to the EU, most of which arrives through Ukraine and Belarus, where recent disputes with Russia quickly translated into reductions in energy supply.

During a disagreement over fuel prices, Russia cut oil deliveries to Belarus for three days in January 2007 along the Druzhba pipeline, with knock-on effects in Germany and Poland.

Russia's state-controlled energy giant Gazprom, which holds one-quarter of the world's gas reserves, has threatened to cut gas supplies to Belarus. Druzhba - named after "friendship" in Russian - is the longest oil pipeline in the world, and passes through both Belarus and Ukraine.

The latter suffered a complete halt in gas flow from Gazprom during another price conflict in January 2006. Supplies to Italy, France, Croatia, Poland, Hungary, Germany and Romania fell sharply, but were restored within days.

Druzhba was built in the 1960s and 1970s, and plumbed Eastern Europe into a network that connected with Siberia's vast oil fields.

Seventeen years after the Soviet Union was consigned to history, new members of the EU and Nato from the Baltic to the Black Sea still rely on fuel from that same pipeline system, despite often-disrupting relations with the Kremlin.

Poland takes 95 percent of its oil and almost half its gas from Russia, and has been warned by Moscow to expect more than just diplomatic protests against its recent deal to host a U.S. missile base.

Russian oil supplies to the Czech Republic have fluctuated since it agreed in July to the construction of a radar base as part of the same U.S. project.

Countries like Slovakia, Finland and Bulgaria depend on Russia for over 90 per cent of their gas, and Germany, the EU's biggest economy, receives more than one-third of its oil and gas from Russia.

The 2006 Ukraine fuel crisis gave energy to EU efforts to wean itself off Russian oil, find new suppliers and build its own pipelines. The Georgia conflict will add more urgency, but many analysts doubt the bloc's ability to end reliance on the Kremlin.

While EU nations have fussed over the planned Nabucco pipeline (which should bring gas from Azerbaijan and Central Asia to Europe through Turkey), Moscow has signed up states - including EU members - to the rival South Stream project, which is well-ahead of Nabucco in preparation.

Furthermore, German and Italian firms have struck major individual deals with Gazprom which critics say undermine EU efforts to forge a united front in energy talks with Russia.

The conflict in Georgia has also cast doubt on the country's suitability as an energy transit alternative to Russia, amid fears for the security of the Baku-Tbilisi-Ceyhan oil link and the Baku-Tbilisi-Erzerum gas pipeline, both of which carry fuel from Azerbaijan across Georgia to Turkey, for onward shipment to western markets.

Some member states are urging the EU to no longer leave it to firms involved in Nabucco to negotiate terms with potential gas suppliers in ex-Soviet Central Asia, but to engage governments directly, as Moscow has always done.

Many industry experts also emphasize the interdependence of the global energy market: the Kremlin relies on sales of fuel to the EU - which accounts for 60 per cent of Russian oil and gas exports - and it has a growing need for western energy expertise.

Russian oil output is flat or falling and it is increasingly costly and difficult for Russian firms to exploit new fields.

Most of the technical know-how and funding for such projects come from European and U.S. specialists and banks, which are now wary of working with Kremlin-controlled companies.

Russia's once-buoyant stock market also plunged when the Georgia crisis erupted, as investors pulled their money away from perceived risk.

Finance minister Alexei Kudrin said €4.7 billion in capital had already been taken out of Russia due to the conflict - a drain not even an energy giant can tolerate for long.

Russia Eyes New Energy Markets Causing Consternaion within the EU

As EU leaders prepared to meet in Brussels September 1 for an extraordinary summit on Russia, the country's former president Vladimir Putin has indicated that Moscow wants to "diversify" oil and gas export markets.

Russia has "no intention" of limiting oil and gas exports to the EU and the country "will abide strictly" by its contractual obligations, former Russian president Vladimir Putin told the Interfax news agency on August 31.

"But we are going to enlarge and diversify our export possibilities for these products which are so essential to the global economy," said Putin, who on the same day reportedly called for the speedier completion of a new pipeline that will carry gas from Siberia to Asian markets.

The comments are fueling speculation that Moscow will increasingly leverage Europe's dependence on Russia's vast oil and gas reserves for geopolitical purposes, particularly if EU leaders decide to impose sanctions on Russia for its actions in Georgia.

Russia is trying to downplay these fears. "We have worked for many years to gain not just the image, but the status of a reliable energy supplier to Europe and we would never let it suffer, even in this political situation," Russian Energy Minister Sergei Shmatko said on August 29.

Despite these assurances, recent cutbacks in supplies to the Czech Republic as well as cuts in deliveries to Ukraine and Belarus, which left several European countries without supply, remain fresh in EU leaders minds, making them nervous about the bloc's dependence on Russian oil and gas.

UK Prime Minister Gordon Brown told the Guardian newspaper on August 31 that "no nation can be allowed to exert an energy stranglehold over Europe". Brown wants to see a greater diversification of fuel suppliers to the EU, which currently depends on Russia for 30% of its oil and 50% of its gas imports, according to the Commission.

In addition to the construction of more oil and gas pipelines that would bypass Russian territory, a feasibility study is underway on the costs of creating large EU gas stockpiles for use in the event of a supply cut from Russia, the UK's Daily Telegraph reported on September 1.

IRAN

Fifteen Countries Eager to Invest in Iran’s Oil and Gas Sector

The vice president for investment affairs at National Iranian Oil Company (NIOC) on September 3 announced that 15 European and Asian countries are eager to invest in Iran’s oil and gas sector.

Talking to Fars News Agency, Hojjatolah Ghanimifard said that Spain, France, Germany, Austria, Italy, Poland, Switzerland, Norway, Turkey, Russia, India, China, Japan, Korea, and Malaysia are the countries that are negotiating with Iran to get involved in its oil and gas projects.

He added that there were no legal limitations for the domestic or foreign investment in midstream or downstream oil sectors.

According to IRINN, the official went on saying that the countries which have proper financial resources, equipment, and technology for the midstream and downstream projects have priority for investment.

Several long negotiations have been held with countries which have first class international oil companies, Ghanimifard pointed out.

South Pars Phase 9 to Start Production in Three Months

Phase 9 of the South Pars gas field is projected to come on stream in the Iranian month of Azar (Nov. 21-Dec. 20), National Iranian Oil Engineering and Construction Company (NIOEC) managing director said in Tehran on September 3.

“At present, natural gas refineries in phases 9 & 10 are in operation using the sweet gas injected from the national gas network,” Roknoddin Javadi explained, noting that the Phase 9 refinery will be ready to use sour gas from mid-October, the Mehr News Agency reported.

He also stated that South Pars phases 9 & 10 are 91 percent complete.

IRAQ

CNPC to Develop Ahdab Oil Field in Iraq

The Iraqi Ministry of Oil, renegotiating an agreement first signed more than a decade ago, has approved arrangements that will allow state-owned China National Petroleum Co. to develop Ahdab oil field.

The agreement, which restores a project that was cancelled after the 2003 US-led invasion of Iraq, was signed by Chinese officials and Iraqi Oil Minister Hussain al-Shahristani.

Under the contract, which still requires approval of the Iraqi and Chinese governments, CNPC will provide technical advisers, oil workers, and equipment to increase production at the field, which is in Wasit province, about 160 km southeast of Baghdad.

Shahristani said the two sides agreed to renegotiated terms of a deal signed in 1997. He said the contract has been changed to a set-fee service deal from the oil production-sharing agreement signed earlier.

CNPC will help Ahdab produce 110,000 b/d, up from the originally agreed 90,000 b/d, with first output expected in 3 years. According to Shahristani, the field should have an active life of some 20 years.

CNPC will own 75% of the joint venture, with Iraq's state-owned Northern Oil Co. owning the remaining 25%. Shahristani said the contract, currently valued at some $3 billion, would be reviewed every quarter over its 22-year term.

Analysts saw the agreement as a breakthrough for China and CNPC over other countries and international oil companies.

Liu Youcheng, a Beijing-based analyst with Hongyuan Securities, noting that it has become more and more difficult to obtain equity and exploit rights in oil fields, said it is good for China to participate in the development through a service contract.

Alex Munton, an analyst with consultant Wood Mackenzie, said the biggest significance of the agreement is that CNPC will benefit as the first international oil company to be developing one of the giant discovered oil fields in Iraq in the new era.

According to Munton, CNPC will be the first with people on the ground and the first to develop a working relationship with Iraq's Oil Ministry.

Iraqi oil ministry officials earlier expressed hopes of signing contracts with international oil companies by the end of June. Now, according to ministry spokespersons, those talks with such firms as Royal Dutch Shell PLC, BP PLC, and Exxon Mobil Corp. are unlikely to proceed.

Previously, a top Iraqi official criticized international oil companies for trying to overcharge the war-torn nation and for ignoring what he referred to as their "humanitarian" duty to help develop Iraq's battered oil industry.

The charge came after Iraq delayed the signing of short-term oil service contracts with oil majors due to disagreements over payment terms and their duration.

"The invitations to take part in these projects have not only an economic but a humanitarian character," said Iraq's electricity minister Karim Waheed after meetings with Russian energy minister Sergei Shmatko and the heads of Russian energy service firms.

"Some companies in those cases demanded sky-high prices for their services, thinking Iraq does not have a grasp of international financial markets. They were unpleasantly surprised when they found out we fully understand global commodity markets and global stock markets," Waheed said.

Iraq Expects to Gross $55 Billion in China Oil Deal

Iraq expects to gross $55 billion in a new 20-year oil deal it recently renegotiated with China, the government said on September 3.

"Iraqi gross revenues obtained in the contract will be $55 billion, equal to 87 percent of total revenues of $63 billion," government spokesman Ali al-Dabbagh said in a statement.

The estimate of Iraq's take in the $3 billion service contract for the Ahdab oil and gas field south of Baghdad is based on projected oil prices of $100 a barrel.

The Iraqi government recently renegotiated the terms of the deal with the Chinese National Petroleum Company (CNPC), which was originally signed in 1997, marking Iraq's first major oil deal with a foreign firm since the fall of Saddam Hussein.

The government of Iraqi Prime Minister Nuri al-Maliki formally approved the renegotiated contract and said it now hopes Chinese officials will sign the renegotiated contract in Baghdad later this month.

Dabbagh said the deal, which is also to include gas extraction and processing, would have an investment value of $3 billion and an operating cost of $4 per barrel.

"The contract aims to produce from the beginning of the fourth year ... an average of 25,000 barrels per day (bpd)," Dabbagh said, detailing decisions from a recent cabinet meeting.

From the seventh year, the contract aims to produce an average of 115,000 barrels per day, he said.

Part of the deal, as Iraq struggles to boost electricity supplies that consistently fall far short of demand, is an agreement to pipe energy to the al-Zubaidiya power station in Wasit province, where the Ahdab field is located.

The deal with CNPC, the parent company of PetroChina and Asia's biggest oil and gas company, comes as world oil majors are angling for long-term deals with Iraq, which has the world's third-largest proven oil reserves.

Yet negotiating with Iraq may not be easy. In renegotiating the Ahdab deal, Iraq secured more favorable terms, changing the contract from a production sharing agreement to a set-fee service deal.

Dabbagh said the new terms would, if oil prices stay around $100 per barrel, give Iraq at least an additional $2.5 billion over the life of the deal compared to the previous terms.

ISRAEL

New Amiad AMF Self-Cleaning Microfiber Filter Ideal for Oil and Gas Production

Amiad Filtration Systems has introduced its new AMF Automatic Microfiber filtration system, a revolutionary automatic self-cleaning system that delivers filtration in the 2-to-20-micron range without consumable media — eliminating filter aids, cartridges and bag filters as well as the associated labor and disposal costs.

Fine microfibers wound around grooved plastic spools capture suspended and colloidal foulants, including both organic and inorganic particles.

The Amiad AMF is designed to perform well in oil and gas production for filtering produced water, as well as service water from either fresh or seawater sources. Cleaner produced water and service water can significantly extend the life of injection wells and equipment.

The Amiad AMF can also be used as part of a multi-stage filtration system for treating supply water or wastewater, protecting expensive membranes and dramatically reducing the need for time- and chemical-intensive membrane cleaning. In fact, installing an Amiad AMF upstream of an RO membrane can reduce membrane cleaning by a factor of four, according to Amiad vice president of sales and marketing Jim Lauria.

Extremely compact, the Amiad AMF's minimal size and weight footprint delivers fine filtration with automatic self-cleaning, minimal maintenance, and no cartridges to replace. Back-wash is far more water- and energy-efficient than with other filtration technologies, and is conducted without breaking the integrity of the filtration.

"The AMF system is a perfect extension of our Clean Water/Clean Technology philosophy," says Lauria. "It helps reduce chemical use, minimize back-flush, reduce footprint and lower energy costs. Those attributes show up on the environmental and economic bottom lines."

Zion Oil & Gas and Aladdin Middle East to Sign Drilling Contract in September 2008

Zion Oil & Gas, Inc of Dallas, Texas and Caesarea, Israel have announced that it and Aladdin Middle East ("AME") intend to enter into a drilling contract by September 12, 2008. The Chief Executive Officer, Richard Rinberg, and the President and Chief Operating Officer of Zion, Glen Perry, are scheduled to visit AME's offices in Ankara, Turkey, in order to sign a drilling contract with AME. It is now anticipated that the 2,000 horsepower rig, to be used to drill Zion's planned Ma'anit-Rehoboth #2 well, will arrive in Israel in November 2008.

Zion Oil & Gas, a Delaware corporation, explores for oil and gas in Israel in areas located onshore between Tel-Aviv and Haifa. It currently holds two petroleum exploration licenses, the Joseph and Asher-Menashe Licenses, between Netanya on the south and Haifa on the north covering a total of approximately 162,000 acres.

AME is an independent oil and gas exploration and production company, incorporated in Delaware in 1962, with its head office in Wichita, Kansas. AME has drilled more than 130 exploration and development wells in Turkey and Egypt for major oil companies, including Exxon, Mobil, Wintershall AG, MOL, Placid Oil, Neste Oy, Burren Energy Inc. and Edison International spa. Its rig inventory includes 11 drilling and workover rigs.

McIlvaine Company,

Northfield, IL 60093-2743

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

E-mail: editor@mcilvainecompany.com;

Web site: www.mcilvainecompany.com

Det Norske Veritas, Partners Developing CO2 Pipeline Standard

Det Norske Veritas, Partners Developing CO₂ Pipeline Standard