Here is the first part of the International Energy Agency report. It is not pleasant reading.

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The World’s Energy System is at a Crossroads.

Current global trends in energy supply and consumption are patently unsustainable — environmentally, economically, socially. But that can — and must — be altered; there’s still time to change the road we’re on.

It is not an exaggeration to claim that the future of human prosperity depends on how successfully we tackle the two central energy challenges facing us today: securing the supply of reliable and affordable energy; and effecting a rapid transformation to a low-carbon, efficient and environmentally benign system of energy supply. What is needed is nothing short of an energy revolution. This World Energy Outlook demonstrates how that might be achieved through decisive policy action and at what cost. It also describes the consequences of failure.

Oil is the world’s vital source of energy and will remain so for many years to come, even under the most optimistic of assumptions about the pace of development and deployment of alternative technology. But the sources of oil to meet rising demand, the cost of producing it and the prices that consumers will need to pay for it are extremely uncertain, perhaps more than ever. The surge in prices in recent years culminating in the price spike of 2008, coupled with much greater short-term price volatility, have highlighted just how sensitive prices are to short-term market imbalances.

They have also alerted people to the ultimately finite nature of oil (and natural gas) resources. In fact, the immediate risk to supply is not one of a lack of global resources, but rather a lack of investment where it is needed. Upstream investment has been rising rapidly in nominal terms, but much of the increase is due to surging costs and the need to combat rising decline rates — especially in higher-cost provinces outside of OPEC. Today, most capital goes to exploring for and developing high-cost reserves, partly because of limitations on international oil company access to the cheapest resources.

Expanding production in the lowest-cost countries will be central to meeting the world’s needs at reasonable cost in the face of dwindling resources in most parts of the world and accelerating decline rates everywhere. Preventing catastrophic and irreversible damage to the global climate ultimately
requires a major decarbonization of the world energy sources.

On current trends, energy-related emissions of carbon-dioxide (CO2) and other greenhouse gases will rise inexorably, pushing up average global temperature by as much as 6°C in the long term. Strong, urgent action is needed to curb these trends.

The 15th Conference of the Parties, to be held in Copenhagen in November 2009, provides a vital opportunity to negotiate a new global climate-change policy regime for beyond 2012 (the final year of coverage of the first commitment period of the Kyoto Protocol). The conference will need to put in place a framework for long-term co-operative action to bring the world onto a well-defined policy path towards a clear, quantified global goal for the stabilisation of greenhouse gases in the atmosphere. It will also need to ensure broad participation and put in place robust policy mechanisms to achieve the agreed objective.

World Energy Outlook 2008

The energy sector will have to play the central role in curbing emissions — through major improvements in efficiency and rapid switching to renewables and other low carbon technologies, such as carbon capture and storage (CCS). Securing energy supplies and speeding up the transition to a low-carbon energy system both call for radical action by governments — at national and local levels, and through participation in co-ordinated international mechanisms. Households, businesses and motorists will have to change the way they use energy, while energy suppliers will need to invest in developing and commercialising low-carbon technologies.

To make this happen, governments have to put in place appropriate financial incentives and regulatory frameworks that support both energy-security and climate-policy goals in an integrated way. Removing subsidies on energy consumption, which amounted to a staggering $310 billion in the 20 largest non-OECD countries in 2007, could make a major contribution to curbing demand and emissions growth. High international oil prices, by deterring consumption and encouraging more efficient demand-side technologies, push in the same direction, but only at the expense of economic growth and of living standards in consuming countries, both rich and poor.

And some of the alternatives to conventional oil that high prices encourage are even more carbon-intensive. Many countries have made progress in crafting national responses, but much more needs to be done. A new international climate agreement is but a first essential step on the road towards a sustainable energy system; effective implementation is just as crucial. Delay in doing either would increase the eventual cost of meeting any given global climate target.

More of the same: a vision of a laisser-faire fossil-energy future.

In our Reference Scenario, world primary energy demand grows by 1.6% per year on average in 2006-2030, from 11 730 Mtoe to just over 17 010 Mtoe — an increase of 45%. To illustrate the course on which we are set, this scenario embodies the effects of those government policies and measures that were enacted or adopted up to mid-2008, but not new ones. This provides a baseline against which we can quantify the extent to which we need to change course. Demand grows at a slower rate than projected in WEO-2007, mainly due to higher energy prices and slower economic growth, especially in OECD countries.

Fossil fuels account for 80% of the world’s primary energy mix in 2030 — down slightly on today. Oil remains the dominant fuel, though demand for coal rises more than demand for any other fuel in absolute terms. The share of the world’s energy consumed in cities — an estimated 7 900 Mtoe in 2006 — grows from two-thirds to almost three-quarters in 2030.

Due to continuing strong economic growth, China and India account for just over half of the increase in world primary energy demand between 2006 and 2030. Middle East countries strengthen their position as an important demand centre, contributing a further 11% to incremental world demand. Collectively, non-OECD countries account for 87% of the increase. As a result, their share of world primary energy demand rises from 51% to 62%. Their energy consumption overtook that of the OECD in 2005. Global primary demand for oil (excluding biofuels) rises by 1% per year on average, from 85 million barrels per day in 2007 to 106 mb/d in 2030.

However, its share of world energy use drops, from 34% to 30%. Oil demand in 2030 has been revised
downwards by 10 mb/d since last year’s Outlook, reflecting mainly the impact of much higher prices and slightly slower GDP growth, as well as new government policies introduced in the past year. All of the projected increase in world oil demand comes from non-OECD countries (over four-fifths from China, India and the Middle East);OECD oil demand falls slightly, due largely to declining non-transport oil demand. Global demand for natural gas grows more quickly, by 1.8% per year, its share in total energy demand rising marginally, to 22%. Most of the growth in gas use comes from the power-generation sector.

World demand for coal advances by 2% a year on average, its share in global energy demand climbing from 26% in 2006 to 29% in 2030. Some 85% of the increase in global coal consumption comes from the power sector in China and India. The share of nuclear power in primary energy demand edges down over the Outlook period, from 6% today to 5% in 2030 (its share of electricity output drops from 15% to 10%), reflecting the consistency of our rule not to anticipate changes in national policies — notwithstanding a recent revival of interest in nuclear power. Nuclear output nonetheless increases in absolute terms in all major regions except OECD Europe.
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For the balance of this important report go to the International Energy Agency Executive Summary.

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+ The UAE holds the fifth largest proven oil reserves in the Middle East and the fifth largest proven natural gas reserves in the world.
+ The United Arab Emirates plans to increase production capacity further over the next seven years.
+ The Dolphin Project pipeline, the first cross-border natural gas pipeline in the Arab Gulf, is slated to import two billion cubic feet per day to the UAE from Qatar by the end of 2007.
+ UAE electricity demand is growing rapidly, and the government is spending billions of dollars to meet future demand.

The United Arab Emirates (UAE) is an important oil producer with the fifth largest proven oil reserves in the Middle East. The UAE is a member of the Organization of the Petroleum Exporting Countries (OPEC) since joining in 1967. The emirate of Abu Dhabi is the center of the oil and gas industry, followed by Dubai, Sharjah, and Ras al Khaimah. In 2004, natural gas supplied 64 percent of the country’s total energy consumption, and oil supplied the remaining 36 percent.

The UAE is a high-income, stable federation of seven emirates with the second largest Arab economy in the Middle East. The non-oil sectors grew 18.6 percent in 2006 and have tripled during the last three years. Good relations with Asian trading partners and a growing domestic population have helped diversify the thriving economy. However, the country remains dependent on oil revenue, and the government has announced large oil production capacity increases within the next seven years. Abu Dhabi is the major hydrocarbon and industrial power while Dubai is the trading, financial, and tourist center of the emirates. Abu Dhabi and Dubai account for 80 percent of the UAE’s income. Hydrocarbon revenues account for around one-third of the UAE’s GDP, though the non-oil finance and service sectors in Dubai are making the city a favored base for multinational corporations in the Gulf.

In 2006, EIA estimates that the United Arab Emirates (UAE) produced 2.9 million barrels per day (bbl/d) of total oil liquids, of which 2.5 million bbl/d was crude oil. The UAE also produced an estimated 300,000 bbl/d of natural gas liquids (NGLs) and 102,000 bbl/d of condensate. UAE oil consumption averaged 423,000 bbl/d in 2006, with the majority of production exported to Asian countries. Foreign Minister Sheikh Abdullah bin Zayed al-Nahyan announced in April 2007 that UAE oil production capacity will increase to 5 million bbl/d by 2014, increasing the UAE’s profile in the region.

According to Oil & Gas Journal(OGJ), the UAE’s proven oil reserves were 97.6 billion barrels as of January 1, 2007. Abu Dhabi leads the other emirates with 92.2 billion barrels followed by Dubai with 4 billion barrels, Sharjah with 1.5 billion barrels, and Ras al Khaimah with 500 million barrels. The UAE holds the fifth largest proven oil reserves in the region. UAE crude streams are expensive due to their light and sweet composite compared to other Middle Eastern producers. The API gravity ranges from 34 to 36.8 degrees in the Zakum field, to 40.4 degrees in Murban.

Sector Organization:
The largest state owned company is the Abu Dhabi National Oil Company (ADNOC), which operates 17 subsidiary companies in the oil and natural gas sectors. ADNOC maintains the right to take up to 60 percent stake in new major oil projects. Hydrocarbon production is handled on a production sharing basis between state-owned companies and foreign investors. The majority of Abu Dhabi’s oil production is under the Abu Dhabi Company for Onshore Operations (ADCO), as well as the Abu Dhabi Marine Operating Company (ADMA-OPCO) and the Zakum Development Company (ZADCO.)

The Supreme Petroleum Council sets energy policy, and oil is the main focus of the UAE’s hydrocarbon policy under Oil Minister Mohammed al-Hamli, who is also the 2007 OPEC President. Foreign investors have a relatively limited role outside of exploration. Foreign contracts tend to fall under an engineering, procurement, and construction (EPC) basis.

Exploration and Production:

The UAE oil reserves account for 8.5 percent of total world reserves, most of which are located in Abu Dhabi. According to Global Insight, the Zakum oil field is the largest in the country, and the third largest in the Middle East, with an estimated 66 billion proven barrels. The UAE has committed itself to infrastructure development and enhanced oil recovery techniques in mature fields. The Upper Zakum project is a partnership between ADNOC, ExxonMobil, and Jodco to increase the Zakum production capacity by 200,000 bbl/d. Increases in production are also expected on onshore fields, Bu Hasa, Bab, and Asab, as well as north-eastern fields, al-Dabbi’iya, Rumaitha, and Shanatet. The government hopes that increased production capacity will make the UAE a ‘swing’ producer, strengthening its role and influence in the region. However, new exploration has been disappointing.

Pipelines:

The Emirates have a network of domestic pipelines linking fields with processing plants and exit ports for trade. There are also inter-emirate pipelines primarily for natural gas injection to increase oil recovery levels in existing Dubai oil fields. The Dolphin natural gas project linking Qatar (See Qatar Country Analysis Brief) and the UAE is the most important recent development in the area (see Natural Gas Section for more information.)

Exports:

UAE lies on the Persian Gulf with a number of ports available for shipping crude oil and natural gas exports. The main terminals are: Jabel Dhana, Zirku Island, Das Island, and Ruwais. Jabel Dhana exports from Abu Dhabi’s Asab, Bab, Bu Hasa, Sahil, and Shah oil fields. According to the EIA, Japan imported 1.36 million bbl/d from the UAE in February 2007, which is 54 percent of the UAE’s total net petroleum exports.

Refining:

According to OGJ, the UAE had 781,250 bbl/d of refining capacity at five facilities as of January 1, 2007. The three main refineries are Ruwais, Umm Al-Nar, and Jebel Ali. The largest two are ADNOC’s Ruwais with a 350,000 bbl/d capacity and Umm Al-Nar with a 150,000 bbl/d capacity. All substantial upgrades have been offered on an EPC basis, and there is discussion over larger roles in refining for private investors. Abu Dhabi’s investment arm IPIC and ConocoPhilips signed a deal in 2006 for a new refinery with 500,000 bbl/d capability.
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The government of Dubai understands full well that their oil resources will not last forever. That explains for the most part why Dubai is using its present high oil revenues to build the infrastructure to made Dubai a prime location for business and tourism.

The following information is kindly supplied by the US government’s Energy Information Administration.

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Iran is a member of the Organization of the Petroleum Exporting Countries (OPEC), and ranks amongst the world’s top three holders of proven oil and natural gas reserves. Iran is OPEC’s second-largest exporter after Saudi Arabia, and is the fourth-largest exporter of crude oil globally after Saudi Arabia, Russia, and Norway.

Natural gas accounts for half of Iran’s total domestic energy consumption, while the remaining half is predominately oil consumption. The continued exploration and production of the offshore South Pars natural gas field in the Persian Gulf is a key part of in Iran’s energy sector development plan.

According to Oil and Gas Journal, Iran has 136 billion barrels of proven oil reserves, or roughly 10 percent of the world’s total proven petroleum reserves as of January 1, 2007. Iran has 40 producing fields, 27 onshore and 13 offshore, with the majority of crude oil reserves located in the southwestern Khuzestan region near the Iraqi border. Iran’s crude oil is generally medium in sulfur content and in the 28°-35° API range.

Iran is OPEC’s second-largest producer after Saudi Arabia. In 2006, Iran produced an estimated 4.2 million barrels per day (bbl/d) of total liquids, of which 3.8 million bbl/d was crude oil, equal to 5 percent of global production.

Iran’s oil consumption totaled 1.6 million bbl/d in 2006. The Iranian government heavily subsidizes the price of refined oil products which has contributed to increased domestic demand. Iran has limited refinery capacity to produce light fuels, and imports much of its gasoline supply. Iranian domestic oil demand is mainly for gasoline and automotive gas oils, but domestic demand for other oil products are declining due to the substitution of natural gas.

However, it is an overall net petroleum products exporter due to large exports of residual fuel oil. Oil export revenues represent the majority of Iran’s total exports earnings, but the country suffers from budget deficits due to a growing population and large government subsidies on gasoline and food products. In 2005, the International Monetary Fund (IMF) estimated that energy subsidies accounted for 12 percent of Iran’s GDP, the highest rate in the world according to an International Energy Agency (IEA) study.

Iran produced 6 million bbl/d of crude oil in 1974, but has been unable to produce at that level since the 1979 revolution due to a combination of war, limited investment, sanctions, and a high rate of natural decline in Iran’s mature oil fields. Iran’s oil fields need structural upgrades including enhanced oil recovery (EOR) efforts such as natural gas injection. Iran’s fields have a natural annual decline rate estimated at 8 percent onshore and 10 percent offshore, while current Iranian recovery rates are 24-27 percent, 10 percent less than the world average. It is estimated that 400,000-500,000 bbl/d of crude production is lost annually due to reservoir damage and decreases in existing oil deposits.

Upstream Projects:

The Azadegan project phases I and II represent the greatest potential increase in Iranian crude oil production. Azadegan contains 26 billion barrels of proven crude oil reserves, but is geologically complex and difficult to extract. Iran and Venezuela have agreed on a $4 billion investment in the Ayacucho 7 block, where there are an estimated 31 billion barrels of oil. Iran’s Northern Drilling Company (NDC) has also worked with Russia’s Lukoil on oil field development in the Caspian Sea.

Iran plans to increase oil production to over 5 million bbl/d by 2010, but it will need foreign help. According to Global Insight, an estimated $25-35 billion is required to meet the government’s 5.8 million bbl/d target by 2015. Investment in Iran’s energy sector has been tempered due to the election of the Conservative government of President Mahmoud Ahmadinejad in 2005, the international controversy surrounding the Iranian uranium enrichment and nuclear program, and economic sanctions. According to the IEA 2007 Medium-Term Oil Market Report, Iran will not be able to increase its net expansion capacity through 2012.
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The tension between the United States and Iran remains high over Iran’s nuclear development program and Iran’s role as a power player in the Mid East. Hopefully, the Bush administration will not launch air attacks against Iran. If that should happen given Iran’s importance to the crude oil market and its strategic location crude oil would probably soar to $250 a barrel almost overnight.

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According to the Oil and Gas Journal (OGJ), Mexico had 12.4 billion barrels of proven oil reserves as of January 1, 2007. Most reserves consist of heavy crude oil varieties, with a specific gravity of less than 25° API. The largest concentration of remaining reserves occurs offshore in the southern part of the country, especially in the Campeche Basin. There are also sizable reserves in Mexico’s onshore basins in the northern parts of the country.

In 2006, Mexico was the sixth-largest producer of oil in the world. The country produced an average of 3.71 million barrels per day (bbl/d) of total oil liquids during 2006, down from 3.78 million bbl/d in 2005. Of Mexico’s oil production, about 88 percent was crude oil and condensate, the rest consisting of natural gas liquids (NGL) and refinery gain. Many analysts believe that Mexican oil production has peaked, and that the country’s production will continue to decline in the coming years. Based on its December 2007 Short Term Energy Outlook, EIA forecasts that Mexico will produce 3.52 million bbl/d of oil in 2007 and 3.32 million bbl/d in 2008. The decline is driven mainly by falling production at the super-giant Cantarell field.

NOTE: production at Cantarell has fallen faster than earlier forecast. This is terrible news for Mexico and for the US.

Mexico’s proven reserves have declined in recent years. According to state-owned Pemex, Mexico’s reserves/production ratio (based on previous-year production levels) fell from 20 years in 2002 to 10 years in 2006. Analysts believe that Pemex does not have sufficient funds available for exploration and investment to reverse the decline, owing to the larger amount of its revenues that the company transfers to the federal government.

Sector Organization
The Mexican constitution provides that the Mexican nation owns all hydrocarbon resources in the country. In 1938, Mexico nationalized its oil sector, creating Pemex as the sole oil operator in the country. Pemex has four operating subsidiaries: Exploration and Production, Gas and Basic Petrochemicals, Petrochemicals, and Refining. Pemex is the largest company in Mexico and one of the largest oil and natural gas companies in the world.

Pemex faces a variety of challenges in its efforts to stem Mexico’s oil production decline. First, Pemex sends a large share of its revenues to the federal government, sometimes transferring amounts in excess of its actual profits. In addition, Mexico’s Congress must approve Pemex’s budget each year. This has the effect of constraining Pemex’s ability to independently make funding decisions and can hinder long-term planning efforts. These fiscal imbalances have led to Pemex carrying a high debt load, which could hinder Pemex’s access to international capital markets and prohibit increased spending on exploration and production. There have been efforts to help address some of these challenges. In September 2007, Mexico’s Congress approved some reforms, including a reduction in the tax rate levied on Pemex, which will make billions of additional dollars per year available to the company.

Exploration and Production:

Most of Mexico’s oil production occurs in the Gulf of Campeche, located off the south-eastern coast of the country in the Gulf of Mexico. In 2006, this area accounted for 80 percent of Mexico’s total crude oil production. Other important production centers are onshore basins in the northern and southern parts of the country. Due to the concentration of Mexico’s oil production in the Gulf of Campeche area, any tropical storms or hurricanes passing through the area can disrupt oil operations. In 2007, Hurricane Dean forced the evacuation of all offshore platforms and shut-in all production for several days. In 2005, Hurricane Emily also impacted Pemex’s operations in the Gulf.

The Cantarell oil field, located in the Gulf of Campeche, is one of the largest oil fields in the world. In 2006, Cantarell produced 1.8 million bbl/d of crude oil, or 55 percent of the national total. The field consists of four major subfields: Akal, Nohoch, Chac, and Kutz. Production at Cantarell began in 1979, but production soon began to decline due to falling reservoir pressure. In 1997, Pemex developed a plan to reverse the field’s decline by injecting nitrogen into the reservoir to maintain pressure. The plan was a success, with production at Cantarell in 2004 double the level seen in 1995. However, production at Cantarell soon began to decline again. Crude oil production at the field peaked in 2004 at 2.14 million bbl/d, and production will likely continue to decline despite any incremental gains by incorporating additional satellite fields.

Map of Cantarell from EIA

The two other major oil production centers in the Gulf of Campeche are Ku-Maloob-Zaap (KMZ) and Abkatun-Pol-Chuc. Located adjacent to Cantarell, the KMZ complex produced 403,000 bbl/d of crude oil in 2006, up from 321,700 bbl/d of crude oil in 2005. Production at the field has risen by 50 percent over the past decade, and Pemex hopes that continued development of the field will replace some of the decline in Cantarell production. By pursuing a nitrogen re-injection program similar to the one used at Cantarell, Pemex hopes to increase production at KMZ to 800,000 bbl/d by 2010. Another source of new crude oil production is Pemex’sCrudeoLigaro Marino, which aims to increase offshore production of lighter crude varieties by 250,000 bbl/d by 2010.

Off the coast of Tabasco state, the Abkatun-Pol-Chuchcomplex produced 332,000 bbl/d of crude oil in 2006, around 11 percent higher than 2005. However, 2006 production was still about half the level seen in 1996.

Important onshore production centers in the southern part of the country include Bellota-Jujoand Samaria-Luna. The largest field in the north is Poza Rica. Pemex sees the onshore Chicontepec project, located northeast of Mexico City, as a potentially large source of future production growth. Chincotepec contains an estimated 6.5 billion barrels of probable reserves. As of the end of 2004, Pemex reported that it had drilled 93 exploratory and 1,004 development wells in the area. However, the Chincotepec project is still in the very early stages of development, and there are no solid estimates available as to its full production potential.

Crude Varieties:

Most of Mexico’s crude oil production consists of heavy crude varieties. Maya, a heavy crude which averages 22° API and 3.5-4.0 percent sulfur content, generally represents around two-thirds of Mexico’s total oil production. The country also produces two lighter crude streams, Isthmus (34° API) and Olmeca (39° API). In general, Mexico retains most of the lighter crude streams for domestic consumption and exports the bulk of its Maya production to the U.S. Gulf Coast, which has the sophisticated refining capacity necessary to process these heavy crudes.

Pipelines:

Pemex operates an extensive pipeline network in Mexico that connects major production centers with domestic refineries and export terminals. This network consists of over 453 pipelines spanning 2,900 miles, with the largest concentration occurring in the southern part of the country. Mexico does not have any international pipeline connections, with most exports leaving the country via tanker from three export terminals in the southern part of the country: CayoArcas, Dos Bocas, and Coatzacoalcos.

Oil Exports;

In 2006, Mexico exported 1.79 million bbl/d of crude oil. The United States receives the vast majority of Mexico’s crude oil exports, which mostly arrive via tanker in at the Gulf Coast. The close proximity of the U.S. market and the sophisticated level of refineries there will continue to attract the bulk of Mexico’s oil exports. Mexico is consistently one of the top three exporters of crude oil to the U.S., along with Canada and Saudi Arabia.
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As previously mentioned falling oil production in Mexico will trigger hardship in both Mexico and the United States. In a world of peak oil sourcing and paying for enough oil for the US economy to function well will be an on going challenge for the US government.

The following information is from the US Energy Information Administration (EIA) website.

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Russia’s production growth in the upcoming decade will depend on the availability of viable export routes for the country’s crude oil. Transneft currently has a monopoly over Russia’s pipeline network.

Destinations of Russian Oil Exports:

During 2007, Russia exported almost 4.4 million bbl/d of crude oil, and over 2 million bbl/d of oil products. Roughly 1.3 million bbl/d were exported via the Druzhba pipeline to Belarus, Ukraine, Germany, Poland, and other destinations in Central and Eastern Europe (including Hungary, Slovakia, and the Czech Republic), around 1.3 million bbl/d via the new flagship Primorsk port near St. Petersburg, and around 900,000 bbl/d via the Black Sea.

The majority of Russia’s oil exports transit via Transneft-controlled pipelines, but around 300,000 bbl/d of oil is transported via other non-Transneft-controlled sea routes or via rail. Because of higher world oil prices recently, almost 170,000 bbl/d of Russia’s oil is transported via railroad.

Oil Product Exports and Balance:

Most of Russia’s product exports consist of fuel oil and diesel fuel, which are used for heating in European countries and, on a small scale, in the United States. Russian oil exports to the U.S. have almost doubled since 2004, rising to over 400,000 bbl/d of crude oil and products in 2007. Updated monthly and annual data are available from EIA’s Petroleum Navigator. Increases in product exports can be attributed to political pressures to maintain refinery operations and higher international oil product prices. A draft plan for the refining sector’s development for 2005-2008 foresees continued increases in the production of high quality light oil products, catalysts and raw material for the petrochemical industry. As production of fuel oil is reduced, local refineries are only meeting about half of the country’s demand for high octane gasoline. Consequently, Russia must import the remainder.

Proposed Oil Pipeline Routes and Pipeline Expansion Projects:

North and West: Baltic Pipeline System (BPS) Expansion

The BPS came online in December 2001 carrying crude oil from Russia’s West Siberian and Timan-Pechora oil provinces westward to the newly completed port of Primorsk in the Russian Gulf of Finland (see Maps section). The BPS gives Russia a direct outlet to northern European markets, allowing the country to reduce its dependence on transit routes through Estonia, Latvia, and Lithuania. Unfortunately for the Baltic countries, the growth of the BPS has come at considerable cost, as Russian crude which traditionally moved through the Baltic region has been re-routed through the BPS.

Throughput capacity at Primorsk has steadily increased, reaching around 1.5 million bbl/d during 2007 on average. With the usage of larger-sized Baltimax tankers, throughput from the port should continue to increase this year. Although the port’s actual export capacity is allegedly twice as large (around 3 million bbl/d), pipeline capacity to the port keeps exports constrained. The Baltic Pipeline System-II (BPS-II) expansion will add new export outlets to the region, and in May 2008 the Russian government decided that a new line will run to the port of Ust-Luga with a branch going to the Kirishi oil refinery, The first stage of the Baltic Pipeline System (BPS, designed to transport oil from both Russia’s oil-producing regions and Kazakhstan, was commissioned in 2001. Transneft has estimated the cost of the second stage to Ust-Luga at around $3.3 billion.

Russian product line operator Transnefteproduct expects began shipments of oil products from Primorsk in May 2008. Exports of around 180,000 bbl/d of products (8.4 million tons/year) were originally expected to begin during the third quarter of 2007.

North and West: Murmansk Area, Kharyaga-Indiga Pipeline, and Varandei Terminal
International shipping from the Murmansk area has two advantages: the port is ice-free most of the year, and it is deep enough to make shipping to the United States economic without reloading in Europe. Several pipeline proposals connecting the Murmansk area to existing producing areas in the south in the last several years have been met with lukewarm reactions by Transneft (see Maps section) The state-owned company now plans a pipeline to Indiga, 240 miles from the Timan-Pechora producing basin, that is closer but iced over in winter. No timeline has been set for construction. Oil from Timan-Pechora has a lower sulfur content and is lighter than the rest of the Urals blend.

Now, Russian oil is delivered to the Murmansk area by rail, and in 2007 around 270,000 bbl/d of crude oil and products were shipped from the area. Lukoil will complete its $1 billion, 240,000-bbl/d terminal at Varandei in June 2008, which will allow shipments from the northern part of Timan-Pechora. Lukoil’s major source of oil for this terminal will be the Yuzhno-Khylchuyu field where production is expected to begin during the summer of 2008 and rise to 150,000 bbl/d by the end of 2009.

West: Druzhba Pipeline and Adria Reversal Project
Of the 1.3 million bbl/d of oil transported via the Druzhba Pipeline, only around 350,000 bbl/d flows to the south to Hungary, the Czech Republic and Slovakia. Reversal of the Adria pipeline, which spans between Croatia’s port of Omisalj on the Adriatic Sea and Hungary (see map), has been under consideration since the 1990s. The pipeline, which was completed in 1974, was originally designed to load Middle Eastern oil at Omisalj, then pipe it northward to Yugoslavia and on to Hungary. However, given both the Adria pipeline’s existing interconnection with the Russian system, and Russia’s booming production, the pipeline’s operators and transit states have since considered reversing the pipeline’s flow, thus giving Russia a new export outlet on the Adriatic Sea. The proposal included expanding the pipeline’s capacity from 100,000 bbl/d to 300,000 bbl/d at a cost of around $320 million.

In 2005, Croatia determined that an environmental impact study of such a reversal was incomplete and not based on enough expert knowledge, thereby killing the proposal. During the Belarus-Russia oil dispute in 2007, Hungary said that it could technically reverse its portion of the pipeline within 20-30 days.

Eastern Siberia Pacific Ocean Pipeline (ESPO): Taishet – Skovorodino – Kozmino Bay
Until 2004, Russian energy officials were unwilling to commit to one of two oil transit pipelines to eastern Asia. President Putin announced that Russia would commit to building a 2,500-mile pipeline route from the Russian city of Taishet to Kozmino Bay, southeast of Nakhodka in two stages. The endpoint for the pipeline was moved from Perevoznaya Bay to protect endangered species there.

The 1,200-mile first stage of the 600,000 bbl/d-pipeline will flow from Taishet to Skovorodino along with a port facility at Kozmino Bay. Although Transneft expects first commissioning of the pipeline by December 2009, as of December 2007 roughly 28% of the first stage of the pipeline route has not been welded and buried. Oil will be shipped via rail to the Pacific coast until the second stage of the pipeline is constructed. China has agreed to finance the 43-mile, 300,000-bbl/d spur from Skovorodino to the Chinese border. Transneft now estimates that the first stage of the project will cost around $12.5 billion, up from an original estimate of around $6 billion. In April 2008, around 1.5 million barrels filled the first stage of the pipeline, which will first operate in reverse mode to bring oil production from East Siberia to refining centers in West Siberia. The second stage of the pipeline will run from Skovorodino to the Pacific Coast, with planned designed capacity of 1.6 million bbl/d.

The route to Kozmino Bay is significantly more expensive than an alternative route to Daqing, China, since it covers a greater distance and involves more investment. However, the new route will open up a new Pacific port from which Russian oil exports could be shipped by tanker to other Asian markets and possibly even to North America.

The initial stage of the ESPO pipeline will get significant volumes of sweet crude from the TNK-BP-led East Siberian Verkhnechonsk field, in which Rosneft is a partner, and from Surgutneftegas’ Talakan field. Also, significant volumes (up to 270,000 bbl/d by 2010 according to Degolyer & McNaughton) would come from Rosneft’s Vankor field. Production from the three fields alone should be able to fill the pipe by around 2011.

Some hurdles exist to the Eastern Pipeline’s plan. First, financing the project is challenging. Russia has obtained Japanese promises of $7 billion for the project, but the first stage will be financed with a $2.4 billion revolving credit from state-owned Sberbank. The route passes through multiple environmentally sensitive areas which could have the potential to further delay the project. Finally, the government estimates that transportation tariffs could be roughly $6 per barrel, but other outside analysts estimate the level at up to $10 per barrel, which would help pay for increasing capital costs.

Black Sea/Turkish Straits:

After Russian oil flows through the various pipelines described above, crude oil and products are shipped onward to Europe, the United States, and Asia via tanker. The bulk of Russia’s oil (roughly 1 million bbl/d of crude) is shipped to the Mediterranean and to Asia via tankers in the Black Sea, mostly from the port of Novorossiysk. With the opening of the BTC pipeline in early 2006 and rising oil production exports from Caspian countries, Black Sea port shipments through the Bosporus will likely remain at around the same levels for the next couple years. The new Russian support for the Bourgas Alexandropoulis pipeline route, combined with existing support, makes this option one of the more commercially-feasible routes to help alleviate flows via the Bosporus.

Rail Export Routes:

Rail exports comprise roughly 5% of Russian crude oil exports. But unless significant investment flows into expanding the Russian pipeline network’s capacity, non-pipeline transported exports are poised to increase even more in the upcoming years. As China’s growth continues, rail routes are the only way to provide Russian crude oil to East Asia. In the absence of a dedicated pipeline route, Russian crude oil is exported via rail to the northeast cities of Harbin and Daqing and to central China via Mongolia. Rail exports of crude oil to China increased from approximately 200,000 bbl/d in 2005 to 300,000 bbl/d by 2006 according to China’s Ministry of Railways.
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In general, while oil importing nations, like the United States, struggle to pay for oil import bills, oil exporting nations like Saudi Arabia and Russia will be adding to their foreign exchange reserves as never before. The greatest transfer of wealth in the history of the world is taking place now and will continue into the foreseeable future. Oil importing nations will be forced to adopt energy conservation methods and must try to develop meaningful alternative sources of energy.

However, due to the heavy oil dependence of their economies the most likely outcome over the next decade or two of continued heavy oil imports is that the nations that are oil production deficient will experience a severe reduction in the standard of living of their citizens. The age of high priced energy is upon us. The adjustments that will be required by nations like the US will be difficult and perhaps lead to resource wars and conflicts without end. Toss in the consequences of global warming and the 21st century will be a trying time for humans, one that demands visionary leadership if we are to survive.

As an oil exporting nation Russia will likely fare better than most.