Bolivia/Uruguay invite
Paraguay to pipeline project
14-03-06 Source: Dow Jones
Bolivian President Evo Morales and Uruguayan counterpart Tabare Vazquez
agreed to consider building a natural gas pipeline linking their
respective countries and invited Paraguay to join the project.
The pact appeared in a joint declaration signed by the two socialist
heads of state to conclude Vazquez's visit to Bolivia.
Vazquez and Morales picked up on the memorandum of understanding set
forth between their nations in 2004 and instructed their energy
ministers to analyze the possibility of building a pipeline and
combined-cycle gas-fired power plants in Uruguay.
Uruguayan Industry, Energy and Mining Minister Jorge Lepra said that
his country needs natural gas to supplement what has become an erratic
supply of the fuel from Argentina.
"It so happens that we often have cuts in the Argentine supply, due to
which many factories have gone to (using) wood and fuel oil" to
generate electricity, he said.
Bolivian Hydrocarbons Minister Andres Soliz said that the idea of
extending a gas pipeline to Uruguay would be difficult because the two
countries do not share a common border and, therefore, the project
would have to pass through Argentine territory.
"The most likely thing is that we'll have to increase the volume of gas
exports to Argentina and from there supply Uruguay and Paraguay," he
said.
Bolivia currently exports 7.2 mm cm (253 mm cf) of gas and, for the
past two years, Buenos Aires and Argentine petroleum firms have been
studying the construction of a conduit to boost the supply of the fuel
from the neighbouring Andean nation. Bolivia has estimated reserves of
48 tcf of natural gas, most of it in south-eastern fields near its
border with Argentina and Paraguay.
Caracas, Buenos Aires and Brasilia have agreed to spend $ 9 mm to study
the feasibility of a pipeline that would carry Venezuela's natural gas
-- it has even bigger reserves than Bolivia -- some 8,000 km (nearly
5,000 miles) across Brazil to Argentina.
Though Venezuelan President Hugo Chavez denies the prospective great
southern pipeline represents an attempt to steal markets from Bolivia,
La Paz's Soliz has expressed concerns that the conduit, if built, would
do just that.
After concluding his talks with Morales, Vazquez left Bolivia for
Venezuela, the second stop on a tour that later will take him to Brazil
and Paraguay.
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Venezuela urges
Bolivia/Uruguay in pipeline project
16-03-06 Source: Business News Americas
Both Bolivia and Uruguay would benefit from participating in the
proposed 8,000 km natural gas pipeline that would link Venezuela to
Argentina and Brazil, Venezuela's President Hugo Chavez said.
Chavez addressed the issue during the first state visit to Venezuela of
Uruguay's recently inaugurated president, fellow socialist Tabari
Vasquez.
"Without the participation of Uruguay and Bolivia, the project doesn't
make any sense," Chavez said.
"Who can think that a gas pipeline between Venezuela and Argentina
would not pass through Uruguay? And who can think that without the
participation of Bolivia and the addition of its gas reserves to ours
the project can be profitable?"
Vasquez was pleased by Chavez's proposal and said his country is
willing to participate in the project. The $ 20 bn-plus project,
expected to transport some 5 bn cf of gas a day initially, is
proceeding on schedule, with the three main countries reporting earlier
they would allocate $ 9.2 mm for preliminary studies.
Venezuela's gas regulator Enagas said earlier this year that approaches
were being made to Bolivia to contribute gas to the pipeline.
Bolivia already sells gas to Argentina and Brazil and has the second
largest reserves in South America after Venezuela.
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Gas boom in western US
conflict of cultures
10-03-06 Source: Associated Press
On a blustery winter day on the rolling plains north of Denver, a herd
of cattle stood grazing a few yards from an idled natural gas pump in a
dormant field as traffic rumbled by on a black-topped, two-lane
highway.
Children play near an oil pump surrounded by a housing development in
Frederick, Colorado. Just down the road are shopping centres and
subdivisions packed with new homes, gobbling up land around this
once-sleepy agricultural town that just happens to sit atop the
Wattenberg gas field, one of the nation's most productive.
Ed Orr knows this land well. A rancher and developer whose family roots
in Colorado date back more than a century, Orr says the real estate
business is growing increasingly difficult because gas producers want
access no matter what the plans are for the property.
"The conflict of the cultures is certainly more prevalent. You have two
industries that are both growing," Orr said. "They think that we have
no valid rights to get any accommodation for development use of the
surface."
Twin engines of growth -- in population and within the oil and natural
gas industry -- are colliding in Greeley, the fastest-growing
metropolitan area in the nation. Developers looking to cash in on
rising land values are running into companies eager to sink more wells
and drawing up plans for multibillion-dollar pipelines to carry gas to
the East Coast.
Similar conflicts are playing out from Montana to New Mexico because
the Rockies' energy boom is in full bloom, prompting worries about the
environment, property rights and the changing character of small towns
swelling with new workers. Many fear another Western rush to fortune
will be followed by hard times -- again.
The gas boom, however, seems to be setting up for an extended run,
according to industry experts. That poses a new set of issues for
communities that have diversified their economies by attracting
tourism, manufacturing, construction and technology companies after the
last bust in the 1980s.
Cities such as Grand Junction and Montrose in western Colorado have
become havens for retirees, while mountain communities that are home to
celebrity-magnet ski resorts are filled with wealthy property owners
who buy up ranches and build second homes.
Even as the West's population grew by nearly 20 % in the 1990s, the oil
and gas industry has returned its focus to the Rockies, thanks to
skyrocketing prices and technology that make the resources easier to
retrieve. Drilling has slowed in other gas fields, and Hurricane
Katrina forced Gulf Coast-oriented companies to consider other options.
Producers -- including EnCana, Kerr-McGee, Noble Energy and Bill
Barrett -- are sinking traditional oil and gas wells across the West,
tapping coal-bed methane reserves and even experimenting with
hard-to-get resources such as oil shale.
According to federal statistics, US gas production has been relatively
flat for years (18.1 tcf in 1993 compared with 18.6 tcf in 2004). But
exploration is red-hot: In New Mexico, Colorado, Utah,Wyoming and
Montana, gas reserves in 2004 totalled 60.7 bn cf, up from 58.8 bn cf
in 2003. And the number of producing wells rose from 73,796 in 2000 to
84,164 in 2004.
The quick pace of production has filled pipelines to capacity,
prompting at least three new pipeline proposals, including a $ 20 bn
project to bring gas from Alaska's North Slope to the Midwest. The
other projects are in the West.
"The Rockies is sort of in its infancy," said Ron Gist, senior
principal of Purvin and Gertz, an industry consulting company in
Houston. "One of the reasons the Rockies has not been developed as
quickly is the local demand isn't that big so then you need an
infrastructure to get it to market."
Kinder Morgan Energy Partners LP and Sempra Energy are building a $ 4
bn, 1,323-mile pipeline to carry up to 2 bn cf of natural gas from
Colorado's Weld County -- home to Greeley -- to Monroe County, Ohio,
for delivery to Midwestern and Eastern markets by June 2009. Kinder
Morgan is also expected to buy another pipeline from EnCana that will
run from Rio Blanco County in western Colorado through Wyoming to the
Weld County hub.
Separately, El Paso has proposed a 1,000-mile pipeline called the
Continental Connector to move up to 2 bn cf of natural gas from Weld
County to Kansas and then into existing pipelines that serve markets in
the Midwest, Southeast and Northeast. The costs have not been
disclosed, but El Paso said it could be in operation by November 2008.
Don Santa, president of the Interstate Natural Gas Association of
America, said the companies will need adequate pledges from producers
for gas before they can get federal approval for the sprawling
projects. He said rising levels of production and the need for gas in
the East suggests a need for the Kinder Morgan-Sempra and El Paso
projects.
"Those two are of a magnitude that we haven't seen in a while," he
said.
Most analysts believe the gas boom will remain strong, noting there is
an insatiable demand not only in the United States but overseas.
"We're looking for continued production increases for 10, 15 years at
least and perhaps longer than that," Gist said. "Our view of things out
to 2020 has gas production in the region continuing to increase. This
is indeed a long-term trend."
Environmentalists are increasingly concerned the operations could
threaten wilderness areas, wildlife habitat, the air and water
supplies. Pete Morton, an economist with The Wilderness Society in
Denver, isn't sure how long the boom will last, given the cyclical
nature of the industry.
"When you see this almost universal response of, 'Oh, high prices are
here to stay and demand is here to stay,' that's when you know it's not
going to happen," Morton said. "These are the same people who were
telling you to buy high tech before the bubble burst."
When liquefied natural gas imports become common and cheap gas from
overseas starts flowing, he said, "boom, the Rockies lose out." EnCana,
meanwhile, recently cut $ 800 mm from its capital spending forecastfor
2006.
Still, the boom has already overwhelmed towns lacking adequate housing,
social services and infrastructure, and authorities say it has led to
more crime. A labour shortage is hitting energy companies and
businesses trying to serve them.
In bustling Rock Springs, Wyoming, energy workers have filled all 1,850
motel rooms. On any given day, there are more than 500 available jobs
posted with the Sweetwater County Economic Development Association,
though director Pat Robbins said as many as 1,000 jobs may be open.
For example, Halliburton would like to double its work force of 755,
and Wal-Mart needs about 200 people to be fully staffed, Robbins said.
She and her counterparts in Campbell and Natrona counties recently held
job fairs in Michigan in hopes of landing laid-off auto workers.
County voters, meanwhile, recently approved a tax increase to help pay
for improvements, including repairs for hundreds of miles of dirt roads
leading to oil- and-gas operations, Robbins said. Despite the
headaches, she said the town of 23,000 people welcomed the growth.
"I got excited when Halliburton did their new building," Robbins said.
"Other people got excited when IHOP opened."
Across the state in Gillette, Wyoming, the labour shortage is getting
acute for Robin Shea, general manager of mine equipment and services
company P&H Minepro Services. In early February, he had 17 jobs
open.
"There are not enough people here to do the jobs that are available,"
said Shea, who sent two employees to the Michigan job fairs and watched
them return with 250 resumes.
Within the industry, meanwhile, workers are retiring and not all are
being replaced.
"It's been a boom-and-bust industry," said Gist, the Houston analyst.
"You see your father get laid off from a job two or three times, you're
probably not interested in going into the same business."
The boom also has taken its toll on ranchers, developers and homeowners
who have little recourse when an oil company with underground mineral
rights elects to drill on their land.
Rancher Chris Velasquez believes his cattle have suffered because of
problems associated with oil-and-gas drilling on 22,000 acres he leases
east of Farmington, New Mexico. There has been lost forage, and he has
had cows killed in collisions. He said his calves have lost weight and
hair.
"They have affected my operation a lot," he said. "It's an ongoing
thing." He isn't opposed to energy production but wants the companies
to be responsible. If the problems continue, he says he may have to
sell the herd and find another line of work.
Orr, the developer, bought property along the Poudre River west of
Greeley several years ago where he wintered his cattle. As the
population grew, a golf course was built nearby and then a high school,
both of which made ranching more difficult. Today, he has turned that
ranch into a mixed-use subdivision and become primarily a developer
with a small herd of cattle. He plans to develop gas wells on his
property.
"There's an agriculture way of life that you know certainly has some
emotion tied to it and that you hate to see go away -- but on the other
hand I see it as progress and I think that change is good," he said. "I
think that ultimately all property should reach its highest and best
use. In this area that is no longer raising cows."
|
Alberta has enough oil
to last for centuries
07-03-06 Source: CHQR
Alberta has enough oil in its tarsands region to last for hundreds of
years, says Energy Minister Greg Melchin. Albertans and Canadians
shouldn't be concerned about Americans draining oil to meet a growing
thirst for energy in the United States, the minister said.
"We have centuries of supplies," Melchin said. "And our policies are
built on a lot of trade, the United States being our most valuable
customer."
Premier Ralph Klein echoed Melchin's comments.
"If we see oil drying up and we see the Alberta supply being threatened
and the Canadian supply being threatened, we can do whatever is
necessary to ensure that Canada receives its supplies first," he said.
"But there's a 300-year supply of oil predicted in the tarsands."
Both men were responding to a report by the Parkland Institute that
says increasing demand from the US is putting the oilsands in jeopardy.
The report deals with threats the tarsands face as production is
forecast to jump to 6 mm bpd from an estimated 1 mm.
"The Americans have become very interested in the tarsands and almost
talk about it as though it's their domestic supply, looking at it as a
way of replacing Middle Eastern oil," said Parkland's director, Gordon
Laxer.
The University of Alberta think tank is calling on Prime Minister
Stephen Harper to implement a made-in-Canada strategy to safeguard
Canada's energy security. But Melchin dismissed any suggestion of a new
national policy that would influence Alberta's energy export decisions.
"The province has the ownership and stewardship and constitutional
authority to develop its resources," said Melchin. "So when we're
talking about energy, Alberta has the primary lead on the oil and gas."
However, he said he's not totally dismissing the idea of keeping an eye
on Alberta's energy supplies.
"When we look at the long-term energy need for Alberta and for Canada,
those are first and paramount," he said. "But we know our resources are
so vast and so large."
Environment Minister Guy Boutilier also said there's a need to ensure
that Canada's energy needs remain a top priority.
"We want to ensure that we supply the needs of Canadians, but there's a
lot of oil to go around based on what we have in the oilsands
development area," said Boutilier.
The Parkland report was commissioned a year ago and was prepared with
the Canadian Centre for Policy Alternatives and the Polaris Institute.
|
Canada’s energy
security in jeopardy
10-03-06 Source: bcpolitics.ca
A report on the Athabasca tar sands by the Canadian Centre for Policy
Alternatives, Parkland Institute, and Polaris Institute warns of the
potential enormous economic, social, and ecological threat from
Athabasca tar sands development.
“The Athabasca tar sands project is the centrepiece of a continental
energy plan to send massive new oil and gas supplies to the US,” says
Tony Clarke, Director of the Polaris Institute. “Canada is sitting back
and letting George W. Bush and the big oil companies dictate our energy
policy.”
“Fuelling Fortress America: A Report on the Athabasca Tar Sands and US
Demands for Canada’s Energy” highlights the need for a coherent
national (and Alberta) energy strategy. Neither government is doing the
analysis or public consultation necessary to develop policies to meet
the world energy crisis -- let alone ensure a secure supply of energy
for Canadians.
Since the signing of NAFTA in 1992, gas exports to the US have sky
rocketed from 41 % to 56 % of our total Canadian production, and oil
from 44 % to 63 % of production. What’s more, as US exports continue to
balloon, NAFTA prevents us from reducing this share to meet Canadian
priorities.
“We have less than a 10-year proven supply of both conventional oil as
well as natural gas remaining, yet most of the tar sands oil is
earmarked for export to the US, and most of the natural gas from the
Arctic -- by way of the yet-to-be-built Mackenzie Valley pipeline --is
also intended for the US market or to fuel extraction of the tar sands
crude,” says CCPA Executive Director Bruce Campbell.
The rapidly increasing exports of Canada’s oil and gas to the US puts
our own energy security as a nation in jeopardy. Despite having the
second largest proven petroleum reserves in the world, Canada is
already forced to import nearly 50 % of the oil its people need. Quebec
and the Maritimes have to import 90 % of their oil needs.
“Canada’s energy is a national concern and all Canadians should have a
say into what role Alberta’s tar sands will play in ensuring the
country’s long-term energy security,” says Parkland Institute Director
Gordon Laxer. “The continuation of current energy policies is clearly
not in the national interest.”
The report concludes with several proposals for a made-in-Canada energy
strategy.
|
US afraid of
Venezuela/Bolivia hinder energy sector invests
06-03-06 Source: Neftegaz.ru
The United States expressed fears over the possibility that both
Venezuela and Bolivia may hinder foreign investments in the energy
sector.
"We are concerned that some countries in our hemisphere are making
decisions that are not going to optimize the development of energy
resources," said Karen Harbert, US Assistant Secretary of Energy for
Policy and International Affairs.
"The moves to curb foreign investments and to expand the scope of state
oil firms do restrict their access to investments, thus hindering
development and reducing access to equipment or infrastructure," she
added during a hearing before the House of Representatives.
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Alaska fears steel shortage
for pipelines
Source: National Post 03-03-06
A shortage of steel could be a problem for the Alaska and the Mackenzie
Valley natural gas pipelines, especially if both projects go ahead in a
similar time frame, the US Energy Secretary said.
Sam Bodman said while he does not expect to see any problems in sorting
out the regulatory regime for the Canadian leg of the 5,700-km Alaska
pipeline, he is worried about finding enough steel for both projects.
"I think there is an issue of production of pipeline, a shortage of
manufacturing capability for the pipe required here," he said at a
Canadian energy conference here. "If there are delays for one, there
will be delays for the other."
Mr Bodman said the United States is counting heavily on the 4.5 bn cfpd
of gas that will come from the $ 20-bn Alaska pipeline.
"It's a very important project for our country," he said. "It will
provide enough gas in quantities that should have a real impact on our
market place."
Although he has not talked to Gary Lunn, Canada's new Natural Resources
Minister, he said he expected Canadian "regulatory approvals that will
be required will be swift."
"I don't anticipate any problems," he said, adding that he expects to
meet Mr Lunn at a Moscow energy meeting later this month.
The state of Alaska and the three major owners of North Slope gas --
ExxonMobil, BP and ConocoPhillips Alaska -- have put together a
tentative package for the pipeline through the Yukon. That deal still
has to be approved by the Alaska legislature.
In addition, Ottawa has to decide whether it will give the Canadian leg
to TransCanada under the Northern Pipeline Act or have the National
Energy Board hold hearings.
Mr Bodman said the United States will also rely heavily on the expanded
production from the Alberta oilsands.
"We very anxious to see them expand as much as reasonable," he said
about plans to more than double current production of 1 mm bpd. He
downplayed concerns the oil may head to China rather than the US market
since the cost of transportation is so high.
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Biofuels for oil
addicts: Cure worse than the addiction
01-03-06 Source: The Institute of Science in Society by Dr Mae-Wan Ho
Bioethanol and biodiesel from energy crops compete for land that grows
food and return less energy than the fossil fuel energy squandered in
producing them; they are also damaging to the environment and
disastrous for the economy.
“We must break our addiction to oil”, President George W. Bush said in
his State of the Union address; but he wasn’t advising people to give
up their cars or to use less oil, say by improving the gas mileage of
cars. Instead, he launched the “Advanced Energy Initiative” that would
increase federal budget by 22 % for research into clean fuel
technologies; including biofuels derived from plants as substitutes for
oil to power the country’s cars.
Successive US presidents have promoted ethanol from corn as a
subsidised fuel additive. President Bush said US scientists are now
working out how to make ethanol from wood chips, stalks, or switch
grass “practical and competitive within six years”, which would replace
more than 70 % of oil imports from “unstable parts of the world” -- the
Middle East -- by 2025.
Currently 60 % of the oil consumed in the US is imported, up from 53 %
since George W. Bush came to power.
What are biofuels?
Biofuels are fuels derived from crop plants, and include biomass that’s
directly burned, biodiesel from plant seed-oil, and ethanol (or
methanol) from fermenting grain, grass, straw or wood.
Biofuels have gained favour with environmental groups as renewable
energy sources that are “carbon neutral”, in that they do not add any
greenhouse gas into the atmosphere; burning them simply returns to the
atmosphere the carbon dioxide that the plants take out when they were
growing in the field.
However, they take up valuable land that should be used for growing
food, especially in poor Third World countries. Realistic estimates
show that making biofuels from energy crops require more fossil fuel
energy than they yield, and do not substantially reduce greenhouse gas
emissions when all the inputs are accounted for. Furthermore, they
cause irreparable damages to the soil and the environment.
Biofuels can also be produced from wood chips, crop residues and other
agricultural and industrial wastes, which do not compete for land with
food crops, but the environmental impacts are still substantial.
Biofuels cannot substitute for current fossil fuel use
Biofuels from energy crops cannot substitute for current fossil fuel
use. The major constraints are land surface available for growing the
crops, crop yield, and energy conversion efficiency, although economics
also plays a large role.
Growing crops for burning -- biomass -- should be the cheapest kind of
biofuel both in energy and financial terms, as it requires minimum
processing after harvest.
Crop scientists at Virginia Tech, David Parrish and John Fike, reviewed
the biology and agronomy of switchgrass, the most researched and
favoured biofuel crop. Switchgrass is a perennial native to the USA,
and has been extensively grown for fodder soon after the Europeans
arrived. It is prolific, does not require much nitrogen fertilizer, and
is considered the most sustainable, or the least environmentally
damaging biofuel crop.
But the review concluded that, “even at maximum output, such systems
could not provide the energy currently being derived from fossil
fuels.”
Substituting switchgrass for coal is estimated to reduce greenhouse gas
emissions by about 1.7 tons CO2 per tons switchgrass. The prices that
growers must receive for biomass, however, must be sufficiently
favourable. Thus, about 8 mm ha would be available if the price reached
$ 33 per ton at the farm gate, increasing to about 17 mm ha at $ 44 per
ton. The market price paid for woodchip biomass in Virginia in 2004
averaged about $ 33 per ton delivered, and the price for hay (all
kinds) is about $ 95 per ton.
One estimate placed the delivery costs of switchgrass at $ 63 per ton.
Adding the costs of processing, such as pressing into pellets or cubes
for handling within a power plant, would bring the user’s costs to
about $ 83 per ton. One ton of switchgrass produces 17-18 GJ of energy
when burned, compared with 27-30 GJ for coal; and coal prices are $ 55
per ton.
Switchgrass for energy is not at all economically competitive, unless
substantial subsidy is available. The same applies, perforce, to other
energy crops.
David Pimentel, a professor of crops science at Cornell University New
York and Tad Patzek, a professor of chemical engineering at University
of California Berkeley, reviewed the energy balance and economics of
producing biomass, ethanol or biodiesel from corn, switchgrass, wood,
soybeans and sunflower using the now generally accepted life-cycle
analysis. Although there is much controversy over the energy balance of
ethanol and biodiesel, the energy balance of biomass yield is generally
less subject to dispute, and is therefore a useful starting point.
It turns out that switchgrass has the most favourable output/input
energy ratio of 14.52, followed by wheat at 12.88,and oilseed rape at
9.21, if the straw is included. Switchgrass is hence the most promising
energy crop, whether as biomass for burning or to make other fuels
downstream, such as ethanol.
A quick calculation showed that even if all the farmland in the United
States were converted to growing switchgrass, it would not produce
enough ethanol for the country’s fossil fuel use.
Switchgrass takes several years to mature. The yield ranges from 0 for
complete failure of the crop to take hold to 20 tons or more per ha, a
lot depending on the rainfall. A yield of 15 t/ha is optimistic; and
would provide some 250 GJ/ha of raw chemical energy a year. If that
energy could be converted with 70 % efficiency into electricity,
ethanol, methanol etc., it would take about 460 mm ha to produce the 80
EJ (ExaJoule = 1018J) fossil fuel energy used in the USA each year. The
total farmland in the USA is 380 mm ha, of which 175 mm ha is harvested
cropland.
Clearly, energy crops are a bad option, and may become obsolete as
ethanol can now be made from wood chips, crop residues and other
agricultural wastes, and industrial wastes, though even that is not
sustainable.
Do you get more energy out of biofuel than the fossil fuel energy you
put in?
There is a huge debate over the energy balance of making ethanol or
biodiesel out of energy crops, with David Pimentel and Tad Patzek
presenting negative energy balance for all crops based on current
processing methods, i.e., it takes more fossil energy input to produce
the equivalent energy in biofuel. Thus for each unit of energy spent in
fossil fuel, the return is 0.778 unit of energy in maize ethanol, 0.688
unit in switchgrass ethanol, 0.636 unit in wood ethanol, and worst of
all, 0.534 unit in soybean biodiesel.
Their paper has provoked a strong riposte from several US government
departments, accusing Pimentel and Patzek of using obsolete figures, of
not counting the energy content of by-products such as the seedcake
(residue left after oil is extracted) that can be used as animal feed,
and of including energy used for building processing plants, farm
machinery, and labour, not usually included in such assessments.
For their part, Pimentel and Patzek, along with many other scientists
like me, are critical of estimates that produce positive energy balance
precisely because they leave out necessary energy investments. In fact,
neither Pimentel and Patzek nor their critics have included the costs
of waste treatment and disposal or the environmental impacts of
intensive bioenergy crop cultivation such as depletion of soil and
environmental pollution from fertilizers and pesticides.
To apportion processing-energy to co-products according to their bulk
composition in the seed may appear unexceptionable. Only 18 % of the
soybean is oil that makes biodiesel, while the rest is soybean cake
used as animal feed. However, as the seedcake is produced as soon as
the oil is extracted, it is simply creative accounting to attribute 82
% of the downstream processing energy for biodiesel -- which is quite
substantial -- to the animal feed.
Energy balance of ethanol from corn
Sure enough, a new study comparing six estimates of energy balance of
corn ethanol did find that “net energy calculations are most sensitive
to assumptions about co-product allocation”.
The new study, carried out by researchers at the University of
California Berkeley, published in the journal Science, evaluated six
analyses of corn-ethanol production, including those of Pimentel and
Patzek. The researchers developed a “model” to allow them to compare
the data and assumptions across the analyses.
Pimentel and Patzek’s negative energy balance stood out in including
energy used for building processing plants, farm machinery, and labour,
and for not giving credit for co-products. Removing those
“incommensurate” factors nevertheless resulted in only a modest
positive energy balance of just over 3 MJ/litre to 8 MJ/litre ethanol
in the analyses that gave positive energy balance, which translates to
1.13 to 1.34 for energy output/energy input (there being 23.4 MJ in one
litre of ethanol), while the reduction in greenhouse gas emissions
averaged about 13 %.
The researchers have devised a way of presenting energy balance in
terms of “petroleum input” -- expressed as MJ petrol/MJ ethanol -- that
puts a very positive gloss on the figures and is very misleading. It
essentially adds 100 % energy credit to the ethanol because it assumes
that the ethanol substitutes 100 % for fossil fuel use.
The researchers then used the “best data” from the six analyses to
“create” three cases with their model (hence all hypothetical): Ethanol
Today, that claims to include typical values for the current US corn
ethanol industry; CO2 Intensive, based on plans to ship Nebraska corn
to a lignite-powered ethanol plant in North Dakota, and Cellulosic,
which assumes that production of ethanol from switchgrass cellulose
becomes economic, an admitted “preliminary estimate of a rapidly
evolving technology”.
Calculating the three cases, the researchers found a positive energy
balance: a whopping 23 MJ/litre ethanol for Cellulosic, 5 MJ/litre for
Ethanol Today, and 1.2 MJ/litre for CO2 Intensive; the corresponding
output/input energy ratios are 1.98, 1.21, and 1.05 respectively.
Cellulosic is the clear winner in terms of energy balance, and also by
a long shot in net greenhouse gas emission saved, which is 89 %; the
corresponding values for Ethanol Today and CO2 Intensive are 17 % and
about 2 % respectively.
These analyses show that current production methods, represented by
Ethanol Today and CO2 Intensive, offer but a small positive energy
balance and little if any savings in greenhouse gas emissions, even
with the most favourable assumptions built in.
Bad economics of ethanol from corn
Ethanol constitutes 99 % of all biofuels in the United States; 3.4 bn
gallons of ethanol were produced in 2004 and blended into gasoline,
amounting to about 2 % of all gasoline sold by volume and 1.3 % of its
energy content.
Ethanol use is set to expand as the federal government has introduced a
0.51 tax credit per gallon of ethanol and issued a new mandate for 7.5
bn gallons of “renewable fuel” to be used in gasoline by 2012, which is
included in the recently passed Energy Policy Act (EPACT 2005).
Pimentel and Patzek have shown not only that the energy return is
substantially negative, the economics is worse. About 50 % of the cost
of producing ethanol is for the corn feedstock itself ($ 0.28/litre).
Ethanol costs a lot more to produce than it is worth on the market, and
without federal and state subsidies amounting to some $ 3 bn per year,
corn ethanol production in the US would cease.
Senator McCain reports that total ethanol subsidies amount to $ 0.79/
litre; adding the production costs would bring the cost to $
1.24/litre. Ethanol has only 66 % as much energy per litre as gasoline;
so corn ethanol costs $ 1.88 per litre -- or $ 7.12 per gallon --
equivalent of gasoline, compared to the current cost of producing
gasoline, which is $ .33/litre.
Federal and state subsidies for ethanol production that total $
0.79/litre mainly end up in the pocket of large corporations, with a
maximum of $ 0.02 per bushel, or 0.2 cent/litre ethanol going to the
farmer. The total costs to the consumer in subsidizing ethanol and corn
production is estimated at $ 8.4 bn/year, because producing the
required corn feedstock increases corn prices. One estimate is that
ethanol production adds more than $ 1 bn to the cost of beef
production.
Clearly ethanol from corn is neither sustainable nor economical, and a
lot of effort has been devoted to finding alternative feedstock.
Worse energy yields as accounting gets more realistic
In a detailed rebuttal to the Science paper showing a positive energy
balance in ethanol production from corn, Patzek exposed the major flaws
in energy accounting used, which greatly inflated the energy return.
These include:
-- Failure to account for the energy in corn grains as energy input;
-- Assuming an impossibly high yield of corn ethanol at variance with
real data available;
-- Assigning away undue energy costs in ethanol production, in
particular, distillation, to co-products such as fermentation residues
that have nothing to do with ethanol production.
In addition, the ethanol industry routinely inflates the ethanol yield
by counting as ethanol the 5 % of gasoline added to corn ethanol as
denaturant; by taking the amount of fermentable starch to be the total
extractable starch, although not all of the latter is fermentable; and
by taking the weight of wet corn (average 18 % moisture) as dry corn.
When the energy accounting done by different authors is reanalysed on
the same set of realistic data, energy yields come out remarkably
uniform. The output/input ratio varies between 0.245 and 0.310. In
other words, the energy balance is strongly negative: for every unit
used in making corn ethanol, one gets at most 0.3 unit of energy back.
It takes at least 9 times more fossil fuel energy to produce ethanol
from corn at the refinery gate than gasoline or diesel fuel from crude
oil.
As Patzek points out, the 7.5 bn gallons of ethanol mandated by the
2005 Energy Bill by 2012 could be compensated by an increase of car
mileage by just one mile per gallon, excluding gas-guzzling SUVs and
light trucks.
The economic consequences of excessive corn production have been
devastating. The price of corn in Iowa, the largest corn producer,
declined 10-fold between 1949 and 2005 as corn yields have tripled.
Today, Iowa farmers earn a third for the corn they sell compared to
1949, while their production costs increased manifold, because they
burn methane and diesel to produce corn. The price of methane has
increased several-fold in the last three years.
“Corn crop subsidies supplemented the market corn price by up to 50 %
between 1995 and 2004.” Patzek writes, predicting more concentration of
industrial corn production in gigantic farms operated by large
agribusiness corporations, and real farmers will only rent the land.
An industrial raw material at rock-bottom price can now be processed
into ethanol at a significant profit, further enhanced by a federal
subsidy of 50 cents per gallon ethanol, plus state and local community
subsidies.
Patzek concludes: “the United States has already wasted a lot of time,
money, and natural resources… pursuing a mirage of an energy scheme
that cannot possibly replace fossil fuels…The only real solution is to
limit the rate of use of these fossil fuels. Everything else will lead
to an eventual national disaster.”
|
US oil supplies oil
boost recovery with C02
28-02-06 Source: US Department of Energy
State-of-the-art enhanced oil recovery with carbon dioxide, now
recognized as a potential way of dealing with greenhouse gas emissions,
could add 89 bn barrels to the recoverable oil resources of the United
States, the Department of Energy has determined. Current US proved
reserves are 21.9 bn barrels.
The 89-bn-barrel jump in resources was one of a number of possible
increases identified in a series of assessments done for the Department
which also found that, in the longer term, multiple advances in
technology and widespread sequestration of industrial carbon dioxide
could eventually add as much as 430 bn new barrels to the technically
recoverable resource.
Beginning efforts to develop the 89-bn-barrel addition to resources
would depend on the availability of commercial CO2 in large volumes. If
this oil could be added to the category of proven reserves, the US
would have the fifth largest oil reserves in the world behind Iraq,
which has 115 bn barrels, based on present estimates; and an additional
430 bn barrels would make it first, ahead of Saudi Arabia with 261 bn
barrels. The capture of CO2 from combustion in power generation and
other industrial uses is the subject of other research and development
programs sponsored by the Office of Fossil Energy.
Next-generation enhanced recovery with carbon dioxide was judged to be
a "game-changer" in oil production, one capable of doubling recovery
efficiency. And geologic sequestration of industrial carbon dioxide in
declining oil fields was endorsed last year as a potential method of
reducing greenhouse base emissions by the Intergovernmental Panel on
Climate Change.
Done in compliance with the National Energy Policy Act of 2005 and
other Congressional directives, the assessments looked at maximizing
oil production and accelerating the productive use of carbon dioxide in
all categories of petroleum resources, including as-yet undiscovered
oil and the new resources in the residual oil zone. The findings are
consolidated in the February 2006 report Undeveloped Domestic Oil
Resources: The Foundation for Increasing Oil Production and a Viable
Domestic Oil Industry.
The 430 bn barrel potential was identified in increments of up to 110
billon barrels from applying today's state-of-the-art enhanced recovery
in discovered fields -- 90 bn in light oil, 20 bn in heavy oil; up to
179 bn barrels from undiscovered oil -- 119 bn from conventional
technology, 60 bn from enhanced recovery; up to 111 bn barrels from
reserve growth -- 71 bn from conventional technology, 40 bn from
enhanced recovery; up to 20 bn from tapping the residual oil zone with
enhanced recovery; and, another 10 bn from tar sands.
The separate assessments and reports contributing to the total resource
estimate are:
-- Basin Oriented Assessments, ten assessments of producing US basins
and the potential of state-of-the-art enhanced oil recovery;
-- Stranded Oil in the Residual Oil Zone, five reports looking at new
resources in the residual oil zone; and,
-- Evaluation of the Potential for "Game-Changer" Improvements in Oil
Recovery Efficiency for CO2 Enhanced Oil Recovery, a report on
next-generation technology.
They were prepared by Advanced Resources International and Melzer
Consulting.
|
Aboriginals
environmentalists split over Mackenzie pipeline
13-02-06 Source: Canada Post by Bob Weber
A split between some northern aboriginals and southern
environmentalists over Arctic energy development burst open like a
piece of corroded pipe during hearings on a proposed natural gas
pipeline down the Mackenzie Valley.
Fred Carmichael, head of an aboriginal group that hopes to take a
one-third share in the project, likened interveners such as the Sierra
Club and the World Wildlife Fund to those who impoverished his people
through the anti-fur lobby.
"Some similar organizations that killed our trapping economy in the
past are once again trying to destroy this opportunity, this
opportunity to gain back our independence, our self-sufficiency and our
pride," Carmichael said. "Without some form of economic base, we will
surely destroy our people."
Carmichael was testifying before the seven-member Joint Review Panel,
which will report to the National Energy Board on the environmental and
social effects of the $ 7-bn proposal after a year of hearings in
communities from Tuktoyaktuk to Calgary.
Carmichael drew on his own life as a bush pilot for an impassioned
speech before the panel. He described how he spent years watching the
changes in the Northwest Territories as he flew from community to
community.
He pointed out that the collapse of the trapping industry about 40
years ago caught northern aboriginals in a snare of government
dependency and poverty.
"This trapping economy was destroyed by people or organizations who
either did not understand or care that this was our livelihood." The
settlement of land claims and the creation of local regulatory boards
have given aboriginals a way out of that trap, said Carmichael.
"In the '60s and '70s, the exploration companies seemed to have little
or no respect for our lands. Today there's an understanding and respect
between industry and aboriginal people. The fact that I'm at this table
representing aboriginal people tells you how far we've come."
He pleaded with the panel to consider the past.
"Today our people are looking for a way to become self-sufficient
again. For this to happen, we must have an economic base. We see this
opportunity in oil and gas and pipeline development."
Outside the hearing, Stephen Hazell, conservation director for the
Sierra Club, defended his organization. He said it had nothing to do
with the anti-fur campaign and is working successfully with other
aboriginal groups in the North.
"It's a myth that there's a split between the environmental and
aboriginal community," he said.
For example, the Sierra Club has worked with the Deh Cho First Nation
to try to expand Nahanni National Park.
"We have a pretty good working relationship with them," acknowledged
Deh Cho Chief Keyna Norwegian. The World Wildlife Fund, too, has played
an important role in a widely popular protected areas strategy intended
to preserve important ecosystems and cultural sites from energy
development.
Hazell admits the Sierra Club opposes the pipeline, in part because the
fossil fuel economy is just as doomed as the trapping economy.
"We think (the pipeline) will create far more problems down the road."
Outside the hearing, Carmichael did say environmental groups have a
role to play in the proposed pipeline.
"Sure, they have a valid role, but why kill our economy?"
Executives of the three energy companies behind the development also
spoke. They warned the panel not to impose too many restrictions on the
project.
"The project continues to face a number of challenges, not the least of
which is its overall economic viability," said David Collyer,
vice-president of frontiers for Shell Canada.
Glen Bishop of ConocoPhillips said the project will collapse if it is
forced to anticipate "every conceivable contingency." Potential
problems such as permafrost melting due to climate change are best
dealt with as they arise, he said.
"Adaptive management is the way to go as opposed to making it so
prohibitively expensive we can't afford to do it." Bishop said the
project's viability is being heavily squeezed by rising labour costs
driven by oilsands expansion, as well as declining prices for natural
gas. Those prices are likely to come under further pressure from liquid
natural gas projects and the eventual development of Alaskan gas.
In afternoon testimony, Imperial Oil officials responded to concerns
that climate change could threaten the pipeline by melting the
permafrost that supports it.
Imperial will conduct further, more specific studies once the project
gets closer to construction and watch for problems to develop, said
spokesman Rick Luckasavitch.
"To ensure pipeline integrity, we are considering the effects of
potential climate change on the design and we're developing monitoring
and mitigation programs to be used throughout the operating life of the
pipelines."
|
Breaking America's
addiction to foreign oil
Source: MyWestTexas.com by Mike Linn 12-02-06
In his recent State of the Union address, President Bush outlined a
recovery plan for breaking America's "addiction" to foreign oil --
mostly by prescribing alternative energy resources that could take
years to deploy.
But, the best medicine for breaking the nation's foreign addiction is
the development of the abundant oil and natural gas resources we have
here at home. It would be a mistake to disregard this country's
most-important, readily available energy solution.
America's oil and natural gas resources were missing not only in the
State of the Union address, but also in the Administration's proposed
budget. The White House's federal budget proposal calls for the
"zeroing out" of the Department of Energy's oil and natural gas
programs.
It doesn't make sense that the United States is the only country in the
world that refuses to develop or ignores its vast oil and natural gas
resources. And now, it's proposed that we have a Department of Energy
that has no oil or natural gas program. This is like having a Health
and Human Services Department that commits its dollars toward voodoo
instead of real medicine.
It is possible for the United States to replace a portion of its oil
imports with oil and natural gas produced in our own country. For
example, the estimated undiscovered oil offshore (east and west coasts,
as well as the Gulf of Mexico) could replace current levels of oil
imports from the Persian Gulf for the next 59 years.
However, 90 % of the offshore is off-limits, including 300 tcf of
natural gas and 50 bn barrels of crude oil. Clean natural gas in the
Rocky Mountain West that is currently off-limits could heat 50 mm US
homes for the next 60 years.
Of course, domestic oil and natural gas will not be the only
prescription for our addiction recovery. But we will need oil and
natural gas for the foreseeable future. Today, 65 % of the energy
Americans use is oil and natural gas. There will be a 34 % increase in
US demand for natural gas by 2025. And many of the alternative fuels
mentioned by President Bush in his Address -- from ethanol to hydrogen
-- require natural gas or oil to produce.
Restrictions, bans, bureaucratic delays and litigation prevent the
responsible development of our nation’s energy. The result is winter
heating costs that are hitting families harder than any winter storm, a
weakening of our nation's industrial base, higher production costs
impacting the US economy in the form of higher prices and the loss of
millions of domestic manufacturing jobs.
According to the results of a national survey released this winter by
the National Association of Manufacturers, nearly 45 % of those
surveyed said they will be forced to lay off workers or impose wage
freezes or reductions. About 22 % of respondents said their companies
would cut health care or benefits in an attempt to keep up with energy
costs.
If the industry were able to develop these oil and natural gas
resources, according to the National Petroleum Council, consumers could
saveup to $ 300 bn in lower natural gas costs over the next two
decades.
Domestic oil and natural gas production will not only save jobs and
lessen our dependence on foreign government, but it will also provide
economic benefits. Federal and state treasuries receive hundreds of
billions of dollars in royalties and taxes from this industry, funding
important programs from education to land preservation.
Furthermore, technology has revolutionized the exploration and
production industry. Today, we use one well instead of four used in
1985 for the same reserves. Lighter rigs and slimhole drilling mean a
smaller environmental footprint. Directional drilling means better
protection of sensitive environments. The best offshore safety measures
ensured that virtually no oil was spilled as a result of the
devastating Hurricanes of Katrina and Rita last year.
America's energy problems should provide enough motivation for Congress
and the President to form consensus on a clear-cut, inclusive and
long-term solution.
Ignoring the great resources we already have here at home will do
nothing but prolong America's energy hangover.
Mike Linn, president and chief executive officer of Linn Energy in
Pittsburgh, also serves as chairman of the independent Petroleum
Association of America, which represents the companies that drill over
90 % of the nation's oil and natural gas wells.
|
Iran complicates
China's energy security
Source: The Power and Interest News Report by Michael Pinskur 14-03-06
In mid-February 2006, amid controversy over Iran's nuclear research
program, China and Iran announced an energy deal potentially worth $
100 bn.
According to the agreement, state-owned China Petroleum & Chemical
Corporation, or Sinopec, will develop Iran's Yadavaran oil field, and
China agreed to buy from Iran 10 mm tons of liquefied natural gas per
year for 25 years beginning in 2009. Sinopec would assume a 51 % stake
in the field, expected to produce 300,000 bpd, with 29 % going to
India's Oil and Natural Gas Corporation (ONGC) and the remaining 20 %
to either Iranian firms or another foreign company such as Royal Dutch
Shell.
China and Iran improve economic relations
This deal is the latest and most significant step in economic relations
between the two states. Trade between China and Iran increased from $
1.2 bn in 1998 to $ 7.5 bn in 2004, and jumped to $ 9.5 bn in 2005.
China currently imports about 13 % of its oil from Iran alone and, as
consumption continues to rise, will be increasingly reliant on foreign
oil.
Additionally, Beijing has made recent significant energy investments in
Indonesia, Venezuela, Sudan, and Nigeria, and plans to construct a
pipeline connecting Iran to Kazakhstan, which would in turn supply
China.
In Iran, China intends to become involved in everything from
exploration, drilling and pipelines in order to meet its own increasing
energy needs. Collaboration extends beyond energy, as there are
presently more than 100 Chinese companies working in Iran in sectors
such as dam and shipbuilding, steel production and development of
seaports and airports. The Iranian Embassy in Beijing described this
collaboration as "following the rule of mutual benefits and respect in
all bilateral cooperation."
It appears that the two states wish to conclude the deal before any
possible international sanctions on Iran are imposed. To do so would
limit US and EU options, and a Chinese veto, or the threat of one, at
the UN Security Council will complicate Western aims to punish Iran.
However, Beijing has stated its commitment to nuclear
non-proliferation, and diplomatic resolution is "not only in the
interests of China, but in the interests of all parties concerned."
Beijing finds itself positioned between the US and Iran
There is much at stake, as China, Iran, and the West all stand to lose
out from conflict, whether diplomatic or militaristic in nature.
Beijing finds itself positioned precariously between Iran and the West,
particularly between Iran and the US Between 2001 and 2004, China
accounted for one-third of the increase in global oil demand, and by
2020 expects its energy consumption to double, with imported oil
accounting for 60 % of the total.
China's dependence on energy would likely centre on Africa and the
Middle East, but with its expanding economy tethered to the US and the
dollar, China's further involvement with Iran could damage its
relations with the US. In recent years, Beijing has stressed the point
that it will not sacrifice trade with the West for Iran, and as such
will toe a fine diplomatic line in order to maintain its relationship
with both.
Meanwhile, the US-China trade gap swelled almost 25 % to $ 201.6 bn in
2005, a figure that has caused US legislators to propose tougher trade
policies against China. Last year, Congress helped to quash a hostile
bid by China's CNOOC to purchase Unocal, the ninth-largest US oil
company.
This showdown proved that nationalism will trump the market when it
comes to energy security, and that the US and China, as the world's top
two energy consumers, are ultimately competing for the same limited
resources. US Senator Joseph Lieberman asked that both sides "recognize
this problem before it becomes an intense competition which can
actually lead to military conflict."
Washington continues to pressure Iran
With regard to Iran, US Secretary of State Condoleezza Rice admitted
that the US must "walk a fine line" and will not likely push for
immediate sanctions. However, Washington has hardened its stance in
recent weeks, asserting that no level of uranium enrichment is
acceptable.
US President George W. Bush called the row a "grave national security
concern," but stated that a diplomatic resolution is imperative. As
such, Washington's options are limited by its current military
engagements in Iraq and Afghanistan, and by fear of a shock to global
oil prices.
Iran is getting support from China and Russia who are attempting to
limit sanctions or to forge a diplomatic resolution that will grant
greater political leverage against the West. Iranian hardliners have
stated that their country's economic relationship with China is
"strategic," and that Western threats are empty. Russia's offer to
enrich uranium for civil nuclear power in Iran is viewed as the best
option for avoiding sanctions.
The other Security Council members support the plan, but Iran has said
it will not comply with the proposal. Both Beijing and Moscow believe
that the matter should be determined by the IAEA, rather than by the
Security Council, and are fearful that forceful actions may well push
Tehran away from negotiations entirely.
Iran, as OPEC's second-largest oil exporter and with its position on
the strategically crucial Strait of Hormuz, largely controls the
climate of the current negotiations. Energy analysts predict that
sanctions on Iranian oil would lead to skyrocketing crude prices that
could potentially cripple the global economy. Worst-case scenarios
envision US military action that would lead to Iran cutting off its
vast oil supplies, with prices at least tripling overnight.
Iran initially stated that it would not use oil as a weapon in the
nuclear dispute. For instance, sighting the goal of keeping crude
prices between $ 50-60 per barrel, Iranian Deputy Oil Minister Mohammad
Hadi Nejad-Hosseinian stated that, "Iran will not use oil as a weapon
because we think it would have a very bad effect on most of the
population of the world." He also predicted that sanctions would not be
imposed on the grounds that such actions would have "very bad
consequences."
However, in light of the IAEA's referral, Iran reversed course by
threatening to use its leverage as a key global energy supplier should
the Security Council pursue drastic measures to halt the nuclear
program. Indeed, Iranian President Mahmoud Ahmadinejad claimed that
"the world needs the Iranian nation much more than the Iranian nation
needs the world."
As a result of the crisis, crude oil prices went up 8 % from
mid-February, and anxious investors hope for a last-minute deal to calm
the markets.
Conclusion
As the Security Council prepares to convene in New York, it can be
expected that China will make every effort to avoid sanctions against
Iran while attempting to mollify anxieties in the United States and
Europe over nuclear proliferation. Iran will count on China's economic
weight, and Security Council permanent member status, to counter
Western desires to punish Iran.
Meanwhile, Russia will continue to negotiate with Iran in order to
settle the matter without official UN action. The US and the EU, on the
other hand, will continue to push China and Russia to agree to some
form of sanctions regime against Iran in an effort to force Tehran to
comply with US and EU demands.
|
Australia plans
gas pipeline New England NSW N-W
24-03-06 Source: ABC
Plans have been unveiled for a $ 700 mm gas pipeline which will be laid
in New England and NSW north-west.
Hunter Energy is to lodge a development application with the State
Government for the pipeline which will link Wullumbilla in Queensland's
south-east with Hexham, near Newcastle. The line will travel through
Moree, Narrabri, Gunnedah on its way into the Hunter.
It comes at a time when the central ranges pipeline will begin
delivering gas to its first customers in Tamworth in April. At the same
time, Eastern Star Gas is considering extending its operations towards
Gunnedah and Tamworth with another gas-fired power station. One is
already operating in the Narrabri district.
Plans for the pipeline are expected to be lodged with Hunter region
councils in the next two months. Hunter Energy met the Upper Hunter
Shire Council earlier to discuss the pipeline.
General manager Matt Somers says the proposal has backing from the ANZ
bank and local developer Hilton Grugeon.
"We're lookingto build a gas pipeline from Wallumbilla down to
Newcastle and to pick up our existing pipeline, which will provide much
cheaper gas down to the Hunter again, but will also give Sydney an
alternate and third gas pipeline running into Sydney," he said. An
environmental impact study for the project is expected to be completed
by the end of June.
|
Venezuela's Seizure Ups the
Ante
Business Week Online 4/4/2006 by Geri Smith
Making good on year-old threats to take more control over its oil
production from international oil companies, Venezuela has seized an
oil field from France's Total and cancelled another oil-field contract
with Eni of Italy.
"These two companies are refusing to abide by our laws," said Energy
Minister Rafael Ramirez in a press conference in Caracas on Monday.
"They won't accept state control over our resources, and they won't
accept the taxes and royalty rates."
The move reflects the changing balance of power between governments and
oil companies. With oil prices in the country soaring above $50 per
barrel, Venezuela wants a better deal from oil companies, like other
oil producers around the world are seeking. Since winning approval for
a new hydrocarbons law in 2001, President Hugo Chavez has been angling
to renegotiate contracts that Venezuela struck with global giants in
the 1990s when oil prices were low and the government was desperate for
investment.
Deadline passes In the last few years, the government has significantly
increased royalties and cracked down on oil companies for alleged
underpayment of income taxes. The series of moves is forcing companies
to decide whether to play ball with Chavez and state-run oil producer
Petrleos de Venezuela, or PDVSA--or pick up stakes and leave the
country.
PDVSA had given foreign oil companies until March 31 to accept new
contracts for 32 oil fields that hand the state-run company majority
control of the operations. Sixteen companies, including Shell, the
Spanish-Argentine company Repsol YPF, Brazil's Petrobras, and China
National Petroleum agreed to the new contracts that will convert the
operations from what had been service contracts to joint ventures in
which PDVSA has at least a 60 percent stake.
But Total and Eni balked at the new conditions, and ExxonMobil, which
has threatened to legally challenge changes in Venezuela's oil
royalties and contracts, decided to sell its own oil field stake to
Repsol.
Take it or leave it Over the past weekend, Ramirez triumphantly and
symbolically raised the Venezuelan flag at Total's Jusepin oil field,
which produces 30,000 barrels a day, and at Eni's Dacion oil field,
which produces 50,000 barrels a day. Both companies, Ramirez said at
Monday's press conference, would be compensated. But he gave no details
on how the compensation would be determined.
Ramirez, who is also president of PDVSA, said last week that if
ExxonMobil were displeased with changing conditions in Venezuela, the
company was free to leave the country. But like Total and Eni,
ExxonMobil has other operations it values in Venezuela, including a 50
percent stake in an exploration venture with Petro-Canada called La
Ceiba. It also has a 41.7-percent share in a joint-venture heavy-crude
production project with BP and PDVSA called Cerro Negro, in Venezuela's
oil-rich Orinoco Belt. Exxon's tougher stance, however, may have
contributed to the company being dropped from a big petrochemical
project three months ago and eliminated from a major natural gas
exportation project several years ago.
Chavez' and PDVSA's moves are the latest signs of shifting fortunes for
oil companies in Venezuela. The government expropriated the oil
industry in 1976 but in the mid-1990s invited international oil
companies to come back to help the country develop its huge reserves.
Rough ride Venezuela has proven reserves of approximately 80 billion
barrels, about 34 billion of which are extra-heavy crude deposits in
the Orinoco basin that must undergo special refining to make them
marketable. But the country also sits on about 235 billion to 250
billion barrels more of extra-heavy crude, which if proven would give
Venezuela the largest oil reserves in the world--greater even than
Saudi Arabia.
However, Venezuela's oil industry has suffered much volatility over the
seven years since Chavez, an ex-paratrooper who once staged a failed
military coup, was elected president and took office in 1999. After a
nationwide recall movement failed to unseat Chavez in 2003, he shook up
PDVSA and fired most of the top executives, many of whom had advocated
his removal from office. That, plus a two month-long strike by oil
workers, disrupted crude production.
In 1999, the country's production capacity was about 3.5 million
barrels per day, of which 150,000 to 200,000 barrels were being
produced by foreign oil companies. Today, although PDVSA claims it is
producing 3.27 million barrels a day, most international oil analysts
believe the real figure is closer to 2.6 million barrels, of which 1.1
million barrels are being pumped by the private companies. More than
half of that private production, or around 600,000 barrels a day, comes
from the 32 oil fields whose investment regimes were changed last week.
No check on power Luis E. Giusti, the former CEO of PDVSA who opened
the country to private investment in the mid-1990s and who is now an
oil expert at the Center for Strategic and International Studies [CSIS]
think tank in Washington, D.C., says the Venezuelan government's
crackdown on foreign oil companies is a "circus." The entire national
congress and Supreme Court are allied with Chavez. "This man is so
powerful now that he can do almost anything he wants," says Giusti.
In the mid-1990s, Giusti says, none of the oil companies was very
interested in helping Venezuela exploit its heavy-crude deposits.
"Nobody wanted to invest in these fields," he says. Venezuela had to
offer lower taxes, offer an attractive investment environment, and
arrange for a pipeline to ship the oil 300 miles to the shore. Foreign
oil companies responded, investing more than $25 billion in Venezuela
over the past decade.
Today, with Venezuelan oil fetching $55.50 a barrel on international
markets, the Chavez government is reaping the benefits of that
investment, yet "now the government claims that none of those
incentives were justified," Giusti says. [The Venezuelan government
plans to try Giusti in absentia in connection with opening up the oil
industry in the 1990s.]
Can't walk away? Not everyone views the rewritten contracts as a bad
deal for the oil companies. Mazhar al-Shereidah, professor of
international oil economics at the Central University of Venezuela in
Caracas, says the new deal will benefit the companies by giving them 40
percent of the oil produced at their fields through 2018. Before, he
says, they were merely operating the oil fields and delivering the oil
to PDVSA for a set fee and reimbursement of investment expenses.
Whether they agree or not, foreign companies investing in other oil
projects in Venezuela, such as the extra-heavy crude deposits in the
Orinoco Belt, can expect those contracts to be reviewed shortly, too.
But, Giusti says, with world oil prices as high as they are, "companies
are just going to have to swallow this" if they want to remain in
Venezuela. It's all a question of supply and demand.
|
California LNG Site
Tidelands Unit Considers
Esperanza Energy LLC 4/4/2006
Esperanza Energy, a newly formed subsidiary of Tidelands Oil & Gas,
announced Tuesday that the company is evaluating the feasibility of
developing an offshore, deepwater Southern California liquefied natural
gas (LNG) receiving terminal.
Although a specific site off the Southern California coast has not been
determined at present, the company is focusing its evaluation on
several potential sites up to 12 miles offshore of the greater Long
Beach area.
"Our goal is to develop a LNG import terminal that can play an
important role in meeting California's growing energy needs by
providing competitively priced natural gas to supplement that which is
currently transported into the state by long-distance pipelines,"
stated Michael Ward, Esperanza Energy's president. "Esperanza will only
pursue this project if it can be sited, designed, and operated in the
safest, most environmentally responsible and economically viable manner
possible. Our goal is not to just meet the environmental, public
health, and safety requirements, but to exceed them."
Esperanza Energy is initiating a project feasibility study with the
assistance of the following LNG, environmental, pipeline, and legal
experts:
David Maul, former manager of the California Energy Commission's
Natural Gas Office and president of Maul Energy Advisors ENTRIX,
a professional environmental consulting company specializing in
environmental permitting and compliance for major offshore oil and gas
projects in California and the U.S. Project Consulting Services,
a provider of engineering, construction, management, and inspection of
onshore and offshore pipelines Pillsbury Winthrop Shaw Pittman,
an interdisciplinary law firm with practices in environmental, land
use, and energy legal advice and in project development and finance.
"As the former head of the California Energy Commission's Natural Gas
Office, I'm intimately familiar with every LNG project on the West
Coast," stated Maul. "I chose to work with Esperanza Energy because of
the company's strong commitment to design and build a LNG project that
is responsive to California's unique environmental and regulatory
sensitivities." Maul added that his company's preliminary analysis
suggests that a site offshore the Long Beach area would offer
considerable benefits to California residents with the greatest respect
for environmental and safety issues. "Before selecting a specific site
for developmental consideration, we will confer with key local,
regional, and state stakeholders," he concluded.
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LNG Florida Port Suez
Energy Pursuit
SUEZ Energy North America, Inc. 4/4/2006
Suez Energy North America (SENA) said that its subsidiary, Calypso LNG,
is pursuing the development of a submerged buoy system off the
southeastern coast of Florida, known as a "Deepwater Port," that would
serve as an offshore delivery point for liquefied natural gas (LNG)
delivered by specially-built LNG tankers.
On March 1, the company filed a deepwater port license application with
the U.S. Coast Guard, which has jurisdiction for the permitting,
operation, and security for such facilities located in federal waters.
The Calypso Deepwater Port is proposed to be located approximately 10
miles offshore from Port Everglades and will comprise a marine
offloading buoy and anchoring system that will reside approximately 150
feet below the ocean surface when not in use.
The proposed facility will connect to an undersea pipeline operated by
another SENA subsidiary, Calypso U.S. Pipeline, that will transport
natural gas from the Deepwater Port to customers in Florida.
A similar project was proposed by an affiliate company of Calypso,
Neptune LNG, which filed a license application with the Coast Guard for
a Deepwater Port on February 15, 2005. That project will be located off
the coast of Massachusetts to serve Boston and the greater New England
market. Development of this offshore installation is within schedule
and is targeted to be up and running in 2009.
The Calypso project is proposing to replicate many of the Neptune
project's specifications in order to accelerate its licensing process
and create operational synergies.
"The overwhelming feedback we have received from Florida customers is
that they need additional, LNG-based gas supplies and they need them as
soon as possible," said Zin Smati, president and CEO of SENA. "It is
our intention to meet our customers' needs and be the first supplier of
natural gas directly into the southeastern Florida market derived from
LNG. We believe our Calypso project is consistent with Governor Bush's
call for fuel diversification as outlined in his comprehensive 2006
Florida Energy Act."
Suez is currently the only major energy company that owns and operates
LNG facilities on each side of the Atlantic Ocean--at Everett,
Massachusetts, serving the New England market, and at Zeebrugge,
Belgium, serving the central European market. An affiliate of Suez
Energy International is also engaged in a longer-term LNG terminal
development project located in Freeport Harbor on Grand Bahama Island.
"The Florida market is very important to us," said Dirk Beeuwsaert, CEO
of Suez Energy International. "As our LNG supply and shipping
portfolios continue to grow, the Calypso project will increase our
already significant position in the Atlantic Basin and give us the
critical mass to serve all of our markets with a level of reliability
that will be unmatched in the industry."
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Shtokman Decision May
Be Delayed to End-April
by Geoffrey T. Smith, Dow Jones FWN Financial News 4/4/2006
Russian natural gas monopoly OAO Gazprom (GSPBEX.RS) may delay choosing
its partners for the Shtokman gas projects in the Barents Sea by
another two weeks, Deputy Chief Executive Alexander Medvedev said
Tuesday. "I hope that the consortium will be announced if not by the
middle of April, as I said earlier, then at least by the end of the
month," Medvedev told a conference.
He later told reporters the delay was due to time needed to consider
new proposals from potential partners.
Gazprom Monday said it would accept proposals from its five prospective
partners until the end of the week. As previously reported, the five
companies short-listed are ConocoPhillips (COP), Total SA (TOT),
Chevron Corp. (CVX), Statoil ASA (STO) and Norsk Hydro ASA (NHY).
According to Chief Executive Alexei Miller, Gazprom intends to take "no
fewer than two, no more than three partners" for the field, which
contains an estimated 3.2 trillion cubic meters of natural gas and is
expected to cost between $12 billion and $14 billion to develop.
Earlier at the same conference, deputy CEO Alexander Ryazanov said
Gazprom intends to allow one of its partners to operate production at
the field, but said Gazprom would retain responsibility for marketing
the gas.
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Shtokman Project
Gazprom Sees Foreign Operator
by Geoffrey T. Smith, Dow Jones FWN Select 4/4/2006 MOSCOW, Apr
04, 2006
Russian gas monopoly OAO Gazprom (GSPBEX.RS) expects to make one of its
foreign partners operator of the production site of its Shtokman
project, the company's Deputy Chief Executive Alexander Ryazanov said
Tuesday. Ryazanov told a conference the foreign partners had
superior production technology and could be expected to oversee its
installation and operation.
"They will be taking on special responsibilities as regards the
implementation and thus they will expect certain privileges," he said.
However, he stressed Gazprom would keep overall responsibility for
marketing the gas from the field. [ 04-04-06 0633GMT ]
Gazprom has shortlisted five companies to partner it on the 3.2
trillion cubic meter field project, which will be the first offshore
project and the first liquefied natural gas project the company has
ever controlled.
Gazprom intends to chose "no fewer than two and no more than three"
partners by April 15, according to Chief Executive Alexei Miller.
Ryazanov repeated Tuesday Gazprom's existing estimate that the first
phase of the project would cost between $12-14 billion.
Separately, Ryazanov said Belarus should pay "at least three times as
much" for the gas its buys from Gazprom. As reported last week, Gazprom
requested Belarus start paying market prices as of 2007, as opposed to
the current agreement under which Belarus pays a little under $48 a
thousand cubic meters.
Ryazanov acknowledged Russian demands for sharp increases in prices
paid by its former Soviet neighbors were painful, but pointed out that,
relative to market conditions in Western Europe, the new price levels
still represent a degree of concessionary pricing. He noted Moldova for
example, even today at the current level of $110 a thousand cubic
meters, pays less than half the Western European price of $240 a
thousand cubic meters.
Five years ago the discount had been much narrower with Moldova paying
$80 and Western Europe paying $100, Ryazanov said.
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Georgian Wells
CanArgo Provides Update
CanArgo Energy Corporation 4/4/2006
CanArgo Energy reports that tests are progressing on the Norio MK72
exploration well, where a comprehensive testing program is being
carried out on oil bearing Oligocene sandstones. The well is located in
the former Soviet republic of Georgia.
According to the company, the Oligocene sands that will now be tested
in the MK72 well had good oil shows while drilling. The oil to surface
and hydrocarbons interpreted on the electric logs reportedly indicated
some 100 meters (330 feet) of net pay sands with porosities in the
range of 15 to 20 percent.
A cement plug was set in the lower part of the hole, sealing off the
oil discovery made at Middle Eocene level. Next, some 98 meters (322
feet) of the sands were perforated over the interval 3,687 meters
(12,096 feet) to 4,152 meters (13,622 feet) measured depth in several
runs using high penetration through-tubing conveyed perforating guns.
CanArgo said that the well is showing good formation pressure, with
surface shut-in pressures of up to 168 atmospheres (2,468 psig) being
recorded, and with oil and gas recovered to surface, together with
quantities of drilling mud.
The oil gravity is approximately 45 degrees API. Natural gas lift is
being used to clean-up the well, which is slugging clean oil and heavy
mud with barite. This section was drilled with heavy mud in 2003 and it
is expected that there is a still some quantity of mud to be recovered
from the formation before continual oil flow is achieved.
The company noted that testing will continue. However, in order to
asses the commercial viability of the flow rate, it could take several
weeks for the well to clean-up properly.
CanArgo is encouraged by the rapid pressure build up observed at the
well-head each time the well is shut in for a period of time. It
expects a more stabilized oil flow to be achieved in time.
CanArgo also said that its Ninotsminda Field horizontal well N97H has
been tested for approximately three weeks. The well has tested a total
fluid rate of up to 1,145 barrels per day, and the maximum oil flow
rate achieved to date has been 385 barrels per day.
The Ninotsminda well is currently being gas lifted but is producing
fluid with a high water cut, said CanArgo, which believes that the well
has intersected a water-bearing fracture from the N4H horizontal well.
N4H is located to the southwest of the end of the N97H borehole.
Interference testing between the N4H and N97H has established that the
two wells are in pressure communication, despite the relatively large
separation, noted the company. Indeed, CanArgo contends that the
testing of the N97H well resulted in an increase in oil production from
the N4H well.
The company believes that it will be necessary to seal off the
water-producing fracture in the N97H well in order to re-establish oil
production. It is considering using a coiled-tubing unit that is
available in Georgia for this purpose once production logging tools
have been run. The logging tools will establish the position of the
water producing zone, which is believed to be toward the end of the
horizontal section furthest from the original well bore.
CanArgo said that its Manavi M12 appraisal well is currently drilling
ahead at 1,611 meters (5,285 feet) in the 17 1/2-inch hole section. It
is still forecast that this well will reach the Cretaceous reservoir
section in early summer, after which testing is planned.
Further testing of the Manavi M11Z well using a Schlumberger
coiled-tubing unit was planned for April. However, lack of certainty on
the availability of equipment and the higher cost of mobilization for a
single job has lead CanArgo to postpone this test until the completion
of the Manavi M12 well. At which point, the equipment could be
mobilized for both jobs should acid stimulation be necessary in M12.
Given the small hole size and other mechanical complications in the
M11Z well, CanArgo has decided that it should focus on getting a good
test on the M12 well. M12 should have a significantly larger hole size,
and M11Z reportedly would provide a sub-optimal test. The company does
plan to test the M11Z well after completing M12, though.
"This is very much an interim update on our testing program on both the
MK72 exploration well on Norio and the N97H development well on
Ninotsminda, and final test results may not be available for a number
of weeks," advised Vincent McDonnell, CanArgo's chief operating
officer.
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Gippsland Basin Block
Apache Becomes Operator
International TME Resources Inc. 4/4/2006
International TME Resources said that Apache has signed an agreement to
become the operator of VIC/P45, a 214,896-gross-acre block offshore
Australia in the Bass Strait in the Gippsland Basin. The deal
calls for Apache to pay 100 percent of the cost to drill the first well
in exchange for a 66.6667-percent working interest.
TME owns 15 percent of two joint ventures that each own a 1/20 of 1
percent over-riding royalty on the total acreage block.
Depending on the results from the 1st well, Apache may elect to drill a
second well and pay 100 percent of the associated drilling cost. In
addition, Apache will assume its share of royalty obligations to third
parties.
Upon approval of this transaction by regulatory authorities, Apache
will become operator of VIC/P45 and begin to select the drilling
location for the first well. The well is slated for drilling once a
suitable rig can be contracted.
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BassGas Project Reaches
Milestones
Origin Energy 4/4/2006
Origin Energy reports that the BassGas Project, which will
commercialize gas from the Yolla field in the Bass Strait offshore
Australia, is continuing through a slower-than-expected commissioning
phase.
In early March, gas from the Victorian grid was introduced to the
onshore gas processing plant at Lang Lang for the final stage phases
gas of equipment testing, preparations, and plant dry-out. This step
preceded the introduction of raw gas from offshore.
Another significant milestone for the project was the Victoria WorkSafe
Authority's completion of its assessment and verification of the Safety
Case for the Lang Lang Plant. The commission subsequently granted
Origin Energy a three-year license to operate.
Origin adds that work offshore on the Yolla platform is continuing in
parallel. The Safe Astoria Accommodation Vessel remains alongside Yolla
to provide logistical support.
Remarking that "good progress" has been made, Origin nevertheless said
that the commissioning phase continues to reveal a significant number
of unexpected construction defects. These defects must be remedied
before the plant commences production. As a result, the phase of the
commissioning and start-up is taking longer than expected.
Origin now expects that first product sales will occur in May, with
production ramp-up and plant testing continuing during May and into
June. The project will thus make no significant contribution to
Origin's financials for the remainder of the fiscsl year, which ends on
June 30, said the company.
In addition to operator Origin Energy Resources (37.5 percent
interest), other participants in the BassGas Project are Origin Energy
Northwest (5 percent), AWE Petroleum (30 percent), CalEnergy Gas (15
percent), and Wandoo Petroleum (12.5 percent).
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Total, Eni, Statoil
Refuse Partnership with PDVSA
BNAmericas 4/4/2006
French oil firm Total (NYSE: TOT), Italy's Eni (NYSE: ENI) and Norway's
Statoil (NYSE: STO) have declined to sign contracts with Venezuela to
enter into joint ventures led by state oil firm PDVSA to operate
different oilfields, Venezuelan government and company officials told
BNamericas, confirming local press reports.
Sixteen oil companies signed accords with Venezuela's energy and oil
ministry on Friday agreeing to convert their operating agreements into
JVs, which gives PDVSA at least 60% control over the operations.
However, Total, Eni and Statoil were not satisfied with the terms.
"We declined to sign, the terms didn't please us," a Total official
told BNamericas on Monday. As a result PDVSA has seized control of
Total's Jusepin field in Monagas state, the official said.
Jusepin is the largest standard crude operation in Latin America with
almost 400,000 barrels a day (b/d) output. Total had been operating
Jusepin for more than a decade.
PDVSA also terminated Eni's operating service contract on the Dacion
field in Anzoategui state and all management of the operations must be
transferred to PDVSA personnel, Eni said in a statement. "Eni will
comply with PDVSA's request by ensuring activities are handed
over in a professional way and at an agreed time. However, Eni believes
this action by PDVSA is a violation of Eni's contract rights," the
statement said.
If an agreement cannot be reached, Eni said it would pursue "legal
action to claim its rights."
The 16 companies that did sign agreements with PDVSA were Spain's
Repsol YPF (NYSE: REP), the UK's BP (NYSE: BP), Japanese firm Teikoku,
the local unit of Canada's PetroFalcon (TSX: PFC) Vinccler Oil &
Gas, local firms Suelopetrol, Inemaka and Open, Brazil's federal energy
company Petrobras (NYSE: PBR), China's CNPC, US-based Chevron (NYSE:
CVX), Anglo-Dutch major Shell (NYSE: RDS-B), Argentina's CGC, fellow
Argentine firm Tecpetrol, France's Perenco, US-based Harvest (NYSE:
HNR) and France's Hocol, Venezuela's state news agency ABN reported.
These companies produce a combined 200,000b/d of crude in Venezuela.
The largest operation is Chevron's Boscan field with 100,000b/d of
production, mostly for asphalt manufacture.
Venezuela's President Hugo Chavez ordered oil companies in operating
agreements with PDVSA to accept the new JV agreements by the end of
last year or face having their fields seized by PDVSA. Chavez has
justified the move by saying the operating agreements were too
expensive for PDVSA to maintain.
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