Wednesday, November 30, 2011

The importance of hydropower for U.S

The importance of hydropower as a source of electricity generation varies by geographic region. While hydropower accounted for 6% of total U.S. electricity generation in 2010, it provided over half of the electricity in the Pacific Northwest. Because hydroelectric generation relies on precipitation, it varies widely from month to month and year to year.

Conventional and Hydroelectric Capacity by year U.S 

Conventional hydroelectric generators of varying capacity operated in 48 states in 2010. Operating expenses for hydroelectric generators are lower than for most other forms of electricity generation but facilities are limited by geography and operations are subject to seasonal constraints. There is a large concentration of capacity in the Pacific Northwest, contributing to low wholesale and retail electricity prices in that region, especially in the spring runoff season.

Hydroelectric capacity as percentage of total capacity by state U.S

Types of Hydroelectric Plants

Conventional hydroelectric generators were among the oldest of the Nation's power plants operating in 2010. The vast majority of hydroelectric generators were built before 1980 and recent changes to hydroelectric capacity have been small.

Conventional hydroelectric plants come in two broad categories: run-of-river and storage. A run-of-river plant utilizes the flow of a waterway (usually a river) to turn a turbine, while a storage plant creates a reservoir using a dam that controls water flow over a turbine.

A run-of-river plant has little control over generator output. A storage plant has some control over generation by controlling spillway water flow at intake through the dam, but is still constrained by total reservoir water levels.

Hydro power and other renewable U.S

There are several other types of non-conventional hydroelectric generators including pumped-storage, hydrokinetic axial flow and wave buoy turbines. Pumped-storage generators represent the only non-conventional form of hydroelectric generation currently in wide commercial use. These systems pump water to high elevations during low load periods then run the same water through the turbines to produce electricity during high demand times. Other hydroelectric technologies, such as wave buoys, are being developed and demonstrated but not in wide use at this time.

Hydroelectric Generation Varies Considerably

Depending on the season and precipitation, the hydroelectric share of total generation varies from 4% to 10%. Precipitation, snowpack, drought conditions, and other meteorological factors contribute to water availability for generation through hydroelectric dams. For example, early snow melt runoff in the Pacific Northwest, elevated snowpack levels throughout much of the Western river basins, and significant rainfall in March in areas of high hydropower capacity resulted in a large increase in hydroelectric generation in 2011.
Hydropower and the Environment

Most hydroelectric generators in the United States were co-located at dams originally built for other purposes, like flood control, municipal water supply, and irrigation. Operations are affected by environmental considerations associated with water use, fish populations, and impact on wildlife in surrounding areas. For example, fish ladders and lifts have been constructed at many dams to help protect migrating populations.

Hydroelectric Generators in United States

The Grand Coulee Dam, operated by the U.S. Bureau of Reclamation, is the fifth-largest power plant operating in the world and the largest in the Nation, with a net summer capacity of 7,079 megawatts.

Tuesday, November 29, 2011

United States and Its Allies Expand Sanctions on Iran

Iran faces new hurdles to getting paid for its oil as the U.S. tightens financial sanctions to deter buyers from the world’s third-largest crude exporter.

The U.S. approved extra curbs on Iran’s banking system and oil industry on Nov. 21, hoping to thwart the country’s nuclear program, and the European Union may follow. Current sanctions have led Indian importers to route payments for Iranian crude through a Turkish bank. These refiners, concerned Turkey may stop cooperating amid the latest U.S. rules, are asking banks in Russia to arrange alternatives, said three people with direct knowledge of the situation.

“The idea of the sanctions is to shrink the circle of buyers and so increase their ability to extract discounts from Iran,” said Robin Mills, an analyst at Dubai-based Manaar Energy Consulting, who worked for a decade at Royal Dutch Shell Plc in the Middle East.

Top Proven Oil Reserves 2011

The U.S. is stepping up pressure after a Nov. 8 report from the United Nations’ International Atomic Energy Agency concluded that Iran was working on a nuclear weapons program. At stake is crude supply from the OPEC nation, whose exports last year were exceeded only by those of Saudi Arabia and Russia. Oil is Iran’s main source of income, earning it $56 billion in the first seven months of 2011, according to U.S. Energy Department estimates.

The country pumped 3.6 million barrels a day last month, a Bloomberg survey showed, and exported an average 2.58 million barrels a day in 2010, according to Organization of Petroleum Exporting Countries statistics.

Iranian Oil Production and consumption 

UK Embassy Stormed

Iranian protesters broke into and vandalized the British Embassy’s compound in Tehran yesterday. The U.K. Foreign Office said in an e-mailed statement that it updated its travel advice “and now advise British nationals in Iran to stay indoors, keep a low profile and await further advice.”

France has proposed that the EU ban Iranian oil, French Budget Minister Valerie Pecresse said Nov. 23. Maja Kocijancic, an EU spokeswoman, said the same day that European foreign ministers will discuss the topic at a meeting scheduled for tomorrow. Iran is already subject to some UN and EU sanctions.

“The latest measures will make it even harder for people to finance trade with Iran,” said Nick Grandage, a London-based partner at law firm Norton Rose LLP, who specializes in trade finance. Sanctions have stifled trading of Iran’s oil in London, Europe’s financial hub, and may have forced importers to pay for crude in non-dollar currencies, he said in a Nov. 22 telephone interview.
Indian, Chinese Buyers

Should Europe adopt more formal restrictions on Iranian crude, the Persian Gulf nation would likely be forced to offer oil more cheaply to refiners in Asia, its biggest market, Olivier Jakob, managing director at Oberwil, Switzerland-based Petromatrix GmbH, said in a Nov. 28 note to investors.

By targeting financial transactions and stopping short of sanctioning international trade in Iranian oil, the U.S. aims to pressure Iran without risking a surge in crude prices at a time of global economic fragility, said Mills of Manaar Energy.

Iran's Top Export Destinations

Indian refiners, which got 11 percent of their imported oil from Iran in 2010, are trying to arrange a conduit for payments via Russia, said the three people familiar with the matter, declining to be identified because the talks are private.

Vladimir Lavrov, a spokesman for Russia’s central bank, declined to comment yesterday about the Indian effort. The U.S. sanctions against Iran are “unacceptable and violate international law,” Russia’s Foreign Ministry said Nov. 22. Iran denies it is developing nuclear weapons. Turkey, which gets half its oil imports from Iran, also criticized the U.S. action.

Iran Crude Oil Export for Key countries

Turkish Bank

Turkiye Halk Bankasi AS (HALKB), the Ankara-based lender Indian refiners have used to transfer cash to Iran, declined to comment on its transactions other than to say Halk complies with UN rules, according to a bank official, who cited company policy for declining to be identified.

Iran’s past flexibility over payment terms makes it an attractive supplier. The country gives Indian refiners 90 days to pay their bills, compared with 30 days from Saudi Arabia, according to the people with knowledge of those purchases. When Indian importers were unable to pay on time because of sanctions, Iran kept supplying them even as they amassed $5 billion in unpaid bills.

Saudi Arabia will increase oil shipments to Indian refiners next year, four people with knowledge of the plans said Nov. 15. India’s Petroleum Ministry Media Director R. C. Joshi didn’t answer two calls for comment to his mobile phone yesterday.
European Buyers

Refiners in Europe, collectively the second-largest market for Iranian oil after China, may also face difficulties from tighter constraints on transactions with Iran.

“Europe has been importing crude oil from Iran, and it certainly hasn’t lowered amounts recently,” Jakob of Petromatrix said by telephone Nov. 22. “Greece is importing most of its crude oil from Iran.”

Oil prices rose this year as political turmoil in the Middle East stoked concern about the reliability of supply. The price of European benchmark Brent crude rose to more than $125 barrels a day in April as exports from Libya dwindled because of the rebellion in that country. Brent has risen 16 percent this year and traded near to $110 a barrel in London yesterday.

Iran’s three biggest national customers -- China, Japan and India -- together buy more than half its exported oil, according to U.S. Energy Department data. This concentration of customers and Iran’s reliance on oil sales for income make the country vulnerable to disruptions, Jakob said.
China Connection

An unintended consequence is that China, a critic of the latest U.S. sanctions, may benefit from any price discounts, said Mills, the Dubai-based consultant. “It will favor non-U.S. allies who will be able to get oil somewhat more cheaply.”

China accounted for 22 percent of Iran’s export volumes in the first half of this year and increased its purchases by 27 percent over the same period of 2010, U.S. data show. The EU, Japan and India bought 18 percent, 14 percent and 13 percent of Iran’s oil, respectively.

China’s economic ties don’t violate UN Security Council resolutions, Foreign Ministry spokesman Liu Weimin told reporters on Nov. 24.

Iranian Oil Minister Rostam Qasemi said in a Nov. 19 television interview with Al Jazeera that any disruption to his nation’s oil exports would create “severe problems” for global markets. Iran abuts the Strait of Hormuz, a chokepoint for about one-fifth of the world’s traded oil supplies.

“If Iran were to respond to outside aggression by sealing off the Straits of Hormuz, this would severely hamper exports from Saudi Arabia, Iraq, Iran, Kuwait, Qatar and the United Arab Emirates,” researchers led by David Wech at Vienna-based JBC Energy said in a Nov. 23 report.

Friday, November 25, 2011

Egypt Energy Report

Hydrocarbons play a sizeable role in Egypt’s economy both from oil and natural gas production and also in terms of revenues from the Suez Canal, an important transit point for oil shipments out of the Persian Gulf. Total oil production, however, has declined since the country’s 1996 peak of close to 935,000 barrels per day (bbl/d) to current levels of about 660,000 bbl/d. Egypt’s consumption is slightly higher than production and the country has begun to rely on a small volume of imports to meet domestic demand. Egypt also has the largest oil refining sector in Africa and since refining capacity now exceeds domestic demand, some non-Egyptian crudes are currently imported for processing and re-export.

Decreases in oil production have been offset by the rapid development of the natural gas sector for both domestic consumption and export. Over the past decade, Egypt has become a significant natural gas producer and a strategic source for European natural gas imports. Egypt currently has a pipeline network for exports to Eastern Mediterranean countries in addition to liquefied natural gas (LNG) exports to Europe, Asia, and the Americas. However, increasing domestic demand for natural gas has led the government to stall natural gas export expansion plans. The government has been actively working to attract foreign investments in the sector to increase exploration, production and downstream activities.

In addition to oil and gas production, Egypt plays an important role in international energy markets through the operation of the Suez Canal and Suez-Mediterranean (SUMED) Pipeline, two routes for the export of Persian Gulf oil and LNG. Fees collected from operation of these two transit points is a significant source of revenue for the Egyptian government.

Almost all of Egypt’s 3.2 quadrillion British thermal units (Btu) of energy consumption in 2008 was met by oil (45 percent) and natural gas (49 percent). Oil’s share of the energy mix is mostly in the transportation sector but with the development of compressed natural gas (CNG) infrastructure and vehicles, the share of natural gas in the transportation sector is expected to grow.

In terms of electricity generation, natural gas accounts for over 70 percent of the total mix, woth the remainder being met mostly by hydroelectricity. Plans are underway to further expand electricity generation capacity by utilizing the country’s vast wind and solar resources, expanding the Gulf Cooperation Council (GCC) Power Grid, and also through development of nuclear power.


According to the Oil and Gas Journal’s January 2011 estimate, Egypt’s proven oil reserves stand at 4.4 billion barrels, an increase from 2010 reserve estimates of 3.7 billion barrels. In 2010, Egypt’s total oil production averaged 660,000 (bbl/d), of which approximately 540,000 bbl/d was crude oil. Despite new discoveries and enhanced oil recovery (EOR) techniques at mature fields, crude oil production continues its decline. At the same time, new natural gas field production has led to increases in the production of natural gas liquids and lease condensates which have offset some of the declines in total oil liquids production. Oil consumption is estimated to be close to 710,000 bbl/d, slightly higher than production. Oil imports are expected to continue with some refined product exports in the short-term, but are still contingent on domestic demand growth. The country did register a small volume of net oil imports in 2010. These imports are, in part, the result of Egypt’s refining capacity being larger than oil production levels (see Refinery section below).

Domestic demand for petroleum products continues to grow. The government had been planning to reduce demand growth by gradually lifting subsidized prices and targeting subsidies more effectively. This is a politically sensitive issue that will be difficult to fully implement. The increased use of compressed natural gas as a fuel for motor vehicles is one trend that may aid government efforts in curbing demand, but natural gas is also subsidized and increasing consumption is beginning to affect natural gas exports.

Sector Organization

The Egyptian General Petroleum Corporation (EGPC) is the state entity charged with managing upstream activities including infrastructure, licensing, and production. International and foreign national oil companies play a significant role in Egypt’s upstream sector on a production-sharing basis with EGPC. The energy sector is broken up into three holding companies in addition to the EGPC and the Egyptian Mineral Resource Authority (EMRA): the Egyptian Natural Gas Holding Company (EGAS), the Egyptian Petrochemicals Holding Company (ECHEM), and Ganoub El Wadi Petroleum Holding Company (GANOPE).

Exploration and Production
Egyptian oil production comes from five main areas: primarily the Gulf of Suez and the Nile Delta but also the Western Desert, the Eastern Desert, and the Mediterranean Sea. Most Egyptian production is derived from mature, relatively small fields that are connected to larger regional production systems. Overall production is in decline, particularly from the older fields in the Gulf of Suez. However, some declines have been offset by small yet commercially viable discoveries in all producing areas.


Although a net oil importer, Egypt did register about 145,000 bbl/d of crude oil exports in 2010. The majority of these exports went to India(50,000 bbl/d), followed by Italy (29,000 bbl/d), and the United States (16,000 bbl/d). The remainder of Egypt’s crude oil exports went to other European countries and Asia.


Egypt has the largest refining sector on the African continent with ten refineries and a combined crude oil processing capacity of 975,000 bbl/d (OGJ and APS Review). The largest refinery is the 146,300-bbl/d El-Nasr refinery at Suez, which is owned by the Egyptian government through the EGPC and operated by its subsidiary, the El Nasr Petroleum Company. The government has plans to increase production of lighter products, petrochemicals, and higher octane gasoline by expanding and upgrading existing facilities and promoting new projects. Current plans call for expansion of refining capacity by over 600,000 bbl/d by 2016 and even further expansions into the next decade – requiring large amounts of foreign investment.

Natural Gas

Egypt's natural gas sector is expanding rapidly with production quadrupling between 1998 and 2009. According to the Oil and Gas Journal, Egypt’s estimated proven gas reserves stand at 77 trillion cubic feet (Tcf), an increase from 2010 estimates of 58.5 Tcf and the third highest in Africa after Nigeria (187 Tcf) and Algeria (160 Tcf). In 2009, Egypt produced roughly 2.3 Tcf and consumed 1.6 Tcf. With the ongoing expansion of the Arab Gas Pipeline, and LNG facilities, Egypt will continue to be an important supplier of natural gas to Europe and the Mediterranean region.

According to Cedigaz, in 2009 the electricity sector accounted for the largest share of natural gas consumption (54 percent) followed by industrial sector (29 percent). While still a relatively small share, Egypt is beginning to incorporate natural gas into the transport sector through the use and development of compressed natural gas vehicles and fueling stations.

The government is also encouraging households, businesses and the industrial sector to consider natural gas as a substitute for petroleum and coal. In January 2008, the World Bank approved loans for the Natural Gas Connections Project, which serves to switchconsumption of liquefied petroleum gas (LPG) to natural gas through investment in new connections and to further expand natural gas use in densely populated, low income areas.

Sector Organization

As is the case with the oil sector, the Egyptian General Petroleum Corporation (EGPC) is the state entity charged with managing upstream activities including infrastructure, licensing and production. The promotion of the sector along with the development strategy is managed by the Egyptian Natural Gas Holding Company (EGAS). Both EGPC and EGAS work with private companies in joint venture partnerships.

The Egyptian government has an ongoing policy to allocate one third of proven natural gas reserves for domestic market requirements, one third for future generations , and the remaining third for exports. Given increasing domestic demand, combined with popular pressures in recent years against LNG and gas export contracts (particularly with Israel), the oil minister declared in mid-2008 that no new gas export contracts would be made. These policies delayed plans to expand the export infrastructure and have also deterred some investment in the more expensive offshore areas.

Exploration and Production

Exploration and production activities in Egypt’s natural gas sector continue to grow. While there have been marked decreases in the production of natural gas associated with oil extraction, new finds of non-associated gas fields combined with growing domestic demand and export capacity, are increasing interest in the Egyptian natural gas sector. Most industry analysts place Egypt’s natural gas production on an upward trend in the short- and medium-term despite the existing limitations to the sector’s growth. To promote exploration in the more expensive deepwater offshore, the Egyptian government revised pricing policies by agreeing to pay more for natural gas produced in these areas, assuring continued international interest in developing these potential resources.

Over 80 percent of Egypt’s natural gas reserves and 70 percent of production is in the Mediterranean and Nile Delta but exploration and production continue in all major hydrocarbon rich areas including the Western Desert.


Egyptian began exporting natural gas in the mid-2000s with the completion of the Arab Gas Pipeline (AGP) in 2004 and the startup of the first three LNG trains at Damietta in 2005. In 2009, Egypt exported close to 650 billion cubic feet (Bcf) of natural gas, around 70 percent of which was exported in the form of LNG and the remaining 30 percent via pipelines.

Pipeline Exports

Egyptian pipeline exports travel through the Arab Gas Pipeline (AGP) that provides gas to Lebanon, Jordan and Syria with further additions being planned. The Arish-Ashkelon pipeline addition, which branches away from the AGP in the Sinai Peninsula and connects to Ashkelon, Israel began operations in 2008. Domestic pressure over contracts, pricing for exports to Israel, and technical problems caused a few interruptions but exports resumed in 2009.

Liquefied Natural Gas (LNG)

Egypt has three LNG trains: Segas LNG Train 1 in Damietta and Egypt LNG trains 1 and 2 in Idku. The combined LNG export capacity is close to 600 Bcf per year with plans to expand in the near future pending export policy changes and legislation. In 2009, LNG exports were approximately 450 Bcf. The largest recipient of Egyptian LNG for 2009 was the United States, which imported around 160 Bcf, representing 35 percent of Egyptian LNG exports for the year and also 35 percent of U.S. LNG imports. Other major destinations for Egyptian LNG include Spain (32 percent) and France (13 percent) with smaller volumes travelling to Canada, Mexico, Asia and other European countries.

Suez Canal/SUMED Pipeline

Suez Canal

The Suez Canal is located in Egypt, and connects the Red Sea and Gulf of Suez with the Mediterranean Sea, spanning 120 miles. Year-to-date through November of 2010, petroleum (both crude oil and refined products) as well as liquefied natural gas (LNG) accounted for 13 and 11 percent of Suez cargos, measured by cargo tonnage, respectively. Total petroleum transit volume was close to 2 million bbl/d, or just below five percent of seaborne oil trade in 2010.

Almost 16,500 ships transited the Suez Canal from January through November of 2010, of which about 20 percent were petroleum tankers and 5 percent were LNG tankers. With only 1,000 feet at its narrowest point, the Canal is unable to handle the VLCC (Very Large Crude Carriers) and ULCC (Ultra Large Crude Carriers) class crude oil tankers. The Suez Canal Authority is continuing enhancement and enlargement projects on the canal, and extended the depth to 66 ft in 2010 to allow over 60 percent of all tankers to use the Canal.

Closure of the Suez Canal and the SUMED Pipeline would divert oil tankers around the southern tip of Africa, the Cape of Good Hope, adding approximately 6,000 miles to transit, increasing both costs and shipping time. According to a report released by the International Energy Agency (IEA), shipping around Africa would add 15 days of transit to Europe and 8-10 days to the United States.

SUMED Pipeline

The 200-mile long SUMED Pipeline, or Suez-Mediterranean Pipeline provides an alternative to the Suez Canal for those cargos too large to transit the Canal (laden VLCC’s and larger). The pipeline has a capacity of 2.3 million bbl/d and flows north from Ain Sukhna, on the Red Sea coast to Sidi Kerir on the Mediterranean. The SUMED is owned by Arab Petroleum Pipeline Co., a joint venture between the Egyptian General Petroleum Corporation (EGPC), Saudi Aramco, Abu Dhabi’s National Oil Company (ADNOC), and Kuwaiti companies.

Source: Oil Capital Ltd.

Crude Oil

The majority of crude oil flows transiting the Canal travel northbound, towards markets in the Mediterranean and North America. Northbound canal flows averaged approximately 428,000 bbl/d in 2010. The SUMED pipeline accounted for 1.15 million bbl/d of crude oil flows along the route over the same period. Combined, these two transit points were responsible for over 1.5 million bbl/d of crude oil flows into the Mediterranean, with an additional 307,000 bbl/d travelling southbound through the Canal. Northbound crude transit represented a decline from 2008 when 940,000 bbl/d of oil transited northbound through the Canal and an additional 2.1 million travelled through the SUMED to the Mediterranean.

Source: Suez Canal Authority, converted with EIA conversion factors. SUMED pipeline flows are EIA estimates based on APEX (Lloyd's MIU) Tanker Data.

*2010 information is year-to-date January-November in '000 bbl/d

Total Oil and Products

Total oil flows from the Suez Canal declined from 2008 levels of over 2.4 million bbl/d in 2008 to just under 2 million bbl/d on average in 2010. Flows through the SUMED experienced a much steeper drop from approximately 2.1 million bbl/d to 1.1 million bbl/d over the same period. The year-on-year difference reflects the collapse in world oil market demand that began in the fourth quarter of 2008 which was then followed by OPEC production cuts (primarily from the Persian Gulf) causing a sharp fall in regional oil trade starting in January 2009. Drops in transit also illustrate the changing dynamics of international oil markets where Asian demand is increasing at a higher rate than European and American markets, while West African crude production is meeting a greater share of the latter’s demand. At the same time, piracy and security concerns around the Horn of Africa have led some exporters to travel the extra distance around South Africa to reach western markets.

Liquefied Natural Gas (LNG)

Unlike oil, LNG transit through the Suez Canal has been on the rise since 2008, with the number of tankers increasing from approximately 430 to 760, and volumes of LNG traveling northbound (laden tankers) increasing more than four-fold. Southbound LNG transit originates in Algeria and Egypt, destined for Asian markets while northbound transit is mostly from Qatar and Oman, destined for European and North American markets. The rapid growth in LNG flows over the period represents the startup of five LNG trains in Qatar in 2009-2010. The only alternate route for LNG tankers would be around Africa as there is no pipeline infrastructure to offset any Suez Canal disruptions. Countries such as the United Kingdom and Italy received more than half of their total LNG imports via the Suez Canal in 2009 while over 90 percent of Belgium’s LNG imports transited through the canal.


The Egyptian electrification rate in 2008 was approximately 99.4 percent, according to the International Energy Agency (IEA); this rate is among the highest in Africa with a 100 percent urban access to electricity and 99.1 in rural areas. Nonetheless, approximately 500,000 people still lack access to electricity.

According to EIA data, Egypt had an installed generating capacity of 23.4 gigawatts (GW) in 2008, 20.3 GW of which was conventional thermal generation capacity, 2.8 hydroelectric and 0.3 GW of wind generation capacity. Current peak demand is estimated to be 21.3 (GW). Ageing infrastructure and rising demand have led to intermittent blackouts. The summer of 2010 highlighted these problems, as the country experienced rolling nationwide blackouts.

Egyptian electricity consumption is increasing much faster than capacity expansions and the government is planning to invest over $100 billion in the power sector over the next decade, while also seeking financing from external sources. The private sector, international organizations, and renewable energy funds such as the World Bank’s Clean Technology Fund have all provided investment in the sector. Under existing plans, Egypt hopes to produce 20 percent of its electricity from renewable energy by 2020 while also developing a nuclear power industry.

Sector Organization

Egypt’s power sector is organized under the Egyptian Electric Holding Company which comprises sixteen affiliated companies (six production, nine distribution, and the Egyptian Electricity Transmission Company). Growing electricity demand in the late 1990s spurred industry restructuring and limited privatization of the sector. The country now has several privately-owned power plants which are either independent power projects (IPPs) or financed under Build, Own, Operate and Transfer (BOOT) schemes. BOOT projects allow for the financing and development of the large scale energy projects without affecting the country’s debt profile.

Conventional Thermal

In 2008, conventional thermal energy sources accounted for 108.5 Billion kilowatt hours (Bkwh) of electricity generation, about 88 percent of the total. Almost all of this was met by domestically produced natural gas. Existing natural gas subsidies combined with plans to expand gas-fired generation capacity indicate that the fuel will continue to play an important role in Egypt’s electricity mix.

High domestic demand for natural gas in all sectors is, in part, the result of government subsidies on the fuel. Subsidies have been costly to the Egyptian government, deterring major investments in the sector, and spurring rapid growth in domestic consumption that has affected Egypt’s natural gas export revenues. However, attempts to remove the subsidies have been politically unpopular and difficult to implement.


Egypt has a well developed hydroelectricity sector and, according to the energy minister, has utilized most of the Nile River’s hydroelectric potential. In 2008-9, Egypt generated around 14 Bkwh from hydroelectric resources, almost all of which came from the Aswan High Dam and the Aswan Reservoir Dams.

Other Renewables

With the Nile River hydroelectric resources utilized, plans are underway to further develop the renewable energy sector. The most recent EIA data indicate that in 2008 wind farms accounted for only 0.9 Bkwh of electricity generation, with no contribution from other renewable sources. Government plans to reallocate natural gas resources for export combined with vast solar and wind resources will lead to further growth in the sector.


According to the Egyptian Electric Holding Company, other projects such as the 140-MW solar-thermal Kuraymat development should see start-up by 2012. This project is part of a general plan to export North African generated electricity to Europe through the Desertec project. The projects are expected to use concentrated solar power (CSP) with back up natural gas fired generators.


In December, the Egyptian government announced that it was planning to expand wind capacity by over 2.6 GW over the next five years as part of a plan to increase wind’s share of electricity generation to 12 percent. To this end, the government had said it would be inviting bids in 2011.


Egypt is also working on developing nuclear power as an energy source. It has a 22-MW nuclear research reactor at Inshas in the Nile Delta which began operation in 1997. The Ministry of Electricity and Energy in 2010 approved a 1,200 MW power station at al-Dab’a which is open to international participation and expected to become operational by 2019 as the country’s first nuclear power plant. Bidding for the development of this plant was supposed to have started in early 2011. Three additional plants are planned by 2025.

International Connections

Work has been completed on the interconnection of Egypt's electric transmission grid with other countries in the region. The five-country interconnection of Egypt's system with those of Jordan, Syria, and Turkey was completed by 2002, and Egypt also activated a link to Libya's electric grid in December 1999.

Gulf Cooperation Council (GCC) Power Grid

The GCC Power Grid project plans to link Egypt to the GCC through Saudi Arabia. The link is expected to be complete between 2013 and 2015 and will allow the sharing of 3GW of electricity between the two countries. This project will indirectly expand each country’s electricity capacity by pulling from each other’s supplies at different peak hours. Longer-term plans call for broader interconnections that would include North Africa, the Middle East and Europe.

Monday, November 21, 2011

More U.S. crude oil is being shipped by Bakken Oil Express

More U.S. crude oil is being shipped by rail, especially from North Dakota where a lack of pipelines has companies relying on tank cars to bring the state's soaring oil production to market. Pipelines remain the most popular transport option, carrying about two-thirds of U.S. oil and petroleum products, but rail is on the rise.

The Association of American Railroads (AAR) tracks combined rail movements of oil and refined petroleum products. In the first ten months of 2011, nearly 300,000 tank cars transported U.S. oil and petroleum products, up 9.1% from the same period in 2010, according to AAR. The growth in petroleum-by-rail shipments is much stronger than the 1.8% increase for all railroad cargo combined during the same period.

U.S Rail carloads of crude oil

While AAR does not issue separate data on crude oil and product shipments via rail, it notes that anecdotal evidence indicates most of the growth in the crude oil and petroleum products category is likely due to crude shipments. Based on different sources of rail traffic data, the trade group said shipments of crude oil and liquefied natural gas accounted for about 2% of all carloads in 2008, 3% in 2009, 7% in 2010, and about 11% so far in 2011. One carload holds 30,000 gallons of oil.

Tank cars are in strong demand in North Dakota, where oil production has soared from about 343,000 barrels per day (bbl/d) in January to a record high of about 464,000 bbl/d in September, according to North Dakota's Department of Minerals Resources (DMR), due to the increasing amount of crude oil extracted from rock in theBakken Shale. DMR expects North Dakota will pass California during the second quarter of next year to become the third biggest oil-producing state. Burlington Northern Santa Fe (BNSF) and other railway companies are building or expanding terminals and adding tank cars to transport North Dakota's growing oil supplies to Gulf Coast refineries.

Bakken Oil Express

On November 7, the first crude oil unit train on the Bakken Oil Express, a newly constructed rail hub near Dickinson, North Dakota, departed via the BNSF Railway carrying its first shipment—70,000 barrels of crude oil destined for St. James, Louisiana. The Bakken Oil Express receives Bakken-area crude oil by both truck and pipeline and has a current takeaway capacity of 100,000 bbl/d. The Bakken Oil Express is already planning a second phase of construction that would significantly expand its takeaway capacity to more than 250,000 bbl/d.

Deliveries of tank cars should total about 8,000 this year, up from only 4,839 last year, and then increase to 11,000 tank cars in 2012, according to Economic Planning Associates Inc., a consulting firm that tracks rail car assemblies. The firm does not have a breakdown of how many of the new tank cars will be devoted to carrying crude oil. Tank cars are also used for shipping ethanol, chemicals, fertilizer, and corn syrup.

Bakken Oil On Railway

Tank cars would also be useful in the major oil hub of Cushing, Oklahoma, where a glut of supply is depressing the key U.S. benchmark crude oil price. Pipelines bringing oil into Cushing from the north are nearly full and there is not enough pipeline infrastructure to move oil south out of the area to Gulf Coast refineries. The Surface Transportation Board (STB), the federal agency that resolves railroad rate and service disputes and reviews railroad mergers, told EIA that it saw little movement in recent months of crude oil out of Cushing by rail. Railway companies send the STB confidential information on their cargo shipments and where they are sending them.

Bakken Oil Express Phases

Thursday, November 17, 2011

Seaway pipeline: Oil Prices Above $100


Oil climbed above $100 a barrel in New York to a five-month high as Enbridge Inc. said it will reverse the direction of the Seaway pipeline, adding an outlet for crude from the central U.S. and Canada.

Futures surged 3.2 percent after Enbridge agreed to acquireConocoPhillips (COP)’s share of the pipeline that runs between Cushing, Oklahoma, and the Gulf Coast and announced the reversal. The change may alleviate a bottleneck at the Cushing storage hub that has lowered the price of benchmark West Texas Intermediate against other oils.

“In the short term, this will definitely clear some of the crude out of Oklahoma,” said Francisco Blanch, head of commodities research at Bank of America Corp. in New York. “This may not be enough to eliminate the glut in the Midwest because output is growing by hundreds of thousands of barrels a year. We still need additional transportation capacity.”

Crude for December delivery rose $3.22 to $102.59 a barrel on theNew York Mercantile Exchange, the highest settlement since May 31. Futures are up 12 percent this year.

Brent oil for January settlement dropped 30 cents, or 0.3 percent, to $111.88 a barrel on the ICE Futures Europe exchange in London. The European contract’s premium to West Texas crude narrowed to $9.28 a barrel, the smallest spread since March 8. The differential surged to a record high of $27.88 on Oct. 14.

Keystone Pipeline

The announcement comes after the U.S. State Department said Nov. 10 that it will delay a decision on TransCanada Corp. (TRP)’s proposed Keystone XL oil pipeline to study an alternative route for the $7 billion project that avoids environmentally sensitive areas in Nebraska. The 1,661-mile (2,673-kilometer) link would deliver 700,000 barrels a day of Canadian oil to the Gulf.

Keystone Pipeline

“We will still need to see the Keystone pipeline built along with additional projects,” Blanch said. “The reversal of the Seaway is not enough.”

The Seaway pipeline will operate with an initial capacity of 150,000 barrels a day by the second quarter of 2012, the company said. Pump modifications expected to be completed by early 2013 will boost daily capacity to 400,000 barrels. Enbridge will jointly own the link with Enterprise Products Partners LP (EPD), the operator, the companies said today.

U.S and Canadian Oil Pipelines

The reversal will enable more oil from Canada and North Dakota to reach the Gulf Coast, home to about half of U.S. refining capacity. Rail and barge projects that are planned, proposed or under construction may boost North Dakota’s oil- loading capacity by 450,000 barrels a day next year, Goldman Sachs Group Inc. said in an Oct. 4 report.

Rail and Barge

The reversal “will definitely reduce the amount of rail and barge that is needed,” said Hussein Allidina, the head of commodity research at Morgan Stanley in New York. “You are still going to evacuate some crude via some of these higher-cost transportation means” as Canadian and U.S. output rises.

north dakota annual oil production 

north dakota oil production 2011

Oil in New York has surged 36 percent since touching $74.95 a barrel on Oct. 4, the lowest intraday price since Sept. 24, 2010. Prices tumbled 17 percent in the third quarter, the biggest quarterly decline since the financial crisis in 2008 on concern that the U.S. and European economies would slow.

“Prices have climbed almost 40 percent in a very short time,” said Todd Horwitz, chief strategist at Adam Mesh Trading Group in New York. “I wouldn’t be surprised if there’s a short- term pullback. Once that occurs, there’s no reason to think we won’t resume this move higher.”

Futures in New York have settled above the 200-day moving average since Nov. 7, forming technical support. The 200-day average stood at $95.22 today. The next resistance is around $105, the 76.4 percent retracement of the drop from this year’s high of $114.83 on a Fibonacci study.
‘Psychological Resistance’

“Crude is carrying a lot of momentum as it takes out key psychological resistance at $100,” said Richard Ross , a technical analyst at Auerbach Grayson, a brokerage in New York. “Given the near vertical ascent from the $70s, a failure here would lead to a fast move down and retest of the 200-day moving average around $95.”

Oil briefly pared gains after the U.S. Energy Department reported that crude supplies at Cushing rose 890,000 barrels to 32 million last week.

“The inventory numbers are being trumped by the announced reversal of the Seaway pipeline,” said David McAlvany, chief executive officer of McAlvany Financial Group in Durango, Colorado. “There won’t be any major impact until the second quarter of next year. It certainly makes sense to reverse the pipeline but it’s not a game-changer.”

U.S. Inventories

Nationwide crude oil stockpiles fell 1.06 million barrels to 337 million, according to the report released at 10:30 a.m. in Washington. A 1.2 million-barrel decline was expected, according to the median of 13 analyst responses in a Bloomberg News survey.

Oil volume in electronic trading on the Nymex was 1.11 million contracts as of 3:12 p.m. in New York, the first day over 1 million since Oct. 25. Volume totaled 743,768 contracts yesterday, 12 percent above the three-month average. Open interest was 1.36 million contracts.

Wednesday, November 16, 2011

The amount of natural gas-fired electric generation in Pennsylvania increasing

Pennsylvania Monthly Electricity Generation from Natural Gas

The amount of natural gas-fired electric generation in Pennsylvania has increased steadily in the past decade, with annual electricity generation from natural gas increasing more than tenfold between 2001 and 2010.

By 2007, a single month (August) of electricity generation from natural gas topped the 2001 annual total (see monthly chart above). The trend continues through 2011, with July reaching a new monthly peak at over 4.7 billion kilowatthours (kWh), although these levels are still well below the amount of coal and nuclear electric generation within the state.

The growth in natural gas-fired generation is reflected in the composition of electric generation in Pennsylvania. In 2001, coal accounted for 57% of Pennsylvania's total generation compared to just 2% for natural gas (see chart below). In contrast, during the first half of 2011, coal made up about 46% of total generation while natural gas generation grew to 17% of total generation.

Pennsylvania's Electric Generation Composition 

Two factors likely underpin increased natural gas generation in Pennsylvania.

Changes in relative fuel prices. Prices of coal and natural gas are key input costs at electric power plants in Pennsylvania and have taken different trajectories in the last couple of years. Accounting for only the first three quarters of each year, between 2009 and 2011 the NYMEX prompt-month Central Appalachian coal prices were up 54%. Over that same period, prompt-month natural gas futures prices at Henry Hub were up only 8%.

Changes in composition of generating capacity mix. Pennsylvania coal and natural gas generation additions were constructed in two fairly distinct waves. Most coal-fired generation was added in the 1960s-1970s, while the vast majority of its natural gas-fired generation was built since 2001, with new natural gas generators achieving greater operational efficiencies than the older coal generators.

Tuesday, November 15, 2011

Europe:Taxing times for diesel

After almost two years of difficult internal and external discussions, the European Commission (EC) finally released its ‘Proposal for Council Directive amending Directive 2003/96/EC restructuring the Community framework for the taxation of energy products and electricity’. This proposal is now with the European Parliament, the Council and the European Economic and Social Committee, commencing the project’s legislative procedure.

Under the existing energy taxation directive the minimum tax rates for energy products are based on volumes. This creates, according to the EC, unfair competition among fuel sources and unjustifiable tax benefits for certain types of fuel compared with others. Indeed, the effect of this tax system is that products with lower energy content, such as gasoline, carry a greater taxation burden per energy unit than products with a higher calorific value, such as diesel. However, although the current taxation system does not explicitly take into account a fuel’s CO2 output, the favourable treatment of diesel fuel was often linked to the better fuel efficiency of diesel engines, which results in lower tailpipe CO2 emission per kilometre.

Translated into numbers, diesel fuel enjoys a relative tax advantage of around 24% compared to gasoline – measured on energy bases – while it generates about 32% more CO2 emissions. This has led to a situation in which the open market diesel price is higher than that for gasoline due to greater diesel demand, but retail prices for final consumers are reversed at the pump because of lower taxation rates. This creates even more demand for diesel, despite EU shortages. The EC wants to put an end to this distortive treatment, with diesel currently taxed at a lower rate than gasoline in all but one EU member state (the UK).

Two other issues the EC’s new proposal seeks to resolve relate to the taxation of renewable fuels and policy consistency in the tax system in relation to the objectives of the EU Emissions Trading Scheme (ETS). Currently, the minimum tax on renewable fuels is equal to the tax rate of the conventional fuels they replace.
For example, ethanol is taxed as gasoline, even though emissions from these fuels are different. Moreover, the current tax directive does not take into account ETS rules, or the potential interaction with this system. Thus there are overlaps in a number of areas. As a result, it eliminates some potential effects of the ETS by distorting price signals.

Two elements of the energy tax

With the new tax proposal, the EC introduces a distinction between fuels specifically linked to carbon intensity (CO2-related taxation) and energy taxation with the purpose of generating budget revenue (a general energy consumption taxation). The first component, the CO2-related taxation, will be based on the reference CO2 emission factors set out in Commission Decision 2007/589/EC. The second component, the general energy consumption tax, will be calculated based on the net caloric value specified in Annex II to Directive 2006/32/EC. 

In the case of biomass and products based on biomass, the reference values shall be those set out in Annex III of the EU’s Renewable Energy Directive (RED). For biofuels, these reference values may be applicable only if biofuels meet the sustainability criteria specified in the RED, otherwise the energy content should be the value used for the equivalent heating fuel or motor fuel. The proposed minimum levels for motor fuels are summarized in the table below.
Proposed Taxation from 1 January 2013- Europe

Despite a number of exceptions to these general guidelines, the proposal assumes a gradual increase to the minimum tax level for on-road motor fuels – apart from gasoline – so by 2018 the minimum tax rate for all fuels is equal. For key motor fuels, gasoline and diesel, the implication is that minimum tax rates on diesel are set to increase by around 25% from €0.33/litre t €0.41/litre, while the minimum duty on gasoline stays roughly the same, at €0.36/litre. Moreover, restrictions on fuel tax neutrality after 2020 could see minimum diesel taxes eventually rise 15% above gasoline.

It is important, however, to recall that only these figures represent minimum tax rates and EU member states are free to set rates much higher. Currently, gasoline is taxed at €0.72/litre in the Netherlands, twice the minimum required rate, while, in the UK, diesel is taxed at €0.66/litre, or double the minimum rate.

Under the new tax directive, diesel taxes would have to rise in more than half the EU’s 27 member states. However, they are already higher in Europe’s largest car markets – Germany, the UK and France – where no changes would be necessary.

On the other hand, this proposal could also be viewed as a signal to EU member states to reverse unwarranted tax advantages to diesel and to steer towards a more balanced future demand pattern which is sustainable for the refining industry. An early assessment of the potential implications of this proposal on gasoline and diesel demand in Europe suggests that the progressive shift in diesel taxes will not be sufficient to reverse diesel demand growth within this decade. However, it could slow down the rate of new diesel car registrations in the coming years, with a subsequent gradual shift to a higher share for gasoline engines.

It is too early at this point, however, to determine the full extent of this proposal. Depending on the response of EU member states to this new directive, the effect is likely to be limited in the medium-term, but should become more visible after 2020.

Sunday, November 13, 2011

Libya's oil production reached 600,000 barrels a day

Libya, the holder of Africa’s biggest oil reserves, will produce as much as 800,000 barrels of crude a day by the end of this year, the chairman of state-run National Oil Corp. said.

Libya’s oil industry will recover more quickly than the International Energy Agency predicted after suffering disruptions this year amid fighting that engulfed the country, Nuri Berruien said today in an interview in Doha, Qatar. The nation currently pumps 600,000 barrels a day, he said, adding in comments to reporters that authorities will not award licenses to energy companies during its political transition after the death of Muammar Qaddafi.

The IAE stated in a Nov. 10 report that Libya’s output capacity will reach an average of 800,000 barrels a day in the first quarter of 2012, then rise to 1.17 million barrels a day in the fourth quarter of next year. The Paris-based IEA doesn’t know “the facts on the ground,” Berruien said.

Libya produced 345,000 barrels a day in October, more than triple the 100,000 barrels it pumped in September, according to data compiled by Bloomberg. The country produced almost 1.6 million barrels a day in January, before protests against the against Qaddafi’s regime flared into armed rebellion.

Libya is using 140,000 barrels a day of the crude and exporting the rest, Berruien said.
Three Fields

The country’s Waha oil field is expected to start producing by the end of this year and will pump more than 400,000 barrels a day at full capacity, Berruien said. The Elephant field, known as “El Feel” in Arabic, started producing on Nov. 11 and is pumping at a rate of 40,000 barrels a day, he said. The offshore Bouri field will begin pumping any day, he said.

Ras Lanuf refinery may resume operations by the end of the year, he said. The facility is Libya’s biggest, with a processing capacity of 220,000 barrels of crude a day, according to Bloomberg data. Abdo A. Ahmed, the acting chief executive officer of Libyan Emirates Refining Co., the plant’s owner, said in an interview on Oct. 17 that Ras Lanuf might start operations as early as November.

Libya issued a tender to buy 3 million metric tons of gasoline for delivery next year, or about 60 to 70 percent of its needs, Berruien said. The nation has been in discussion with suppliers such as Vitol Group, Glencore International Plc, Trafigura Beheer BV and Exxon Mobil Corp. to buy the 95-octane fuel, he said.

Following the start of the Ras Lanuf refinery, the state won’t import diesel next year, he said. It is currently buying gasoline and diesel from the spot market while exporting some naphtha, Berruien, he said.

Libyan natural-gas exports through Eni SpA (ENI)’s Greenstream pipeline to Italy reached 300 million cubic feet a day and will jump to 900 milliob by the middle of next year, Berruien said. Shipments through the pipeline resumed last month. The country is resuming exploration for gas with companies that already hold licenses, he told reporters.

Friday, November 4, 2011

Availability and Use of Alternative Fuels at U.S.

Since the petroleum "shocks" of the 1970s, the inflation-adjusted price of crude oil has generally declined until the spring of 2000 when prices increased due to renewed resolve by OPEC and some non-OPEC members to control crude oil supply to raise prices. Since the oil shocks of the 1970s several events combined to keep oil prices low: the end of the Cold War; a diminution in the market power of OPEC due to an increase in petroleum production from non-OPEC nations; and the cementing of U.S. security ties to the most important oil-exporting nations. Unfortunately, these developments have engendered a complacency on the part of the American public not unlike that which preceded previous oil shocks. The growing dependence of the U.S. on imported petroleum offsets the positive developments that have occurred in the global petroleum market over the past 20 years, i.e., the potential impact of a petroleum shock on the U.S. is growing regardless of its origin or whether it is politically motivated. Historically, periods of low prices have been followed by steep price spikes, of which we have just recently been reminded.

Based on information collected by the EIA in 2010, world crude oil reserves amount to about 1,380 billion barrels, and world natural gas reserves amount to about 187,1 trillion cubic meter. Of this total, the Middle East controls about 54 percent of the world's oil reserves and about 40 percent of the world's natural gas reserves (the former U.S.S.R. controls another 45 percent of the world's natural gas reserves). North American reserves of oil amount to just 5,5 percent of world reserves, and North American reserves of natural gas amount to just 5 of world reserves. Today, the Persian Gulf region holds about two-thirds of the entire world's known oil reserves. The U.S. imports more than 53 percent of its petroleum-much of it coming from the Persian Gulf region. EIA's Annual Energy Outlook 2010 estimates that this oil importation will increase to 62 percent by the year 2020.

The world's oil resources are as concentrated as ever in the OPEC nations, notably in the Persian Gulf. EIA projects that by 2020, OPEC's market share is likely to reach the levels of the 1970s, as its share of world supply grows from 41 percent in 1992 to 52 percent in 2000 to over 65 percent in 2020. In addition to concern about concentration of oil resources, new concerns have recently been raised that the peak in oil production could occur within ten years. Economic growth in the Pacific rim is giving rise to a growth in world oil demand that could well lead to a short-supply situation within the next five to ten years. Recent analysis by EIA indicates that the world oil production peak may not occur for another 20 to 50 years. Regardless of when the peak is reached, crude oil prices are likely to increase significantly in advance of peak production.

The costs to the U.S. economy from a future oil price shock could be enormous. Based on analyses of previous oil shocks, recent studies have estimated the macroeconomic impacts as reducing U.S. economic activity by an average of over 2 percent per year for three to four years or more, which translates into gross national product (GNP) reductions in the range of six hundred billion dollars over three years, up to possibly $3 trillion over fifteen years if the lost economic growth were not subsequently made up.

Unfortunately, unlike other energy using sectors, which have introduced substitute fuels and fuel switching flexibility since the oil shocks of the 1970s and 1980s, the transportation sector remains overwhelmingly dependent on petroleum-based fuels (approximately 95 percent of transportation energy coming from petroleum) and on technologies that provide virtually no flexibility. The transportation sector currently accounts for approximately two-thirds of all U.S. petroleum use and roughly one-fourth of total U.S. energy consumption. Highway transportation petroleum consumption has risen from 121 billion gallons per year in 1979, when CAFE was enacted, to 155 billion gallons per year in 1999 (28 percent over 20 years). EIA's Annual Energy Outlook 2000 projects U.S. dependence on imported petroleum will grow to 54 percent in 2000 and 60 percent in 2005.

In light of this dependence of the transportation sector on petroleum (and recent sharp increases in the price of gasoline), it is clear that substitution of petroleum-based transportation fuels (gasoline and diesel) by non-petroleum-based fuels ("replacement fuels," including alternative fuels such as electricity, ethanol, hydrogen, liquefied petroleum gas, methanol, and natural gas) could be a key means of reducing the vulnerability of the U.S. transportation sector to disruptions of petroleum supply and have significant benefits to the U. S. economy. Even moderate uses of alternative and replacement fuels in place of petroleum can bestow significant economic benefits by reducing the global demand and price for oil. Displacing petroleum with alternative and replacement transportation fuels helps hold down petroleum prices in two ways. First, reducing the demand for petroleum decreases the world price for oil. Although the actual impact will depend on precisely how OPEC responds, a reasonable rule of thumb is that a 1 percent decrease in U.S. petroleum demand will reduce world oil price by about 0.5 percent, in the long-run. Short-run (one year or less) impacts would be even greater, due to the short-run inelasticity of oil supply and demand.

A second benefit of increased alternative and replacement fuel use is its potential to reduce the impact of a supply shortage on prices. As evidenced in the industrial and utility sectors, the existence of alternatives to oil provides potential substitutes for oil in the event of a production cutback. Since it is precisely the non-responsiveness of transportation oil demand to oil production cutbacks that makes oil price shocks possible, increasing competition for oil by using alternative fuels reduces the ability of oil suppliers to constrain supply in order to increase the price of oil.

Availability of Alternative Fuels

The National Energy Policy Development Group, in its May 17, 2001, report on the National Energy Policy states that, "The lack of infrastructure for alternative fuels is a major obstacle to consumer acceptance of alternative fuels and the purchase of alternative fuel vehicles." The report further states that lack of infrastructure, "is also one of the main reasons why most alternative fuel vehicles actually operate on petroleum fuels, such as gasoline and diesel." The report's discussion of alternative fuel vehicles includes the statement that, "ethanol vehicles offer tremendous potential if ethanol production can be expanded." Additionally, the report states that, "a considerable enlargement of ethanol production and distribution capacity would be required to expand beyond their current base in the Midwest in order to increase use of ethanol-blended fuels."

The National Renewable Energy Laboratory reports that there are 5,236 alternative fuel refueling sites as of May 2001, with alternative fuel refueling sites in all 50 states. In comparison, there were 4,676 alternative fuel refueling sites in the U.S. in 1995. Unfortunately, while ethanol is the alternative fuel that most of the dual-fuel vehicles that have been produced can operate on, less than three percent of the alternative fuel refueling sites offer ethanol.

The Federal government, and specifically DOE, the General Services Administration and the Department of Agriculture are involved with efforts to promote the use and expansion of alternative fuels and the alternative fuel infrastructure. A major focus of these efforts is the development of different feedstocks for ethanol and on partnerships that result in the expansion of the ethanol fueling infrastructure.

DOE runs the Clean Cities Program, which unites public-private partnerships that deploy AFVs and build supporting infrastructure, with the common goal of building the alternative fuels market. Within these partnerships reside fuel suppliers, which are continually committing to providing facilities, fuels and services.

DOE also operates the Office of Fuels Development (OFD), whose primary focus is on working to reduce the cost of replacing imported oil with ethanol made from domestic resources such as corn fiber, bagasse and rice straw. OFD programs look to the longer term, with efforts investigating more advanced ethanol conversion technologies utilizing plants, trees and other feedstocks grown specifically for energy purposes. OFD also includes a vital outreach and educational effort under its purview - the Regional Biomass Energy Program (RBEP). The specific goal of the RBEP is to increase the production and use of bioenergy resources, and help to advance the use of biomass feedstocks and technologies.

DOE and the General Services Administration (GSA) are jointly managing a program called the Federal AFV USER Program, whose goal is to support the expansion of an alternative fuel infrastructure by concentrating large quantities of Federal AFVs and substantially increasing the use of alternative fuels in Federal AFVs in six selected areas: Albuquerque, NM; Denver, CO; Melbourne/Titusville/Kennedy Space Center, FL; Minneapolis/St. Paul, MN; Salt Lake City, UT; and the San Francisco Bay area.

In August 2001, the USDA announced that its agencies will use ethanol fuels in their fleet vehicles where practicable and reasonable in cost. USDA's more than 700 E-85 flex-fuel vehicles will use ethanol fuel where those vehicles operate in geographical areas that offer E-85 fueling stations, and USDA agencies will purchase or lease alternative fuel vehicles, including E-85 flex-fuel vehicles, for geographic areas that offer alternative fueling.

Presented below is information on the number of sites providing each alternative fuel and some additional information on where these sites are located.

Latest figures are dated at 10.25.2011 from U.S. Department of Energy.

Ethanol: There are 2454 ethanol (E85) refueling sites(10.25.2011) in the U.S., up from 37 in 1995. Ethanol refueling sites can be found predominantly in the Midwest, close to the major supplies of ethanol. Efforts by DOE are underway in Minnesota to help construct a number of ethanol refueling sites. As seen with the CNG, fuel suppliers can rise to meet the demand by developing the necessary infrastructure. Although the trend in alternative fuels is in the direction of E85 use, the infrastructure has been slow to develop because these vehicles could use conventional fuel. However, it is important to note that even if relatively few of these vehicles are actually being operated on E85, it is still valuable to be increasing that capability throughout the fleet because it could potentially contribute to the future transition away from petroleum, could spur an increase in the number of E85 refueling sites, and provide consumers an alternative if there are gas shortages or gas prices increase significantly.

Further, studies have shown that refueling stations need at least 200 steady customers for any single grade in order to make profitable use of the facilities. Though large numbers of flexible-fuel vehicles are being sold, they are spread out over the entire nation, and achieving a "critical mass" of 200 that use a single refueling station is still difficult to achieve. The small number of outlets available today points out the need to intensify the E85 refueling infrastructure. In addition, it is safe to say that many people who have purchased flexible-fuel vehicles do not know they could use E85. More public education in areas where E85 refueling stations exist is needed to inform people so that they are aware they can use E85.

Methanol: There are only two methanol (M85) refueling sites in the U.S., significantly down from 88 in 1995. Both of these sites can be found in California. The total number of methanol (M85) refueling sites has been dropping in the past few years, due to the lack of M85-capable flexible-fuel vehicles.

Natural Gas: There are currently 910 CNG refueling sites and 43 LNG refueling sites in the U.S., down from 1,065 CNG refueling sites in 1995. Natural gas refueling stations are usually located in urban areas near the major concentrations of natural gas vehicles, and are frequently constructed on a company's site to serve its fleet vehicles.

Electricity: There are 4012 electric recharging sites in the U.S., up from 188 in 1995. The vast majority of electric recharging sites can be found in the Southwest (California and Arizona), where the majority of electric vehicles are being sold. There is also a large concentration of electric recharging sites in Alabama and Georgia, where electric utilities have been proponents of electric vehicles. The availability of public refueling is not as important for electric vehicles as it is for other alternative fuels, since most (if not all) operators of electric vehicles will have a charger located at the vehicle's storage yard or garage to recharge the vehicle when it is not being used.

Liquefied Petroleum Gas (LPG): There are currently 2556 propane sites in the U.S.. LPG is sold throughout the U.S. as a home heating fuel, and many stations offering refueling of propane tanks also offer vehicle refueling.

Biodiesel: There are currently 610 biodiesel refueling sites in the U.S. The National Biodiesel Board counts seven major suppliers of biodiesel as members, located mostly in the Midwest. Biodiesel can be pumped through conventional diesel refueling equipment, so widespread availability of biodiesel would not pose a major obstacle with respect to infrastructure.

As of May 2001, there were 2454 public E85 refueling outlets in operation. 

Above you will find a listing of Alternative Fuel Station counts by state and fuel type, CNG-Compressed Natural Gas, E85-85% Ethanol, LPG-Propane, ELEC-Electric, B20-Biodiesel, HY-Hydrogen and LNG-Liquefied Natural Gas.

Russia oil output hits new record

Cuts in export duty pushed Russia's oil production, the world's largest, to a post-Soviet high of 10.34 million barrels per day (bpd) in October, the Energy Ministry said on Wednesday.
This compared with a previous record high of 10.30 million bpd hit in September.
But gas output at the world's top producer, Gazprom , slumped year-on-year on high gas prices for buyers.
Russia has kept ahead of Saudi Arabia as the world's largest crude producer. Last month the kingdom's output declined to 9.4 million bpd from 9.5 million bpd, according to a Reuters survey.
Russia Oil Production Consumption 

October was the first month of the new "60-66" taxation regime for the Russian oil industry, which cut duties on crude oil and some refined products to stimulate output of high-grade oil products and crude.
Hydrocarbons are a major source of state revenue, which must be replenished after a rise in spending ahead of parliamentary elections in December and a presidential vote in March.
Russia's third-largest oil company TNK-BP , half-owned by BP , contributed the most to the crude production increase, with output edging up 0.2 percent month-on-month to 6.27 million tonnes.
Russian Top Oil Importers 
Small producers -- a category which includes joint ventures such as Salym Petroleum, operated by Shell (RDSa.L) and Gazprom Neft -- also made a significant impact with a 2.2 percent increase to 3.6 million tonnes.
According to the West's energy watchdog, the International Energy Agency, Russia's oil production peaked at 11.41 million bpd in 1988, when it was still part of the Soviet Union.
Analysts polled by Reuters at the end of last year, expected Russian oil output would increase by 1.1 percent to 10.26 million bpd this year.
Year-to-date, output has averaged at 10.25 million bpd.

Russia Oil Production By Region

Russia's overall daily natural gas production increased by 13 percent to 1.80 billion cubic metres (bcm) last month from 1.59 bcm in September. Gas output at Gazprom rose 15 percent to 1.35 bcm a day month-on-month.
But Gazprom's output dropped 9.2 percent from October 2010 as buyers in Europe struggled to cope with high gas prices -- approaching $500 per 1,000 cubic metres -- and had bought volumes in advance.
"It is the lowest October production in the history of Gazprom," Mikhail Korchemkin of East European Gas Analysis said.
The state corporation has been suffering from competition with independent producers including Novatek , whose production jumped by 54 percent year-on-year to an all time high of 4.8 bcm last month.
Oleg Maximov from Troika Dialog brokerage said non-state gas producers were gaining the upper hand on the domestic market.
"We estimate that over 9 months in 2011, Russian consumption increased by 10 bcm y-o-y, while the output by the independents rose by 12 bcm, hence leaving no room for Gazprom to participate in growth on the domestic front," he said.