Tuesday, May 31, 2011

U.S. Oil Import Dependence is declining




U.S. oil import dependence is an issue perhaps as hotly debated as it is loosely defined. As discussed in a This Week in Petroleum article published in 2008, there is more than one way of measuring it. Different methods of calculation yield different results. But whichever way it is defined, U.S. dependence on imported oil has dramatically declined since peaking in 2005, continuing a trend that was beginning to emerge the last time This Week In Petroleum examined the issue. By the broadest measure, U.S. dependence on imported oil fell below the 50 percent mark last year for the first time since 1997. To put it succinctly, discrepancies in the way dependence is assessed arise because oil, for the most part, is imported as crude oil, but is consumed as refined products, of which crude oil is the main but not the only input - hence the need to clarify whether dependence is assessed at the output/consumption level or at the input level, and in the latter case what range of inputs is included as a basis for comparison. Two of the most common and straightforward definitions measure dependence as the ratio of total net oil imports (including crude and products) to total product consumption, or much more narrowly as the ratio of net imported crude oil to net crude oil inputs to refineries.

By the broadest standard (Measurement A in Table 1), U.S. dependence on imported oil fell from 60.3 percent in 2005 to 49.3 percent in 2010. If processing gains obtained from imported crudes are counted as imports (Measurement B), then dependence falls from a high of 63.6 percent in 2005 to 52.8 percent last year. A much narrower measure that looks at crude oil imports into the United States as a percentage of total refinery crude inputs (Measurement C) excludes ethanol, biodiesel, and natural gas liquids (NGLs) as sources of petroleum products that are almost entirely domestic in origin and also does not reflect the substantial recent growth in U.S. petroleum product exports. By that measure, import dependence was 62 percent last year, still significantly below its 2008 peak of 66.6 percent.



US Oil Dependence



There is no single explanation for the decline in U.S. oil import dependence since 2005. Rather, the trend results from a variety of factors. Chief among those is a significant contraction in consumption. U.S. oil product deliveries declined by 1.7 million barrels per day (bbl/d) to 19.1 bbl/d in 2010, from 20.8 million bbl/d in 2005. This decline partly reflects the downturn in the underlying economy after the financial crisis of 2008. Not surprisingly, demand has bounced back somewhat from a low of 18.8 million bbl/d in 2009, when the U.S. economy bottomed out. But the downward trend in consumption started two years before the 2008 crisis and reflects factors such as changes in efficiency and consumer behavior as well as patterns of economic growth.

Shifts in supply patterns, including increases in domestic biofuels production, NGL output and refinery gain, also played an important role in moderating import dependence. U.S. ethanol net inputs grew from 230,000 bbl/d in 2005 to 779,000 bbl/d in 2010, helping to displace traditional hydrocarbon fuels and so reducing petroleum import needs. Strong gains in the deepwater Gulf of Mexico and the Bakken formation brought decades of contraction in domestic oil production to a sudden halt, and even led to a rebound. U.S. crude oil output increased by an estimated 334,000 bbl/d between 2005 and 2010, further eroding the need for imported crude oil.

Incremental refinery gains provide a smaller, but non-negligible, source of domestic supply growth. As U.S. refineries become increasingly complex, the amount of light products they are able to extract from crude oil keeps rising. Between 2005 and 2010, the volumetric increase in product output compared to crude oil input -- the "processing gain" -- rose by 75,000 bbl/d. The effect on U.S. oil dependence measurements depends on whether that entire gain, or only the portion of the gain that is specifically derived from domestic crude, is treated as domestic supply. Because oil is a global market, domestic supply and demand factors are only part of the story. Another component of reduced U.S. oil import dependence is the growth in export demand for U.S. refined products. Increased demand beyond the U.S. borders has lifted U.S. product exports to 2.3 million bbl/d in 2010 from 1.1 million bbl/d in 2005. Nowhere have U.S. product exports increased more than in the Americas, including Mexico, Canada, Central and South America and the Caribbean, thanks to economic and population growth and inadequate refining capacity in those countries. As a result, U.S. net imports (imports minus exports) of petroleum products plummeted in 2010 to their lowest level seen in the data history that begins in 1973.

The recent rise of U.S. product exports explains why a measure of U.S. import dependence based exclusively on refinery input, such as Measurement C in Figure 1, shows significantly higher dependence, and a slower decline in dependence, than broader measures based on total consumption. In other words, rising product export demand has caused U.S. net imports of products to decline much faster than net imports of crude oil.

The past, as the saying goes, is no guarantee of future performance. The EIA expects that the moderating trend in U.S. oil-import dependence to go on in the next decade. But the mix of factors responsible for it looks likely to evolve. In particular, EIA projects that continued improvements in energy efficiency, driven in part by tighter fuel economy standards, will prove increasingly important in moderating future demand growth, offsetting the upward impact of economic recovery.



Table 1: Three Alternative Measurements for U.S. Oil Import Dependence
( Percent Dependence)
Measurement AMeasurement BMeasurement C
YearNet oil imports (crude
& products) as
share of total
demand
Same as A with
refinery gain for
imported crude oil
counted as imports
Net imported
crude oil as a
percentage of
net crude oil
inputs to refineries
1995-200049.251.855.7
200155.558.361.5
200253.456.461.1
200356.159.263.1
200458.461.765.0
200560.363.666.3
200659.963.266.2
200758.261.566.0
200857.060.566.6
200951.554.862.6
201049.352.862.0


Retail gasoline and diesel prices show sizeable weekly decreases
The U.S. average retail price of regular gasoline dropped 11 cents to hit $3.85 per gallon, marking the largest weekly decline since December 2008. The average price is $1.06 per gallon higher than last year at this time. The biggest decrease came in the Midwest, where prices plummeted almost 16 cents on the week. The Gulf Coast recorded an 11-cent decline; prices in the region are the lowest in the country at $3.71 per gallon. The average price on the East Coast fell about nine cents, while West Coast prices were down eight cents on average, but remain the highest among the major regions at $4.04 per gallon. Price movements were more muted in the Rocky Mountains, with the average gasoline price down about two cents for the week.




The national average diesel price fell for the third consecutive week, dropping more than 6 cents last week to $4.00 per gallon. This was the largest weekly decline in the national average diesel price since May 2010. The diesel price is $0.98 per gallon higher than last year at this time. Like gasoline, Midwest prices saw the biggest regional decline, dropping more than seven cents on the week. On the East Coast and Gulf Coast, average diesel prices were down more than six cents, while the West Coast average price fell about a nickel. Rounding out the regions, the Rocky Mountain diesel price was three cents lower this week.



Propane stocks continue to climb
Total U.S. inventories of propane rose last week, gaining 1.1 million barrels to end at 31.6 million barrels in total. The largest build was in the Midwest region with 0.7 million barrels of new propane stocks. The East Coast region added 0.3 million barrels and the Gulf Coast region grew by 0.1 million barrels. The Rocky Mountain/West Coast regional stocks were up slightly. Although propane stocks are tracking below the average range for this time of year, inventories have risen steadily for five consecutive weeks, an increase of 5.2 million barrels during that period. Propylene non-fuel use inventories represented 5.7 percent of total propane inventories.


Ref: http://www.eia.gov

US Oil Independence by 2030

Contrary to what most people might think, oil independence is possible for the United States by 2030.


The news is especially important when one considers that, between 1970 and 2000, economists estimate that the costs of American dependence on foreign supplies of oil have ranged between $5 and $13 trillion dollars. That’s more than the cost of all wars fought by the U.S. (adjusted for inflation) going all the way back to the Revolutionary War. 


The trick is to start by thinking about oil independence a little differently. Oil independence should not be viewed as eliminating all imports of oil or reducing imports from hostile or unstable oil producing states. Instead, it should entail creating a world where the costs of the country’s dependence on oil would be so small that they would have little to no effect on our economic, military, or foreign policy. It means creating a world where the estimated total economic costs of oil dependence would be less than one percent of U.S. gross domestic product by 2030.

Conceived in this way (and contrary to much political commentary these days), researchers at the Oak Ridge National Laboratory (ORNL) have calculated that if the country as a whole reduced their demand for oil by 7.22 million barrels per day (MBD) and increased supply by 3 MBD, oil independence would be achieved by 2030 with a 95 percent chance of success. By reducing demand for oil, increasing its price elasticity, and increasing the supply of conventional and unconventional petroleum products, ORNL researchers noted that the country would be virtually immune from oil price shocks and market uncertainty. If large oil producing states were to respond to the U.S. by cutting back production, their initial gains from higher prices would also reduce their market share, in turn further limiting their ability to influence the oil market in the future.


So if decreasing American demand for oil by 7.22 MBD and increasing supply by 3 MBD would enable the U.S. to achieve oil independence in 2030, which combination of policies offers an optimal strategy? Policymakers, for instance, could lower demand for oil by making automobiles more efficient (by legislating more stringent fuel economy standards for light and heavy duty vehicles or lowering the interstate speed limit), promoting alternatives in mode choice (such as mass transit, light rail, and carpooling), or establishing telecommuting centers and incentives for commuters to work from home. They could also promote rigorous standards for tire inflation and reduce oil consumption in other sectors of the economy. Alternatively, they could increase alternative domestic supplies of oil, develop better technologies for the extraction of oil shale, mandate the use of advanced oil recovery and extraction techniques, and promote alternatives to oil such as ethanol, bio-diesel, and Fischer-Tropsch fuels. 


Taken together, such policies could reduce demand for oil by 8.266 to 12.119 MBD and increase American oil supply by 8.939 and 12.119 MBD by 2030—well over the target set by the ORNL study. Thus, to insulate the American economy from the vagaries of the world oil market, policymakers need not focus only geopolitical power structures in oil producing states. Instead, attempts to change the behavior of the country’s automobile drivers, industrial leaders, and homeowners could greatly minimize reliance on foreign supplies of oil. To battle the “oil problem” policymakers need not talk only about sending more troops to Iraq or Saudi Arabia nor drafting new contracts with Nigeria and Russia. They could also focus on curbing American demand for oil and expanding domestic conventional and alternative supplies.

Thursday, May 26, 2011

China Lures Crude From U.S.



Ecopetrol SA (ECOPETL), the Colombian oil producer which expects to more than double output this decade, said it plans to ship a greater share of its crude to Asia as growing demand in China competes for supplies with the U.S.

The company may no longer ship the majority of its crude to the U.S. in 10 years because Asia sales will be more profitable, Chief Executive Officer Javier Gutierrez said yesterday in an interview in Bogota. A pipeline the company is weighing that would carry oil to a new port on the Pacific coast to supply Asian refineries may also attract Chinese investment, he said.

“We are opening markets in the East -- China and India are starting to be significant for us,” Gutierrez said. Asian “markets will keep growing a lot,” he said.

China is buying oil assets in Latin America and helping finance exploration at companies such as Brazil’s Petroleo Brasileiro SA (PETR4) to meet rising demand as its economy surges. The U.S. is also seeking new sources of crude as traditional suppliers such as Mexico and Venezuela struggle to maintain output. U.S. President Barack Obama said in March that the U.S. wanted to become one of Brazil’s “best customers” for oil.

The Bogota-based company plans to boost output to 1.3 million barrels per day in 2020 as it taps reserves in Colombia, the U.S. Gulf of Mexico, Peru and Brazil through exploration and asset purchases. Ecopetrol, which had average output of about 615,900 barrels per day last year, plans to spend about $80 billion over the next 10 years to reach its goals, he said.
Investment Plan

Ecopetrol’s investment plan includes construction of the $4.2 billion Bicentennial pipeline, which will carry crude from fields in eastern Colombia to the Caribbean coast.

The company will need to build infrastructure to meet its goal of boosting exports because fuel transportation capacity has lagged gains in its production, Mauricio Restrepo, an analyst at Medellin-based brokerage Bolsa & Renta, said.

“There is more than enough oil -- what is lacking is a way to carry it,” Restrepo said in a telephone interview.

China, the world’s largest energy consumer, is snapping up more Colombian coal and crude after the Asian economy expanded 9.7 percent in the first quarter. China Petroleum Corp., known as Sinopec, also agreed to pay $7.1 billion for a 40 percent stake in Repsol YPF’s Brazilian unit in October as part of asset purchases the company made throughout Latin America last year.
Third-Largest Producer

Colombia, South America’s third-largest crude producer, may more than double output in 2020 to 2 million barrels per day, as Ecopetrol and other companies increase production, Gutierrez said. Improved security after the government repelled guerrilla groups has helped lure investors including billionaires Eike Batista and Carlos Slim to the nation’s energy reserves.



This year, Ecopetrol has had to repair pipelines in eastern and southern Colombia after guerrilla sabotage. Attacks by rebel groups on Colombian pipelines, roadways and bridges fell to 76 in 2009 from more than 800 in 2002, according to the government.

To fund expansion, Ecopetrol plans to sell shares for the first time since raising $2.7 billion in an initial public offering in 2007.

The sale will take place this year “in principle,” with the timing dependent on “market conditions,” Gutierrez said, declining to provide further information on the sale.

Ecopetrol rose 20 pesos, or 0.5 percent, to 3,960 pesos in Bogota trading. The stock has fallen 3.4 percent this year, while Colombia’s benchmark Colcap index had dropped 3.9 percent in the same period.
Ecopetrol Stake

Ecopetrol by law can sell as much as a 9.9 percent stake, which at current prices is worth about $8.6 billion. Colombia’s government said in March it will sell as much as 1.5 percent of Ecopetrol at year-end as part of a plan to ultimately divest up to 10 percent.

Colombia’s improved credit rating and greater security is luring international companies, increasing the chance of new oil discoveries, according to Gutierrez.

Carlos Slim’s Grupo Carso this year bought a stake in Geoprocesados SA’s Tabasco Oil Co., which is exploring in eastern Colombia. Batista’s OGX Petroleo & Gas Participacoes SA said last year that it may begin production in 2012 in Colombia after garnering exploration rights in a 2010 government auction.

The two billionaires “wouldn’t take the risk if they didn’t see the opportunity of a return,” Gutierrez said. “Colombia has awakened a lot of interest.”

Investment from more than 100 companies seeking oil reserves in Colombia may trim Ecopetrol’s share of the nation’s output to less than 50 percent over a decade from more than two- thirds currently, even as its production jumps, Gutierrez said.

Crude oil for July delivery fell $1.09 to settle at $100.23 a barrel on the New York Mercantile Exchange. Prices have increased 40 percent in the past year.

Oil in New York settled at $113.93 a barrel on April 29, the highest since September 2008.

Standard & Poor’s raised the nation’s foreign debt rating one step on March 16 to BBB-, the lowest level of investment grade. Moody’s Investors Service and Fitch Ratings rate Colombia one level below investment grade with a positive outlook.

Wednesday, May 25, 2011

2012 forecast of Brent oil prices increased to $140



Gasoline rose along with crude oil after Goldman Sachs Group Inc. and Morgan Stanley boosted their oil price forecasts.Futures advanced as Morgan Stanley increased its Brent oil 2011 outlook by 20 percent to $120 a barrel and Goldman estimated prices would hit $130. Prices also gained as the dollar fell 0.3 percent against the euro as of 12:31 p.m. in New York, adding to the investment appeal of commodities.


"Goldman is calling for crude to go back up and the dollar is starting to show signs of weakness," said Phil Flynn, vice president of research at PFGBest in Chicago.

Gasoline for June delivery rose 3.19 cents, or 1.1 percent, to $2.97 a gallon at 1:06 p.m. on the New York Mercantile Exchange. Futures rose as much as 3 percent.Crude oil for July delivery increased 98 cents, or 1 percent, to $98.68 a barrel on the exchange.

Gasoline also gained as U.S. inventories were 16 percent below a year earlier, according to Energy Department data. This weekend's three-day Memorial Day holiday period is the traditional kickoff of the summer driving season.

"You have fairly tight gasoline supplies and the dollar turned down today," said Gene McGillian, an analyst and broker at Tradition Energy in Stamford, Connecticut.

Inventory Report Tomorrow

The department is scheduled to report last week's inventories at 10:30 a.m. tomorrow in Washington. Gasoline stockpiles rose 400,000 barrels, according to the median estimate of 14 analysts in a survey by Bloomberg News.

Supplies of distillate, including heating oil and diesel, increased 50,000 barrels, according to the survey's median estimate.

U.S. refining margins have been strong, largely due to the discount for benchmark West Texas Intermediate versus Brent oil that is likely to narrow, analysts at Goldman Sachs led by Jeffrey Currie said in a report today.

"We maintain that refining margins will remain under pressure owing to the large increase in refining capacity in Asia," Currie said. "For 2012 and beyond, we believe that crude will be the bottleneck in the system, rather than refining."

Goldman raised its end-of-2012 forecast of Brent oil prices to $140 a barrel from $120.Regular retail gasoline dropped 1.5 cents to $3.828 a gallon, AAA said on its website.

Heating oil for June delivery added 4.19 cents, or 1.5 percent, to $2.889 a gallon on the exchange.


Tuesday, May 24, 2011

Bakken Formation Oil will be updated by U.S. Geological Survey



Secretary of the Interior Ken Salazar today announced that the U.S. Geological Survey will update its 2008 estimate of undiscovered, technically recoverable oil and gas in the U.S. portion of the Bakken Formation, an important domestic petroleum resource located in North Dakota and Montana.

“The Administration supports safe and responsible oil and gas production as part of our nation’s comprehensive energy portfolio,” Salazar said. “We must develop our resources armed with the best science available, and with wells drilled in the Bakken during the past three years, there is significant new geological information. With ever-advancing production technologies, this could mean more oil could potentially be recovered in the formation.”

The 2008 USGS assessment estimated 3.0 to 4.3 billion barrels of undiscovered, technically recoverable oil in the U.S. portion of the Bakken Formation, elevating it to a “world-class” accumulation. The estimate had a mean value of 3.65 billion barrels. The USGS routinely conducts updates to oil and gas assessments when significant new information is available, such as new understanding of a resource basin’s geology or when advances in technology occur for drilling and production.


The 2008 Bakken Formation estimate was larger than all other current USGS oil assessments of the lower 48 states and is the largest "continuous" oil accumulation ever assessed by the USGS. A "continuous” or "unconventional" oil accumulation means that the oil resource is dispersed throughout a geologic formation rather than existing as discrete, localized occurrences, such as those in conventional accumulations. Unconventional resources require special technical drilling and recovery methods.
North Dakota Oil Production

North Dakota Oil Production hits record 359 589 Barrels per day in March 2011. 

“The new scientific information presented to us from technical experts clearly warrants a new resource assessment of the Bakken,” said USGS Energy Resources Program Coordinator Brenda Pierce. “The new information is significant enough for the evaluation to begin sooner than it normally would. It is important to look at this resource and its potential contribution to the national energy portfolio.”

The 2008 USGS assessment showed a 25-fold increase in the amount of technically recoverable oil as compared to the agency's 1995 estimate of 151 million barrels of oil. New geologic models applied to the Bakken Formation, advances in drilling and production technologies, and additional oil discoveries resulted in these substantially larger technically recoverable oil volumes. About 135 million barrels of oil were produced from the Bakken between 1953 and 2008; 36 million barrels in 2008 alone. According to state statistics, oil production from the Bakken in North Dakota has steadily increased from about 28 million barrels in 2008, to 50 million barrels in 2009 to approximately 86 million barrels in 2010.

“The Bakken Formation is producing an ever-increasing amount of oil for domestic consumption while providing increasing royalty revenues to American Indian tribes and individual Indian mineral owners in North Dakota and Montana,” Salazar noted. Interior agencies have been working closely, for example, with the Three Affiliated Tribes (the Mandan, Hidatsa and Arikara) and individual Indian mineral owners on the Ft. Berthold Reservation in North Dakota to facilitate this development.

Technically recoverable oil resources are those producible using currently available technology and industry practices. USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources.

The new update effort will be a standard assessment task under the existing USGS National Oil and Gas Assessment. It will begin in October 2011, at the start of the 2012 fiscal year. Depending on funding, it is expected to take two years to complete. Drilling and production will continue while the USGS conducts its assessment update.

For more information about the Bakken Formation, please visit the USGS frequently asked questions that were developed after the 2008 resource assessment at http://www.usgs.gov/faq/index.php?action=show&cat=21

Monday, May 23, 2011

Iran’s oil reserves reached 155 billion barrels



Iran’s crude reserves increased by 758 million barrels following the discovery of a deposit of light oil in southern Iran, Press TV reported, citing Ahmad Qalebani, National Iranian Oil Co.’s managing director.

Qalebani said last week that Iran’s oil reserves reached 155 billion barrels from an earlier 151.3 billion due to the discovery of new fields, tni opeche state-run satellite news channel said. The report on the broadcaster’s website didn’t specify whether today’s announced increase is in addition to or part of the earlier figure.OIL RESERVES IN IRAN







The deposit off the Persian Gulf coast is located at the Khayyam field in Iran’s southern Hormozgan province and has the potential to produce 35,000 barrels of oil a day, Qalebani said, according to Press TV.

Iran is the second-largest crude producer in the Organization of Petroleum Exporting Countries after Saudi Arabia.




Friday, May 20, 2011

U.S. Contains Enough Oil and Gas Reserves to Fuel Country for 100 years



The US uses 25 percent of the world's oil, but has only 3 percent of the world's oil reserves. That 3 percent, which amounts to 21 billion barrels of oil, refers to something called "proven reserves," which is oil ready to be pumped using current technology and under current environmental rules. At current use rates, it will last eight years. According to the U.S. Department of the Interior, US also have 134 billion barrels of "estimated reserves." That's oil that could be recovered if off-shore oil, Anwar, and the massive discoveries in Montana and North Dakota are opened and new technologies like horizontal drilling are employed. That gives US another 51 years.


Besides the U.S. has the world's largest supply of oil-shale, amounting to 2.2 trillion barrels of oil. It's more expensive and tougher to recover, but US is already getting such oil from Canada. If oil prices per barrel remain above $100, digging out these reserves will be profitable. Read more about this reserves issue


Oil companies invest hundreds of billions to do so.Finding, recovering, and refining oil is hard work. The rate of return on their investment is in line with most other businesses. They provide lots of jobs, and produce something US need. Oil stocks is the part of the plan for US citizens for their retirement plans.


A study by Wood Mackenzie, also released at the event, shows that increased access to America’s oil and natural gas reserves could, by 2025, create 530,000 jobs, generate $150 billion in taxes, royalties, and other revenue for the government, and “boost domestic production by four million barrels of oil a day,” stated API in a press release.

On a related note, North Dakota is one of the fastest growing oil producing regions in the United States, where 80 million barrels were produced in 2009, the report states.

With new horizontal drilling technology it is believed that from 175 to 500 billion barrels of recoverable oil are held in this 200,000 square mile reserve that was initially discovered in 1951. The USGS did an initial study back in 1999 that estimated 400 billion recoverable barrels were present but with prices bottoming out at $10 a barrel back then the report was dismissed because of the higher cost of horizontal drilling techniques that would be needed, estimated at $20-$40 a barrel.

Monday, May 16, 2011

2030 Energy Outlook Volume2



China is the largest source of oil consumption growth in our outlook, with consumption forecast to grow by 8 Mb/d to reach 17.5 Mb/d by 2030, overtaking the US to become the world’s largest oil consumer.

Growth is expected to remain concentrated in the industrial and transport sectors through 2020. Industrial growth slows post-2020 as industrial expansion becomes less energy-intensive and population growth slows; transport will then be the dominant growth driver.

Despite contributing almost half of net global oil consumption growth to 2030, our outlook projects a slower increase in per capita consumption than seen historically in other Asian economies. China is much less dependent on oil in its overall fuel mix (c. 20%) than many other emerging economies at similar points in their development.

In addition, China is likely to implement policies to slow oil consumption growth - such as increasing taxes on transport fuels and maximising use of other fuels. Oil prices are higher than faced historically by other emerging economies; rising import dependence is a policy concern.








Globally, liquids production is expected to increase to meet the growth in consumption, though the sources of growth will change the global balance. Global liquids supply is set to rise by about 16.5 Mb/d by 2030.

OPEC accounts for over 75% of global supply growth, with OPEC NGLs expected to grow by more than 4 Mb/d - driven in part by rapid growth of natural gas production.

Iraqi crude output is projected to grow from about 2.5 Mb/d currently to more than 5.5 Mb/d; Saudi output is likely to expand by nearly 3 Mb/d.

Non-OPEC output will rise by nearly 4 Mb/d. Unconventional supply growth should more than offset declining conventional output, with biofuels adding nearly 5 Mb/d and oil sands rising by nearly 2 Mb/d.

Declining conventional crude supply in Europe, Asia Pacific and North America is partly offset by growth in deepwater Brazil and the FSU, resulting in a net decline of just over 3 Mb/d.

In this outlook, Russia and Saudi Arabia will each sustain their current market share of roughly 12% over the next 20 years.









The importance of OPEC is expected to grow. On our projections, OPEC’s share of global production would increase from 40% in 2010 to 46% in 2030 (a level not reached since 1977).

In the early years of the outlook, OPEC production growth can be met by utilizing current spare capacity. Over time, capacity must expand to meet expected demand growth. In addition to NGL growth, we project an increase in crude oil production capacity of nearly 5 Mb/d by 2030 – to nearly 40 Mb/d – largely in Iraq and Saudi Arabia.

These projections imply that Saudi production capacity, currently at 12.5 Mb/d, is likely to be sufficient to meet demand and maintain a reasonable buffer of spare capacity until around 2020; thereafter a modest expansion appears likely.

While we do not attempt to forecast long-term energy prices, the ability and willingness of OPEC members to expand capacity and production clearly is one of the main factors determining the path of the oil market.






The pace of Iraqi capacity expansion – and production growth – is a key source of uncertainty for this outlook. Iraq is expected to account for 20% of global supply growth from 2010 to 2030.

Service contracts awarded since mid-2009 have signaled the notional (contractual) possibility that Iraqi capacity could reach 12 Mb/d by 2020. However, limited project development capacity and infrastructure constraints may result in project delays and cost inflation.

Key challenges exist in developing export pipelines, terminals and water injection infrastructure. Security challenges, as well as political constraints, are also likely to weigh on capacity expansion plans.

A rapid increase in Iraqi output could have an impact on oil prices. OPEC is likely over time to seek to reintegrate Iraq into the quota system, which is an additional source of uncertainty.

While substantial capacity growth is likely, a number of factors should constrain the pace of expansion. Weighing these factors, we assume Iraqi production exceeds 4.5 Mb/d by 2020 and 5.5 Mb/d by 2030.








Iraq’s proven oil reserves of 112 billion barrels are the world’s second largest, behind Saudi Arabia.













Saturday, May 14, 2011

2030 Energy Outlook



The first great wave of industrialisation was based almost entirely on a truly disruptive technology, the steam engine, and on coal. Coal remained the dominant fuel until after WWII.

The next major transition came with electricity and the internal combustion engine, which enabled diversification away from coal. Oil replaced coal use in transport. And while coal remains the principal fuel in power generation, it is gradually being replaced first by natural gas, and now by renewables.






The three fossil fuels are converging on market shares of 26-27%, and the major non-fossil fuel groups on market shares of around 7% each.

Oil continues to suffer a long run decline in market share, while gas steadily gains. Coal’s recent gains in market share, on the back of rapid industrialisation in China and India, are reversed by 2030.




Oil is expected to be the slowest-growing fuel over the next 20 years. Global liquids demand (oil, biofuels, and other liquids) nonetheless is likely to rise by 16.5 Mb/d, exceeding 102 Mb/d by 2030. Growth comes exclusively from rapidly-growing non-OECD economies. Non- OECD Asia accounts for more than three-quarters of the net global increase, rising by nearly 13 Mb/d. The Middle East and South & Central America will also grow significantly. OECD demand has likely peaked (in 2005), and consumption is expected to decline by just over 4 Mb/d.

Rising supply to meet expected demand growth should come primarily from OPEC, where output is projected to rise by 13 Mb/d. The largest increments of new OPEC supply will come from NGLs, as well as conventional crude in Iraq and Saudi Arabia.

Non-OPEC supply will continue to rise, albeit modestly. A large increase in biofuels supply, along with smaller increments from Canadian oil sands, deepwater Brazil, and the FSU should offset continued declines in a number of mature provinces.






Energy used for transport will continue to be dominated by oil, but should see its share of global energy use decline as other sectors grow more rapidly. Growth is expected to slow over the next twenty years to average 1.1% p.a. vs 1.8% p.a. during 1990-2010, with OECD demand slowing and then declining post-2015.

The slowing of growth in total energy in transport is related to higher oil prices and improving fuel economy, vehicle saturation in mature economies, and expected increases in taxation and subsidy reduction in developing economies.

The growth of oil in transport slows even more dramatically, largely because of displacement of oil by biofuels and is likely to plateau in the mid-2020s. Currently, biofuels contribute 3% on an energy basis and this is forecast to rise to 9% at the expense of oil’s share.

Rail, electric vehicles and plug-in hybrids, and the use of compressed natural gas in transport is likely to grow, but without making a material contribution to total transport before 2030.








Check more about the 2030 Energy Outlook at Bp Website.

Thursday, May 12, 2011

Is Saudi Arabia running out of oil?



The latest startling revelation to come via documents leaked to Julian Assange's muckraking website and published by The Guardian should give pause to every suburban SUV-driver: U.S. officials think Saudi Arabia is overpromising on its capacity to supply oil to a fuel-thirsty world. That sets up a scenario, the documents show, whereby the Saudis could dramatically underdeliver on output by as soon as next year, sending fuel prices soaring.

The cables detail a meeting between a U.S. diplomat and Sadad al-Husseini, a geologist and former head of exploration for Saudi oil monopoly Aramco, in November 2007. Husseini told the American official that the Saudis are unlikely to keep to their target oil output of 12.5 million barrels per day output in order to keep prices stable. Husseini also indicated that Saudi producers are likely to hit "peak oil" -- the point at which global output hit its high mark -- as early as 2012. That means, in essence, that it will be all downhill from there for the enormous Saudi oil industry.








"According to al-Husseini, the crux of the issue is twofold. First, it is possible that Saudi reserves are not as bountiful as sometimes described, and the timeline for their production not as unrestrained as Aramco and energy optimists would like to portray," one of the cables reads. "While al-Husseini fundamentally contradicts the Aramco company line, he is no doomsday theorist. His pedigree, experience and outlook demand that his predictions be thoughtfully considered."

Matthew Simmons, after very extensive research, questioned the numbers that the Saudis were quoting back in 2005 when he published his comprehensive analysis in the seminal book “Twilight in the Desert“.

Simmons extensive documentation showed that Saudi oilfields were being exploited too hastily or vigorously. He explained the risks associated with overproducing and that this meant that oil fields were irreparably damaged which meant that far more oil was being permanently left behind. Overproducing, he showed, brought more immediate returns but reduces the longevity of a field and the amount of oil that can ultimately be recovered.



The inescapable conclusion of his book, based on the evidence,was that Saudi oil production is at,or nearing, its peak sustainable level, and that it is likely to start dropping irreversibly in the quite foreseeable future. He wrote that book in 2005.

And he went on to state that when that decline happened the decline rate would probably be quite steep because the experimental use of water injection to maintain reservoir pressure right at the start of the fields’ development—rather than at the end, as is standard—had depleted the supplies.

That creates a problem for Saudi Arabia since it depends on oil for 90% of its exports and 75% of its government revenues. Oil accounts for 45% of GDP in this sparsely populated country of 25 million people. However, as the price increases it will still do very well.

Tuesday, May 10, 2011

UK North Sea Production Decline: A new oil importer



While debate continues over how proposed changes to the UK's tax regime will impact North Sea oil and gas production, exploration activity declined in the first quarter of this year and weakness in oil output for the UK North Sea is expected to continue.

Nine exploratory and appraisal wells were drilled on the UK Continental Shelf (UKCS) during this year's first quarter, a 25 percent decline from the same period in 2010 and the previous quarter, according to a report by Deloitte's Petroleum Services Group. Five of those wells have been started in the Central North Sea; two in the Southern North Sea; one in the Northern North Sea, and one on the Faroe-Shetland Escarpment.




Prior to the announcement of tax increases by the UK government, Deloitte said that, despite the decrease in drilling activity, industry outlook for UK drilling had initially appeared positive this year as the average Brent Blend oil price continued to rise. Deloitte noted that there were indications that increased Brent prices and tax incentives were encouraging companies to return to pre-recession strategies.

However, the announcement of tax increases has had a negative effect on industry optimism and a number of companies have already announced that they intend to put appraisal and development projects on hold. "At present, it is unclear how these factors will affect levels of drilling activity over the coming months," Deloitte said in the report.

Deloitte reported seeing more farm-in activity than asset acquisitions in the first quarter, noting that farm-in activity for this quarter was higher than fourth quarter 2010. The uptick in farm-in activity could be indicative of companies beginning to return to corporate strategies that were in place pre-recession. The increase in farm-ins could also be attributed to the continued rise in oil prices, which may provide incentive for companies to increase their equalities in reserves.

UK Oil Production Weakness Last month, Barclays Capital reported that it anticipated weakness in UK total oil liquids output to continue as no major field start-ups to boost output are in sight.

UK total oil liquids output averaged 1.3 million b/d in December, a year over year decline of 128,000 b/d, with production falling by 111,000 b/d across 2010 as a whole. The decline is a step up from the declines in 2008 and 2009, when output declined by 106,000 b/d and 73,000 b/d, respectively.



Barclays expects output to fall by .15 million b/d this year, and it's fair to say that the UK Treasury's proposed tax hike on UK North Sea oil and gas production will hurt UK oil production, said Amrita Sen, oil analyst for Barclays. "Because it's a mature basin, production costs in general are already higher, so if you add additional costs, it will be difficult to incentivize research and development efforts for technology in this area."

The tax increase announcement has already prompted Norway-based Statoil to put plans on hold to develop two heavy oil fields in the UK North Sea in light of the proposed tax hike. This delay and other possible delays mean ongoing weakness in UK oil output will continue.

Sen estimates that an additional 100,000 b/d of oil is needed to maintain current UK oil production, and that an additional 200,000 b/d of oil is needed to maintain existing Norwegian oil production, which is experiencing even steeper declines than UK oil production.

New Production Coming Online Weakness in oil output is expected to continue; however, new oil and gas production is expected to come online within the next year. Endeavour International Corporation expects oil production from its Bacchus development on UK Block 22/6a in the Central North Sea to begin during the second half of this year, and gas production from its Columbus development on UK Block 23/16f to begin in 2012.



In late February, the UK Department of Energy and Climate Change (DECC) approved Endeavour's Rochelle Field Development Plan (FDP) for Block 15/27 in the Central North Sea, now known as East Rochelle. The current FDP calls for the subsea development to be linked by a 18.6-mile pipeline to production facilities on the Scott Platform. First production is planned for the second half of 2012. West Rochelle, which was successfully appraised in October 2010, will be integrated into this development plan as the second phase.

DECC also has approved RWE Dea's field development plan for the Clipper South gas field in the UK North Sea. The field will be developed by five horizontal wells, each containing up to six hydraulic fractures, connecting to a wellhead platform and then piped to the LOGGS PR platform. First gas is expected in the first quarter of 2012, with production is anticipated to reach a maximum rate of 100 MMcf/d.

O&G Employment Outlook for UK Salaries in the UK oil and gas industry through 2010 were some 50% lower than those in other oil and gas regions, such as the U.S. or Norway, as the UK oil and gas industry was dragged down by the recession experienced by the overall UK economy. While these are now rising, they are still lagging some way behind their counterparts. "Consequently, many international companies are targeting the UK as a location in which they can recruit highly skilled talent at relatively low costs," said Matt Underhill, managing director for oil and gas at Hays Recruiting.

"The one positive sign in the market regards salaries is that day rates for contractors have shown some excellent growth and this is usually a pre-cursor to staff salaries following suit," Underhill noted.



Related Article: UK Energy Report

Monday, May 9, 2011

Crude oil production rises at Bakken and other U.S. shale plays



North Dakota is currently the fourth largest producer of oil in the United States and has been setting new production records almost every month. At the end of 2010 oil production had grown to 342,000 barrels of oil per day . The key impediment to even faster growth is the oil pipeline and transport infrastructure limits.



U.S Oil production 1986-2010

Oil Shale Reserves in the US Prospects Outweigh Challenges


The North Dakota Department of Mineral Resources updated its estimate of recoverable oil in 2008 and 2010 based upon better E&P data and now believes there are 4.0-6.3 billionbarrels of recoverable reserves in North Dakota’s Bakken and Three Forks formations alone. And there are additional oil plays including the Lodgepole, Tyler, and Spearfish that are yet to be explored for development.


North Dakota Oil Production



At the current actual oil production rate of 350,000 barrels of oil per day (BOPD) at the current price of Cushing oil of $112.43 per barrel (4/27/11) North Dakota alone is reducing oil imports by $39.3 million per day or more than $14.4 billion per year annualized.

Economically recoverable oil is cost effective to extract and process. Of course, “cost effective” is a continuum, not a point: what makes economic sense is very different at crude oil prices of $40 per barrel, $80 per barrel, or $120 per barrel. Also, what is economically recoverable depends on technology as well—as technology improves and becomes more widespread (creating economies of scale), price drops. Cost reductions of 50 – 75% over 20 years are feasible.


US EIA’s Annual Energy Outlook 2011, says there is 2,552 trillion cubic feet (Tcf) of potential natural gas resources in the US. Unconventional natural gas from shale resources are 827 Tcf of this resource estimate, more than double the EIA estimate published last in the AEO2010. Based upon the 2009 rate of U.S. consumption (about 22.8 Tcf per year), that is enough natural for 110 years of use. EIA expects these unconventional gas estimates to grow and other potential oil and gas plays are explored and validated.

Higher oil prices reflect the global tradable market for oil as a commodity. Lower domestic natural gas prices reflect the reality that natural gas trades primarily as a regional commodity. There was a time not long ago when energy experts expected LNG to transform natural gas into the same globally priced commodity as oil. Russia, Qatar and others even considered forming an LNG cartel like OPEC to fix prices for natural gas.



Shale Liquids Production

Liquids production (crude oil and condensate) is rising significantly at several shale plays in the United States as operators increasingly target the liquids-bearing portions of these formations.

In North Dakota, for example, total liquids production has risen nearly 150% since 2005 due primarily to escalating development of the Bakken shale (which extends into Montana). Using similar horizontal drilling and hydraulic fracturing technologies applied to the Nation's shale gas plays, operators increased Bakken production from about one million barrels in 2005 to nearly 50 million barrels in 2009, or about 135,000 barrels per day. Excluding Bakken volumes, the State's liquids production increased by only about 5% over the same period.

  • Shale plays known primarily for natural gas production—or where horizontal drilling initially targeted natural gas—are also seeing accelerating liquids-focused drilling.
  • At the Barnett in Texas, overall liquids production more than doubled (and production from horizontal wells swelled roughly six-fold) from 2005 to 2009.
  • Liquids production from the Woodford in Oklahoma surpassed one million barrels in 2009, up 83% from 2008 and nearly eight times 2007 volumes.
  • At the Eagle Ford formation in Texas, liquids production in 2009 grew more than five-fold over the previous year, and is on pace to exceed five million barrels in 2010.
  • Liquids production from Appalachia's Marcellus shale nearly quadrupled in 2009 and is expected to show another considerable increase in 2010.

The number of oil rigs drilling horizontal wells rose significantly through the first half of 2010. Further increases are likely as operators sharpen their focus on liquids in these and other shale plays.









Thursday, May 5, 2011

Liquefied Coal will be China's Future

Coal is a high carbon content, but only 5% of hydrogen content in the solid. And liquid fuels (crude oil extracted from) compared to coal is not easy to handle and transport.


By carbon and hydrogen, coal can be directly or indirectly, into liquid fuels for transport, one of which is coking or pyrolysis, another method is liquefied. As a result of coal into liquid fuel costs than the high cost of crude oil refined, but relatively low price of coal itself, which is coal liquefaction technology will be implemented as a major motivating factor.


With the diminishing oil reserves, can be expected some time in the future, will need alternative liquid fuel. As the world's most abundant reserves of coal, coal liquefaction is one of them.

World Unconventional Production 


Back in the early 70s, due to soaring international oil prices, the United States, Britain and Japan and other countries began to carry out extensive research and development of coal liquefaction technology. From the 80's, most of the coal liquefaction project was shelved, but the exception of South Africa. The reason is not oil and natural gas resources in South Africa, only the rich coal resources, In addition, until the mid-'80s, South Africa by a 30-year trade embargo, these factors have contributed to large-scale use of coal liquefaction products in South Africa. Currently, 60% of transport fuels in South Africa is provided by the coal.
World Coal Production 


With a shortage of domestic oil and an automobile market that's now the world's biggest, China has begun a large-scale program to transform its abundant coal resources into motor fuels. It's already home to the world's largest coal liquefaction plant--a facility in Inner Mongolia that reached its full capacity last year and can now pump out a million gallons of diesel fuel per day.


The plant made China only the second country in the world, after South Africa, to successfully derive liquid fuels from coal on a commercial scale. Built by coal producer Shenhua Group, the facility uses the heat and hydrogen generated by gasifying a small amount of coal to brew a wet slurry made from a second stream of coal into diesel fuel. The process makes economic sense but inflicts an environmental double whammy. Simply making the fuel produces prodigious amounts of carbon dioxide, even before the fuel itself is burned. It also uses enormous amounts of another scarce Chinese commodity: water.


China Coal Consumption 
Despite these negatives, China will keep pursuing the technology. "They do not have a better way to meet this need," says Qingyun Sun, a coal-to-­liquids expert at West Virginia University. Indeed, Shenhua Group is planning to quintuple its coal-to-diesel capacity by 2013. And that company is not the only player involved.


Other Chinese plants are turning coal into methanol and catalytically synthesizing gasified coal into a variety of chemical commodities. Since 2007, Chinese fuel marketers have been blending a billion gallons or more into gasoline at the pump. To try to mitigate emissions, Shenhua has started a small carbon sequestration project that is expected to inject 100,000 tons of carbon dioxide into a deep saline aquifer by the end of this year. Its vast plant can potentially capture 2.9 million tons of carbon dioxide annually--about four-fifths of the plant's emissions.

Wednesday, May 4, 2011

Strategic Petroleum Reserve- Fact Sheet

Strategic Petroleum Reserve -Quick Facts and Frequently Asked Questions


The Strategic Petroleum Reserve is a U.S. Government complex of four sites with deep underground storage caverns created in salt domes along the Texas and Louisiana Gulf Coasts. The caverns have a capacity of 727 million barrels and store emergency supplies of crude oil owned by the U.S. Government.

The US SPR is the largest emergency supply in the world with the current capacity to hold up to 727 million barrels (115,600,000 m3).

The current inventory is displayed on the SPR's website. As of May 5, 2011, the current inventory was 727 million barrels (115,600,000 m3). This equates to 34 days of oil at current daily US consumption levels of 21 million barrels a day. At recent market prices ($120 a barrel as of May 2011) the SPR holds over $34 billion in sweet crude and approximately $45 billion in sour crude (assuming a $15/barrel discount for sulfur content). The total value of the crude in the SPR is approximately $79 billion USD. The price paid for the oil is $21.635 billion (an average of $29.76 per barrel)


Inventory
Current inventory - Click to open inventory update window
Highest inventory - The SPR completed its fill program on December 27, 2009. Today's inventory of 726.5 million barrels is the highest ever held in the SPR. Actual physical capacity is 727 million barrels.
Previous inventory milestones -


2008. Prior to Hurricane Gustav coming ashore on September 1, 2008, the SPR had reached 707.21 million barrels, the highest level ever held up until that date. A series of emergency exchanges conducted after Hurricane Gustav, followed shortly thereafter by Hurricane Ike, reduced the level by 5.4 million barrels.


2005. Prior to the 2008 hurricane releases, the former record had been reached in late August 2005, just days before Hurricane Katrina hit the Gulf Coast. Hurricane Katrina emergency releases of both crude oil sales and exchanges (loans) totaled 20.8 million barrels.
Crude oil inventory distribution -


Bryan Mound - holds 254 MMB in 20 caverns - 78 MMB sweet and 176 MMB sour.

Big Hill - holds 170.1 MMB in 14 caverns - 73 MMB sweet and 98 MMB sour.

West Hackberry - holds 228.2 MMB in 22 caverns - 120 MMB sweet and 108 MMB sour.

Bayou Choctaw - holds 73.2 MMB in 6 caverns - 22 MMB sweet and 52 MMB sour. 



Current storage capacity - 727 million barrels
Fill status - The SPR completed fill on December 27, 2009 with a cargo that arrived and began to unload on Christmas Day. The cargo was 493,000 barrels of Saharan Blend, a light sweet crude that ws delivered to the Bryan Mound site.
Current days of import protection in SPR - 75 days (based on EIA data of 9.70 million barrels/day for 2009 net petroleum imports 2009). Note: the maximum days of import protection ever held in the SPR was 118 days in 1985.
International Energy Agency requirement - 90 days of import protection (both public and private stocks). The United States fulfills its commitment with a combination of SPR stocks and industry stocks.
Average price paid for oil in the Reserve - $29.76 per barrel 



Drawdown Capability

Maximum drawdown capability - 4.4 million barrels per day
Time for oil to enter U.S. market - 13 days from Presidential decision

Summary List of Historical Releases - click here
Past Sales [click on link for more details]
2005 Hurricane Katrina Sale - 11 million barrels
1996-97 total non-emergency sales - 28 million barrels
1990/91 Desert Shield/Storm Sale - 21 million barrels
(4 million in August 1990 test sale; 17 million in January 1991 Presidentially-ordered drawdown)
1985 - Test Sale - 1.0 million barrels



Reference :http://www.fossil.energy.gov/programs/reserves/spr/spr-facts.html

Tuesday, May 3, 2011

Diesel automobiles for US could help to reduce oil consumption

"Diesel is the invisible force that moves the American economy, but until now it has also been a big polluter," said Richard Kassel, head of the NRDC's clean fuels and vehicles project. "Combining the new fuel with cleaner and more energy-efficient engines will mean healthier air and reduce our dependence on oil."

Environmental Protection Agency officials also predicted significant long-term health benefits, including $150 billion in annual health-care and welfare-related savings and 20,000 fewer premature deaths each year.



Until now, diesel has primarily powered trucks and buses in the U.S. Diesel trucks move more than 18 million tons of the nation's freight a day, according to the NRDC. About 14 million Americans ride half a million diesel buses to work and school, the group says.Diesel has historically been viewed as an environmental problem because burning it produces more pollutants than gasoline. But diesel engines get better mileage than gasoline engines.






Distillate fuel oil use ranks second behind gasoline. Unlike gasoline, which is used almost exclusively in the transportation sector, distillate fuel oil is used in every sector: for home heating fuel, for industrial power, for electric generation, as well as for diesel-fueled vehicles. The largest use of distillate is in the transportation sector. Diesel fuel used in vehicles on the highway -- trucks, buses, passenger cars -- must be low sulfur (no more than 0.05 percent sulfur by weight), an Environmental Protection Agency regulation implemented in late 1993. Distillate fuel oil used off the highway -- for vessels, railroads, farm equipment, industrial machinery, electric generation, or space heating -- is not subject to the low on-highway standard, but as a matter of course contains only a small amount of sulfur, commonly 0.2 percent sulfur by weight. (California has a more stringent standard, requiring that all distillate meet the current low highway specification.) The U.S. Department of the Treasury also requires that the non-highway product be dyed to distinguish it from the taxable on-highway diesel. These requirements also limit distribution flexibility for distillate fuels, requiring segregated storage and transportation, and preventing one product from easing shortages of the other.

Now, Americans could see more diesel engines in passenger cars. Researchers at J.D. Power & Associates predict diesel sales will nearly triple in the next 10 years because of the engine's fuel efficiency -- typically 20% to 40% more miles per gallon than gasoline engines.

The Extended Policies case modifies the Reference case by assuming a 3-percent annual increase in the stringency of CAFE standards for MY 2017 to MY 2025, with subsequent standards held constant. The LDV CAFE standards in the Extended Policies case increase from 34.1 mpg in 2016 to 46.0 mpg in 2025, as compared with 35.6 mpg in the Reference case. Sales of unconventional vehicles (including those that use diesel, alternative fuels, and/or hybrid electric systems) play a substantial role in meeting the higher fuel economy standards, growing to around 70 percent of new LDV sales in 2035, compared with about 40 percent in the Reference case.







Volkswagen of America, Inc. reported 27,176 units sold in March 2011, a 22.7 percent increase over prior year sales. The company also announced 16,969 Jetta models sold – more than any other month in company history.

More Americans are discovering diesel as an alternative fuel option. Annual registration of diesel passenger vehicles has grown by 80%, from just over 300,000 in 2000 to nearly 550,000 in 2005. And most analysts expect this trend to continue.

Researchers at J.D. Power and Associates predict that diesel sales will triple in the next 10 years, growing to more than 10% of U.S. vehicle sales by 2015 - up from 3.6% in 2005.

Greater use of diesel technology would help the U.S. reduce petroleum consumption and improve energy security. The U.S. Environmental Protection Agency estimates that America could save up to 1.4 million barrels of oil per day – an amount equivalent to the oil we currently import from Saudi Arabia – if one-third of U.S. cars, pickup trucks and SUVs were diesel-powered.







In Europe, diesel cars account for nearly half of the car market. In the U.S., diesel-powered passenger cars and light trucks are a niche market, despite recent efforts by VW and DaimlerChrysler to reignite interest in their European diesel engines.








A new generation of clean diesel is fueling even greater environmental progress. As of 2007, exhaust
from a clean diesel truck or bus is so clean that it would take 60 new trucks to equal the soot emissions
of one truck sold in 1988. By 2010, truck and bus emissions levels will be near zero – a total reduction
of 98% from 1988. The EPA predicts that these new trucks, once they fully replace the existing fleet,
will reduce emissions of smog-forming gases by 2.6 million tons each year and cut soot emissions by
110,000 tons annually.
Cost is an issue. In North America, diesel engines could add $2,000 to passenger-car prices, and possibly more, said Charles Freese, GM's executive director of diesel engineering. In addition, after-treatment technology to address nitrous oxide and particulate emissions can run thousands of dollars, he said.