Global primary demand for oil will rise by one percent per year on average, from 85 million b/d in 2007 to 106 million b/d in 2030, 10 million b/d less than projected last year, while its share of world energy use drops from 34 percent to 30 percent, according to the International Energy Agency's (IEA's) World Energy Outlook 2008, which was released November 12.

Despite the slowdown in oil demand, oil will remain the world's main source of energy for many years to come, even under the most optimistic of assumptions about the development of alternative technology. But the sources of oil, the cost of producing it and the prices that consumers will have to pay for it are extremely uncertain.

"One thing is certain," said Nobuo Tanaka, executive director of the IEA in London. "while market imbalances will feed volatility, the era of cheap oil is over.

"A sea change is underway in the upstream oil and gas industry with international oil companies facing dwindling opportunities to increase their reserve and production. In contrast, national companies are projected to account for about 80 percent of the increase of both oil and gas production in 2030," said Tanaka.

The downward revision is due to the impact of much higher prices and slightly slower gross domestic product growth, as well as new government policies introduced in the last year. All of the projected increase in world oil demand comes from non-Organization for Economic Cooperation and Development (OECD) countries, with over four-fifths from China, India and the Middle East.

Assuming no new government policies, IEA reports that world primary energy demand will grow by 1.6 percent/year on average between 2006 and 2030 from 11,730 million tonne of oil equivalent to 17,010 million tonne of oil equivalent, an increase of 45 percent. This growth is slower than estimated last year, mainly due to the impact of the global economic slowdown, prospects for higher energy prices and some new policy initiatives.

Global demand for natural gas will grow more quickly than oil, by 1.8 percent per year, its share in total energy demand rising marginally to 22 percent. Most of the growth in gas use comes from the power-generation sector. Demand for coal rises more than any other fuel in absolute terms, accounting for over a third of the increase in energy use.

Modern renewables will grow mostly rapidly, overtaking natural gas to become the second-largest source of electricity soon after 2010. Falling costs as renewable technologies mature, assumed higher fossil-fuel prices and strong policy support provide an opportunity for the renewable industry to eliminate its reliance on subsidies and to bring emerging technologies into the mainstream.

Excluding biomass, non-hydro renewable energy sources, wind, solar, geothermal, tide and wave energy, together grow faster than any other source worldwide, at an average rate of 7.2 percent per year over the projection period. Most of the increase occurs in the power sector.

China and India account for over half of incremental energy demand to 2030 while the Middle East emerges as a major new demand center, contributing a further 11 percent to incremental world demand. The share of the world's energy consumed in cities grows from two-thirds to almost three quarters in 2030. Almost all of the increase in fossil-energy production occurs in non-OECD countries.

These trends call for energy-supply investment of €26.3 trillion (US$32.9 trillion) to 2030, or over €1 trillion/year (US$1.3 trillion/year). Yet the credit squeeze could delay spending, potentially setting up a supply-crunch that could choke economic recovery.

"Current trends in energy supply and consumption are patently unsustainable, environmentally, economically and socially, they can and must be altered," said Tanaka. "Rising imports of oil and gas into OECD regions and developing Asia, together with the growing concentration of production in a small number of countries, would increase our susceptibility to supply disruptions and sharp price hikes. At the same time, greenhouse-emissions would be driven up inexorably, putting the world on track for an eventual global temperatures increase of up to 6 degrees Celsius."

IEA noted that it is far from certain that these companies will be willing to make this investment themselves or to attract sufficient capital to keep up the necessary pace of investment. Upstream investment has been rising rapidly in the past few years, but much of the increase is due to surging costs. Expanding production in the lowest-cost countries, most of them in the Organization of Petroleum Exporting countries, will be central to meeting the world's oil needs at reasonable cost.

The prospect of accelerating declines in production at individual oilfields is adding to these uncertainties. The findings of an unprecedented field-by-field analysis of the historical production trends of 800 oilfields indicate that decline rates are likely to rise significantly in the long term, from an average of 6.7 percent today to 8.6 percent in 2030.

"Despite all the attention that is given to demand growth, decline rates are actually a far more important determinant of investment needs. Even if oil demand was to remain flat to 2030, 45 million b/d of gross capacity, roughly four times the current capacity of Saudi Arabia, would need to be built by 2030 just to offset the effect of oilfield decline," said Tanaka.

Rising global consumption of fossil fuels is still set to drive up greenhouse-gas emissions and global temperatures, resulting in potentially catastrophic and irreversible climate change. IEA projects that, with no change in government policies assumed, the world is on a course of doubling the concentraiton of these gases in the atmosphere to around 1,000 parts per million of carbon dioxide (CO₂) equivalent by the end of this century. Without a change in policy, the world is on a path for a rise in global temperature of up to 6 degrees Celsius (42.8 degrees Fahrenheit), IEA noted.

On current trends, energy-related CO2 emissions are set to increase by 45 percent between 2006 and 2030, from 28 gigatonnes to 41 gigatonnes. Three-quarters of the increase arises in China, India and the Middle East and 97 percent in non-OECD countries as a whole.

"We cannot let the financial and economic crisis delay the policy action that is urgently needed to ensure secure energy supplies to curtain rising emissions of greenhouse gases. We must usher in a global energy revolution by improving energy efficiency and increasing the deployment of low-carbon energy," said Tanaka.

IEA said that strong, urgent action is needed to curb the growth in greenhouse-gas emissions. The post-2012 global climate change policy regime that is expected to be established at the United Nations conference on climate change in Copenhagen, Denmark in November 2009 will provide the international framework for that action.

"With energy-related CO₂ accounting for 61 percent of global greenhouse-gas emissions today, the energy sector will have to be at the heart of discussions on what level of concentration to aim for and how to achieve it. The target that is set for the long-term stabilization of greenhouse-gas concentration will determine the pace of the required transformation of the global energy system, as well as how stringent the policy responses will need to be," IEA said.

Stabilizing greenhouse gas concentration at 550 particles per minute of CO₂ equivalent, which would limit the temperature increase to about three degrees Celsius (37.4 degrees Fahrenheit), would require emissions to rise to no more than 33 gross tons in 2030 and to fall in the longer term. The share of low-carbon energy, including hydropower, nuclear, biomass, other renewables and fossil-fuel power plants equipped with carbon capture and storage, in the world primary energy mix would need to expand from 19 percent in 2006 to 26 percent in 2030.

"We would need concerted action from all major emitters. Our analysis shows that OECD countries alone cannot put the world onto a 450-ppm [parts per million] trajectory, even if they were to reduce their emissions to zero," said Tanaka.

Achieving such an outcome would require even faster growth in the use of low-carbon energy, to account for 36 percent of global primary energy mix by 2030.

AMERICAS

U.S.

Pipeline Operator Kinder Morgan Eyes Growth during Economic Downturn

As companies scramble to cut expenses amid the economic turmoil, pipeline operator Kinder Morgan Energy Partners (KMP) is bucking the trend, forging ahead with $8 billion of major projects and reporting a 54% increase in third-quarter earnings.

Kinder Morgan, one of the largest pipeline companies in North America, operates 14,700 miles of natural gas pipelines and owns 153 terminals for coal, petroleum coke and other products. The Houston company also transports gasoline, diesel, jet fuel and carbon dioxide.

In a climate of financial uncertainty, Kinder Morgan's steady cash flows, diversified assets and strong growth prospects could make the company a compelling defensive buy for nervous investors. Other strong points: Its earnings are relatively predictable because shippers pay predetermined fees, and it pays out cash distributions similar to dividends every quarter. Possible downsides include a drop in revenue if a slumping economy reduces energy demand, and difficulty in arranging financing for projects should the credit crisis worsen.

Although shares of pipeline operators were hammered during the broad market downturn earlier in October, Kinder Morgan has staged an impressive comeback, recently trading around $53, up nearly 50% from their 52-week low on Oct. 10. That was before the company posted third-quarter net income of $329.8 million, up 54% from a year ago.

Other than the short-lived drop in early October, the share price has been relatively stable over five years. Despite the market's free fall this year, the company's share price is up 2.3% over the last 12 months. It has a forward one-year PE ratio of 22.1, compared with 11.3 for the industry, according to FactSet.

"The capital markets have been very tumultuous, but I think we've traded a lot better than some other companies on a relative basis," company President C. Park Shaper said.

"Kinder Morgan has a very large, well-diversified asset portfolio, not just geographically but also operationally," said Mark Reichman, an analyst with SMH Capital in Houston.

Kinder Morgan's roster of pipeline projects, are likely to bolster the company's earnings in coming quarters, analysts said. Kinder Morgan is planning to expand its Rockies Express pipeline, which has been a significant earnings driver, farther east to Ohio by mid-2009. The $6 billion pipeline brings gas from the Rocky Mountain region to more populous areas in the Midwest.

"What we've liked about [Kinder Morgan] is that they have a visible growth outlook because they've announced a lot of projects under development," Reichman said.

The company's other projects include joint ventures with Energy Transfer Partners (ETP) to build two major pipelines: the $1.27 billion, 507-mile Midcontinent Express Pipeline, which will stretch from Oklahoma to Alabama, and the $1.3 billion, 187-mile Fayetteville Express Pipeline, which will carry gas from Arkansas to Mississippi.

Kinder Morgan's business model has enabled the company to generate stable returns for investors. Kinder Morgan is a master limited partnership, or MLP, a type of tax-efficient investment vehicle that receives 90% or more of its income from interest, dividends, property sales, commodities or mineral and natural resources activities.

Kinder Morgan's earnings are relatively stable because shippers pay predetermined fees, usually under long-term contracts, to transport natural gas and other products through the company's pipelines. Changes in commodity prices don't affect those fees.

That's not to say that Kinder Morgan won't be forced to cut distributions if a weakening economy reduces energy demand, particularly among industrial natural-gas consumers. And the ongoing credit crisis could limit the company's access to the capital markets to fund projects. But overall, Kinder Morgan's balance sheet is strong and the company's growth outlook remains bright, analysts said.

The company's president said Kinder Morgan's exposure to the varying values of commodities is limited because the company generally transports energy products without taking ownership of them.

"We're just moving somebody else's product from Point A to Point B or storing it for them, and we get paid a fee for doing that," he said. "Typically the fees are not dependent on volumes. It's like charging a fee for renting the capacity in our pipelines and storage tanks, whether all the capacity is actually used or not."

Others aren't worried. "When the markets open up, Kinder Morgan and the other investment-grade names will be the first ones to be able to fund their capital requirements," said Mark Easterbrook, an analyst with RBC Capital Markets in Dallas.

Kinder Morgan investors have also benefited from the wide variety of pipeline and storage businesses the company owns. The diversity of the company's asset base mitigates the risk that downturn in a single sector or commodity will deal a severe blow to the company's earnings.

"Our business model translates into very stable cash flows," Shaper said. "That doesn't mean we're immune to economic conditions. I don't think anybody is."

For example, Kinder Morgan's products pipelines business, which includes movement of gasoline, diesel and jet fuel, saw third-quarter earnings of $140.6 million, down 9% from $155.2 million last year. The business was hurt by the sale of a portion of the pipeline system, lower products demand and lost business from Hurricanes Ike and Gustav.

But the losses were offset by gains in Kinder Morgan's natural gas pipelines business, which saw earnings soar $177.2 million, or 25%, from $142 million in the third quarter of 2007. Revenue from the natural gas business was bolstered by the new Rockies Express pipeline moving gas out of the mountain region.

Petroleum Elastomers Joins Simrit Oil and Gas

Simrit Oil & Gas, LLC (Simrit), a wholly-owned subsidiary of Freudenberg-NOK General Partnership (Freudenberg-NOK), announced the acquisition of the assets of Petroleum Elastomers of Houston, a manufacturer of specialized custom sealing components for the oil and gas industry. Terms of the agreement were not disclosed.

Petroleum Elastomers molds a wide range of elastomeric products but is widely known for its blow out preventer (BOP) ram packers and spherical packing elements. The company is particularly well regarded in the oil patch for its BOP products operating in extreme conditions, such as snubbing and H2S service, and offers replacement seals for most popular BOPs. Other products include strippers, bonnet seals, top seals and seal kits for the oil and gas industry.

"The addition of Petroleum Elastomers to Simrit and the Freudenberg-NOK family of companies exemplifies our commitment to grow in the oil and gas industry," said Brian Jones, vice president -- Oil and Gas of Freudenberg-NOK's Simrit Division. "The company's products greatly expand our coverage in the oilwell pressure control segment and its workforce brings years of experience to the Oil and Gas team. Likewise, current Petroleum Elastomers customers will now have access to the full array of products we produce in our U.S., Canada, Norway and Scotland locations."

All key personnel will remain with Petroleum Elastomers, including Mike Ward, who becomes technology manager and Mike Viator, who will become lead center manager.

"We look forward to the growth opportunities that result from being associated with a global organization," said Ward. "The product synergies, coupled with the capabilities of Simrit's 55,000 sq. ft. technology center in Plymouth, Mich., open many areas of the market we have not yet explored."

Simrit is based at Freudenberg-NOK's headquarters in Plymouth, Mich. Freudenberg-NOK is part of the Freudenberg and NOK Group Companies, which have total annual sales of more than $12 billion. The Simrit Division offers an extensive portfolio of precision-manufactured products for the semiconductor, aerospace, appliance, diesel engine, marine, off-highway equipment, oil and gas, and recreational vehicle markets.

Companies Balk at Advancing Ethanol Pipeline System

Pipeline companies are balking at building a new system to transport ethanol, just as technological hurdles begin to diminish.

Corn-derived ethanol is currently carried by a "virtual pipeline" of trucks and railcars from producers in the Midwest to markets around the country, where it is blended with gasoline. Federal law requires renewable fuel production to quadruple by 2022, which threatens to overwhelm the virtual pipeline. Real pipelines would be more efficient along many routes, but technological and financial barriers have so far slowed development.

Both technological and financial hurdles became significantly less of a problem this month, however. Kinder Morgan Energy Partners LP (KMP) successfully sent a test batch of ethanol from Tampa to Orlando 105 miles along the Central Florida fuel pipeline in mid-October, and plans to begin regular service later this month. The financial bailout bill at the end of September also included a tax break considered crucial to entice pipeline companies to commit to developing ethanol pipelines.

Yet for all the recent progress, investors remain unwilling to commit to major ethanol pipeline projects until they see evidence of a stable, steady market. Federal mandates can change; pipeline companies note, and so far none has been willing to bet that the market in 2022 will resemble what government forecasters predict today. The ethanol industry's current woes do little to inspire confidence: Verasun Energy Corp. (VSE), the country's largest publicly traded ethanol producer, filed for bankruptcy protection on Friday.

"We like building pipelines...but we won't build pipelines for the sake of doing it," said Jim Lelio, director of business development at the Houston-based Kinder Morgan. "There's not a compelling reason for us to be building large-scale ethanol pipelines right now."

While ethanol is easily contaminated and can corrode steel, gasoline containing up to 20% ethanol has recently been found safe to transport in conventional pipelines, said Eric Thomas, chief operating officer at the Pipeline Research Council International, which is studying the corrosion issue for the pipeline industry and U.S. government.

Kinder Morgan transported pure ethanol along its Tampa-Orlando gasoline pipeline by mixing in an anticorrosion agent, Lelio said. The company is evaluating whether to upgrade other pipelines for ethanol use, and has no plans to build new pipelines, he said.

New pipelines would almost certainly be needed if ethanol use comes anywhere near government and industry forecasts, analysts and pipeline companies say. Most ethanol is produced in the Midwest, but the bulk of fuel pipelines connect oil refineries to the biggest gasoline and diesel markets, with the largest linking Gulf Coast refineries to East Coast cities, or snaking up and down the West Coast.

Iowa and Nebraska are the top two ethanol-producing states, and most consumers are in Midwestern cities. The relatively short distance from plant to market is easily covered by trucks, and ethanol transportation makes up only 1% of rail traffic.

The federal renewable fuel standard set in 2005 created a timetable for nationwide adoption of ethanol-gasoline blends. U.S. ethanol use is required to grow to 36 billion gallons by 2022, or four times the amount expected to be consumed this year. It's not clear whether railroads can easily handle that increase, or if long-distance trucking on such a large scale will prove too costly.

"Ethanol is produced in the Midwest and is mostly consumed in the Midwest, but for mandates to be met, (producers) are going to have to have new markets," said Divya Reddy, an energy analyst with Eurasia Group, a consultancy. "We will need different routes for ethanol, and that will require constructing new pipelines entirely."

Pipeline companies expect ethanol consumption to increase, but can't say for certain how much, or where. The mandates are no guide - Texas asked for a 50% waiver from the renewable fuel standard when food and fuel prices spiked earlier this year. The Environmental Protection Agency denied the request, but the battle highlighted the fragility of recent increases in ethanol demand.

The federal mandate doesn't require ethanol to come from the Midwest. Brazil produces ethanol from sugar, at a lower cost than corn-based producers, and could easily export to the U.S. were it not for a tariff. That tariff's withdrawal would redraw the map for necessary pipelines.

"Ethanol is different from other petroleum products from that standpoint that it has public policy initiatives in place promoting its use," said Bruce Heine, spokesman for Magellan Midstream Partners LP (MMP).

Magellan, along with Buckeye Partners LP (BPL) announced preliminary plans to build a $3.5 billion, 1,700-mile ethanol pipeline from Iowa to New York Harbor. But the green light likely won't come without a federal loan guarantee, where the government would take on some of the financial risk, Heine said.

The $700 billion financial rescue package included a second provision pushed for by pipeline companies, with language allowing most to collect tax-free income from ethanol transportation.

Even if a loan guarantee is granted soon, the earliest an ethanol pipeline would enter service is 2014, Heine said.

By then, U.S. biofuel consumption is expected to hit 18 billion gallons under the renewable fuel standard, double 2008 demand.

Parker Hannifin Acquires Manufacturer of Water Filtration and RO Equipment

Parker Hannifin Corporation, the global leader in motion and control technology, announced November 3 that it has acquired Aqua Pro, Inc. a manufacturer of reverse osmosis ("RO") filtration systems for military, commercial and pleasure marine applications. Aqua Pro sales for fiscal 2008 were $33.0 million. The acquisition is expected to be accretive to earnings within its first year following acquisition and its results will be reported as a component of Parker's Industrial North America segment. Terms of the acquisition were not disclosed.

With manufacturing centers in Gardena and San Fernando, California, Aqua Pro does business as Village Marine Tec and Offshore Marine Laboratories. Sales and service locations are located in California, Florida, Hawaii, Virginia, and Washington. The company sells to Original Equipment Manufacturers including boat and ship builders, independent distributors, U.S. military branches and end users. Aqua Pro's product line includes RO systems for military on-board submarines, and land applications as well as offshore oil rigs, work boats, fishing vessels, and pleasure boats.

"Aqua Pro is recognized as the leader in on-board marine reverse osmosis products and their innovative, engineered systems are currently in use on the most advanced Navy ships and premier motor yachts," said Peter Popoff, President of the Parker Filtration Group. "Expansion of the current business as well as additional applications in aerospace, biosciences, and industrial filtration will complement Parker's existing products in growth markets. The water filtration and purification systems enable Parker to respond to one of the greatest challenges facing mankind, available potable water. The Aqua Pro product line will contribute to the sales growth of Parker Filtration's global operations including our Racor Division and their widely-accepted marine filtration systems."

DeepBlue Technologies Opens Subsea Operations Base

DeepBlue Technologies, a proven provider of customized subsea safety systems, has opened a new subsea operations base in Broussard, Louisiana. The 6,000 square foot facility features a 10-ton overhead crane, a tool string assembly system, a 15-foot wet assembly area and a biological water treatment and recirculation system. Testing capabilities include 25,000 psi hydro testing, a fixed pressure test bay and mobile pressure screening. An additional 3,800 square feet of office space and a closed storage area complete the property.

DeepBlue Technologies specializes in the design and supply of customized subsea safety systems. A suite of 15,000 psi working pressure subsea equipment allows customers to safely deploy or work over their completions in particularly harsh environments. DeepBlue is currently expanding through the manufacture of new equipment inventory.

Bobcat Gas' Salt Cavern Begins Natural Gas Storage in Louisiana

Bobcat Gas Storage, its owners Haddington Energy Partners III LP and GE Energy Financial Services, announced they have introduced one of the newest natural gas storage facilities in the United States.

The first cavern, which has completed its first week of successful commercial operations, is fully subscribed with customers. A second cavern is expected to be completed in the third quarter of 2009. After nearly three years of planning, permitting, construction and receipt of final permits from the state and federal agencies for the project 1.5 miles southeast of Port Barre in south-central Louisiana, Bobcat Gas Storage began providing storage services to its customers on Nov. 1. Bobcat’s initial capacity is nearly 5.4 billion cubic feet of working gas (bcfw), which is planned to be increased to 10.3 bcfw by the third quarter of 2009 with the in-service of cavern 2, which is currently under construction, and fully built-out to 15.6 bcfw by year end 2009. The Bobcat site contains adequate space for Bobcat to expand on its success with additional natural gas storage caverns.

“We overcame escalating construction and material costs, a direct hit by hurricane Gustav and extreme weather with Hurricane Ike to complete this state-of-the-art cavern to meet our contractual commitments. In this environment, this is a huge win for Bobcat,” said Tom Dill, CEO of Bobcat.

Underground natural gas storage is a critical component of the US natural gas infrastructure that balances weather-driven, highly seasonal demand and fluctuations in supply. Among underground gas storage facilities, salt caverns provide the greatest operational flexibility, supporting the widest range of storage. The Bobcat project benefits from its strategic location in the natural gas infrastructure grid and strong growth forecasts for US gas demand.

The Bobcat facility is located in St. Landry Parish, Louisiana, 45 miles from Henry Hub, the clearing point for NYMEX natural gas futures contracts and the most liquid trading point in the natural gas over-the-counter and cash markets. The project provides access to natural gas from offshore in the Gulf of Mexico, onshore in Texas and Louisiana, as well as from the Barnett Shale. Bobcat interconnects with five major interstate pipelines -- Florida Gas Transmission Company, Texas Eastern Transmission Corp., Transcontinental Gas Pipeline Corp, ANR Pipeline Company and Gulf South Pipeline Company. It provides gas to five key US natural gas consuming markets: the Northeast, Midwest, Mid-Atlantic, Southeast and Florida.

Each cavern is fully surrounded by salt and is approximately as deep as four football fields, beginning at approximately 4,500 feet beneath the surface and extending to a depth of close to 6,000 feet.

Woodside Energy USA Selects Paradigm Software for U.S. Operations

ParadigmTM announced that Woodside Energy (USA) Inc. has selected Paradigm's next-generation geology and geophysics (G&G) solutions for developing leases in the Gulf of Mexico. The announcement was made at the 78th Annual Meeting of the Society of Exploration Geophysicists (SEG) in Las Vegas.

Woodside selected Paradigm's technology for interpretation and velocity modeling. Paradigm possesses advanced workflows in processing, interpretation and analysis of very large geographic regions where complex salt structures exist. Paradigm will provide Woodside with industry solutions for workflows spanning seismic processing, velocity analysis, stratigraphic delineation, structural interpretation, formation evaluation, and reservoir modeling.

Aker Solutions Signs $23 Million in Contracts for Murphy's Subsea Inventory Program

Aker Solutions has signed contracts with Murphy Exploration & Production Company - USA to provide subsea trees, control systems and steel tube umbilicals to the company's Gulf of Mexico (GOM) program. The initial order is worth approximately US$23 million.

These initial orders - which will launch Murphy's inventory stocking program for its upcoming eastern GOM development schedule - includes two wellsets and an umbilical. Delivery of all components is scheduled for Q2 2009.

"Murphy has an ambitious strategy for subsea developments in the Gulf of Mexico. We are very pleased to be chosen as partner for their forthcoming subsea projects in this part of the world," says Erik Wiik, president of Aker Solutions' subsea business area in the U.S.

Engineering design and project management will be provided from Aker Solutions' office in Houston, Texas, with manufacturing of most components at Aker Solutions' hi-tech subsea manufacturing centre in Kuala Lumpur, Malaysia. Umbilicals will be manufactured at Aker Solutions' facility in Mobile, Alabama. Offshore installation support will be provided from Aker Solutions' service base in Houston.

"We have successfully delivered several projects to Murphy in the U.S. and Malaysia. This award is an acknowledgement of our project teams' efforts and a recognition of our global capability within subsea production systems," adds Wiik.

The contract party is Aker Solutions Inc.

SulphCo Inks Extension on Upgrading Tech with Industrial Sonomechanics

SulphCo, Inc. has exercised its option to extend the term of the license agreement dated Nov. 9, 2007 with Industrial Sonomechanics, LLC covering ISM's patented ultrasound horn and reactor technology. The term has been extended to the date on which the ISM patents expire. Under the terms of the License Agreement, ISM granted SulphCo exclusive worldwide rights to use its patented ultrasound horn and reactor technology for ultrasound upgrading of crude oil and crude oil fractions. Pursuant to the terms of the License Agreement, SulphCo will issue 50,000 restricted shares of the Company's common stock. All other terms of the License Agreement remain unchanged.

"We are pleased to continue our relationship with ISM as an important member of the SulphCo team and, by the exercise of this option, we will continue to maintain access to their cutting edge probe and reactor chamber technology," said Dr. Larry D. Ryan, CEO of SulphCo.

ISM is a U.S.-based company formed in 2006 to commercialize its patented high-power ultrasonics technology, which was developed by its founders during several decades of research in Russia. ISM specializes in very high capacity industrial ultrasonic reactor systems, which incorporate powerful ultrasonic horns capable of simultaneously providing high output vibration amplitudes and large output diameters.

History of the $100 Million GE-Wyoming Coal-Gasification Project

The history behind the new $100-million GE-Wyoming coal gasification project goes back to the early 1980s when a then-California-based energy company, Tosco, was trying to extract fuel from massive oil shale deposits outside Grand Junction, Colorado.

The challenge at the time, former Tosco CEO Morton Winston recalled in an interview was to build a device that could introduce precisely measured amounts of crushed oil shale into a mildly pressurized chamber. Winston turned to a brilliant British mechanical engineer named Donald Firth for help.

What Firth came up with looks like a pipe with a big bulge. Inside the bulge is a rotating spool similar to that used to wind up cable

The Colorado oil shale effort failed. But Winston and Firth quickly saw the potential of their new device, now called the Stamet Pump, for moving coal.

In re-engineered form, the Stamet Pump has become the controversial centerpiece of what many feel could be a major advance in coal gasification technology. Most energy experts consider coal gasification a critical step in capturing CO2 emissions in the fight against global warming.

For Wyoming, the pump figures prominently in University of Wyoming’s recent 50-50 partnership with one company, General Electric, among a half-dozen major energy companies competing to gasify Wyoming’s high-moisture Powder River Basin Coal.

How much the state will gain from the exclusive arrangement with GE is not clear since much of the Oct. 14 agreement between GE and UW is blacked-out to protect what GE deems commercial and trade secrets.

But if the project develops a more efficient and economical process for gasification of Powder River Basin coal, it could be a significant boost for Wyoming’s considerable coal interests.

In gasification, coal, along with oxygen and steam, are injected into a high temperature, high pressure reactor until the chemical bonds of the coal break down. The resulting “syngas” - primarily methane - can be refined and burned as fuel. Even the steam used to produce syngas can be used to drive electric turbines.

From a global warming perspective, the “pre-combustion” gasification process makes it much easier to remove CO2 and other greenhouse gases from coal than in traditional “post-combustion” pulverized coal power plants that currently dominate the electric power industry.

Central to GE’s ambitions for Powder River Basin coal is the Stamet Pump. The controversy is that officials with the U.S. Department of Energy feel strongly that the Stamet technology should belong to the public and not be “sequestered” by GE into the expensive new gasification system it is developing.

Beginning in 1997, the DOE devoted ten years and nearly $3 million in public funds adapting the Stamet Pump for coal gasification.

In May 2007, Carl Bauer, the DOE director of the National Energy Technology Laboratory, testified before Congress that successful tests on the Stamet pump at the DOE Power Systems Development Facility in Wilsonville, Alabama, marked a potential breakthrough in coal gasification technology, particularly on high-moisture, sub-bituminous coals like those mined in Wyoming’s Powder River Basin.

“It allows coal to be ‘pumped’ directly into a high pressure gasifier,” Bauer told the House Science and Technology Subcommittee on Energy and Environment, “thus avoiding the need for coal drying and a complex lock-hopper feeding system or, alternatively, a slurry feeding system that is inefficient when used to feed high-moisture western coals.”

Since 40 percent of electricity in this country is generated with these high-moisture coals, mostly from Wyoming, the tests represented a major advance in the industry. The presumption was that the pump’s developer, Stamet Inc. of Gardena, CA, would license the device and sell it for use in gasification systems. Thus, the whole world could benefit from the DOE-funded research.

But less than a month after Bauer’s report, General Electric bought Stamet Inc. for an undisclosed price. Over the strident objections of DOE officials who felt the federally funded Stamet research should be in the public domain, GE took the technology private.

GE officials say the Stamet Pump will be incorporated into a new Integrated Gasification Combined Cycle (IGCC) electric power generation system it is developing. So instead of selling the pumps separately, GE could ask customers to buy the whole IGCC system with a price-tag well over $2 billion.

After the Stamet sale, at least two meetings took place between GE representatives and DOE officials. A participant in one of the meetings said there were heated exchanges between the two sides.

“Public tax dollars were used,” said Gary Stiegel, National Energy Technology Laboratory gasification manager."We felt that the public should reap the benefits of that technology. We urged GE to make it available to any and all gasification projects in the country.”

However, existing federal laws limit public ownership of technology developed with DOE-funded research to matters of national security. As a result, Stiegel said the DOE could do little more than exert “moral pressure” on the company to release the technology. GE refused.

A few months later GE took the additional step of withdrawing support for a scientific report on the pump that was scheduled to be presented at the European Gasification Conference in Antwerp Sept. 10-12, 2007.

On Oct. 14, 2008, Wyoming Gov. Dave Freudenthal, University of Wyoming President Tom Buchanan, and GE executives signed an agreement to build the $100-million High Plains Gasification Advanced Technology Center at a yet-to- be-determined site in Wyoming. Both GE and the state of Wyoming agreed to contribute $50 million to the project.

According to GE gasification manager Monte Atwell, the center, to be built at a 1-100 scale of a full-size gasification plant, will be fully operational in 2012.

One of the main purposes of the new facility is to test the Stamet pump gasification system for private commercial sale by GE. The company says the Wyoming coal has too much moisture to be used in GE’s other “slurry feed” gasification technology.

Keith White, GE director of IGCC products, said, his company is grateful to DOE for its work with the Stamet Pump, formally called the Stamet Posimetric High Pressure Solids Feeder.

But White said the High Plains Center “is not just for Stamet but a test bed for many things.”

Among the challenges, White said, is dealing with gasification at Wyoming’s high altitude. “There are also a lot of other advanced cleanup technologies that, quite frankly, we don’t know anything about yet”. If the High Plains Center research is successful, GE stands to make billions of dollars, particularly if, as many expect, the United States and other countries begin imposing penalties on CO2 emissions to reduce global warming.

New IGCC power plants of the type GE hopes to build now cost about $2.3 billion each. China, which last year surpassed the United States as the leader in greenhouse gas emissions, is a likely major customer.

In a press conference, November 13, Gov. Freudenthal, with GE executives and University of Wyoming officials at his side, heralded the project as a “milestone for Wyoming and for those who use Powder River Basin coal. It will demonstrate the ability to continue to use Powder River Basin coal in a wide market.”

The governor defended the numerous secret parts in the agreement as complying “directly with the open records laws and public records laws we have in Wyoming.”

The Wyoming Public Records Act states the public does not have the right to view “the specific details of bona fide research projects being conducted by state institutions” nor “trade secrets, privileged information and confidential commercial, financial, geological or geophysical data.”

But the heavily redacted sections of the agreement also mean that the public has no information about what the university or GE can expect to gain from their $50-million investments. For example, the unredacted sections available to the public do not say if the state will get any money from future sales of technology developed at the center.

To represent its interests in the delicate negotiations with GE over intellectual property, the university hired a Denver law firm, Hogan & Hartson. The negotiations took several months longer than originally expected.

“The agreement,” said Freudenthal, “took an immense amount of time in large part because it was Wyoming’s first extended experience with some of the more detailed aspects of intellectual property.”

The governor and UW President Buchanan each spoke of the academic potential of having a facility of this type on Wyoming soil and partly staffed by UW faculty and students. GE gasification executive Atwell described the center as “a magnet for the best and the brightest who want to be in this game long term.”

However, the arrangement also means that the state of Wyoming and its university will be doing what the federal government refused to do.

After GE refused DOE urgings to share the Stamet technology with other gasification efforts, Stiegel said the DOE immediately halted all cooperation and research into the Stamet Pump.

Rather than side with the DOE contention that the Stamet technology should be made public, the university has pledged formally to assist GE in keeping it secret.

After dropping its Stamet research, Stiegel said, the federal energy laboratory has accelerated research into a competing system being developed by Pratt & Whitney Rocketdyne Inc., a subsidiary of United Technologies Corp. that, he said, has “comparable potential” to the Stamet pump.

On Oct. 3, Pratt & Whitney Rocketdyne announced a partnership with oil giant ExxonMobil to develop compact gasification technology, about one-tenth the size of other gasification projects, using this new technology.

When the DOE withdrew support, GE couldn’t get access to federal laboratories. GE began looking for a place to test its new pump and other technology advances at a commercial scale, while still maintaining its proprietary interests.

GE has a sophisticated coal testing laboratory in Shanghai, China, but most American companies consider China too risky for testing cutting-edge technology because of the country’s notorious history of intellectual property theft.

Wyoming and its university stepped up as willing and discreet partners for GE.

In the summer of 2007, GE engineers and UW officials met several times to discuss a possible collaborative project.

According to Gov. Freudenthal’s staff, however, the proposal for a jointly funded research facility using Powder River Basin Coal took a serious step forward at the November 2007 World Energy Conference in Rome where Freudenthal and GE chairman Jeff Immelt were both speakers.

“When it first became real to me,” said Rob Hurless, the governor’s energy advisor, “was when the governor came back from Rome and said this thing might happen. Then the discussion became more ‘How much it would cost?’ and ‘What would we gain from it?’ and ‘Where would we get the money?’”

For more than a decade Wyoming and other western coal states had been arguing for their share of billions of dollars collected and held in reserve by the federal government under the 1977 Abandoned Mine Land act. In part because of legislation sponsored by Wyoming Sen. Mike Enzi, the money finally became available last winter.

“It had been a 10-year battle and it was finally resolved,” said Hurless. “The governor made the argument that the money ought to be used for energy and not become general-fund money.”

In February 2008, Freudenthal announced that all of Wyoming’s $50-million share of the GE gasification project would come from previously untapped Abandoned Mine funds due the state. The legislature agreed, allocating $20-million in the last session and promising more when the governor asks for it.

On November 13, the governor said the state now has $82 million in Abandoned Mine money available.

With the state money available, the GE partnership fit perfectly into Freudenthal’s long-held ambition to protect Wyoming’s coal interests in the face of changing environmental and public policy conditions.

The 1990 amendments to the Clean Air Act aimed at reducing acid rain gave Wyoming coal an edge over higher grade, but much higher sulfur, eastern coals.

Now the Powder River Basin coal faces the prospect of falling victim to another round of environmental adjustments brought on by global warming.

Most industry experts expect the Obama administration and the Democratic Congress to impose some kind of penalty or tax on CO2 emissions that contribute to global warming. Both Barack Obama and John McCain campaigned on platforms endorsing “carbon cap and trade” proposals that would penalize CO2 polluters.

Gasification of coal, the basics of which date to pre-World War II Germany, is a cheaper and more efficient way of capturing greenhouse gas emissions than traditional pulverized coal power plants. Freudenthal wants to make sure that technologies exist to gasify Wyoming coal under the anticipated CO2 regimen.

“The governor feels it is important to keep the discussion in play for Powder River Basin coal,” said Freudenthal Chief of Staff Chris Boswell.

At the same time, Immelt and GE also had been seeking a more promising way to gasify Powder River Basin Coal. The coal slurry gasification system GE bought from Chevron-Texaco in 2004 was too expensive to use for Wyoming coal because of its high moisture content.

This represented a problem for the world’s largest manufacturer of power plants. The Stamet pump with its dry-feed system was one possible solution.

“If GE wants to play in the Powder River Basin game,” said one gasification industry expert who asked not to be named, “it will have to redesign its basic gasifier design to allow use of dry feedstock. Competing technologies can now do this.”

One potential problem with Wyoming’s exclusive agreement with GE is that at least four other companies already have gasification technology that can process Powder River Basin coal. Two of the rival companies, Siemens and Shell, both operate their own dry feed IGCC systems.

This raises the issue that by partnering exclusively with GE, the state of Wyoming could be accused of subsidizing one company at the expense of its competitors. In this case, one could even argue that Wyoming, with its $50-million cash infusion, is helping GE catch up with more advanced rivals.

“The notion that existing gasification technology cannot process Powder River Basin coal is pure nonsense because there are a number of technologies today that can do that,” said James Childress, executive director of the Gasification Technologies Council, the main industry trade group.

One of the rival companies, ConocoPhillips, has already successfully used Wyoming coal in its 260-megawatt Wabash River power plant in West Terre Haute, Indiana, and in several other facilities.

“We’ve actually gasified more Powder River Basin coal than we have the other fuels we’ve run combined,” ConocoPhillips executive Phil Amick testified in a February 2007 deposition in Texas.

Amick also said in the deposition that the widely held contention that coal gasification doesn’t work with Powder River Basin coal or lignite is a “myth.”

In his press conference, Freudenthal dismissed the idea that the state of Wyoming is playing favorites among private, corporate competitors.

“I don’t subscribe to the characterization that this is a [state] subsidy. It is a mutually beneficial partnership,” Freudenthal said.

Freudenthal chief of staff Boswell observed, “GE just came in with a more mature proposal than the others. They had far more traction.”

Even Gary Stiegel, one of the DOE officials who objected to GE’s privatizing the Stamet Pump technology, sees potential in the GE-Wyoming project.

The rival dry-feed systems now offered by Siemens and Shell, Stiegel said, “are very costly and problematic in operation. What GE is doing has the potential of reducing the costs and improving the efficiency of coal gasification projects.”

Ecopetrol and Eni will Drill 5 Prospects in Gulf of Mexico

Ecopetrol S.A. signed a participation agreement with Italian oil company Eni, to drill at least five deep sea prospects in the Gulf of Mexico (GoM) between 2008 and 2012.

The five prospects will be selected from a portfolio of prospects to be presented by Eni and evaluated by both companies.

Pursuant to the agreement, Ecopetrol will hold between 20% and 25% of the prospects. Initial assessments indicate that Ecopetrol's investment may amount to US$220 million.

The agreement enables Ecopetrol to consolidate its internationalization process, particularly in the GoM, where it already participates in exploration blocks, together with a number of its partners, including Shell and BP. Ecopetrol is also present in the area through its participation in the production blocks in the K2 field operated by Anadarko.

In addition to increasing its presence in one of the world's most prospective regions for oil and gas production, this partnership enables Ecopetrol to diversify its exploratory risk and acquire know-how and technology for the development of deep sea projects.

Ecopetrol and Eni also signed a memorandum of understanding to develop joint exploration and production opportunities in South America and other parts of the world.

The participation agreement and the memorandum of understanding were signed in Bogota with the attendance of Ecopetrol's President, Javier Gutierrez, and executives from Eni.

Court Halts Shell's Plan to Drill for Oil in Beaufort Sea

The Ninth Circuit Court of Appeals, a federal appeals court, has blocked a major oil-drilling program of Royal Dutch Shell in the Beaufort Sea off Alaska's North Slope, saying the U.S. government has failed to conduct an environmental study before issuing the company's drilling permit.

The court has ruled that federal officials had failed to address the consequential environmental impact when granting permission to Shell to drill wells over a three-year time frame.

Rapping the U.S. mineral management service, the court said that it did not pay adequate heed to the risks of oil spills, hindrances that it would pose to migrating whales, disruptions to traditional hunting lifestyle of Inupiat Eskimos, and other potential harms from Shell's plan to drill at a prospect called Sivulliq.

It also said that before it authorizes any drilling, the US mineral management service needs to start afresh a review and maybe even launch a full-scale environmental impact statement instead of an abbreviated environmental assessment. "There remain substantial questions as to whether Shell's plan may cause significant harm to the people and wildlife of the Beaufort Sea region," the court said.

The ruling is in conclusion to a temporary order that was issued last year, which had placed on hold Shell's drilling at Sivulliq, around 16 miles off the coast of northern Alaska. The prospect was earlier called Hammerhead, and is known to hold oil. Though it was earlier drilled decades ago, drilling was halted on account of economic reasons. The ruling was in response to a couple of combined lawsuits that had been filed by environmental and Native groups, the North Slope Borough and the Alaska Eskimo Whaling Commission.

The mineral management service defended its environmental review process, and issued a statement expressing their disappointment on the ruling. ''We intend to review the court's ruling closely," the statement said, while adding that the mineral management service did conduct the required ''hard look'' to see if an environmental impact statement was necessary.

In a statement, Shell said that the mineral management service had done a "thorough job", and Shell "met or exceeded requirements for responsible Arctic exploration."

"The decision by the court delays drilling and extends the timeline it will take to bring this much-needed U.S. production on-line," Shell's statement said.

Sivulliq is an integral part of Shell's program to develop oil and gas resources in Alaska's federally-managed outer continental shelf. That is an area where there has been little development to date. Shell spent around $2.1 billion earlier in the year for exploration rights in the remote Chukchi Sea off Alaska's northwest coast, over and above a combined $83.7 million spent to acquire Beaufort Sea exploration rights in the mineral management service lease sales in 2005 and 2008. The oil company also initiated a broad program to conduct seismic tests in the Chukchi and Beaufort that will gather geological data needed ahead of drilling.

The Alaska outer continental shelf holds an estimated 26.6 billion barrels of undiscovered recoverable crude oil. Additionally, it is assumed to hold around 132 trillion cubic feet of undiscovered recoverable natural gas, as per the most recent mineral management service resource estimates. Almost all of those reserves are said to fall in the Chukchi and Beaufort Seas.

Shell had abandoned U.S. arctic exploration 21 years ago. Lawyers for Shell and the Bush administration, which had supported the company in the case, deposed before the appeals court at a hearing in December saying that studies showed that the drilling did not have a significant effect on the whales.

Environmental Protection Advocated amid Michigan’s Drilling Boom

Michigan lawmakers have been adamant about their quest to turn the state green.

Movement toward an eco-friendly state include constructing renewable energy facilities that would convert unused natural resources into fuel and adopting more innovative technology.

But in the wake of an unstable fossil fuels market and ailing economy, attention is turning toward tapping into Michigan’s oil and natural gas resources.

The Department of Natural Resources (DNR) oversees leasing of state-owned lands for oil and natural gas production.

Mary Uptigrove, a supervisor in DNR's Mineral and Land Management Section, said the department received almost $100 million from leasing and production of oil and natural gas mineral rights this year. That's the highest amount on record, compared to $67.1 million in 2007.

"The unprecedented amount of state-owned minerals we saw auctioned in 2008 was a result of the rising oil and natural gas market prices seen earlier this year and last year," said Uptigrove.

A report by the Environment Michigan Research and Policy Center evaluated the state's ability to address risks associated with drilling on public lands.

The Ann Arbor-based nonprofit organization said its research indicated that current policies and practices leave state lands at environmental risk from drilling.

John Rumpler, a senior attorney for Environment Michigan and adviser for the report, said state guidelines aren't adequate.

"The state appears to place a lot of faith in the industry's ability to implement its own safety practices, but the track record shows that damage does occur when these activities are allowed," he said.

According to the report, contamination remains an issue after cleanup of two state-owned sites in Wexford County. Though the systems were closed in 1999, when cleanup was deemed a success, polluted groundwater in some areas measure above state criteria. The area continues to be monitored.

Almost 879,000 acres of state land are leased for oil and gas development, according to the DNR. The report said an additional 100,000 acres are under consideration for development.

The Wilderness and Natural Areas Act of 1972 allows state agencies like the DNR to protect such areas from drilling.

In June, the DNR moved to permanently protect Carney Fen, an area with more than 2,000 acres of forest and marsh in the Escanaba State Forest in the Upper Peninsula, from mining, drilling, logging, development and other activity that could harm the area's ecology. The decision came under the 1972 law.

Rumpler said that move features the kind of protection Environment Michigan advocates. Tahquamenon Falls and the West Michigan dunes are among the group's top preservation priorities. But, he said, there's still a long way to go to reach its goal of protecting one million aces of state land.

"The DNR is not using its legal authority in a broad enough way yet," said Rumpler. "The point of this report was not to cast dispersions on the agency. We want to see more of the same as Carney Fen."

The Office of Geological Survey, under the Department of Environmental Quality (DEQ), supervises drilling from the initial permit to plugging a well once it's no longer productive.

"If there's contamination in between, we would oversee that, too," said Tom Godbold, field operations supervisor at Geological Survey. "We have inspectors out there on a regular basis inspecting wells and looking for contamination."

He said a 1994 "orphan well" program is a step in the right direction for environmental protection. It allows the DEQ to plug abandoned or mismanaged oil, gas and brine disposal wells and clean up contaminated sites.

Today, there are more than 19,200 oil and natural gas wells operating around the state.

Manistee County leads in both oil and natural gas production. In the first half of the year, 346,000 barrels of oil and more than 1.8 million cubic feet of gas were produced in the county, according to Geological Survey.

Manistee is at the southwestern end of the Niagaran Reef formation, an oil-and gas-producing belt that spans the top of northern Michigan, between Oceana County and Presque Isle County. Calhoun, Otsego, Montmorency and Kalkaska counties are also among the state's top producers.

According to the Michigan Oil and Gas Producers Education Foundation, oil and gas production generates nearly $2 billion a year in gross revenue. Michigan ranks 17th among the 33 petroleum-producing states, but its wells produce less than 5 percent of the state's consumption.

The Mitten State ranks higher as a natural-gas producer, at 13th nationwide, with enough gas to fill nearly one-third of the state's needs.

In early July, a federal judge denied efforts to drill in the Mason Tract, a 4,700-acre wilderness area along the AuSable River east of Grayling. Both state and federal permits had been granted during the initial site evaluation.

The decision was the result of a 2005 lawsuit filed by the Anglers of the AuSable, the Sierra Club and Tim Manson, grandson of the man who donated the Crawford County land to the state.

Rep. Mark Meadows, D-East Lansing, said the court case indicates that the law governing drilling permits needs to be amended to prevent future problems.

"Some change in the law needs to be made if we're going to protect areas like the Mason Tract from drilling," he said. "Even angle drilling, which may occur some distance from a waterway, could affect ground water and the ability to keep a stream viable."

Environment Michigan's Rumpler said the industry's extremely powerful presence in Lansing is a big obstacle to stricter controls.

"Any effort for broad protection is going to run up against that opposition and it's going to take bold and courageous leadership to confront that power."

U.S. Takes First Step toward New Offshore Oil Drilling off Virginia Coast

The federal government announced November 19 that it would be taking the first major step to expand offshore oil drilling after a long-standing ban on new energy exploration off much of the U.S. coast expired last month.

Officials with the U.S. Minerals Management Service, which oversees oil and gas development in federal waters, said that it would begin the process that could lead to leases at a potential site at least 50 miles off the coast of Virginia, an area that has not had offshore drilling.

Although the move involves only one coastal area, it represents the first turn of the crank in a much larger offshore drilling campaign that rose to a fury this summer amid a tumultuous election season and soaring gas prices -- and now stands to increase energy exploration in federal waters around the country, including off the coasts of California, Alaska and Florida.

"We've had some discussion, but now we're getting serious about it," said Randall Luthi, director of the Minerals Management Service. "This is actually an important step in our nation's energy security picture."

It could, however, be only a temporary step.

Democratic lawmakers and President-elect Barack Obama have said they would consider offshore drilling as a compromise in a comprehensive energy policy and as a way to wean the U.S. off foreign oil.

But whatever the new administration and Congress decide is likely to be more restrictive than current rules under the lapsed ban, which technically allow oil companies to drill as close as three miles offshore with federal approval.

"The issue of offshore drilling will be addressed by the next president and the next Congress," said Drew Hammill, spokesman for House Speaker Nancy Pelosi (D-San Francisco), who recently supported letting states decide whether to permit energy exploration 50 miles to 100 miles off their coasts.

Since 1981, a congressional moratorium on new offshore drilling has prevented the Interior Department from establishing leases in virtually all coastal waters outside of the western Gulf of Mexico and some areas of Alaska. The ban was enacted after a massive oil spill devastated the Santa Barbara coast in 1969.

Last month, however, the Democratic-controlled Congress allowed the moratorium to lapse amid pressure from the White House, Republican lawmakers and even members of the Democratic caucus who had come under attack for not doing more to bolster domestic energy supplies with gas prices topping $4 a gallon over the summer.

The process in Virginia will begin with a 45-day public comment period ending Dec. 29. The Interior Department does not expect to start leasing the area until at least 2011, after an environmental impact analysis is performed.

Virginia Gov. Tim Kaine, a Democrat, and the Legislature have supported offshore gas exploration.

According to rough estimates, the Interior Department believes there could be 130 million barrels of oil and 1.14 trillion cubic feet of natural gas in the area they expect to begin leasing off Virginia's coast.

In total, the Interior Department has estimated that there could be 18 billion barrels of oil and 77 trillion cubic feet of natural gas beneath 574 million acres of federal coastal waters that were off-limits before the ban lapsed.

But environmental groups and some Democrats have argued that the resulting gasoline could be years away and would do little or nothing to substantially reduce prices any time soon.

The Department of Energy has estimated that crude oil and gas production and prices would not be substantially affected until 2030.

"It is not going to make a meaningful difference in terms of gas at the pump," said Daniel Hinerfeld, spokesman for the Natural Resources Defense Council. "It is just a distraction from our need to cut off our dependence on oil."

In addition to Virginia, the Interior Department has announced a new five-year plan that could lead to opening formerly prohibited waters off California and Florida -- two states that have shown greater opposition than Virginia to new drilling.

The Minerals Management Service expects to come out with a list of specific locations by the beginning of next year. The move has been seen by some as a last attempt by the Bush administration to expand drilling before Obama becomes president in January.

New Mexico Receives $615 Million in Oil, Gas Royalties in 2008

New Mexico has received more than $615 million from the federal government for oil and gas production in 2008.

Sen. Pete Domenici, RN.M., said in a news release the money comes from federal royalties paid by the federal Mineral Management Service for oil, natural gas and coal produced within the state's borders.

Domenici says while there's a continued push for more clean energy, New Mexico can't discount the continued economic importance the oil and gas sector provides to the state.

This year was the third year in a row that royalty payments to the state were more than a half billion dollars.

In 2003, New Mexico earned $298 million in federal energy production royalties, Domenici said.

Aker to Supply Murphy Subsea Trees with $23 Million Contract

Murphy Exploration has awarded Aker Solutions a $23 million contract to provide subsea trees, control systems, and steel tube umbilicals for the company's Gulf of Mexico development program.

The initial order includes two wellsets and an umbilical. Delivery of all components is scheduled for 2Q 2009, the company says.

Engineering design and project management will be provided from Aker Solutions' office in Houston, Texas, with manufacturing of most components at Aker Solutions' subsea manufacturing center in Kuala Lumpur, Malaysia.

Umbilicals will be manufactured at Aker Solutions' facility in Mobile, Alabama. Offshore installation support will be provided from Aker Solutions' service base in Houston.

CANADA

Sonic Confirms Heavy Oil Upgrade to 25 Degrees API from Canadian Fields, U.S. Refineries and International Oil Producers

Sonic Technology Solutions Inc. confirmed that it has completed its test program of a number of heavy oils and has confirmed that the PetroSonic upgrading process is able to consistently achieve the target improvements in API. For Canadian bitumen samples this represents an upgrade from nominally 10 degrees API to 25 degrees API.

The test program included heavy oils and bitumen from the Canadian Athabasca and Lloydminster fields, heavy oil from USA refineries, and crude oil from two international oil producers. The testing was conducted at SONIC's Sonoprocess Development Facility in Richmond, British Columbia and at the PetroSonic Development Facility in Edmonton, Alberta.

Most of the parameter testing has been done with oil which nominally has an API gravity of 10° at 15°C. The PetroSonic upgraded oil quality is typically:

Density - from 23° to 28°API gravity, meeting pipeline specifications;
Viscosity - less than 100 cSt at 25°C (greater than 99% reduction), meeting pipeline specifications;
Liquid yields - From 85% to 92% by volume depending on the quantity, and quality of asphaltene by-product required;
Sulfur - reduction by up to 40% by mass;
Heavy Metals - typical reduction of Vanadium up to 80% and Nickel by up to 88% by mass.

PetroSonic upgrading allows producers to capture more of the heavy sour oil (HSO) to medium sour oil (MSO) crude oil price differential. The cumulative test data affirms the potential competitive advantage of the PetroSonic upgrader when integrated with various heavy oil production and processing facilities targeting the following markets:

Field installations for smaller producers who will be able to improve the quality of their oil without the use of diluents with minimum infrastructure cost and increased net returns;
Regional or integrated upgraders where the PetroSonic upgrader is part of an upgrading and energy system providing process steam and reducing natural gas usage; and
Larger scale upgraders designed to meet producer and midstream system requirements.

The Company's immediate objective is establishing tolling plants for small HSO producers offering tangible advantages:

The PetroSonic scalable upgrader technology can be designed to maximize oil product revenues or integrated to optimize overall oil and energy revenues;
Asphaltene by-product quality can be adjusted depending on the end-use;
Sonic reactor technology reduces processing costs in a low temperature and pressure process; and
PetroSonic field upgrading reduces or eliminates the need for diluents for pipeline transport.

PetroSonic has now generated data for the design and construction of its first field upgrader installation and work on the preliminary engineering is ready to proceed. These results have allowed SONIC to advance discussions with heavy oil producers regarding possible PetroSonic upgrader installations.

PetroSonic is a wholly owned subsidiary of SONIC and the exclusive licensee of a heavy oil upgrading process utilizing proprietary processes and sonic reactor technology developed and owned by SONIC. The PetroSonic upgrading process incorporates de-asphalting and oxidation stages in a low temperature and pressure process. PetroSonic is marketing its upgrading process to small oil producers on a tolling fee basis whereby the net benefit of the upgrading is shared by PetroSonic and the producer. The PetroSonic upgrading technology will extend to larger projects where PetroSonic facilitates the incorporation of systems which can provide sustainable integrated upgrading.

Spectra Energy Holds Open Season for Expansion in Northern B.C.

Spectra Energy is holding an open season to solicit participation in the expansion of the company's Transportation North ("Zone 3") natural gas transmission facilities in northern British Columbia.

Spectra Energy plans to construct up to 260 million cubic feet per day (mmcf/d) of incremental eastbound transportation capacity for deliveries to interconnection points with TransCanada Pipelines and Alliance Pipeline near Gordondale, Alberta. Spectra Energy also plans to construct up to 135 mmcf/d of incremental westbound transportation capacity on its Fort St. John mainline for delivery to Spectra Energy's compressor station #2, near Chetwynd, British Columbia. These new facilities are expected to be in-service in fourth quarter 2009.

"We are offering new pipeline capacity to meet the growing demand for transportation service for emerging natural gas plays in British Columbia," said Rob Whitwham, vice president, pipeline, Spectra Energy Transmission (West). "Customers will benefit from our ability to leverage our existing pipeline assets to develop cost-effective and timely expansions, while minimizing impacts on the environment, landowners, and other stakeholders in the area."

ConocoPhillips Gas Well Burns Out of Control in B.C.

A natural gas well burning out of control in northeast British Colombia may take weeks to cap.

The incident occured near Chetwynd which is about 100 kilometers from where natural gas firm EnCana, has been targeted with three explosions on pipelines and a well head since October.

The well is owned by ConocoPhillips, and company spokesman Patrick DeFoe said, there is no cause to believe this fire was deliberate.

"These incidents are completely unrelated. This was strictly an operational incident," he said from his Calgary office.

DeFoe said an equipment failure in a control mechanism in the well is believed to have caused the breach on and the leaking gas is fuelling the fire.

"We've mobilized people and equipment to begin to take control of the well, but it could take us several weeks to actually bring this well under control."

No one was hurt, the crew was evacuated and the site has been closed.

Because the area is remote it's expected there will be no danger to the public.

"We have air monitors circling the area, moving throughout the area, checking air quality," said DeFoe. "At this point we've had no adverse readings of any kind that would indicate there's a health issue to the public."

The company says they are looking into all options as to how to fix the breach, including drilling a relief well that would intersect to the damaged line to stop the leak.

This is the second such fire in under a year for ConocoPhillips.

There was a fire in a gas rig about 60 kilometers from the community of Tumbler Ridge last December.

DeFoe said there is no connection between the two fires.

The company temporarily shut down all its Canadian operations after the Tumbler Ridge fire while it reviewed its procedures, equipment and drilling plans.

Alberta Tweaks Royalty Rates Change to Keep Drilling Going

To ensure that preparatory oil and gas well drilling work is not shelved for the next five weeks, the Alberta government announced November 24 that it has decided to alter the rules for its new transitional royalty rates.

Wells commenced between Nov. 19, the date the new rates were announced, and Dec. 31 will be eligible for the new rate regime.

Companies with oil and gas wells between 1,000 and 3,500 meters where staging or initial drill work has begun during this period will be eligible to make the one-time choice to have the transitional rates applied to production beginning Jan. 1, 2009. Any wells producing oil or gas prior to Jan. 1 must transition to the New Royalty Framework, Alberta Energy said in a release.

The NRF has been harshly criticized by the conventional oil and gas industry, and some producers have opted to move onto properties in British Columbia and Saskatchewan that charge lower royalty rates.

Alberta Energy says that because the change will apply to a nominal number of wells and only on production after Jan. 1, the adjustment is not expected to affect the estimated $1.8-billion impact of the five-year program.

Aker Awarded Deep Panuke Wellhead Contract

EnCana has awarded Aker Solutions a contract for the transport and installation of wellhead protection structures on the Deep Panuke development, offshore Nova Scotia, Canada.

The contract will be undertaken by Aker Solutions subsidiary Aker Marine Contractors AS. The scope of work comprises engineering, planning, and offshore operations. The work will begin immediately. The offshore operations will be performed by one of the company's fleet of specialized offshore construction vessels in the 2Q or 3Q 2009, the company says.

MEXICO

Oil Drillers Eye Mexico Expansion despite Contract Delays

In October, Petroleos Mexicanos said it would rent five large offshore rigs, grabbing the attention of local and foreign rig suppliers.

A week later, Pemex withdrew the rate tenders to make revisions, underscoring the rewards and difficulties of working for Mexico's state-run oil monopoly. Pemex is spending more on oil equipment and services to revive the struggling industry. This creates new opportunities for oil services firms, but bureaucratic hurdles can also delay project startups for months.

"They're going to roll it out again, but we don't know when," said a Mexico-based executive at a foreign firm that plans to compete for the upcoming contracts.

Rig suppliers such as Schlumberger Ltd. (SLB), Noble Corp. (NE) and Diamond Offshore Drilling (DO) expect to see the tenders reemerge before the end of the year, and are generally upbeat on the outlook for Mexico.

Mexican oil production is in steep decline as the country's most accessible oil formations run dry. This means the country must drill a larger number of wells at less-prolific oil fields just to stabilize output.

Pemex plans to double exploration spending over the next three years, expanding the opportunities for oil service firms that have worked in Mexico for decades.

"As far as we can tell it is still full steam ahead, so you've got to love Pemex," said Noble Corp. CEO David Williams recently. "They need the hydrocarbons, so you don't expect to see a lot of pullback there."

Noble plans to compete for the five rigs, when Pemex publishes the new terms.

Contract Delays Hurt Production Pemex regularly delays bidding on service contracts, complicating the company's efforts to tap new oil fields fast.

Pemex delayed a contract for 600 wells in the Chicontepec basin by around five months until May 2008, when it was awarded to Weatherford International Ltd. (WFT). Pemex CEO Jesus Reyes Heroles recently said the delay contributed to the company's failure to meet production targets for this year. Output has fallen 10% to under 2.8 million barrels a day.

Bronco Drilling has described similar delays at a smaller project where it has three rigs under an 18-month contract.

"We have faced numerous delays in commencing operations, but we do believe that all three rigs will begin work during the fourth quarter," Bronco Drilling (BRNC) CEO Frank Harrison said in a recent conference call.

Pemex has already made some progress. During the first nine months of this year it expanded its rig fleet 8.5% to 242, more than half of which are owned by independent contractors. Pemex also increased the number of offshore platforms 5.1% to 226, including those that house workers and provide telecommunications services.

Reyes Heroles says Pemex will double its exploration budget over the next three years. Pemex's total investment budget has doubled since 2004 to around $20 billion a year at present.

This spending has helped service providers, but Pemex is only just starting to make up for lost ground. For decades it relied on one field, Cantarell, for the bulk of total output, and the company spent little exploring for and developing new oil deposits.

With the Cantarell pumping less than half of peak production as it enters old age, Pemex is scrambling to make up for lost time. Some officials expect it to take a decade to restore overall production to 2007 levels of 3 million barrels a day. Energy Minister Georgina Kessel said that the government will be happy just to halt the decline for now.

An energy reform passed last month will help. It will streamline contracting procedures on the hopes of preventing delays such as the recent rig tender withdrawal.

Pemex also hopes to draw new players into the oil industry with performance-based service contracts allowed under the reform. Pemex needs help from international oil firms with experience in the deep waters of the Gulf of Mexico. Pemex says around half of Mexico's undiscovered oil lies in its underexplored section of the Gulf.

Despite the hassles, Bronco Drilling expects to expand in Mexico.

"We continue to believe that Mexico could provide opportunities for additional rigs in the future," said CEO Harrison.

BRAZIL

Brazil’s Mauá Shipyard to Upgrade Two Brasdril Rigs for $13 Million

Brazil's Mauá shipyard has closed a deal with drilling contractor Brasdril, a subsidiary of Houston-based Diamond Offshore, to update two rigs, BNamericas reports.

The contract to update semis Ocean Worker and Ocean Whittington rigs is valued at US$13 million.

The rigs are due to operate for federal energy company Petrobras after the completion of upgrade works, which are slated to run 60 days.

This will mark Mauá's third upgrade project for Brasdril. The shipyard recently worked on Diamond drillship Ocean Clipper, also for Petrobras operations.

Brazil Poised to Become the Region’s New Type of Oil Giant

The largest discovery of oil in the Western Hemisphere in a generation is located more than 180 miles off Brazil's coast, where billions of barrels of light, sweet crude lie trapped under a few miles of water, rock, and salt.

Accessing it will require some of the most advanced technology on the planet. But Brazil, once a heavy importer that celebrated its "oil independence" only two years ago, is uniquely positioned to extract reserves trapped millions of years ago when South America and Africa began to separate. The state-controlled oil company, Petroleo Brasileiro (Petrobras), says it will begin production by 2010.

The potential is enormous and would thrust Brazil to the list of top oil exporters and help end the nation's wealth disparities. It is also a significant discovery for the world: proven reserves have been declining, and drops in both Norway and Mexico last year were offset in part by Brazil.

New discoveries are creating fresh challenges as to how the oil wealth should be spent. And some of the enthusiasm has been tempered by the global market turmoil that will make financing harder to find. But the fact remains: as its peers in the region see their oil production slipping – most notably state-owned oil companies in Mexico and Venezuela – Petrobras is entering a new era as the region's silent giant. And with oil in ever-deeper waters and more inaccessible nooks, more countries are turning to Brazil for its expertise.

"Petrobras is really a standout: in finding reserves, developing reserves, and investing in technology and human capital," says Francisco Gros, former chief executive of Petrobras and vice president of the board of OGX, one of Petrobras's competitors. "It should be a model; national companies should first be treated as oil companies."

The hope Brazil has placed on oil's transformative potential is on view in the bay of Angra dos Reis, where the massive P-51 oil platform juts out from the water. Weighing 48,986 tons – with capacity to sleep 200 and its own movie theater and soccer field – it is the first semisubmersible platform built entirely in Brazil and has created 4,000 direct jobs.

Petrobras is already the biggest company in Brazil, with a market value of more than $240 billion, and it is the government's largest single taxpayer. It employs some 52,000 workers, but the new oil find has kindled optimism that new jobs and opportunities lay ahead, especially in the shipping industry in ports along the Atlantic coast. "Petrobras has discovered a lot of oil, and there will be a lot of jobs in the future to build these platforms," says Pierre Robert da Silva, who just started at a new trade school dedicated to building oil rigs like the P-51.

But hopes for the future lie in more than job generation. Last November, Petrobras announced its discovery of the Tupi field, which holds an estimated 5 to 8 billion barrels of oil. In September, the company said that the nearby Lara field holds up to 4 billion barrels. But analysts estimate that the region could contain up to 80 billion barrels, about the same as Venezuela. Brazil currently produces more than 2 million barrels a day. By 2015, that could increase to 3 million.

Brazil's president Luiz Inácio Lula da Silva said the discoveries will narrow the gap between the rich and poor – and has floated the idea of a new company that has managed the "pre-salt" province. The company says it believes that Brazil, unlike other oil-producing nations that have squandered oil wealth or allowed it to exacerbate inequality and corruption, is a different story. "Our country has the maturity to take advantage of this oil," says Ricardo Beltrao, the general manager of production research at the research arm of Petrobras, called Cenpes. "Some other countries have a lot of resources but don't use those resources in a way that brings an increase in the standard of living of people."

How did Brazil get here? When Petrobras began operations in 1954, it was producing just 2,700 barrels a day, less than 3 percent of the country's needs. Brazil remained a heavy crude importer over the next two decades, but the oil shock of the 1970s unfurled a technological fervor. Unlike Mexico, whose discovery of the Cantarell field in 1976 – one of the world's largest oil reserves – thrust it easily into oil exportation, most of Brazil's richest deposits were offshore.

"We learned early that to be successful we had to have technological domain," says Carlos Tadeu da Costa Fraga, the executive manager of Cenpes, which was created in 1955 and today, with 2,000 employees, is the largest research center in Latin America. "In deep waters, we have much more experience than other countries in the world."

In the 1970s, Petrobras developed equipment and techniques to pump oil that lay deeper than most other companies could reach at the time. And today a new task is at hand as Brazil gets set to tap its newest oil find, which sits at some of the deepest levels in the world – more than 7,000 meters under the ocean's surface.

But investment in technology is only part of the story. In 1997, Brazilian lawmakers created a concession model, opening up what had been a monopoly to outsiders who compete with Petrobras on bidding and developing leases. Its shares have been publicly traded on the New York Stock Exchange since 2000. The government owns the majority of voting shares, but today 70 percent of total equity is in the hands of private investors, making it much more responsive to global accounting standards and corporate governance.

"When it opened up, Petrobras could begin to act as an oil company. The lesson from Brazil is opening up the system," says John Forman, the former director of Brazil's oil and gas regulator and today an independent consultant at J. Forman Consultoria.

The discoveries, of course, come with financial, logistical, and technical challenges. It is unclear whether the production will be economically viable, especially as the price of oil has fallen about 60 percent since mid-July to less than $60 a barrel today. The first "presalt" well cost $240 million to drill. Although newer ones cost a quarter of that, the demands on financing and infrastructure are high. The most common estimate cited, by the bank UBS, puts the cost of development at $600 billion. And some of the most promising reserves are the farthest away.

Still, all the wells sunk so far – eight in total – have struck oil, and confidence runs high. "We have reason to be optimistic. There are not barriers, but challenges we will be able to overcome," says Jose Formigli, executive manger of Petrobras's subsalt exploration and production.

The euphoria here stands in contrast to the outlook at other state-oil companies in the region. Mexico's production is in trouble since output at Cantarell has been declining at a rapid clip. At its peak four years ago, Mexico, the third-largest supplier to the US, was producing 3.8 million barrels a day; today production has slipped to 2.8 million barrels.

In order to maintain its position as a major oil exporter, the company says it will have to start aggressively exploring deepwater reserves – where they estimate 30 billion barrels lie. But they have not had the technology or money to undergo such exploration. Carlos Morales Gil, exploration chief for Mexico's state-owned oil firm, says that Petroleos Mexicanos (Pemex) wasn't forced to put resources in deepwater research because its oil was in shallow waters. Now that is starting to change, but catch-up alone will not suffice. "We are entering an era of big challenges for the oil industry in Mexico," says Mr. Morales Gil. "We have to put all capacities into deepwater [drilling] as fast and as strong as we can."

Mexico has been caught in a political storm over ways to revamp Pemex. Its Constitution mandates that the industry remain under state control – the country celebrates the 1938 nationalization of the industry as one of the defining moments in its history. A heavy tax burden has also hindered its technological development for years. Last month, Mexico's Congress passed a reform, enabling limited foreign participation in Pemex, but it was a watered-down version that Mexican President Felipe Calderón originally floated to attract investment in the Gulf of Mexico and help revive the stagnating company.

Today, Petrobras is gaining momentum while Pemex is slipping – a scenario that was unlikely 10 years ago. "The gap is narrowing considerably," says David Shields, a Mexico-based oil expert who has written extensively on Pemex. "Pemex is a giant bureaucracy and national symbol, and in that context has become very inefficient," he says. "Brazil hasn't had that problem. Petrobras is still a national company in a way but it doesn't have any hang-ups."

The region's other oil giant, Petroleos de Venezuela (PDVSA), is also starting to stagnate. Production in Venezuela has slipped from 3.1 million barrels a day in 1999 to 2.6 million barrels daily last year, according to the Energy Information Administration. Jorge Piñón, an energy researcher at the University of Miami and a former executive for Amoco in Latin America, says the drop is due partly to the fact that Venezuela's leftist President Hugo Chávez has used the proceeds to fund his social programs instead of investing it back into the company. In 2006, its earnings before spending on social development and income tax were $22,931 billion and the company contributed $13 billion of that to his social missions, including literacy and health programs in the most marginalized neighborhoods, according to the company website.

"PDVSA was not created as a social entity, but it's performing as one," Mr. Piñón says. "That's where your performance fails; this goes back to stewardship. You shouldn't take away money from the company that is supposed to be creating the future of the country."

But political challenges are on the horizon in Brazil. Just as Mexico debates the merits of private enterprise, Brazil's politicians are discussing whether it should move in the opposite direction. An inter-ministerial commission has been debating how to govern future oil proceeds, including the prospect of creating an entirely new state-run company. "Brazil has found a new oil province with a large potential. It is no sea of oil without risks of production," says Mr. Forman.

And if it gets bogged down in a political morass, Petrobras could lose its competitive advantage. "If they follow the right policies, this could bring the country very fast to being one of the most developed countries in the world," says Marcio Rocha Mello, a petroleum geologist who worked for Petrobras for 26 years and was one of the first pushing for ultradeep exploration, earning him the nickname "Mr. Go Deep." "And if they try to hold down production, we'll become importers of oil."

Brazil's Petrobras Discovers another Oil Patch of 2 Billion Barrels

Brazil's Petrobras announced November 21 that a new offshore discovery of as much as 2 billion barrels of light crude in ultra-deep deposits about a mile below the ocean floor.

The company said in a statement to financial markets that the find had already been officially communicated to the National Petroleum Agency, which regulates Brazil's oil and gas sector.

The firm said it had concluded drilling of two new wells in the "pre-salt" layer off the coast of the southeastern state of Espirito Santo in an area known as Parque das Baleias.

Brazil's pre-salt deposits - considered by the global petroleum industry as among the most promising new frontiers for oil exploration and production - are so-named because they lie far beneath the ocean floor under a layer of salt some two kilometers (1.2 miles) thick.

"The recoverable volume of these discoveries in pre-salt reservoirs located underneath (the Baleia Franca, Baleia Azul, and Jubarte) heavy oil fields is estimated to be between 1.5 and 2 billion barrels," Petrobras said in the statement.

Petrobras shares trade on the Sao Paulo, New York, Madrid and Buenos Aires stock exchanges, but the Brazilian government's golden share gives it control over the firm.

It was one year ago that Petrobras announced the discovery of massive amounts of crude in the pre-salt layer, which is located at a depth of up to seven kilometers (4.3 miles) below the ocean surface.

The volume found to date is sufficient to double Brazil's current proven reserves of roughly 14 billion barrels of oil equivalent.

The two new wells, called 6-BFR-1-ESS and 6-BAZ-1DB-ESS, were drilled at a spot close to 80 kilometers (50 miles) from the coast of Espirito Santo and a few kilometers from a pioneer well, the 1-ESS-103A, which is also located in the "pre-salt" layer and which came on-stream in September.

The new discovery is of light crude with an American Petroleum Institute gravity ranking of 30 and is of greater commercial value than the oil contained in traditional Brazilian fields.

Petrobras to date has drilled six wells in the Espirito Santo "pre-salt" layer and it said "the excellent results," as well as the logistics facilities already installed, have prompted the company to heighten studies to accelerate production of those deposits.

Deep Down Receives $11.1 Million Delba III Buoyancy Contract

Deep Down, Inc announced that it has received an executed $11.1 million contract from Delba Drilling International Cooperatie U.A. to supply and install the deepwater marine drilling riser flotation system for the new-build Delba III semisubmersible drilling rig.

The original letter of intent, initially estimated at $9 million, was received May 23, 2008. The increase in the value of the contract is reflective of engineering changes to satisfy additional lift requirements. The Delba III semisubmersible drilling rig is rated to drill in 2,400 meters of water and is readily upgradeable to 2,700 meters. The Delba III has long-term contracts to drill in Brazilian waters. The rig set of flotation for the Delba III is scheduled to be delivered by early 2010.

The manufacturing requirements under the Delba III contract will be managed by Flotation Technologies, a Deep Down subsidiary. The installation of the drilling riser flotation system will be managed by Deep Down (Delaware), also a Deep Down subsidiary.

Delba International has secured financing for the construction of the Delba III semisubmersible drilling rig. Deep Down is now focused on achieving a successful contract execution on the Letter of Intent for the Delba IV semisubmersible drilling rig, which was announced on June 6, 2008.

"Significantly, Delba International recognizes the benefits of our innovative, newly-engineered deepwater flotation system which provides greater durability at even greater depths," commented Ronald E. Smith, Deep Down's president and chief executive officer. "This innovation is embodied in our patent-pending CoreTec(TM) drilling riser buoyancy modules, a product of Flotation Technologies, for the offshore drilling industry. The CoreTec(TM) drilling riser buoyancy modules provide a more durable, longer lasting, and cost effective buoyancy solution for our customers."

"We chose Deep Down to satisfy our buoyancy requirements on the Delba III for two principle reasons. We believe the highly engineered CoreTec(TM) modules provide a superior and cost-effective solution with its demonstrated durability and longevity at ultra high ocean depths. A second, and equally important consideration, is Deep Down's long-standing reputation for providing exemplary installation services of all types of equipment in offshore operations at any depth," commented Drilmar Monteiro, Delba Drilling International Cooperatie U.A. "We anticipate continued use of this solution in our Brazilian operations, as we have a significant backlog of rigs all requiring an effective and durable buoyancy solution for deepwater operations."

Deep Down specializes in the provision of innovative solutions, installation management, engineering services, support services, custom fabrication and storage management services for the offshore subsea control, umbilical, and pipeline industries. The company fabricates component parts of subsea distribution systems and assemblies that specialize in the development of subsea fields and tie backs. These items include umbilicals, flow lines, distribution systems, pipeline terminations, controls, winches, and launch and retrieval systems, among others. Deep Down provides these services from the initial field conception phase, through manufacturing, site integration testing, installation, topside connections, and the final commissioning of a project.

Deep Down's ElectroWave subsidiary offers products and services in the fields of electronic monitoring and control systems for the energy, military, and commercial business sectors. ElectroWave designs, manufactures, installs, and commissions integrated PLC and SCADA based instrumentation and control systems, including ballast control and monitoring, drilling instrumentation, vessel management systems, marine advisory systems, machinery plant control and monitoring systems, and closed circuit television systems.

Deep Down's Mako subsidiary serves the growing offshore petroleum and marine industries with technical support services, and products vital to offshore petroleum production, through rentals of its remotely operated vehicles (ROV), topside and subsea equipment, and diving support systems used in diving operations, maintenance and repair operations, offshore construction, and environmental/marine surveys.

Flotation Technologies engineers, designs and manufactures deepwater buoyancy systems using high-strength Flotec(TM) syntactic foam and polyurethane elastomers. Flotation's product offerings include distributed buoyancy for flexible pipes and umbilicals, drilling riser buoyance modules, CoreTec(TM) drilling riser buoyancy modules, ROVits(TM) buoyancy, Hydro-Float mooring buoys, Stablemoor(TM) low-drag ADCP deployment solution, Quick-Loc(TM) cable floats, Hardball(TM) umbilical floats, Flotec(TM) cable and pipeline protection, Inflex(TM) polymer bend restrictors, and installation buoyancy of any size and depth rating.

Deep Down's strategy is to become a leading provider of products and services to the offshore industry, including shallow, deep and ultra-deep water applications in oil and gas exploration, development and production activities and maritime operations. Management plans to achieve this strategy through organic growth and strategic acquisitions of complementary businesses with technological advantages in deepwater environments.

ASIA

AUSTRALIA

MEC Resources Confirms Hydrocarbon Gas in Offshore Sydney Basin

MEC Resources has announced that investee company Advent Energy Ltd is confident that the offshore Sydney Basin is an active hydrocarbon system following the recent industry research and reporting on the area. . Advent holds an interest in the offshore Sydney Basin Petroleum Exploration Permit PEP 11.

A hydrocarbon gas source has been analyzed and confirmed in the offshore Sydney Basin. The confirmation of a hydrocarbon based gas analysis was released at the Petroleum Exploration Society of Australia (PESA) "Eastern Australasian Basins Symposium", 14-17 September 2008.

The confirmation of this type of hydrocarbon gas seepage is an extremely significant development for MEC Resources investee Advent Energy, which holds an interest in the offshore Sydney Basin Petroleum Exploration Permit PEP 11. Active seeps of the nature reported are considered by experts in this field to occur in basins now actively generating hydrocarbons and or that contain excellent migration pathways. The methane gas has been reported by independent testing to comprise a mixture of thermogenic and biogenic gas.

Hydrocarbon gas analysis has been confirmed to be;

Methane(CH4) 90.69%
Oxygen(O2) 1.58%
Carbon Dioxide (CO2 ) 4.12%
Nitrogen(N2) 3.7%

The gas seepage has been observed from repeated sea floor positions in an area off the coast of New South Wales and along the mainland margin of the PEP11 Permit. The gas is believed by Advent Energy to be sourced from areas within the PEP11 permit area.

The area where the gas has been identified is in the same area where oil and gas seeps have been recorded from Long Reef to Catherine Hill Bay, giving rise to periodic oil slicks occurrences along the coast , especially in the Cape Three points, Terrigal area. Visible gas seeps have been audio-visually recorded, and are available to view at http://www.adventenergy.com.au/.

Advent is in discussions with a number of international oil sector groups on potential joint ventures.

Advent is also continuing to pursue the securing of an appropriate drilling rig.

Terminals Pty Ltd Chooses Emerson Smart Wireless Solution to Monitor Pipeline Temperatures

Terminals Pty Ltd has chosen Emerson Process Management's Smart Wireless solution to monitor temperatures in a 900m long, 8in heat-traced pipeline used for unloading bitumen from ships at its Geelong Terminal in Australia.

It is necessary to make certain the electric heaters are operating all along the pipeline to keep the bitumen hot and fluid in order to facilitate pumping. If a heater fails, a cold spot could form, causing the bitumen to solidify and plugging the line with expensive consequences.

Eight Rosemount wireless temperature transmitters are to be evenly spaced along the pipeline, sending temperature readings on one-minute intervals to a Smart Wireless Gateway on shore that channels data to the AMS Suite predictive maintenance software used for instrument configuration and performance monitoring. The collected data will be forwarded to a SCADA system in the terminal control center via fiber-optic cable.

CHINA

China Okays $67.4 Million Cross-provincial CBM Pipeline

China's first cross-provincial coalbed methane pipeline has been approved by the National Development and Reform Commission (NDRC), said China United Coalbed Methane Corp.

The project, with a total investment of $67.4 million (458 million yuan), would channel coalbed methane from the Qinshui basin of Shanxi Province in north China to Henan Province in central China for use in homes and chemical factories.

There is no clear timetable, but the company said the construction would begin very soon and is scheduled to be completed by the end of 2009, sources with the company said.

The designed gas transport capacity of the pipeline is 1 billion cubic meters per year. China United Coalbed Methane Corp. would supply for the coalbed methane.

The 98.2-km pipeline would promote the development of coalbed methane in the Qinshui basin and help boost gas supply in areas along the channel, the NDRC said in a statement to the company.

Cnooc Plans $29 Billion South China Sea Exploration

Cnooc Ltd. and its partners may spend about $29 billion (200 billion yuan) to develop fuel deposits in the South China Sea in the nation's biggest push to tap reserves off the coast.

The investments between next year and 2020 include an estimated 15 billion yuan by parent China National Offshore Oil Corp. to build deepwater drilling equipment, Luo Donghong, chief development engineer at Cnooc's Shenzhen unit, said on Nov. 22. He didn't name the companies that will partner China's biggest offshore oil producer.

Rising energy demand in the world's fourth-biggest economy is prompting state-run Cnooc to boost exploration in an area where nations including Vietnam and Indonesia have laid territorial claims. The company will drill twice the depth of its existing wells off the coast of China as its global rivals cut spending after oil prices fell 66 percent from its July record.

``Huge potential lies untapped for the company in the South China Sea, which is largely unexplored,'' Wang Aochao, a Shanghai-based analyst with UOB-Kay Hian Ltd., said. ``The company will need to tackle the relationship between countries well.''

The South China Sea, covering 3.5 million square kilometers, stretches from Singapore to the Straits of Taiwan and is a third of the size of China. In July, the Chinese government opposed a plan by Exxon Mobil Corp., the world's biggest oil company, to explore for fuel in the area with Vietnam, saying the project marks a breach of its historical claim to the region.

Cnooc climbed 2 percent to close at HK$5.16 in Hong Kong trading, while the benchmark Hang Seng Index dropped 1.6 percent.

China, the world's second-biggest oil user, is expediting projects including nuclear power plants, gas pipelines and oil refineries to help stimulate the domestic economy and meet future energy demand. The country will overtake the U.S. as the world's biggest oil and gas consumer in about five years, Royal Dutch Shell Plc said in September.

``The company will maintain its exploration budget for the South China Sea next year,'' Li Fanrong, general manager of the unit of the Beijing-based company, said in the southern city of Shenzhen. ``The investment is only a rough estimate that reflects the immense potential of oil and gas reserves in the area.''

Geological fuel reserves in the deepwater fields of the South China Sea may reach 22 billion barrels of oil equivalent by 2020 and overall annual output may rise to 350 million barrels, Luo said. China may consume 8.2 million barrels of oil a day in 2009, according to the International Energy Agency, the Paris-based adviser to 28 oil-consuming nations.

China's demand for natural gas is ``huge'' in the coastal provinces of Guangdong, Fujian and Zhejiang, said Li.

Cnooc and its future partners aim to drill up to 3,000 meters deep in the offshore area by 2020, compared with the current maximum depth of 1,485 meters, said Luo. ``Deepwater is a key area for future incremental reserves,'' he said.

The actual spending for the South China Sea will depend on other variables including the price of raw materials such as steel, said Li.

Cnooc's current exploration partners in the South China Sea include Devon Energy Corp., Husky Energy Inc. and Anadarko Petroleum Corp., Luo said. The Chinese explorer said in January it will invest $1.04 billion in exploration in 2008 as it aims to at least replace any reserves it depletes

The company plans to produce between 195 million and 199 million barrels of oil equivalent this year, compared with last year's output of between 169 million and 171 million barrels, it said then.

INDONESIA

Lundin Petroleum Signs New Production Sharing Contracts in Indonesia

Lundin Petroleum AB has signed two new production sharing contracts (PSCs) for the Baronang and Cakalang Blocks with BPMIGAS, the Indonesian oil and gas regulating authority in Jakarta on November 13. Both blocks are located in the Natuna Sea, offshore Indonesia.

The Baronang Block covers an area of approximately 5, 157 km2 and the Cakalang Block 4,520 km2. Previous drilling activities on the blocks have confirmed the presence of active petroleum systems in or adjacent to both blocks. Several prospects and leads have been identified in the blocks from earlier 2D seismic campaigns.

Lundin Petroleum holds a 100 percent interest in both the Baronang and the Cakalang blocks.

SINGAPORE

Seadrill, Scorpion, Lewek Evaluating Keppel

Keppel Offshore & Marine Ltd. (Keppel O&M) received indications from Seadrill Ltd., Scorpion Offshore Ltd. and Lewek Shipping Pte Ltd. that they are reviewing their options on newbuilding contracts that were signed in the middle of this year. The contracts under review are for two jackups for Seadrill, a semisubmersible for Scorpion and a multi-functional support vessel for Lewek.

Keppel O&M is in talks with the companies to arrive at mutually acceptable arrangements for the contracts. Construction work has not started on the projects, for which Keppel O&M has already received down payments.

If these contracts are canceled, the cancellations are not expected to have any material impact on the net tangible assets or earnings per share of Keppel Corp. for the financial year ending Dec. 31, 2008.

EUROPE / AFRICA / MIDDLE EAST

AUSTRIA

TDW Offshore Completes Onshore Pipeline Operations in Austria for OMV Gas

TDW Offshore Services AS announced that it has successfully completed an onshore pipeline isolation operation for OMV Gas GmbH. The operation was carried for OMV Gas GmbH in Austria in conjunction with the company's Trans Austria Gas pipeline (TAG) expansion program.

One of the key developments of the expansion program is the newly constructed compressor station in Eggendorf, Austria. OMV Gas GmbH needed to safely re-route the existing pipelines to this new station. To achieve this, TDW was retained to carry out pipeline isolation services on the 38-inch import pipeline that stretches approximately 70km from Baumgarten to Eggendorf, and on the export pipeline that runs approximately 70km from Eggendorf to Grafendorf.

TDW isolated these pipelines by using its remote-controlled 38-inch SmartPlug® trains to create double-block isolations against the gas pressure. Both SmartPlug trains were launched and pigged with production gas into excavated sections of the pipelines, travelling approximately 100 meters from launcher to the work position. Using wireless, through the wall communication system, TDW manuvered each plug train into place, and set them horizontally in the excavated area of the pipeline. While the plug trains were in place and isolated pipeline sections, OMV Gas GmbH carried out the necessary modifications and re-routed the two pipelines to the new compressor station in Eggendorf. Once this was completed, TDW released the SmartPlug trains and pigged them back to the launcher and receiver using gas pressure from the pipelines. The pipeline pressures for both pipelines were 50 bar during the isolation operations. While each SmartPlug train isolated the pipeline sections for three days, the entire isolation operation took just 10 days from TDW's arrival onsite in Austria through to demobilization.

In order to help the two pipeline sections cope more effectively with the additional internal pressure exerted by the SmartPlug trains, TDW developed eight custom-made tension belts specifically for the OMV Gas GmbH operation. Although traditional belts can be cumbersome and time-consuming to attach to the pipelines during onshore isolation operations, TDW designed the tension belts in such a way that they are quickly and easily mounted. As a result, TDW was able to reduce the time and effort required to attach the belts and progress more rapidly to isolating the pipeline sections in order that the modifications could be made, and the pipelines safely re-routed.

Throughout the operation, the SmartPlug trains were continuously monitored by TDW as they travelled along the pigging route using TDW's SmartTrack system that interacts with the transceiver systems that are featured as standard in all SmartPlug trains.

"As a result of our ability to effectively isolate the pressure in the two pipelines so efficiently, OMV Gas GmbH was able to initiate modifications to the system sooner than anticipated, which was highly beneficial, reducing the overall pipeline re-routing program schedule," said Rune Haddeland, General Manager TDW Offshore Services. "Coupled with that was the fact that the pipelines were isolated with minimal venting of product into the atmosphere in accordance with OMV Gas GmbH environmental policy," he added.

ITALY

Italy Grants Po Valley Energy the Castello Gas Field Concession

Italy has granted Sydney-headquartered producer Po Valley Energy Ltd a 20 year production concession for Castello gas field near Milan. It is the first concession grant in the Po Valley region since the country's gas sector was deregulated in 1998.

The field will be produced from a single well at an initial production rate of about 2.7MM cu/ft per day of gas. The field's remaining proved gas reserves are put at 4.6 billion cu/ft of gas.

Po Valley Energy has completed construction of a surface plant for Castello, and connection of the pipeline to the Italian national gas grid 500m away will begin in December to be completed early in 2009. Gas production is scheduled to begin in second quarter 2009.

NORWAY

Marathon Sells Heimdal Interests Offshore Norway to Centrica for $416 Million

Marathon Oil Corporation has finalized the sale of its non-operated interests in the Heimdal infrastructure, covering both producing fields and undeveloped acreage offshore Norway. The assets were sold to Centrica plc, the parent company of British Gas, for a total of US$416 million, which includes a US$375 million purchase price and US$41 million in Norwegian asset tax pools, with an effective date of Jan. 1, 2008.

The sale of these non-core Norwegian assets is part of Marathon's ongoing review of its global asset portfolio and the company's goal to achieve from between US$2 billion to US$4 billion in gross proceeds by the middle of next year.

The deal sees Centrica buying Marathon's 23.8 percent interest in the Heimdal field, as well as its 46.9 percent interest in the Vale field. Twenty percent interest in the Byggve field has also been sold alongside a 20 percent interest in the Skirne field and a 50 and 20 percent interest in the Peik and Heimdal East discoveries.

Marathon's net proved reserves in the assets as of the 2007 year end were 4.8 million BOE, and total net risked resources of approximately 17.5 million BOE.

Net production from these operations averaged around 7,000 BOE/d during the first three quarters of 2008. None of the assets involved in this agreement are associated with Marathon's Alvheim/Vilje development or related operations on the Norwegian Continental Shelf.

POLAND

Polish Premier Visits Kuwait and Qatar for Gas Contract Talks

Polish Prime Minister Donald Tusk has visited Kuwait and Qatar for three days of talks on gas contracts and lessening Poland's reliance on Russian supplies.

Tusk would meet with Gulf leaders for talks on economic cooperation, energy, and the chemical and petrochemical industry, his chancellery said.

"The Polish government also wants to demonstrate readiness for more engagement in the dialogue between the European Union and countries of the Gulf Cooperation Council," the chancellery said.

"It's about support for signing an agreement on free trade between both organizations." Tusk is also scheduled next year to visit Saudi Arabia and the United Arab Emirates.

Treasury Minister Aleksander Grad recently said Poland would start working to attract Saudi investors. A Polish-Saudi investment fund was to be launched next year.

"They're counting on strengthening their position on Central and Eastern Europe by investing in Poland," Grad said.

SCOTLAND

Cromarty Firth Port Authority Celebrates Arrival of 600th Rig

Scotland’s Cromarty Firth Port Authority (CFPA) is celebrating the arrival of the Ocean Princess, 600th oilrig to visit the service base, since it was established in 1973.

Over the last 35 years, the port authority has generated significant income and job opportunities within the local community, across all sectors of the business.

Another significant development is the arrival of the Jacky platform from Holland. The platform is to be located at a new oil field close to the Beatrice field, in the Inner Moray Firth. The Jacky platform is awaiting installation using the crane barge, Matador III, also currently moored at Invergordon.

Ken Gray, CFPA's port manager/harbour master said: "The arrival of the 600th rig to the Cromarty Firth is a significant milestone in the history of the service base. The arrival of both the Ocean Princess and Jacky platform, demonstrates the importance of the Cromarty Firth in generating both income and employment opportunities in the Highlands."

SWITZERLAND

Switzerland’s Manas Petroleum Appoints New Independent Director

Manas Petroleum Corporation announced that the Board of Directors has unanimously appointed Dr. Richard Schenz as an Independent Director.

Dr. Richard Schenz brings experience and expertise as the former CEO of OMV, Central Europe's leading oil and gas company. In 1969 he started his career with the Austrian oil & gas company OMV, and was its CEO from 1992 to 2001.

In 2001 he was appointed representative for the Austrian Capital Market by the Austrian government. Additionally Dr. Schenz holds the positions of Vice President of the Austrian Federal Economic Chamber and President of the International Chamber of Commerce in Austria (ICC-Austria). In 2002 he was appointed Chairman of the Austrian commission for Corporate Governance.

Manas Petroleum’s activities are primarily in South-Eastern Europe, Central Asia and South America.

In Albania Manas has developed a giant exploration project with a total resource potential (P50) of 3 billion barrels. Manas also recently signed a PSC with the Albanian government covering 2 blocks, one which includes a light oil discovery.

In Kyrgyzstan Manas has signed a US $54 million farm-out agreement with Santos a large independent Australian oil and gas producer covering its 1.2 billion barrels in place, light oil play. Drilling is expected to begin imminently.

The development of the company's neighboring Tajikistan license is now covered by an option farm in agreement also with Santos where a seismic program was recently completed.

In Chile, Manas and U.S. partner IPR farmed out a large natural gas exploration project to a consortium of local operators. Work developing the natural gas exploration play is expected to commence early 2009. In Mongolia the company recently completed a phase 1 geological program which defined structural trends with potential petroleum accumulations in preparation for a planned 2009 seismic program.

TURKEY

Oil Pipeline Fire Extinguished in Southeast Turkey

Firefighters in southeast Turkey on November 23 extinguished a fire on a section of oil pipeline that had been set ablaze by an explosion.

The bomb attack on the Kirkuk-Ceyhan pipeline November 21 halted oil exports from Iraq through Turkey.

The separatist Kurdistan Workers' Party, also known by its Kurdish initials PKK, claimed responsibility for the blast.

Although the fire was out, officials said it could take a week or more to repair the damages to the line, located 80 kilometers from the Iraqi border near the town of Midyat.

With ongoing construction of major oil and gas pipelines in the Middle East and central Asia, Turkey is positioning itself as an international energy hub.

But in the past year, the PKK has increasingly targeted energy pipelines supplying Turkey as part of its campaign for Kurdish autonomy.

In August, an explosion tore through another oil pipeline, disrupting the flow of petroleum from Azerbaijan for three weeks.

UNITED KINGDOM

Petrofac Energy Awards BJ Services North Sea Casing and Tubing Operation

BJ Services Co. has announced that its Tubular Services line has been awarded a contract to provide casing and tubing running services in the northern North Sea by Petrofac Energy Development Ltd. Services will be completed in the Don SW and West Don fields. The development is located approximately 150km NE of the Shetland Islands and 12km north of the Thistle Field in water depths of approximately 152m.

To ensure that the casing and tubing running operation is carried out effectively, BJ Services will use a fully mechanized running system that includes its Leadhand tong manipulating technology with hydraulic casing and backup tongs.

In addition, BJ plans to install its Derrickman system on the drilling rig. This remotely-operated mechanical arm makes it possible to manuver tubulars and drillpipe into a vertical position without a crew member acting as a traditional stabber. BJ Services will work from the John Shaw semisubmersible drilling rig on the seven-well drilling program, with plans to begin operations in November 2008. The drilling program is scheduled for completion at the end of 2009.

ALGERIA

Sonatrach Awards Saipem LPG Contract worth $1.63 Billion

Saipem has been awarded a new onshore contract in Algeria worth approximately US$1.63 billion (€1.3 billion).

The Algerian oil company Sonatrach has awarded Saipem the lump sum turn-key contract for the Liquefied Petroleum Gas processing facility project at the Hassi Messaoud oil and gas complex in central Algeria, 900 kilometers southeast of Algiers.

The contract covers engineering, procurement and construction of three LPG production trains with a total capacity of 8 million cubic meters a day.

The works will be completed by first half of 2012.

NIGERIA

Nigerian Militants Threaten Oil and Gas Facilities in Western Delta

Nigerian militants threatened to bring chaos to the western Niger Delta by interrupting shipping and attacking oil and gas facilities run by U.S. firm Chevron unless the region's military commander was removed.

The Ijaw Youth Leaders Forum (IYLF) said it wanted Brigadier General Wuyep Rimtip, commander of the joint military task force in the western delta, who has taken a tougher line on oil-related crime than his predecessor, transferred immediately or they would “stop the free flow of boats and vessels in the Delta waterways and make Delta state ungovernable".

The threat raised the prospect of a new campaign of violence against the oil industry in the western delta, which has been much quieter than the volatile east for several years.

Security experts say the IYLF is effectively the political wing of a network of militants and activists from the Ijaw community, the predominant ethnic group in the delta.

The IYLF also threatened attacks on facilities run by Chevron in Delta state, which include the Escravos crude oil export terminal and the Escravos Gas-to-Liquid (EGTL) project.

"We will take over Chevron Nigeria Ltd and EGTL despite the numerous gunboats and helicopters," the statement said.

Chevron could not immediately be reached for comment.

Attacks by militants on oil facilities in the Niger Delta, home to Africa's biggest oil and gas industry, have shut down around a fifth of Nigerian output since early 2006. Nigeria currently pumps around 2 million barrels per day.

The unrest has mostly been in Rivers state in the east, where the Movement for the Emancipation of the Niger Delta (MEND) has blown up pipelines and flow stations.

Delta and Bayelsa, the two other main oil-producing states to the west, have been comparatively quiet.

Their state governments have preferred to negotiate with the militants and award them security contracts rather than take an overtly military strategy.

But Rimtip appears to be taking a tougher stance.

Security sources say he has replaced several battalions -- including one in the Delta city of Warri and one in Bayelsa's capital Yenegoa -- whose soldiers were deemed to have become too close to criminals engaged in a lucrative trade in stolen oil.

UGANDA

Libya says Work Set to Start on 354 km Uganda Oil Pipeline

Construction of the Kampala - Eldoret oil pipeline to transport petroleum products starts in two months, the Libyan Minister of Economy, Trade and Investment, has said.

Dr Ali Abdulaziz Isawi said the 354 km pipeline will be in place within 20 months from January 2009.

On October 30, Isawi and the heads of Libyan companies operating in Uganda met with President Yoweri Museveni at the State House in Entebbe.

The President assured the delegation that the Government would acquire land for the construction of an oil terminal in Jinja, which would facilitate the pipeline, according to a statement.

Museveni assured the investors of facilitation to promote their ventures.

The President added that the Government would initially refine diesel and kerosene from the oil in the Albertine region for local and the East African region.

The businessmen told Museveni that Uganda Telecom had made a profit of sh9bn since Libyan investors bought shares in the company.

Ministers Ssemakula Kiwanuka, Nelson Gaggawala and the Libyan Ambassador Abdullah Bujeldian attended.

RUSSIA

Tied Loan to Spend $110 Million on Chinese Drilling Rigs Conflicts with Interests of Russian Industry

OJSC “Gazprombank” and the Export-Import Bank of China signed an agreement on October 28, whereby OJSC “Gazprombank” would open a credit line to the amount of $300 million. The money will be used to finance Chinese equipment supplies to Russia and insurance services provided by China’s export credit insurance agency SINOSURE.

According to OJSC “Gazprombank”, the decision was to spend more than $110 million to bring Chinese drilling rigs to Russia.

The Association of Oil and Gas Equipment Manufacturers, respects the efficient efforts of the Chinese government to provide state support to drilling rig exporters. Specifically, financing provided by the Export-Import Bank of China helps to keep Russian drilling equipment away from the markets of Central Asia. Russian manufacturers today have difficulties competing with Chinese suppliers that receive state subsidies.

Russia has a strong drilling rig industry. Rigs are manufactured by Uralmash Plant, Tyumen Shipyard, Volgograd Drilling Equipment Plant, Kungur Machinery Plant and other companies. In recent years, big investments were made to improve production and technology capabilities of the domestic oil and gas equipment industry. The evidence on competitiveness of Russian drilling rigs was rig purchases by western drilling contractors and the use for drilling in Yamal Peninsula - a strategic source of natural resources of the Russian Federation.

The big tied loan provided by OJSC “Gazprombank” to purchase Chinese drilling rigs will hit the Russian oil and gas equipment industry. Many companies will have to reduce their personnel and scale down their development programs. Such loans discriminate against manufacturing companies in the country and are adverse to the interests of the Russian industry.

The Association of Oil and Gas Equipment Manufacturers has addressed the government of the Ural Federal District and the Russian Trade Union of Equipment Manufacturers to prepare a joint address to the government of the Russian Federation.

IRAQ

Shell Forms Partnership for Iraq Exploration and Marketing with Turkish Firms

Turkish state firms Botas and TPAO and global energy major Royal Dutch Shell have formed a natural gas exploration and marketing partnership in Iraq, Turkish Energy Minister Hilmi Guler said November 20.

TPAO has also been invited to enter exploration tenders for eight oilfields in Iraq, for which the firm may form a partnership with Shell, Guler said.

"There is a possibility of a TPAO partnership with Shell, especially on the Kirkuk field," Guler said during the signing of a memorandum of understanding with the energy major.

TPAO Chief Executive Mehmet Uysal said his company had reached the final stage of talks with Shell to bid together in a partnership in oil exploration tenders in Iraq.

The agreement between Turkey and Shell will also cover possible gas infrastructure projects in Turkey including links with neighboring countries, Shell said in a statement.

"These infrastructure projects may enable countries such as Iraq to export its future surplus gas to Turkey and further into Europe once Iraq's domestic demand has been satisfied," the statement said.

TPAO had said it was interested in opportunities in neighboring Iraq's oil and gas sectors, The company was added in April to the list of companies that pre-qualified to bid in oil exploration tenders.

Iraq, reliant for revenue on oil, needs major investment to boost output after years of sanctions and war.

KUWAIT

Kuwait Oil Co. Awards Petrofac $543 Million Pipeline Contract

Petrofac has been awarded an approximately US$543 million (KD147 million) lump-sum contract by Kuwait Oil Company (KOC). The contract is for engineering, procurement and construction services for a new gas pipeline running from KOC's Booster Station 131 in North Kuwait to its liquefied petroleum gas plant located at the Mina Al-Ahmadi refinery.

Petrofac is the main contractor and will commence work shortly, undertaking engineering design, procurement and construction, pre-commissioning and commissioning of the pipeline. The project is expected to last for 21 months.

The pipeline, approximately 140 kilometers long, will transport gas from Kuwait's northern fields for processing at Mina Al-Ahmadi refinery before being transported to Kuwait's power generation plants.

Commenting on the project, Maroun Semaan, chief executive of Petrofac's Engineering & Construction division, said: "We are delighted to have been selected by KOC for this contract which continues our longstanding involvement in Kuwait with KOC with whom we have an excellent relationship and consolidates further the group's position in the Middle East."

SAUDI ARABIA

Mitsubishi Receives Two Orders for 150 MW Gas Turbine and Generator for Saudi Aramco’s Manifa Project

Mitsubishi Heavy Industries, Ltd. (MHI) has received an order from Tecnicas Reunidas, S.A., a Spanish engineering company, for two sets of its natural gas-fired 150 megawatt M501F gas turbine and generator. The gas turbines and generators on order are for a large-scale oil and gas production/processing project of Saudi Arabian Oil Company (Saudi Aramco), Saudi Arabia's state-owned oil firm. The latest order brings the cumulative number of gas turbines ordered for Saudi Aramco to seven units.

The gas turbines and generators, slated for delivery in 2010, will be installed at a Saudi Aramco plant facility that will process 900,000 barrels a day of crude oil to be produced at the Manifa oilfield. The plant is composed of various facilities, including those for oil-gas separation, oil storage, water injection, shipping and power generation. The gas turbines and generators on order will serve as the core equipment of the combined-cycle power and heat co-generation facility. MHI will supply the two M501F gas turbines and Mitsubishi Electric Corporation will provide the two generators. Mitsubishi Corporation will handle the trade particulars.

Previously MHI has received orders from Saudi Aramco for five 150 MW gas turbines: two units for the Berri Gas Plant, delivered in May 2005; two for the Khursaniyah Oil and Gas Facilities, delivered in August 2007; and one for the Karan Gas Facilities, an order placed in June 2008. MHI believes the customer's high evaluation of its delivery and operational track record for these turbines, as well as of its technological expertise, led to the latest order.

Going forward MHI will continue to aggressively conduct marketing activities for its high-capacity, high-performance gas turbines, which contribute to both effective utilization of energy and reduction in environmental loads.

Aramco Wants Cheaper Deals for New Refineries

State oil giant Saudi Aramco is looking to renegotiate contracts for equipment for new export refineries to reflect falling prices for raw materials, an Aramco executive said.

The two 400,000 barrels per day refineries are joint ventures, one with France's Total and the other with U.S. firm ConocoPhillips.

"These projects have long lead times, so purchase orders may be restructured or revalued based on the drop in prices," Fahad al-Aohad, a business development specialist at Aramco, told Reuters.

The projects were in no danger despite uncertainty about future oil demand growth amid a global economic slowdown, Aohad said.

"All of these projects have been approved and will continue," he said.

Prices for raw materials used in construction, such as steel, have fallen amid a general decline in commodity prices. They had previously increased over a long period of growing demand, leading to rises in the costs of energy projects.

Total has said the cost estimate for its refinery has doubled to around $12 billion from initial estimates of around $6 billion. Conoco has given no estimate, but its plant has seen similar cost inflation, industry sources have said.

The two refineries will process oil from Aramco's heavy oil producing Moneefa field, due for completion with 900,000 barrels per day of capacity in late 2011.

Aramco is also looking to cut the cost of contracts for that field.

Flowserve Signs Long-Term Strategic Agreement with Saudi Aramco

Flowserve Corporation, one of the world's leading providers of flow control products and services for the global infrastructure markets including oil and gas, power, chemical water and general industries, announced it has signed a 10-year strategic supplier agreement with Saudi Aramco, one of the world's largest oil producing companies.

The supply agreement includes Flowserve's entire range of flow control products (pumps, valves and seals) and value-added services for use in Saudi Aramco's existing and planned facilities.

Specifically, the new supply agreement will provide for the:

-- Streamlining of the procurement process for all new Flowserve equipment, which will include pumps, valves, actuators and mechanical seals.

-- Reduction in Flowserve lead times through access to guaranteed production capacity

-- Delivery by Flowserve of aftermarket services to support Saudi Aramco operations through the industry leading Flowserve "LifeCycle Advantage" program, which is designed to help deliver the lowest possible total cost of ownership through optimizing spare parts inventories, reducing life cycle costs, increasing equipment life, and maximizing reliability

-- Engagement in a joint product and technology development program

-- Addition of local training centers and educational services that will complement Saudi Aramco's training and Saudization programs

-- Expansion of Flowserve's locally provided value-added services and operations, supported by Flowserve's extensive global organization

Flowserve cited its strong aftermarket capabilities, broad product portfolio, technology leadership, and long-standing partnership with Saudi Aramco as key reasons for the expanded relationship.

Flowserve recently invested in a new regional pump Quick Response Center (QRC) service, repair and manufacturing facility nearing completion in Saudi Arabia, through a joint venture between Flowserve and Al Rushaid Group. This QRC is located at the Al Rushaid Oil Field Center in Dhahran, and has been designed to feature the largest pump-testing capability in the Middle East, with a reservoir capable of testing pumps up to 5960 kW (8000 hp). This QRC will help support the Saudi Aramco supply chain for original equipment, parts and aftermarket services. It will also provide access to Flowserve technology and innovative solutions to help improve equipment reliability and ensure lower costs.

Flowserve has also supported Saudi Aramco's mechanical seal requirements through its QRC joint venture with S & A Abahsain Co. Ltd, located in Al Khobar, since 1989. The mechanical seal QRC has recently doubled its capacity, and is now being expanded to further optimize customer response.

Part of Flowserve's local support will be through the establishment of a local world-class training center in the Dhahran QRC with both static and power laboratories and classrooms. The objective will be to promote technical and mechanical skills excellence, both internally and externally. This demonstrates Flowserve's continuously expanding support of Saudi Aramco's pumping needs dating back to 1939.

UNITED ARAB EMIRATES

Mustang Wins Contract for Abu Dhabi Carbon Capture and Storage Project

Masdar, an Abu Dhabi government initiative, owned by Mubadala Development Company, announced the selection of Houston, Texas-based Mustang Engineering, a subsidiary of international energy services company John Wood Group PLC, to provide front-end engineering and design (FEED) services for Masdar's Carbon Capture and Storage (CCS) project in the United Arab Emirates.

The project constitutes the first phase in a series of facilities capturing carbon dioxide emissions from Abu Dhabi's industrial and power generation plants. The CO2 will be transported in a pipeline network and injected in Abu Dhabi's oil reservoirs for enhanced oil recovery. The objective of the CCS network is to reduce Abu Dhabi's carbon footprint and replace the vast amount of natural gas currently re-injected into oil reservoirs.

The first phase consists of five million tons of CO2 gas captured per year as of end 2013 from three emission sources: a gas-fired power plant, an aluminum smelter and a steel mill.

"This project marks a major milestone in our leadership's vision to provide clean energy, reduce carbon emissions and promote sustainable development," said Masdar CEO Dr. Sultan Al Jaber.

"We selected Mustang Engineering because of their industry-leading position in CO2 recovery, conditioning and injection projects, as well as their expertise in energy production projects worldwide. This series of projects will reduce our carbon footprint, and position Masdar and Abu Dhabi as global leaders in clean power."

The FEED follows a successful eight-month feasibility study conducted by Masdar in 2007 to investigate CO2 emission sources in Abu Dhabi and evaluate the technical and economic feasibility of CO2 capture and transportation to oil reservoirs.

"Mustang is excited to be part of this strategic initiative with Masdar. This world-class CCS development greatly complements our extensive experience with CO2 related projects. We are committed to the support of sustainable development and look forward to seeing the impact this project will have on the environment of the region," said Steve Knowles, Mustang president.

J P Kenny, also a Wood Group company and operating from their Abu Dhabi office, will be responsible for FEED services for the CO2 pipeline network that will connect the capture sites in Abu Dhabi to the oilfield injection sites. This work is scheduled for completion in the 4th quarter 2009.

Petrofac Wins Brownfield Consultancy Contract in Abu Dhabi

Petrofac has been awarded an engineering consultancy contract by the Abu Dhabi Company for Onshore Operations (ADCO) for de-bottlenecking services for the onshore North East Bab field, located approximately 50 kilometers southwest of Abu Dhabi. This is the first contract secured by Petrofac with ADCO, which is a subsidiary of the Abu Dhabi National Oil Company (ADNOC).

Specialist consultants from Petrofac Brownfield, which is part of the group's Facilities Management business, are working on the project in both Abu Dhabi and Aberdeen, Scotland. Using extensive operating experience and UK North Sea techniques, Petrofac is reviewing options for changes to operating conditions to enable the de-bottlenecking of critical equipment. The aim is to add value and increase production without major technical changes to ADCO's Al Dabb'iya and Rumaitha processing plants.

Bill Bayliss, VP Petrofac Brownfield, said: "This contract award further confirms our strategy for supplying our differentiated brownfield services in the Middle East.

Occidental, Mubadala to Invest $500 Million in Oman Gas Fields Development

Occidental Petroleum Corp and Abu Dhabi investment firm Mubadala Development Co have signed an exploration and production sharing agreement with the Sultanate of Oman, the companies said in a joint release November 24.

The agreement allows the parties to develop four existing gas fields and explore for new discoveries in a newly formed contract area in Northern Oman. The 20-year agreement covers an area of 2,269 square kilometers (876 square miles).

Occidental will serve as operator under the agreement and hold a 48 percent interest, with Mubadala holding 32 percent and the Oman Oil Company holding the remaining 20 percent.

Total capital investment in the contract area is expected to be about $500 million over the next four years.

The companies expect exploration, appraisal and development activities to begin immediately, while natural gas production from the area is expected to begin in 2010 and plateau at 27,500 barrels of oil equivalent per day (boepd) by the end of 2011.

Occidental's net share of production at plateau is expected to be about 10,000 boepd, with Mubadala's net share around 6,000 boepd.

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