February 10th, 2006:

Analysts say loss of sales would hurt Venezuela, which exports about half of its oil to the U.S., most refined by Citgo
Natalie Obiko Pearson
AP Business Writer
Venezuelan President Hugo Chavez has stepped up threats to sell off his nation’s oil refineries in the United States, but some oil experts argue a quick break with the key U.S. market would hurt Venezuela.
Tensions between the U.S. and Venezuela escalated with the expulsion of a U.S. Embassy official accused of spying. In return, Washington expelled a Venezuelan official.
Chavez threatened to sell off all of Venezuela-owned Citgo Petroleum Corp.’s refineries and divert U.S. oil exports to other countries.
“I could easily order the closing of the refineries that we have in the United States,” Chavez said Feb. 4 in a speech to supporters. “I could easily sell the oil that we sell to the United States to other countries in the world … (to) real friends and allies like China, India or Europe.”
Chavez’s threat comes amid jitters about a disruption in world oil supplies: Iran, OPEC’s second-largest producer, has been referred to the U.N. Security Council over its nuclear intentions, while Nigeria has been wracked by violence.
“The United States doesn’t face many alternatives at this moment” and could face a hike in oil prices if forced to find replacements for Venezuelan imports, said Carlos Rossi, an economic adviser to the Venezuelan Hydrocarbons Association.
But Rossi and other experts said the bigger loser likely would be Venezuela.
About half of exports to U.S.
The South American country says it exports about half of its official production of 3.2 million barrels per day to the United States — much of that refined by Houston-based Citgo and sold through its 15,000 retail gas stations.
Finding alternatives to Citgo’s refineries — specially designed to refine Venezuela’s heavy, highly sulfurous crude — would be difficult, critics say.
“If they sell these refineries, there are no other refineries in the world able to process Venezuelan crude, not in sufficient capacity,” said Jose Toro Hardy, a Chavez critic and former director of the state oil company, Petroleos de Venezuela SA, or PDVSA.
PDVSA has domestic refineries and smaller operations in Europe, the U.S. Virgin Islands and Curacao, but they don’t have the capacity to take on Citgo’s share.
“You need refineries to sell oil,” Rossi said. “The U.S. would feel the impact, but Venezuela would feel it much more.”
Citgo paid $785 million in dividends to PDVSA in 2005 — revenues that Chavez’s government stands to lose if it sells.
Geography also works against Chavez’s threat of making a clean break with the U.S. market: an oil tanker leaving Venezuela can get to Citgo’s Gulf Coast refineries in five days compared to about 30 days to travel to China.
The United States remains Venezuela’s No. 1 buyer of oil. It relied on Venezuela for 10 percent of its oil imports in November, the latest month for which U.S. figures are available. read more

Mild winter in Western Canada, with early thaw, restricts access to northern Alberta well sites; drilling still at record levels
Gary Park
For Petroleum News
Capital budgets up, land sales up, operator ranks up, drilling predictions up — all the ingredients for another scorching year in Canada’s upstream, except for another mild winter in Western Canada that threatens to turn oil fields mushy.
Across some pockets of British Columbia, Alberta and Saskatchewan the peak drilling season is experiencing some setbacks.
An early thaw is restricting access to well sites in northern Alberta, where a deep freeze is vital to build ice bridges and carry the heavy rig loads.
However, a report by investment dealer Peters & Co. in January said the conditions have not yet caused “wholesale delays in E&P programs,” although weather is “rearing its ugly head” as it did when record spring and summer rains saw producers struggling ever since to meet production goals.
And the first reports on upstream activity show record drilling levels in Alberta, Saskatchewan and Manitoba, with only Northern Canada and British Columbia lagging.
Of the 722 rigs available across Canada a staggering 94 percent were at work during January, compared with 93 percent a year earlier.
Alberta had an average 537 rigs operating, rising to 543 in the final week of January, when 136 were at work in British Columbia and 51 in Saskatchewan.
Association sticks to prediction
Meanwhile, the Petroleum Services Association of Canada is sticking to its prediction of a record 25,295 well completions in 2006.
Peters & Co. is going one better, forecasting 25,500 wells this year and 27,500 in 2007, while the Canadian Association of Oilwell Drilling Contractors is betting on 26,000 wells in 2006.
Drilling contractors President Don Herring and petroleum services President Roger Soucy said the winter melt has yet to affect early-year operations, with active rigs climbing from 539 in the first week of January to 743 by late in the month.
Soucy said with the industry’s growing emphasis on spreading drilling more evenly through the year weather has less affect on operations.
Also contributing to a positive outlook is an increase in the number of operators to 572 in 2005, up 50 from 2004.
A total of eight companies increased their well completions last year by 100 or more wells than in 2004, including Canadian Natural Resources (up 570 wells), coalbed methane producer Trident Exploration (up 277), Apache Canada (up 264), Compton Petroleum (up 188), Nexen (up 156), Pioneer Natural Resources (up 122), Tundra Oil & Gas (up 107) and coalbed methane producer MGV Energy (up 101).
Those whose tally declined included EnCana (down 510), EOG Resources (down 377), Husky Energy (down 221) and Petro-Canada (down 184).
Capital budgets for 76 companies up 27%
Capital budgets for 76 companies stand at C$42 billion, 27 percent above 2005 for those same firms, with heavy spending earmarked for the oil sands.
Heading the list are Canadian Natural C$6.8 billion, EnCana C$6.75 billion, Talisman Energy C$4.4 billion, Suncor Energy C$3.5 billion, Petro-Canada C$3.4 billion, Nexen C$2.89 billion, Husky Energy C$2.85 billion and Shell Canada C$2.7 billion — all except Talisman and Husky heavily committed to the oil sands.
FirstEnergy Capital is predicting that just over C$2 billion will go to coalbed methane, more than C$600 million above 2005, which was affected by the heavy rains, and expects more aggressive coalbed development this year after 2005 saw only a modest increase of 175 million cubic feet per day of production after a net gain of 412 million cubic feet per day in 2004.
The scramble to accumulate exploration rights shows no signs of easing, with Alberta posting a new record C$378 million at the second sale of January when 583,257 hectares (1.44 million acres) at an average C$1,012 per hectare, including 209,152 hectares of oil sands leases that fetched C$217 million.
That has pushed the year-to-date returns to C$591 million, compared with C$108 million for January 2005.
British Columbia has been equally hot, collecting C$52 million from 59,235 hectares and its January auction, beating the comparable 2005 sale by C$24 million, with the per hectare average climbing to C$874 from C$578.
With many observers expecting the land buyers will waste no time moving ahead with their exploration programs, the momentum built up in the second half of 2005 should extend into 2006, weather and available rig hands permitting.
Boosted by the addition of new rigs, a drilling surge after mid-year resulted in 92.46 million feet of hole drilled by all contractors, up 17 percent from the same period of 2004.
For all of last year, the average well took 6.36 days to complete compared with 5.61 in 2004 – the first time in many years that drilling times increased, partly due to a 7 percent rise in average well depth to 3,779 feet.
The dominant contractors were Precision Drilling which posted 27.9 million feet of hole and Ensign Energy Services which tallied 20.4 million feet.
The other major contractors were Savanna Energy Services 8.1 million feet, Nabors Drilling 6.46 million feet, Trinidad Drilling 6.4 million feet and Akita Drilling, the leading contractor in Northern Canada, 4 million feet. read more

Kyoto’s role, using Arctic gas in oil sands and access to pipeline by independent explorers all get aired at Mackenzie gas line hearings
Gary Park
For Petroleum News
It took less than a week for some of the anticipated stickier issues to formally surface in the Mackenzie Gas Project regulatory hearings.
In the first round that ended in Inuvik on Feb. 2, there were few surprises, least of all when the Sierra Legal Defence Fund — representing the World Wildlife Fund Canada and the Sierra Club of Canada —asked whether the Kyoto Protocol has been taken into account by Imperial Oil when it estimates the future demand for natural gas and raised the standard bogey-man that Arctic gas may merely be used as feedstock for developing Alberta’s oil sands.
Defence fund spokesman Paul Falvo told National Energy Board hearings that Imperial may have blundered by not considering whether changes to Canada’s energy policy under Kyoto could affect the long-term viability of the Mackenzie project.
He said any major energy projects should take a serious view of Kyoto if the federal government imposes limits on the consumption of fossil fuels which contribute to greenhouse gas emissions.
Harper may move away from Kyoto
That, however, may be a moot point if the new government of Prime Minister Stephen Harper delivers on its promise to shift Canada away from its Kyoto commitment and seeks a “made-in-Canada” approach to cutting emissions along with an energy policy that ensures maximum benefits are achieved from technology.
One of the nagging questions surrounding the Mackenzie project was also aired by Falvo.

Critics have argued that the bulk of production, whether it’s 1.2 billion or 1.8 billion cubic feet per day, will be shipped directly to the oil sands to support operations by the anchor field owners, Imperial, ConocoPhillips, Shell Canada and ExxonMobil Canada.
Imperial spokesman Pius Rolheiser told the hearing he has grown weary of the claims that there is a direct link between the Mackenzie project and the oil sands.
“It’s simply not true … I don’t know how to say it plainer than that,” he said.
Rolheiser insisted the two developments are completely separate and the Mackenzie would have proceeded with or without the oil sands.
Shipping cost concerns
E&P companies outside the main owners group also introduced their concerns about the cost of shipping gas on the pipeline.
Imperial says all gas producers will have a chance to access the pipeline, but they should be ready to make 15- to 20-year commitments — a demand that troubles smaller companies such as Paramount Resources, who say their medium-sized finds, including an estimated 250 billion cubic feet in Colville Hills, might have only an 8-year lifespan.
Allen Hollingworth, for Paramount, said Imperial’s threshold would force his company to find more gas, or pay more in tolls.
A report by GLJ Petroleum Consultants for Imperial laid out the challenge facing the industry if the Mackenzie pipeline is to have an adequate supply at a price that is profitable for the next 23 years.
It estimates companies will need to drill at least 124 exploration wells in the Mackenzie Delta, 161 in Colville Hills and 23 in the Beaufort Sea to achieve that goal — a drilling level that Falvo worries will put protected areas at risk.
The next round of hearings is due to start by mid-February in Inuvik.
Furor in Northwest Territories legislature
Separately, a furor has surfaced in the Northwest Territories legislature, where Premier Joe Handley has been accused of selling out the territory in a “letter of comfort” delivered to the gas producers in November.
Bill Braden, a member of the legislature from Yellowknife, said that in promising the companies his government won’t raise the resource royalties Handley failed the Northwest Territories.
He said the letter is one of “extreme disappointment” for legislators, communities and northerners.
Handley suggested that Braden did not seem to grasp that while his government was “looking at making a fair fiscal environment, we are looking at resource-revenue sharing.”
In a budget tabled Feb. 3, Finance Minister Floyd Roland unveiled cuts in the corporate tax rate to 11.5 percent from 14 percent effective July 1 to build on the success of a diamond industry and the economic promise of the Mackenzie project.
“To encourage businesses and industry to locate and do business here in the Northwest Territories we have to compete on taxes,” he told the legislature.
“We simply cannot afford to see businesses continue to file their income tax outside of the NWT in order to avoid higher tax rates.”
In a special appeal to Harper, Roland reiterated the NWT’s case to keep more of its resource revenues. Currently it keeps only 20 cents of every dollar it generates. read more

By THE ASSOCIATED PRESS
Published: February 10, 2006
Filed at 2:40 p.m. ET
ENSENADA, Mexico (AP) — In late 2003, Sempra Energy's bid to build the first liquefied natural gas terminal in western North America was in deep trouble. Plans to import gas from Bolivia sparked a popular uprising that killed dozens of people and toppled the government there.
Today, Sempra is leading the race. It turned to Indonesia for the gas, and is building a $1-billion plant on Mexico's pristine coastline, just 50 miles south of San Diego. The terminal, to be completed in early 2008, will be a key fuel source for California homes and businesses for decades to come.
The decision to build in Mexico is paying off big for Sempra, which owns Southern California's two major gas utilities. Rivals who want to build LNG terminals on California's coast are being stymied by environmental and NIMBY — ''not in my back yard'' — groups. For Sempra, the choice was easy.
''The Mexican government had their arms open, saying, 'Please, anybody who wants to build an LNG plant, come here and apply,''' said Donald Felsinger, chairman and chief executive officer.
Sempra isn't the only company using a cross-border strategy in the energy industry's rush to LNG.
Terminals are being built in Canada to fuel the eastern United States — one by Anadarko Petroleum Corp. in Point Tupper, Nova Scotia and one by Repsol YPF in Saint John, New Brunswick. Gas from those plants will be sent on a pipeline that connects to the U.S. grid in Calais, Maine.
LNG is supercooled liquefied gas that is shipped from far-flung countries — Iran, Qatar, Russia and Indonesia are major suppliers — to coastline terminals, where it is heated, vaporized and fed into a pipeline. Sempra and other companies are convinced that LNG is key to keeping a lid on gas prices in the United States as domestic supplies dwindle.
The rub: Many coastal communities don't want massive fuel tankers hogging their shores. Regulators approved five new LNG terminals in Texas and three in Louisiana, but companies have struggled to find a home outside the Gulf of Mexico, particularly in California and New England.
That's not to say that all Mexicans welcome LNG either. Lobster fishermen and the owner of a neighboring resort say Sempra's hulking plant threatens business. Surfers say a phenomenal surfing spot was destroyed after the San Diego-based company began construction in March.
Environmentalists have waged a spirited — and so far unsuccessful — campaign to derail Sempra, regularly blocking traffic at the plant entrance and bringing activists from around the world to rally local opposition. They sued the California Public Utilities Commission in state court last year to force the regulator to reconsider a ruling that cleared the way for Sempra to pipe gas from the plant to the U.S. grid near Tecate, Calif.
Mexican opponents have scored big victories against other companies that planned LNG terminals in nearby cities that, by comparison, made Sempra's location look downright remote. ConocoPhillips Co. dropped plans for a terminal in Rosarito, a spring-break hotspot just 15 miles south of San Diego. Marathon Oil Corp. was forced out in 2004 when municipal authorities seized its beachfront property in the crowded border city of Tijuana.
''They are using Mexico as a dumping ground, as a back door to the United States,'' said Jose Luis Sanchez, 47, an environmental activist in Tijuana.
Sempra says the plant is good for Mexico, which will split the gas with the United States. ''They wanted to make sure that their economy is not stranded, and they've acted,'' said Darcel Hulse, president of Sempra's LNG unit.
The drone of bulldozers and cement trucks fills the air as some of the plant's 820 construction workers labor on a grated hillside of agave and desert shrub one recent morning. Cranes hover above the concrete foundation of two giant cylindrical tanks that will store the liquid gas.
The plant sits on a 395-acre lot on the northern edge of Ensenada, a port city of 250,000 people. When finished, it will process up to 1 billion cubic feet of gas daily — equal to about one-sixth of California's consumption — and there's enough room to more than double capacity to 2.5 billion cubic feet a day.
A tiny fishing village of about a dozen makeshift trailers lies next to the plant. Men fish for lobster, crab and sea cucumber in a stretch of ocean also populated by seals, dolphins and whales. Renato Gonzalez, 32, ekes out a living finding starfish, which are sold to tourists in Tijuana.
''What can we do?'' Gonzalez said as he waited for the sunlight to bake dozens of starfish on a wire-mesh table. ''It's a very powerful company. We don't have a choice.''
Mario Loera, who has fished for lobster for 13 years, said he will move in 2008, when the plant begins operations. ''I still have two years to go.''
Sempra, which was formed in 1998 in the merger of Southern California Gas Co. and San Diego Gas & Electric Co., has transformed from a stodgy utility to a diversified company that builds pipelines and power plants.
In 2000, the company turned suspicious of forecasts by the U.S. government and industry consultants that domestic natural gas would remain cheap and plentiful.
A company researcher pored over microfiche showing drilling patterns going back to the early 1900s. Employees scoured public records in Texas, New Mexico and Oklahoma. Their conclusion: the United States cannot produce enough gas to feed itself and will turn increasingly to imports, just as it did with oil.
Sempra's dour outlook became the premise for a $2.9-billion investment in LNG. Aside from Mexico, it began building a $950 million terminal near Lake Charles, La., last year and plans to start on a $700 million plant next year in Port Arthur, Texas.
Sempra was sent scrambling in late 2003 when plans collapsed to import the gas to Mexico from Bolivia on a pipeline to Chile's north coast. The project rekindled old animosities from a 19th-century war that left Bolivia landlocked, and violent protests toppled the government.
Things quickly turned in Sempra's favor. It signed a 20-year agreement with BP PLC to import liquefied gas from Indonesia, and defrayed costs by agreeing to rent half the Mexican plant to Royal Dutch Shell Group of Cos.
Environmentalists say their fight to block the Sempra is far from over, but they face a formidable foe.
In 2002, environmentalists sued the U.S. Department of Energy in U.S. federal court to prevent Sempra from sending power to the United States from its new electricity plant in the Mexican border city of Mexicali. Critics said Sempra was exploiting Mexico's looser regulations. Sempra said shutting the power lines would raise prices for U.S. consumers.
The environmentalists sought an injuction to stop the power transfer. Sempra won that round, but the case continues. read more

By THE ASSOCIATED PRESS
Published: February 10, 2006
Filed at 4:24 p.m. ET
WASHINGTON (AP) — The United States is increasingly going overseas to meet its natural gas needs, setting in motion a significant shift with a familiar, if unpleasant, side effect for the world's largest energy consumer.
As America becomes a bigger player in the global natural-gas trade, its vulnerability to faraway production snags and price gyrations will rise, as will its dependence on energy from the Middle East and other volatile regions.
Unlike oil, natural gas has for decades had the advantage of being a local energy source. It either came from within the United States or by pipeline from Canada. But as North American supplies dwindle and demand grows, the energy industry is investing billions of dollars to ship the fuel across oceans as liquefied natural gas, or LNG.
LNG is still a relatively small source of supply for the U.S. But imports are expected to rise fivefold over the next decade, intensifying the competition with Europe and Asia for natural gas coming primarily from the Middle East, West Africa and countries formerly part of the Soviet Union.
''There's a geopolitical overlay that's going to look similar to oil,'' said Michael Zenker, managing director of the global natural gas team at Cambridge Energy Research Associates.
Which means the price that American homeowners, manufacturers and power plants pay for natural gas will increasingly be linked to the weather in Europe and the pace of economic growth in Asia — not to mention the political stability of countries such as Russia, Iran and Qatar, which combined hold more than half of the world's natural gas reserves.
The reverse is also true. ''A surge in U.S. demand could effectively raise the price for spot LNG cargoes, affecting the price in Japan and other countries,'' said George Beranek, a manager in the global gas group at PFC Energy in Washington.
Fuel-hungry America is already the third largest LNG importer behind South Korea and Japan, according to Energy Department statistics. Spain and France are other major importers today, while China and India are expected to be significant players down the road.
Until recently, the North American natural-gas market was an island unto itself with an abundant resource, and prices were relatively cheap. A supply disruption in the Gulf of Mexico might temporarily drive up prices, but a problem with natural gas output in the Persian Gulf would have virtually no impact.
The fact that natural gas is cleaner-burning than heating oil and coal only burnished its public image, and demand grew rapidly during the 1990s as it became the fuel of choice for heating new homes and running new power plants.
Gradually, though, U.S. — and then Canadian — output began to taper off. Producers drilled many more wells, but still could not offset the depletion of existing wells while satisfying rising demand.
To bridge the gap, LNG imports tripled in the '90s, rising to 226 billion cubic feet per year by 2000. And they nearly tripled again by 2004, climbing to 652 billion cubic feet, or 3 percent of the country's total natural gas consumption.
But there is still not much of a supply cushion in the U.S. natural-gas market, which is a major reason why prices climbed steadily in recent years — and then skyrocketed after Hurricane Katrina disrupted output in the Gulf of Mexico. Natural gas futures averaged $9.01 per 1,000 cubic feet in 2005, more than five times the price in 1995.
Meeting the country's anticipated demand by 2015 could require the U.S. to import more than 10 billion cubic feet per day of LNG, according to government and industry statistics. That's greater than the amount of gas it will get from Canada via pipeline.
The competition for LNG will be most pronounced in the spot market, a small piece of the global trade in which tankers are usually directed on short notice to wherever the price is highest. But analysts said it could also affect long-term supply contracts because those deals are benchmarked to futures prices, which rise and fall based on short-term events. The U.S. buys LNG primarily on the spot market.
The industry prefers to sell at least a portion of its LNG through long-term agreements to help pay for the large capital investments needed to build critical infrastructure, including plants to liquefy the natural gas, refrigerated double-hulled ships to transport it and terminals on the receiving end to regasify the fuel. It also gives producers a measure of confidence that there will be a market for their supply.
Indeed, companies such as Exxon Mobil Corp., Royal Dutch Shell Plc and BG Group — the largest importer of LNG into the U.S. — are making multibillion-dollar investments up and down the LNG supply chain, creating what one BG executive referred to last fall as a ''global virtual pipeline.'' The U.S. has five LNG import terminals today, with four more under construction and dozens more proposed.
Some analysts say the U.S. is already feeling the impact of global events that a decade ago would not have registered the slightest ripple in its natural gas market.
For example, UBS natural gas analyst Ronald Barone noted in a recent report how U.S. supplies tightened in January because LNG originally scheduled for delivery at a terminal in Cove Point, Md., was redirected to Europe. European demand for natural gas rose over the past year, analysts said, because of a new import terminal in Britain and a drought that sapped strength from Spain's hydropower sector.
In fact, much of the LNG shipped to the U.S. from Trinidad — the biggest supplier to the U.S. — is actually contracted for delivery to Spain, which resells the fuel it does not need into the U.S. market. But as Spanish utilities required more LNG to help fuel power plants, fewer shipments were available to the U.S.
''When things go bad, the U.S. is currently the one that suffers worst because it's mostly a spot market. It's the market of last resort,'' said Gavin Law, head of the global LNG practice at consultant Wood Mackenzie in Houston.
But Cambridge Energy's Zenker said there's another way to look at the situation, one that underscores how the booming LNG business is rapidly connecting natural gas consumers around the globe like never before.
In order to lure back LNG cargoes from the U.S., Spanish utilities paid a premium to the already soaring market price at the Henry Hub, a key Gulf Coast delivery point.
''One could say the Spaniards are paying a price for U.S. hurricanes,'' Zenker said. read more

By REUTERS
Published: February 10, 2006
Filed at 5:07 p.m. ET
WASHINGTON (Reuters) – The U.S. government should share more of the royalties it collects from energy companies for offshore oil and natural gas drilling with the states, particularly to help rebuild hurricane-ravaged Louisiana, a top Shell Oil executive said on Friday.
Gulf Coast states that have offshore drilling collect royalties for oil and gas production in the their waters which usually extend only a few miles from shore. Any exploration beyond that is in federal waters, where the government collects royalties that go to the general treasury to pay for various programs benefiting the whole country.
Marvin Odum, who is responsible for Shell's energy exploration and production businesses in the United States and the rest of the North and South America, said he supports efforts by the Gulf Coast states and local communities to get some of the federal oil and gas revenue.
“It's certainly something that we think the government can and should push through,'' Odum said in a interview with Reuters.
Louisiana Gov. Kathleen Blanco said this week she wants the government to give the state 50 percent of the federal offshore royalties to help repair coastal wetlands left vulnerable to hurricanes due to oil industry development.
While Odum supports revenue sharing, he would not comment on how much federal royalties Louisiana or any other state should get or what they should spend it on.
“That's between the states and the federal government, that's what they need to work out,'' he said. “Whether or not Louisiana would choose to use some of that money specifically for hurricane restoration and recovery, obviously that's a great need, that would be again a government decision.''
Separately, Odum said “quite a bit'' of the $15 billion that Shell's parent company, Royal Dutch Shell Plc, plans to spend worldwide this year for oil and gas exploration and production will be targeted for the United States.
While that amount reflects higher drilling and exploration costs, he said there will still be money for new investment. ''It's a significant increase in activity worldwide,'' he said.
In the United States, he said Shell will focus on drilling for new oil in the deeper waters of the Gulf of Mexico and off the Alaskan coast, and developing natural gas resources from south Texas through the Rocky Mountain region.
The company will also invest in developing the vast oil shale resources in the Western United States, which the government estimates holds more than 1 trillion barrels of oil.
Oil shale is sedimentary rock containing organic material that can be crushed and heated to produce oil. The process is a costly one, and most U.S. oil shale projects were abandoned in the early 1980s when crude prices collapsed.
However, with oil prices expected to average above $60 a barrel in the next two years, oil shale development looks profitable again.
Odum said the company will know in about five years whether developing oil shale is commercially viable.
He said the government should open more offshore and onshore areas to drilling to help reduce U.S. reliance on foreign oil imports.
Odum declined to say whether President Bush's goal of cutting U.S. Mideast oil imports by 75 percent in 2025 could be reached.
However, he said even if more areas are opened to drilling the United States will still be heavily dependent on foreign suppliers to meet its energy needs over the next two decades. ''I think that's a reasonable case,'' he said. read more

Sam Fletcher
Senior Writer
HOUSTON, Feb. 10 — The oil and gas industry must apply new technologies on unprecedented scale and pace to meet the world's expanding demand for fossil fuels, said Jeroen van der Veer, chief executive of Royal Dutch Shell PLC, at the Cambridge Energy Research Associates annual energy conference in Houston.
With continued economic growth, the world's energy needs could increase by 100 million b/d of crude over the next 25 years—”more than we added over the past quarter century,” Van der Veer said. Most of that increased demand will be in new markets where infrastructure and international trade must be developed. “And this has to go together with cutting carbon dioxide emissions from energy,” he said.
“I have a vision of green—or greener—fossil fuels with much of their carbon dioxide captured and sequestrated either underground or in inert materials,” Van der Veer said. “A typical 1 Gw coal-fired power plant produces the same carbon emissions as 1.5 million cars. China alone is building about 17 of these plants a year. That's why I think sequestration for power plants should be a priority.”
Alternative energy sources
Consumption of liquefied natural gas could double over the next decade, depending on “technological as well as commercial innovation,” said Van der Veer. Gas-to-liquids technology also “will be increasingly important, providing high-quality fuels to help reduce transport emissions.” Other large unconventional resources include heavy oil, oil sands and shales, “contaminated” and tight gas, coalbed methane, and “lots of coal, particularly in countries like the US and China,” he said. Royal Dutch Shell and other major oil companies are involved in developing those resources.
The biggest benefit, said Van der Veer, would be to increase the amount of crude recovered from reservoirs. That can be done through “smart technology” that allows engineers to monitor and control development and production. Enhanced oil recovery techniques using heat, gas, or chemicals to increase the oil flow are costly, complex, and technically demanding but will be increasingly important, he said.
The challenge facing the industry is to deliver the necessary technology. “That means applying advances on the scale necessary to make real progress,” Van der Veer said. “It means learning from experience to use them increasingly effectively and quickly sharing that learning around the world. It means integrating many technologies because that's where the real benefits come in this complex business. It means applying those technologies in increasingly demanding projects—accessing more difficult resources and creating the complex chains needed to deliver the energy people need.”
Van der Veer also sees a growing need for energy efficiency. “I believe the world is just starting this journey, partly because it is politically painful to push forward changes that must involve all energy users,” he said.
The technology to develop those new energy sources depends on experienced workers in the industry. Shell is focusing on global recruitment of new employees, “with considerable success last year,” Van der Veer said.
“In North America and Europe, fewer young people pursue scientific and technical education. Here in the US, for example, the number of university students studying petroleum engineering has fallen by more than 80% since the early 1990s,” he said. “We need to convince young people that a technical career in this industry is both stimulating and worthwhile.”
The International Energy Agency, Paris, estimates the oil and gas industry will have to invest $17 trillion by 2030 to meet the world's future energy needs.
“Oil and gas prices have risen. But so have industry costs. And developing more difficult resources will mean higher unit investment,” Van der Veer said. “Given the urgent investment needs, exacting 'windfall' taxes is counterproductive, particularly in an industry with a history of volatile prices. In an increasingly uncertain world, long-term investors need predictable terms.”
Contact Sam Fletcher at [email protected]. read more

All indications are that Shell, Statoil and their supporters in Government are preparing for a full scale re-invasion of North Mayo.
The Rossport Solidarity Camp is busy recruiting volunteers to resist the unwanted pipeline and refinery project. Legal, fundraising and awareness work continues throughout the country and abroad and spirits are high.
The momentum is rising and we are confident that PEOPLE POWER will win the day. This is only possible with the support of all the great individuals and groups from all over – the people who've rang in radio shows, written letters to papers, made donations, attended protests, stayed at the camp, supported the community, organised meetings, boycotted Shell and Statoil, and sent out an international message that PEOPLE AND THE ENVIRONMENT MUST COME BEFORE PROFIT!!
Please continue to do all you can to help out in whatever way, however small.
[email protected] read more

TRANSCRIPT OF VIDEO
Introduction
Hello and welcome to our weekly look at what's been happening in the markets and how it affects you and your pocket. I am Matthew Vincent, Editor of Investors Chronicle, so lets have a look at the stories in this week's edition.
Everybody's talking about them – oil companies' reserve replacement ratios. We explain what they are and why they matter.
BAA finds itself being courted by a Spanish suitor but will it succumb to Ferrovial's Iberian charms.
And this latest curious website is the latest wheeze from the Financial Services Authority aimed to educate the public about the murky world of finance.
Reserve replacement ratios
Q.
Now, reserve replacement ratios are terribly important things when it comes to judging the strength of our two major oil players. So, to find out exactly what they are and why I should sit up and pay attention to them, I am joined by Investors Chronicle's online Editor, Jonathan Ely. Jonathan, everyone's been paying an awful lot of attention to the profits made by Shell and BP but why are the reserve replacement ratios important?
A.
Well Matthew, oil is getting more and more difficult and expensive to find. Companies are having to operate in geographically very remote locations and in quite inhospitable environments to find the reserves they need to replace the oil they are already taking from the ground. A lot of the oil that is coming out of the ground is in very nice, safe, known about locations such as Alaska or the North Sea. A lot of the oil that they are replacing that production with is from much more tricky environments.
Q.
How will all this affect the prospects for Shell and BP?
A.
Well, if we look at Shell, they really have had substantial problems replacing their reserves over the past year. If you go back further in history, Shell has actually been quite successful at replacing reserves. Now the big worry for Shell is that if they continue to struggle to replace the reserves, they will be forced to go out and make an acquisition. And with oil prices where they are in the cycle at the moment, now is emphatically not the time to be doing the big acquisition, especially as they will have to compete with Chinese and Indian companies who are usually state run and are not answering to shareholders. Their goal is to secure oil reserves for strategic national reasons rather than for wealth creation.
Q.
And the billion dollar question for investors – what is your recommendation on Shell and BP shares?
A.
Well historically at the Investors Chronicle we have been very keen on Shell because they had this mighty credit rating – AAA credit rating – so it was almost like owning government debt, and it paid this wonderful dividend yield and dividend was declared in sterling and paid in sterling. Now, Shell's finances don't look quote so secure as they once did, although they are still very solid and, in addition, the dividend is now declared in euros and converted to sterling so there is an element of currency risk that wasn't there before.
Now if you add in the risk of them doing a big expensive acquisition and if you add in things like the project management failures that we've seen over the past year or so, particularly the major cost overrun on the Sakhalin Project in the Russian Far East, then Shell looks a lot more risky a proposition than it did even a few years ago.
At BP, the management there has done a much better job. They have been the first mover. They were the first company to do these very big acquisitions back in the late 90s. They stole a march on everybody else into Russia and, of course, Lord Brown, BP's Chief Executive, is very highly regarded in the City. So, at the moment, we think that their shares are the better bet, even though they are marginally more expensive in relative terms than those of Shell. Q.
Well Jonathan, I think I'd better go and buy a new pocket calculator. Thank you very much.
A.
Thank you.
Matthew Vincent is Editor of the Investors Chronicle – the UKs leading retail investor magazine. Click here for www.investorschronicle.co.uk read more

By EDMUND L. ANDREWS
and SIMON ROMERO
Published: February 10, 2006
WASHINGTON, Feb. 9 — More than three dozen energy companies fell nearly $500 million behind last year on royalty payments the federal government says they owed for oil and gas extracted from public territory, according to Interior Department documents released Thursday.
While most of that money was later turned over after the government demanded payment, almost $60 million remains in dispute.
The companies, which included major producers like Chevron, Shell and ConocoPhillips, had claimed lucrative government incentives for drilling in the Gulf of Mexico even though the incentives were not supposed to be available if market prices climbed above certain “threshold prices.”
The Interior Department, in a report sent to lawmakers looking into the energy royalty program, identified 41 companies that incorrectly claimed about $493 million in “royalty relief” during 2004, when prices for both oil and gas climbed to records.
The Interior Department said that 38 of the 41 companies quickly paid $435 million in back royalties after it sent out warning letters in December, months after the money should have been paid.
But three companies — Kerr-McGee, Forest Oil and AGIP — continue to protest $58 million in additional payments.
Indeed, Kerr-McGee officials suggested on Thursday that they planned to challenge the government's legal authority to impose price thresholds in the first place.
“We pride ourselves on operating legally,” said John Christiansen, a spokesman for Kerr-McGee, which is based in Oklahoma City. “Now the Interior Department is claiming it has the power to cancel royalty relief granted by Congress.”
Mr. Christiansen said Kerr-McGee would fight the case if the government did not back down. “We'll take this issue to the federal court system if necessary,” he said.
Royalty payments for oil and gas extracted from federal territory have drawn increased attention from Congress since The New York Times reported last month that payments had not climbed in line with the huge increase in market prices.
Last year, the government received about $5.15 billion in royalties on natural gas and about $3.5 billion in royalties on oil. While royalties have climbed sharply since 2003, they are still barely even with amounts collected in 2001, when market prices were much lower.
One apparent reason for the shortfall is that the government has had trouble auditing the flow of money.
Under the government's royalty relief program, companies that drill in deep waters off the Gulf of Mexico do not have to pay the standard royalty of 12 percent on large quantities of the oil or gas they produce.
But federal regulations also call for that special incentive to be suspended if market prices rise above certain threshold levels. Market prices for both oil and natural gas have been higher than those levels since the end of 2002.
Administration officials said Thursday that they sent out letters to 41 companies in December, almost a full year after the end of 2004, reminding the companies that they had not been entitled to the incentives and needed to pay up.
The list included many of the biggest producers in the Gulf of Mexico: Anadarko, Amerada Hess, British Petroleum, Chevron, ConocoPhillips, Kerr-McGee, Shell and more than two dozen others.
But several major producers, like Exxon Mobil, the sixth-largest producer of natural gas in the Gulf of Mexico, were not on the list. Exxon officials said that their company stopped claiming royalty relief long ago, because market prices had exceeded the price thresholds.
Lawyers for some of the companies said that they should never have been included on the list released by the Interior Department, because the companies had actually paid the proper royalties or had not disputed the demand for additional royalties.
“We think it was inappropriate for Chevron and Unocal to have been included on the list,” said Donald Campbell, a spokesman for Chevron, which acquired Unocal last year.
“Chevron's policy is to pay royalties when deepwater lease price thresholds are exceeded,” Mr. Campbell said. “Based on our review to date, Chevron has consistently followed that policy and has paid royalties for the calendar years when lease price thresholds have been exceeded.”
Edmund L. Andrews reported from Washington for this article and Simon Romero from Houston. read more

By EDMUND L. ANDREWS
and SIMON ROMERO
Published: February 10, 2006
WASHINGTON, Feb. 9 — More than three dozen energy companies fell nearly $500 million behind last year on royalty payments the federal government says they owed for oil and gas extracted from public territory, according to Interior Department documents released Thursday.
While most of that money was later turned over after the government demanded payment, almost $60 million remains in dispute.
The companies, which included major producers like Chevron, Shell and ConocoPhillips, had claimed lucrative government incentives for drilling in the Gulf of Mexico even though the incentives were not supposed to be available if market prices climbed above certain “threshold prices.”
The Interior Department, in a report sent to lawmakers looking into the energy royalty program, identified 41 companies that incorrectly claimed about $493 million in “royalty relief” during 2004, when prices for both oil and gas climbed to records.
The Interior Department said that 38 of the 41 companies quickly paid $435 million in back royalties after it sent out warning letters in December, months after the money should have been paid.
But three companies — Kerr-McGee, Forest Oil and AGIP — continue to protest $58 million in additional payments.
Indeed, Kerr-McGee officials suggested on Thursday that they planned to challenge the government's legal authority to impose price thresholds in the first place.
“We pride ourselves on operating legally,” said John Christiansen, a spokesman for Kerr-McGee, which is based in Oklahoma City. “Now the Interior Department is claiming it has the power to cancel royalty relief granted by Congress.”
Mr. Christiansen said Kerr-McGee would fight the case if the government did not back down. “We'll take this issue to the federal court system if necessary,” he said.
Royalty payments for oil and gas extracted from federal territory have drawn increased attention from Congress since The New York Times reported last month that payments had not climbed in line with the huge increase in market prices.
Last year, the government received about $5.15 billion in royalties on natural gas and about $3.5 billion in royalties on oil. While royalties have climbed sharply since 2003, they are still barely even with amounts collected in 2001, when market prices were much lower.
One apparent reason for the shortfall is that the government has had trouble auditing the flow of money.
Under the government's royalty relief program, companies that drill in deep waters off the Gulf of Mexico do not have to pay the standard royalty of 12 percent on large quantities of the oil or gas they produce.
But federal regulations also call for that special incentive to be suspended if market prices rise above certain threshold levels. Market prices for both oil and natural gas have been higher than those levels since the end of 2002.
Administration officials said Thursday that they sent out letters to 41 companies in December, almost a full year after the end of 2004, reminding the companies that they had not been entitled to the incentives and needed to pay up.
The list included many of the biggest producers in the Gulf of Mexico: Anadarko, Amerada Hess, British Petroleum, Chevron, ConocoPhillips, Kerr-McGee, Shell and more than two dozen others.
But several major producers, like Exxon Mobil, the sixth-largest producer of natural gas in the Gulf of Mexico, were not on the list. Exxon officials said that their company stopped claiming royalty relief long ago, because market prices had exceeded the price thresholds.
Lawyers for some of the companies said that they should never have been included on the list released by the Interior Department, because the companies had actually paid the proper royalties or had not disputed the demand for additional royalties.
“We think it was inappropriate for Chevron and Unocal to have been included on the list,” said Donald Campbell, a spokesman for Chevron, which acquired Unocal last year.
“Chevron's policy is to pay royalties when deepwater lease price thresholds are exceeded,” Mr. Campbell said. “Based on our review to date, Chevron has consistently followed that policy and has paid royalties for the calendar years when lease price thresholds have been exceeded.”
Edmund L. Andrews reported from Washington for this article and Simon Romero from Houston. read more

UNAUTHORIZED PUBLICATION – EDITED EMAIL RECEIVED FROM DR JOHN HUONG AND PUBLISHED SOLELY AT OUR INITIATIVE.

Dear Mr. Donovan’s,
Good evening

“The world is not running out of energy,” van der Veer said today at an energy conference in Houston sponsored by Cambridge Energy Research Associates.”
I cannot understand this news. I know that he and his company have a reputation for being rather optimistic over reserves but this is surely stretching credulity into the realms of the surreal.

His conclusion seems to be at odds with the assessment of most experts. What is he on? I could do with a dose because I have eight companies suing me. read more

CHICAGO — General Motors will add 26 E85 refueling pumps to Chicago-area stations through collaborative partnerships with Shell Oil Products US and VeraSun Energy Corp. to boost the use and awareness of ethanol-based E85 fuel in the United States, reported Agriculture Online.
South Dakota-based VeraSun Energy, the nation's second-largest producer of ethanol, announced the availability of VE85 at 20 Gas City stations in the Chicago metro area. VE85 is VeraSun's branded E85, according to the report,
Shell will participate in a test pilot with GM to gauge consumer interest in alternative fuels by monitoring behavior at the pump. The company will supply E85 refueling pumps at approximately six stations in Chicago, Agriculture Online reported.
GM already has 1.5 million flexible-fuel vehicles on the road, which can run on any combination of gasoline and/or E85, a fuel blend of 85 percent ethanol and 15 percent gasoline. The company has nine models that are E85-capable, and says it plans to add more than 400,000 E85-capable vehicles to the fleet in 2006, according to the report.
Later this year, all new GM FlexFuel vehicles will be equipped with yellow fuel caps at the factory to remind owners that their vehicles are E85-capable. Some current owners will receive the special caps as well, reported Agriculture Online. read more

The Ijaw have threatened more attacks on oil installations
A militant Nigerian group says it believes that the government intends to assassinate two jailed leaders of the Ijaw ethnic group and said it will resume attacks on oil industry targets soon.
The group kidnapped four foreign oil workers for 19 days last month during a campaign of sabotage that crippled a tenth of Nigeria's oil output and pushed world oil prices to a four-month high. They had demanded the release of the two Ijaw leaders and local control over the delta's oil wealth.
In an email sent to Reuters on Thursday, the Movement for the Emancipation of the Niger Delta (MEND) said: “We believe the Nigerian government intends to poison these individuals and [we] warn of terrible consequences should this plan materialise.
“We will resume our attacks on oil installations of our choosing with effect from the second week in February.”
MEND is also demanding $1.5 billion in pollution compensation to villages from Royal Dutch Shell.
Treason charges
The jailed Ijaw leaders are Diepreye Alamieyeseigha, the former governor of Bayelsa state, and Mujahid Dokubo-Asari, a militia leader.
Alamieyeseigha was charged with money laundering in December and is on trial for corruption.
He was taken to hospital at the weekend for an unexplained illness, prosecutors said.
Asari, who faces treason charges, was removed from prison in Abuja on Wednesday and taken to an undisclosed location for his own safety, police said.
The militants waged a six-week campaign of violence against the oil industry during which Royal Dutch Shell to cut 221,000 barrels a day of output.
The company later resumed production at its 115,000 barrels-per-day EA oilfield where the abduction took place. The rest is expected back shortly, sources said.
Shell warned
The militants warned Shell not to repair its damaged pipelines and oil platforms and said contractors caught at previously attacked installations would be killed.
Statement by the Movement for the Emancipation of the Niger Delta
“We will attack these companies and facilities with unimaginable ferocity as we have no intention of taking hostages in future attacks,” the group said.
The militants had warned foreigners last month to leave the delta, which pumps most of Nigeria's 2.4 million barrels of oil a day, and said they aimed to cut exports by 30% this month.
The hostages – an American, Briton, Bulgarian and Honduran – were released on 30 January, but the government has not disclosed the terms of the deal.
One militant source said 100 million naira ($770,000) was paid to the kidnappers, but this was denied by the militants themselves.
Poor villagers feel cheated out of their resources by oil firms
Olusegun Obasanjo, the Nigerian president, had denounced the kidnappers as “rascals who are practising the things they watch on television”, but diplomats fear that they may represent a new, more dangerous threat to the oil industry.
Oil industry kidnappings and sabotage are frequent in the Niger Delta, where poor fishing villages are reluctant hosts to a multi-billion dollar industry.
Many in the region feel cheated out of their resources by the oil firms and central government, and some of the militants' demands have been echoed by local politicians.
Industry officials estimate that about 100,000 barrels a day of crude oil is stolen from pipelines in the delta by criminal syndicates working with international smuggling rings.
Much of the money is spent on arms, fuelling a cycle of violence. read more

VIEWPOINT
Andrew Simms
The fossil fuel industry is a major source of tax revenue for western nations, which is a disincentive to cutting greenhouse gas emissions, says Andrew Simms in this week's Green Room. But while some of that taxation depends on the huge profits reported by companies like BP and Shell, he argues they would be bankrupt if the taxes they paid reflected the social costs of their emissions.
The UK appears to be in denial as it becomes more deeply addicted to oil and its profits
The last week has raised a new problem of substance abuse in Britain.
In a world of growing climate chaos and oil scarcity, at least US President George Bush admitted his country's “serious problem” of fossil-fuel addiction.
But the UK appears to be in denial as it becomes more deeply addicted to oil and its profits, raising the real danger that growing oil revenues could become a big disincentive to cut oil use and tackle global poverty.
Oil magnate J Paul Getty set the template for 20th Century inequality when he declared: “The meek shall inherit the Earth, but not its mineral rights.”
Based on statistics from the International Energy Agency (IEA), an average US citizen will in a single day generate as much of the chief greenhouse gas, carbon dioxide, as someone in China does in more than a week.
For someone in Tanzania to generate the same amount would take a staggering seven months.
Such inequality is a major barrier to agreement on international environmental action.
Shell: In profit only because of 'fantasy economics'?
The UK and the US became rich by burning more than their fair share of a finite inheritance of fossil fuels.
Now the profits of oil companies like Exxon, Shell and BP are breaking records and worsening the addiction.
The consequence is a creeping climate chaos that disproportionately affects some of the world's poorest and most vulnerable places like Bangladesh, the South Pacific islands and sub-Saharan Africa.
To halt this climate chaos, we must reduce burning of fossil fuels; yet our global economy depends on them for about 80% of its primary energy.
Rising growth, increasing demand for fossil fuels, climate concerns; the outcome will be higher prices. The poor, already deprived of their equitable share of the world's energy, are likely to see their share shrink even further, just as they bear the biggest burden of climate change.
In a carbon-constrained world, the energy pie can only shrink; who gets what becomes the crucial question.
Trickle down, flood up
Virtually all conventional economists say economic growth is the answer to poverty.
But more growth means more greenhouse gas emissions, and in turn more rapid climate change which then hurts the poorest most.
If growth brought other benefits to the poorest, this might still be a path with merit. But our latest research at Nef, the New Economics Foundation, shows that wealth is not trickling down, it is flooding up.
Between 1990 and 2001, just 60 cents of every $100 of extra global income from growth went to reduce poverty for those living on less than $1 a day.
In the previous decade, the figure was $2.20 per $100.
In the 1990s, then, it took an extra $166 of production and consumption – with all its associated environmental damage – to generate each $1 of poverty reduction.
In environmental terms, it is a suicidally low level of economic efficiency, as the world's poor miss the benefits of growth but pay its costs.
Climate change becomes an ecological debt.
Tax and burn
So what are the chances of western governments such as Britain's, which have standing commitments on eradicating poverty, linking their programmes in this arena to their policies on curbing greenhouse gas emissions?
Not good, it would appear; not only do our homes, transport, and food system rely on fossil fuels, but so does the public purse.
For someone in Tanzania to generate the same amount of CO2 as the average American generates in a day would take a staggering seven months
Our new calculations from research in progress with WWF, based on Treasury statistics, show that UK government income from the fossil fuel sector – conservatively estimated at £34.9bn ($61bn) – is greater than revenue from council tax, stamp duty, capital gains and inheritance tax combined.
Policies aimed at reducing carbon emissions could therefore have a major impact on the government coffers; a serious disincentive to action.
But even this level of revenue from the fossil fuel sector does not reflect the true cost of its environmental impact.
Treasury estimates suggest that the environmental damage per tonne of carbon dioxide could be around £20 ($35).
Combining the emissions that stem from BP's direct activities and the sale of its products leads to 1,458m tonnes of CO2-equivalent entering the atmosphere, with a damage bill of £29bn ($51bn).
Subtracting that from the £11bn ($19bn) annual profit it has just reported puts it £18bn ($31bn) in the red; effectively bankrupt.
The same calculation puts Shell £4.5bn ($8bn) in the red, even as it reports an annual profit of £13bn ($23bn).
That is how unsustainable the economy has become.
Fossil-fuelled fantasy
The way we view economic success in the UK has become a fossil-fuelled fantasy.
No accounting system with a hint of common sense would view profiting from the liquidation of a never-to-be-repeated natural asset as a good thing, even less so when it leads to global warming.
Sweden kicks the oil habit
Yet the UK's economic addiction to oil is set to deepen. There is talk of a windfall tax; and in his pre-Budget report, Chancellor Gordon Brown announced measures that will increase revenues from North Sea oil by £3.9bn ($6.8bn) during this financial year, and a further £2.6bn ($4.5bn) next year.
The only possible justification will be if these amounts go towards a major economic detox diet to cure the UK of its fossil fuel habit, following Sweden's recent lead.
This would pay for a huge roll-out of clean renewable energy technologies, and to redesign the UK's hopelessly inefficient energy system and national grid in favour of a more decentralised power supply.
We could also pay up our shamefully overdue contributions to special funds set up to help poor countries adapt to climate change.
The economic detox diet would mean Gordon Brown and Tony Blair delivering on three key issues:
putting human well-being at the heart of the political agenda instead of growth
implementing aggressive plans to cut our own emissions
pushing for the next phase of the Kyoto Protocol to cap global emissions at a safe level, and give developing countries their fair and equal share of the greenhouse gas emissions pie.
Anything less will mean the UK as an addict slipping into potentially fatal decline.
Andrew Simms is policy director of the New Economics Foundation (Nef) and author of Ecological Debt: the Health of the Planet and the Wealth of Nations
The Green Room is a series of environmental opinion articles running weekly on the BBC News website read more

By Richard Black
Environment Correspondent, BBC News website
The huge profits reported by oil and gas companies would turn into losses if the social costs of their greenhouse gas emissions were taken into account. That is the conclusion of research by the New Economics Foundation (Nef).
Nef found that the £10bn-plus profits just reported by Shell and BP are dwarfed by costs of emissions associated with their products.
Nef also suggests UK Treasury revenues from oil and gas may be a disincentive to curbing greenhouse gas emissions.
The comments come in an article for The Green Room, the BBC News website's weekly series of opinion pieces on environmental issues.
Reporting previously undisclosed figures, Nef's policy director Andrew Simms writes: “Our new calculations from research in progress with WWF, based on Treasury statistics, show that UK government income from the fossil fuel sector – conservatively estimated at £34.9bn ($61bn) – is greater than revenue from council tax, stamp duty, capital gains and inheritance tax combined.
“Policies aimed at reducing carbon emissions could therefore have a major impact on the government coffers; a serious disincentive to action.”
Profits into loss
But, Nef concludes using more government figures, this revenue does not reflect costs associated with climate change resulting from burning oil and gas.
Andrew Simms: Carbon addicts and climate debt
A report prepared for Defra and the Treasury estimates that each tonne of carbon dioxide emitted costs about £20 ($35) in environmental damage.
“Combining the emissions that stem from BP's direct activities and the sale of its products leads to 1,458m tonnes of CO2-equivalent entering the atmosphere, with a damage bill of £29bn ($51bn),” writes Andrew Simms.
“Subtracting that from the £11bn ($19bn) annual profit it has just reported puts it £18bn ($31bn) in the red; effectively bankrupt.
“The same calculation puts Shell £4.5bn ($8bn) in the red, even as it reports an annual profit of £13bn ($23bn).”
Both Shell and BP contend they are investing in renewable energy schemes and other initiatives to reduce greenhouse gas emissions.
Like other members of the European Union, Britain is signed up to the European Emissions Trading Scheme, which aims to reduce greenhouse gas production from industry.
But Tony Blair, along with other European leaders, has been accused by environmental groups of having no policies to reduce emissions from transport, the principal user of oil.
Earlier this week the RAC Foundation suggested a major hike in vehicle excise duty for petrol-thirsty cars.
Nef believes the government has to link its commitments to poverty reduction into domestic policies on energy use and climate change.
Otherwise, it warns, the world's poor will suffer, being less able to afford energy as prices rise, yet the most vulnerable to impacts of climate change.
[email protected] read more