New Realities in Oil Transit Through the Turkish Straits · the Dardanelles [Canakkale Strait]), separated by the Sea of Marmara, constitute the only passage for ships either entering

CERA

New Realities in Oil Transit Through the Turkish Straits

Special RepoRt™

Special Study,

euraSian tranSportation Forum

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IHS CERA Special Report

CONTENTS

1. Introduction and Scope of the Study ………………………………………………………………… 1

2. Executive Summary ……………………………………………………………………………………… 5

Overall Findings ……………………………………………………………………………………………… 5

Analysis of Key Drivers Affecting Black Sea Flows …………………………………………………… 8

Black Sea and Bosphorus Evacuation ………………………………………………………………… 10

Comparison with Other Straits ………………………………………………………………………… 10

The Bosphorus Bottleneck ……………………………………………………………………………… 11

Maritime Safety Issues …………………………………………………………………………………… 12

Bosphorus Bypasses …………………………………………………………………………………… 14

3. Analysis of Key Drivers Affecting Overall Oil Flows from the Black Sea …………………… 15

3.1 Eurasian Crude Oil Production …………………………………………………………………… 15

3.1.1 Methodology for the eurasian oil production outlook ……………………………………… 15

3.1.2 oil production in the Russian Federation ……………………………………………………… 21

3.1.3 oil production in Kazakhstan …………………………………………………………………… 33

3.1.4 oil production in azerbaijan …………………………………………………………………… 44

3.1.5 oil production in turkmenistan ………………………………………………………………… 47

3.2 Eurasian Crude Oil Consumption ………………………………………………………………… 49

3.3 Eurasian Crude Oil Exports ………………………………………………………………………… 61

3.3.1 Russia’s crude oil exports ……………………………………………………………………… 61

3.3.2 Kazakhstan’s crude oil exports ………………………………………………………………… 63

3.3.3 azerbaijan’s crude oil exports ………………………………………………………………… 65

3.3.4. turkmenistan’s crude oil exports ……………………………………………………………… 77

3.4 Eurasian Pipeline Developments and Export Capacity ………………………………………… 78

3.5 Black Sea Oil Balances ……………………………………………………………………………… 88

3.5.1 Methodology Underlying iHS ceRa’s Black Sea oil Flows Scenarios ……………………… 88

3.5.2 eurasian crude oil arriving in the Black Sea ………………………………………………… 88

3.5.3 outlook for offshore Developments in the turkish Black Sea ……………………………… 102

3.5.4 offtake Volumes of crude by countries along the littoral of the Black Sea ……………… 102

3.5.5 Volume of crude oil Needing evacuation from the Black Sea ……………………………… 103

4. The Bosphorus Bottleneck: Pushing toward or away from the Congestion Threshold? … 108

4.1 Key Elements of the Bosphorus Bottleneck …………………………………………………… 111

4.1.1 Geographic and Meteorological Restrictions affecting the turkish Straits ………………… 111

4.1.2 Historical trends in Vessel traffic and Vessel Size …………………………………………… 112

4.1.3 administrative Restrictions on tankers ………………………………………………………… 116

4.1.4 the “perfect Storm” of the Winter of 2003/04: a one-off event or Glimpse of the Future? 126

4.2 Comparison with Other High-Traffic Straits …………………………………………………… 130

4.2.1 turkish Straits: Bosphorus ……………………………………………………………………… 134

4.2.2 Malacca …………………………………………………………………………………………… 134

4.2.3 Strait of Hormuz …………………………………………………………………………………… 135

4.2.4 Danish Straits ……………………………………………………………………………………… 137

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4.3 Congestion Model for the Turkish Straits ………………………………………………………… 143

4.3.1 Methodological approach and assumptions ………………………………………………… 144

4.3.2 Nominal and Real capacity of the turkish Straits …………………………………………… 145

4.3.3 Modeling Results ………………………………………………………………………………… 146

4.4 Maritime Safety Issues ……………………………………………………………………………… 152

4.4.1 Where the Major Safety Risks lie ……………………………………………………………… 152

4.4.2 improving pilot Usage and pilot Boarding ……………………………………………………… 155

4.4.3 improving Use of escort tugs …………………………………………………………………… 156

4.4.4 Vessel Vetting Standards ………………………………………………………………………… 156

5. Status of Turkish Straits Bypass Proposals ……………………………………………………… 158

5.1 Burgas-Alexandroupolis …………………………………………………………………………… 158

5.2 Samsun-Ceyhan ……………………………………………………………………………………… 161

5.3 Odessa-Brody-Gdansk ……………………………………………………………………………… 164

5.4 AMBO …………………………………………………………………………………………………… 166

5.5 Constanta-Trieste …………………………………………………………………………………… 167

5.6 Istanbul Canal ………………………………………………………………………………………… 169

6. Oil Demand Developments in Global Markets …………………………………………………… 171

6.1 Overview of Methodology …………………………………………………………………………… 171

6.2 Oil Demand in IHS CERA’s Three Global Energy Scenarios to 2030 ………………………… 173

6.2.1 Europe ………………………………………………………………………………………………… 174

6.2.2 North America ……………………………………………………………………………………… 177

6.2.3 Asia Pacific ………………………………………………………………………………………… 179

6.2.4 Mediterranean Region …………………………………………………………………………… 182

Appendix: IHS CERA’s Global Energy Scenarios …………………………………………………… 193

About the Authors ………………………………………………………………………………………… 204

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1. INTRODUCTION AND SCOPE OF THE STUDy

The Turkish Straits are one of several important “chokepoints” on global sea routes that are considered critical to global energy security because of the high volume of oil that transits through them. The Turkish Straits form the maritime trade route between the Mediterranean and the Black Sea, and therefore are an important route for Eurasian oil exports to the global market (see Figure I-1). The Turkish Straits represent an impediment to the flow of oil tankers; the build-up of wintertime queues at either end of the straits is common when daylight hours grow fewer.

In fact, the Turkish Straits (the Bosphorus [referred to as the Istanbul Strait locally] and the Dardanelles [Canakkale Strait]), separated by the Sea of Marmara, constitute the only passage for ships either entering or exiting the Black Sea, going to or from the Mediterranean Sea (Aegean Sea). As a result, the Bosphorus is one of the busiest waterways in the world (measured in terms of total ship passages). Furthermore, mainly because of its narrow and winding form, which also makes it necessary to change direction frequently, restrictions are placed on the size of vessels that can navigate the straits. Added to this, of course,

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2 Private and Confidential



are ferry services between the European and Asian parts of the Istanbul metropolis and numerous private motor yachts and pleasure vessels, which aggravate the overall situation in terms of traffic.

Because of the importance in international seaborne trade, international passage through the Turkish Straits has long been governed by international treaties between Europe’s “Great Powers” and Turkey. The latest of these is the 1936 Montreux Convention, a multilateral international convention, which confirmed the international status of the straits and the general regulatory regime governing vessels directly passing through the straits. The treaty explicitly guarantees international freedom of passage for commercial vessels through the Turkish Straits during peacetime.

Despite this, Turkish opposition to any large-scale increase in oil tanker traffic through the straits, especially the crowded Bosphorus, has long been obvious. A long-standing goal of Turkish policy has been to reduce oil transiting the straits, and with the opening of the Caspian region’s oil resources to international development following the dissolution of the USSR, Turkish policymakers became determined to prevent the Turkish Straits from becoming the primary conduit for the flow of this oil to international markets. This concern has been one of the key drivers behind Turkish support for various bypass pipeline schemes, especially those through Turkish territory, such as the Baku-Tbilisi-Ceyhan (BTC) pipeline.

The purpose of this Special Report is to review the general situation, analyze recent trends, and provide an outlook for oil transport through the Turkish Straits. The goal is to offer a broad assessment of the impact of this flow on the relative risks involved and overall maritime safety. This report is being issued under the auspices of IHS CERA’s Eurasian Transportation Forum. The Forum was established over a decade ago to create a global forum designed to help improve the oil and gas transportation environment in Russia and the Caspian region. This Special Report represents part of our efforts in engaging key decision-makers on such issues and providing a fact-based understanding and assessment of regional oil and gas transportation issues and problems.

There is a strong perception, or even what might be called a passion, that shipping crude oil via the Turkish Straits creates unacceptable congestion, safety, and environmental hazards. But for the most part, we find that this perception is driven by

A misunderstanding or exaggeration of the number and type of vessels transiting the •Turkish Straits

A misunderstanding of, or uncertainties in, the type of cargoes and existing and projected •crude oil volumes intended to use the Turkish Straits for evacuation

A misunderstanding that crude oil tankers, in terms of the traffic and volumes of freight •moved, pose the greatest risk of an accident to the straits

Part of the reason for these misunderstandings is the lack of readily available data on passages and cargoes moving through the straits. Although Turkish authorities collect data on ship passages and the flow of cargoes, these are not widely disseminated, so there is a lack of transparency in data availability.



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In turn, these misconceptions have typically fueled much of the debate over the various options and proposals for bypasses to remove oil from the Turkish Straits. In many ways, these bypass solutions do not address the real safety and environmental hazard: the greatest risk of an accident probably comes from the large number of smaller vessels that account for over 95% of total passages through the Turkish Straits and not from the much smaller number of larger tankers (over 200 meters [m] in length) associated with crude oil shipments. In particular, these smaller vessels tend to “fly a flag” (be registered in a country) associated with a lower standard (as determined by the Paris Memorandum of Understanding [MOU] on Port State Control—see below), and are generally older and less well-equipped and managed. What is also often overlooked is that all of them also carry a significant load of bunker fuel that could be spilled in the event of an incident. A common misperception is that only tankers can cause oil spills.

Our overall goal for this Special Report is to correct these misunderstandings and to provide a broader, fact-based assessment to drive discussions, actions, and policies that lead to outcomes that do create a safer transportation environment in the Turkish Straits. The report is being issued now because of the confluence of several recent events:

Launch of the expansion of the Caspian Pipeline Consortium (CPC) pipeline from •Kazakhstan to the Black Sea. This development is commonly perceived as leading to a sizable increase in oil transit through the Turkish Straits and dramatically raising the accident risk, a perception that is grossly inaccurate.

Delays in development of the Kashagan field, a megaproject that significantly •drives Kazakhstan’s oil production profile from 2015. The project delay postpones much of Kazakhstan’s rise in oil exports until after Azerbaijan’s and Russia’s regional exports are in decline, which “smoothes out” the Black Sea oil evacuation profile over the longer term.

The launch of additional Russian pipeline capacity (Eastern Siberia–Pacific Ocean •[ESPO]-1, ESPO-2, Baltic Pipeline System [BPS]-2). This moves Russian oil exports away from the Black Sea (and the Turkish Straits).

Changes in Russian oil export taxation.• This will result in the decline of exports of refined products.

The demonstration over nearly a decade of improved traffic flow in the Turkish •Straits, culminating in the winter of 2010/11. The professional approach to traffic management indicates that congestion in the straits can be reduced significantly without compromising safety.

This study covers the situation in the Turkish Straits generally, but predominantly focuses on the Bosphorus, even when the more restrictive regime traditionally applied only to the Bosporus was extended to the Canakkale (Dardanelles) in 2002, the Canakkale has since become the more dominant bottleneck for shipping between the two (see below). This focus on the Bosphorus is because in many ways, the current situation in the Canakkale is only a side effect of administrative restrictions intended to safeguard the navigationally more difficult Bosphorus. Also, the Bosphorus really remains at the heart of Turkish and




international concerns because of Istanbul, and its historical and cultural importance. Finally, because of the study’s focus on oil transit, that situation becomes more muddled and difficult to track after the Bosphorus. This is due to complications of Turkish offtake at the Izmit refinery on the Sea of Marmara, accounting for other sources of crude coming to the refinery, and uncertainties in the additions and subtractions of refined products flows in the Istanbul area.

Following this introductory section (Chapter I), IHS CERA summarizes its key research findings and conclusions in an executive summary (Chapter II). The overall analysis of oil trends in the Eurasian region is presented in Chapter III, which comprises an evaluation of Eurasian crude oil production and export trends, with emphasis on the volumes of Eurasian crude oil that are likely to need transit from the Black Sea.

Chapter IV focuses on the problem of congestion in the Turkish Straits in recent years, and how this relates to changes in vessel traffic and the administrative restrictions on traffic imposed by Turkish authorities (particularly from October 2002). Chapter IV also includes some comparisons with other high-traffic straits (or “chokepoints”) for global tanker shipments. Chapter V provides an update on the status of the proposed bypass pipelines and other options, and evaluates their comparative advantages and disadvantages (e.g., Burgas-Alexandroupolis, Samsun-Ceyhan, Odessa-Brody-Gdansk, Albanian Macedonian Bulgarian Oil Corporation [AMBO], and Constanta-Trieste, as well as the proposed Istanbul Canal). Chapter VI includes an overview of oil demand trends in the primary target markets (Europe, North America, Asia Pacific, and the Mediterranean region) and how these might affect the overall attractiveness of the Black Sea as an evacuation route for Eurasian oil exports.



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2. ExECUTIvE SUMMARy

OvERAll FINDINGS

The shipment of crude oil through the Turkish Straits accounts for a relatively small part of the current safety and environmental risk profile for the straits—contrary to what is commonly perceived. Overall oil shipments (crude and products combined) represented only 5.4% of total ship passages through the Bosphorus in 2010, and crude oil passages alone made up a mere 3.2% (see Figure II-1). Even when measured in volume terms, oil-related shipments remain quite modest in the total tonnage passing through the Bosphorus: total oil-related deadweight tonnage of vessels (crude + products) accounted for only 22.7% of the overall total that passed through the Bosphorus last year (see Table II-1).

The greatest accident risk in the straits does not come from crude oil tankers but from the large number of nontankers (other cargo carriers). This relative risk derives from both the total number of passages involved (they accounted for 85% of total passages and 68% of total traffic volumes [measured in deadweight tons] in 2010) and because these vessels are generally of a lesser standard, being much older and less well-equipped and managed. Of the crude oil tankers going through the Bosphorus in 2010, 78% were less than 10 years old, with 41% less than five years old. Product tankers tend to be older on average, while among other types of cargo ships (all ships other than tankers), which represented over 85% of all passages in 2010, only 23% of the vessels were less than 10 years ago and 61% were over 20 years old. What is also often overlooked is that all of these “nonoil” vessels also carry a load of bunker fuel aboard—for some, a fairly significant amount—that could

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be spilled in event of an incident. Furthermore, none of the crude oil tankers that passed through the Bosphorus in 2010 were flagged in “black-list” flag registries (as determined by the Paris MOU), where vessel safety and management standards are much lower. Yet a sizeable number of ships in all the other major vessel categories, particularly the general category of “other ships” (i.e., nontankers), had such registries.

Oil evacuation through the Turkish Straits will not continue to rise. This study shows that the number of oil-related passages has been declining in recent years; and according to the projections presented in this study, total oil volumes passing through the straits are likely to decline further or remain flat in the future. In the base case, we project that total oil flows through the Bosphorus reach a maximum of 135.9 million metric tons (mt) in 2025 (about the same as in 2010 and less than the peak volume of 151.6 mt already achieved in 2005) (see Figure II-2). While we also project a rise in crude oil evacuation volumes through the straits within this overall total (+10.3% by 2025), we expect the number of tanker passages to decrease substantially because of an ongoing shift toward larger tankers and a rationalization of oil flows (i.e., more crude in larger tankers and less refined products). Tanker passages of crude oil are projected to decline to about 1,062 outbound (or 2,124 in both directions) through the Bosphorus by 2025 in the base case, compared with 2,741 recorded in 2009 and 2,239 in 2010 (see Figure II-3). Product tanker passages are projected to decline significantly. In contrast, passages of other cargo ships (nontankers) rose substantially in 2010 (+9.2%) and will probably continue to rise in the future, concomitant with overall economic growth in the Black Sea region as a whole.

One of Russia’s new pipelines starting up at the end of 2011, BPS-2 that bypasses Belarus and extends to the Baltic Sea, has been established as spare or “strategic” export capacity, to be used in the event of a dispute with Belarus and/or other emergency. But its capacity could also be used in the wintertime to divert Russian (or Kazakh) crude oil from the Black Sea if significant backups or congestion in the Turkish Straits occurred or were threatening to develop. Therefore, wintertime oil volumes targeting the Bosphorus could be even lower than envisioned in our base case. This is a significant development over available choices

Table II-1

Ship Traffic in the Bosphorus, 2009–10

Number of passagesShip Volumes (thousand

Deadweight tons)2009 2010 2009 2010

total Ships 65,887 69,338 1,343.5 1,359.0

total tankers 11,739 10,226 519.8 438.2 crude oil tankers 2,741 2,239 323.2 271.6 products tankers 1,873 1,487 47.2 36.3 chemical/Gas/other tankers 7,125 6,500 149.3 130.3 other Ships 54,148 59,112 823.7 920.9

Source: aiS (aggregated and compiled by iHS lloyd's Fairplay).



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in the past, as the new route provides a cost-effective alternative should congestion costs in the Turkish Straits begin to escalate during winter seasons.

Although the CPC pipeline is expected to be the major source of incremental crude volumes arriving in the Black Sea for the future after its planned expansion (maximum throughput of 69 mt per year is expected in the base case scenario in 2030), incremental CPC throughput does not necessarily translate into incremental Black Sea export volumes. A key element of CPC expansion involves consolidation of export flows into this single route (with loadings accomplished at a deep-draft terminal) from various producers that currently already reach the Black Sea, such as rail-based exports through smaller, shallow-draft Ukrainian or Georgian ports. CPC expansion would, in fact, seem to improve the overall level of safety in the Turkish Straits, as it will cause a rising share of total crude evacuation from the Black Sea to be lifted in larger (Suezmax) tankers. These larger ships tend to be safer vessels overall, and the increased use of larger tankers reduces the total number of passages needed, improving the risk.

Therefore, in our overall assessment, shipping crude oil through the Turkish Straits by tanker does not create unacceptable congestion, safety, and environmental hazards, as is commonly perceived.

ANAlySIS OF KEy DRIvERS AFFECTING BlACK SEA FlOwS

Eurasia (i.e., the countries of the former Soviet Union [FSU] excluding the Baltic states) is one of the world’s preeminent oil producers and oil-exporting regions, and it is clear that the region will continue to be a major center of oil production and exports during the period under consideration (out to 2030).

In 2010 total Eurasian crude oil production was 655.7 mt, the equivalent of about 13.1 million barrels per day (mbd). This represented about 16.8% of global oil production last year. The bulk of Eurasian crude output (98.6%) was produced within the Russian Federation and the three Caspian producing states of Kazakhstan, Azerbaijan, and Turkmenistan.

Russian oil production has risen slightly in the past two years after declining slightly in 2008 (the first fall in a decade), reaching 505.1 mt (10.1 mbd) in 2010. In IHS CERA’s base case scenario, Russian production is projected to continue to rise (albeit slowly) through 2020, to reach 531.7 mt (10.6 mbd) in 2020 before declining over the following decade to 518.0 mt (10.4 mbd) by 2030.

Therefore, much of the overall growth in Eurasian crude output between now and 2030 is expected to come from Kazakhstan. Altogether, Kazakhstan produced 79.7 mt (1.7 mbd) of oil in 2010, and under IHS CERA’s base case its output is projected to increase steadily, to reach 153.3 mt (3.25 mbd) by 2030. In the high scenario, output is projected to reach 194.2 mt (4.2 mbd), while in the low scenario, growth is much less than in either of the other scenarios, but national output is still projected to reach 103.5 mt (2.2 mbd) in 2030.

Aggregate crude oil production for Russia and the three Caspian producing states in the base case is projected to grow from 646.7 mt (13.2 mbd) in 2010 to 704.8 mt (14.4 mbd) in 2020



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and reach 725.4 mt (14.9 mbd) in 2030. In the high scenario, aggregate oil production is projected to reach 790.0 mt (15.7 mbd) in 2020 and 845.3 mt (17.4 mbd) in 2030. In the low scenario, regional aggregate oil production is projected to reach 559.9 mt (11.8 mbd) in 2020 before declining to 526.9 mt (11.0 mbd) in 2030.

Crude consumption in Eurasia is expected to decline, making more crude available for export. This is due to changes in the Russian export tax regime, which previously made exports of refined products (artificially) the most profitable export channel, and ongoing refinery modernization across the region. The economics of investment in domestic Eurasian refineries are improving to the point where oil companies are spending significant capital on refinery modernization to lighten the product slate, meaning that less crude needs to be refined to meet projected light product demand internally (the part of the demand barrel that is growing while consumption of heavy products is declining).

Russia’s crude oil exports outside the FSU (i.e., excluding Lithuania) amounted to 218.9 mt (4.38 mbd) in 2010. This was up by 5.5% compared to 2009, but represented an increase of 96% from the 1998 level of 111.9 mt (2.23 mbd). But Russian crude exports to the non-FSU have been relatively flat since 2005 because of the incentive provided by Russia’s export tax regime to refine crude domestically and export refined products instead of exporting crude directly. As a result, refined product exports from Russia increased by 36% between 2005 and 2010, rising to 132.2 mt (2.64 mbd), of which 126.6 mt (2.53 mbd) was to countries outside the Commonwealth of Independent States (CIS).

Over the outlook period, Russia’s crude oil exports in the base case are projected to increase to a maximum of 347.3 mt (6.95 mbd) in 2020 and then drift slowly down to 334.8 mt (6.7 mbd) by 2030. At the same time, refined product exports outside the CIS are projected to decline to 47.8 mt (0.96 mbd) in 2020 and 42.6 mt (0.85 mbd) by 2030. In the high case, crude exports are projected to hit a maximum of 403.2 mt in 2025 (8.06 mbd), while in the low case crude exports contract to 224.1 mt (4.5 mbd) in 2030.

The second largest Eurasian crude exporter, Kazakhstan, has always exported the bulk of its crude oil production (85% in 2010). Its total crude exports have increased from 20.3 mt (0.5 mbd) in 1992 to 67.5 mt (1.35 mbd) in 2010, with 65.5 mt (1.32 mbd) of this exported to markets beyond the CIS. Azerbaijan’s crude oil exports have climbed steadily in recent years, to reach 44.3 mt (0.89 mbd) in 2010, a nearly sixfold increase from 7.6 mt (152,000 barrels per day [bd]) in 2000.

In the base case scenario, Kazakhstan’s crude exports are projected to expand to 140.4 mt (2.8 mbd) in 2030, while Azerbaijan’s decline to only 34 mt (0.7 mbd). In the high case, Kazakhstan’s crude exports rise to 182.0 mt (3.6 mbd), and Azerbaijan’s hold up at 48.3 mt (1.0 mbd). In the low case, crude exports are much lower in 2030: 90.6 mt (1.8 mbd) for Kazakhstan and 19.9 mt (0.4 mbd) for Azerbaijan. Turkmenistan’s crude exports are expected to remain relatively small and provide only a minor contribution to the region’s overall export volumes.




BlACK SEA AND BOSPHORUS EvACUATION

The figures estimated for 2010 (with data available as of October 2011) show total flows of oil (crude and products) through the Bosphorus (in both directions) at 134.7 mt (2.7 mbd), of which 92.4 mt (1.85 mbd) was Eurasian crude flowing south out of the Black Sea through the Turkish Straits. IHS CERA’s central or expected outlook (the combination of Russian base scenario–Caspian base scenario) is for a slight decline through 2015 in total oil flows targeting the Bosphorus (to 129.2 mt), before a rebound through 2025 to reach 135.9 mt (2.72 mbd), falling off slightly thereafter to 131.4 mt (2.62 mbd) by 2030. The volume of Eurasian crude targeting the Bosphorus, which accounts for the bulk of this flow, is projected to follow a somewhat different path: rising steadily through 2025, to reach 112.1 mt (2.24 mbd), a 21% increase from the 2010 level, followed by a subsequent decline to 108.0 mt (2.16 mbd) by 2030. Consequently, the total number of tankers using the straits will decline substantially, mainly due to the reduction of product volumes; the number of crude oil tankers will have a lesser decline despite the increased volume because of the shift to larger tankers (see Figure II-3).

COMPARISON wITH OTHER STRAITS

Total ship passages in the Turkish Straits (most importantly, in the Bosphorus) are roughly on the same order of magnitude as total ship passages through two of the other important waterways in the world where tanker traffic is relatively high (i.e., about 65,000–70,000 passages in total per year)—Danish Straits and Malacca—but well ahead of total passages through the Strait of Hormuz (at only 36–37,000 per year). But tanker traffic (of all types) in the Bosphorus represented only about 15% of the total amount of ship passages through the strait in 2010, down from about 17–18% where it has been historically; this reflects the recent significant decline seen in tanker traffic. In the other three straits of interest, tanker traffic comprises a more significant part of the overall ship traffic than in the Bosphorus: in the Danish Straits, tankers make up just over 30% of the total traffic, and in the Malacca Strait, the share of tanker traffic is slightly higher, at about a third of the total traffic, while in the Strait of Hormuz, the tanker share of the total traffic is even higher, at about half of the total number of vessels transiting.

Therefore, in terms of number of tanker passages, all the other straits are much busier than the Bosphorus; annual passages through them were about two times greater than through the Bosphorus. In terms of the total deadweight tonnage or volumes carried, the amount going through the Bosphorus for all types of tankers, 438.2 million deadweight tons (dwt) in 2010, was far less than for any of the other major straits of interest here. The Danish Straits total in 2010, 654.5 million dwt, was about 50% more than for the Bosphorus. And the total tanker tonnage through the Bosphorus is, in turn, dwarfed by the tanker tonnage passing through the Strait of Malacca (2,029.4 million dwt) and the Strait of Hormuz (2,762.4 million dwt). The latter carry about six times as much volume as the Bosphorus.

The Strait of Hormuz and the Malacca Strait can both accommodate even the largest tankers, although for Malacca the draft restriction makes it a tight fit for very large crude carriers (VLCCs). Still, both Hormuz and Malacca serve as major thoroughfares for VLCC vessels, and the average size of crude oil tankers passing these two straits is more than 200,000



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dwt. The size restrictions in the Bosphorus and Danish Straits essentially preclude the use of VLCCs. Thus, the average size of crude oil tankers passing those areas tends to be much smaller: 120,000 dwt for the Bosphorus and 104,000 dwt for the Danish Straits.

The situation in the Danish Straits is a fairly close analogue to the Turkish Straits. The Danish Straits, like the Turkish Straits, is an international waterway regulated by an international convention. The principal international agreement is the Copenhagen Treaty of 1857. The opening of Danish waterways to foreign shipping occurred as a result of a Danish government decision when the previous practice became a diplomatic and trade liability. Similarly, navigation in the Danish Straits is quite complicated because of strong currents, poor weather, shifting sandbanks, long and narrow winding passages with sufficient depth, as well as high traffic volumes. Still, the only restriction on vessels is draft (15 m). Most importantly, although in many respects passage appears at least as difficult as through the Bosphorus, transits of large vessels/tankers are not restricted to only daylight hours. Safety standards are still very high, partly because about 96–98% of large vessels passing through the Danish Straits in recent years have had a pilot on board. This is even though, like in the Turkish Straits, pilotage is voluntary rather than compulsory.

THE BOSPHORUS BOTTlENECK

It has been a long-standing goal of Turkish policy to reduce oil transiting the congested Straits, and with the opening of the Caspian region’s oil resources to international development following the dissolution of the USSR, Turkish policymakers became determined to prevent the Turkish Straits from becoming the primary conduit for the flow of this oil to international markets. This is reflected in the particular transit regime imposed on the Turkish Straits, as it mainly aims at restricting the flow of large crude tankers.

The largest ships allowed to pass the Bosphorus without special permission are 300 m long and 58 m high. Vessels that carry hydrocarbons or derivatives thereof (mainly tankers) and other designated cargoes (see below) are considered “hazardous vessels.” A hazardous vessel of 200 m or more is considered a “restricted vessel” (mainly crude oil tankers) and is only allowed to transit the strait during daylight hours. It is strongly recommended that all vessels over 150 m long take a pilot for safety and good bridge management.

The principal issue with the current Turkish regulations is that they restrict passage by large “hazardous” vessels (mainly crude oil tankers) to daylight hours only and then at certain transit intervals (75–90 minutes). Therefore, the problem of delays/demurrage in the straits is a wintertime phenomenon when crude oil evacuation exceeds (hypothetical) potential capacity because of the fewer daylight hours available. This is when delays and queues typically form.

For shippers the practical implications of stricter Turkish regulations over traffic through the straits were vividly illustrated in the winter of 2003/04. Delays in tanker shipments (due to both changes in the implementation of Turkish regulations and winter weather) cost oil exporters over US$800 million in additional transportation charges, fueled also by high freight rates that spiked because of the loss of tanker capacity because of the queues.




But delays (and resulting costs) have declined since, both through improved operations by Turkish traffic control as well as reduced oil transit volumes. The average number of “extra” days (i.e., those beyond the usual 48 hours, or two days needed [during the October–March winter period]) to transit the Turkish Straits (either from the Bosphorus to the Canakkale or vice versa) had declined to only 6.4 days in the winter of 2010/11 from a high of 10.1 extra days in the winter of 2006/07. During winter 2010/11, following initial periods of extreme weather, traffic control authorities kept the delay and queue buildup to reasonable levels by scheduling that limited the number of directional changes in the one-way traffic scheme and especially by reducing transit spacing time between the “restricted vessels.” An important point is that such minor changes in transit spacing did not compromise safety. This action also demonstrates the Turkish authorities’ real commitment to reduce shipping delays in areas where such adjustments are possible without diminishing safety.

Another way to apply reduced intervals with relatively little increased accident risk would be to dispatch inbound, empty tankers at greatly reduced intervals (say 30–40 minutes instead of the present practice of 75–90 minutes). Empty tankers have a high power-to-displacement ratio, and they proceed against the oncoming current, which provides good steerage and control. Furthermore, high powered vessels, including large empty tankers, could be dispatched during the early part of each one-way transit schedule and thereby not only reduce the accumulation of large ships at the entrances but also reduce the problem of greater immediate concern, that of overtaking slower vessels during the transit. Such reduced intervals between transiting tankers would still provide sufficient distance and locations for an emergency anchorage in case of an emergency occurring ahead.

These rather significant improvements in delay times over the past few winters are another indicator that transit through the Turkish Straits was probably quite close to the congestion threshold in 2004/05, as relatively small changes in volumes have made a big difference in backups and overall congestion costs since. Most importantly, it appears that traffic volumes are moving away from the congestion threshold rather than toward it, provided that the transit regime does not change. Furthermore, an option to “bypass” the Bosphorus that becomes available in early 2012 is to use the spare capacity of the BPS-2 pipeline more heavily during the winter months.

MARITIME SAFETy ISSUES

A key misconception about the Turkish Straits is that the major seaborne safety risks are from crude oil shipments in large tankers. Therefore, the public policy goal for the Turkish government has been to remove crude oil flows altogether (or reduce them as much as possible) from the Turkish Straits. But all oil shipments (crude and products combined) represented only 5.4% of total ship passages through the Bosphorus in 2010, and tankers carrying crude oil alone made up a mere 3.2%. Clearly, even removing all crude oil shipments from the straits, such as through a pipeline, would have an immaterial impact on overall ship traffic. Even when measured in tonnage, oil-related shipment volumes remain quite modest in terms of the overall total passing through the Bosphorus. The vast bulk of ship traffic in the straits is related to non-oil cargoes. All other things being equal, such passages should be considered at least as risky as those relating to oil.



13


More importantly, these other issues are not equal and actually make non-oil traffic (or even product tankers versus crude) a riskier endeavor in general. One key aspect, as mentioned earlier, is the average age of the vessels. For crude oil tankers going through the Bosphorus in 2010, 78% have been in service for less than 10 years, with 41% only 0–4 years of age. Products tankers tend to be older; only 44.5% of such vessels passing through the Bosphorus in 2010 less than 10 years old. But for nontankers (other ships), nearly 85% of all passages, only 23.2% of vessels were less than 10 years old, while 61% were 20+ years old. Other factors are often overlooked. All the nontankers also carry a significant load of bunker fuel that could be spilled in an accident. Another indicator of vessel quality is the country of registry: none of the crude oil tankers over 200 m in length that passed through the Bosphorus in 2010 were flagged in “black-list” countries. In contrast, this is not the case for any of the other major categories of vessels, particularly the general category of other ships (nontankers).

Also, the number of oil-related passages has been declining in recent years. According to the projections presented in this study, while the toil oil flow through the straits will remain relatively steady to 2025, tanker transits will continue to decline, mainly due to lower oil product flows. In contrast, passages by other ships (nontankers) rose substantially in 2010 (+9.2%) and will probably continue to rise with overall economic growth in the Black Sea region.

Another factor that makes nonoil traffic in the straits a higher-risk operation than crude oil shipments relates to the use of pilots. Overall only 29% of all ships passing through the Bosphorus used pilots in 2010 (excluding ships bound for Turkish ports where usage is mandatory). But virtually 100% of large crude tankers (and for all ships over 200 m length overall [LOA]) use pilots. This means that use of pilots by smaller vessels transiting through the straits remains very low. The pilot’s boarding location is related issue with the potential to improve safety significantly in the Turkish Straits. Five nautical miles outside of each entrance to the Straits is a designated pilot-boarding area, marked on the appropriate navigation chart. These locations, endorsed and agreed with the International Maritime Organization (IMO), have the appropriate distance to allow a joining pilot and vessel master to conduct a proper master-pilot information exchange and tests. The locations also allow the vessel’s master to abort the passage should the pilot have difficulty in reaching or boarding the vessel. To improve safety standards, this boarding location should become universal, which is not always the case at the present time.

Another change to help to improve overall safety would be to tether to the vessel the escort tug that currently accompanies “restricted” tankers (> 250 m LOA, empty or loaded)—and this should apply to any vessel that may be impeded by its size or maneuverability, not only tankers. This way the escort tug could be more effectively employed in an emergency. A certified escort tug tethered to a vessel can provide both arresting and steering force and tug has been proven to be the single most effective tool for reducing groundings and collisions.

Another practice that could improve the overall safety of the Turkish Straits is more widespread use of vessel-vetting procedures. Structured vetting procedures are not widely practiced at Black Sea ports and oil terminals, but they are used at CPC and Supsa, the two Black Sea




terminals operated by international companies. Similarly, the Black Sea countries could act as a group to implement a uniform set of standards or a standard vetting procedure for all ships that call (and load or discharge) at Black Sea ports.

BOSPHORUS ByPASSES

The analysis presented in the study shows that a Bosphorus bypass pipeline is not needed from an economic perspective (excluding any other underlying environmental and/or safety issues). Our analysis suggests that oil evacuation volumes and transiting tankers are likely to decline, and with them the costs generated by congestion in the straits will also decline—thus undermining what would be a key element of the cost advantage of a bypass. Also, a bypass pipeline represents a modal substitution of pipeline transportation for tanker transportation (albeit for a particular segment). Because of this, high tanker rates are naturally advantageous for bypasses (favoring more pipeline transportation), while low rates are not (favoring tanker transportation). IHS CERA’s long-term outlook calls for much lower tanker rates than during the recent period of tight tanker markets, greatly diminishing the potential cost advantage of bypass pipelines. Finally, a bypass pipeline does not address the real safety issues in the straits as it targets the removal of just one or two (out of four to six) transits each day of the most modern, most scrutinized, and well-managed vessels transiting the Turkish Straits.



15


3. ANAlySIS OF KEy DRIvERS AFFECTING OvERAll OIl FlOwS FROM THE BlACK SEA

This chapter addresses the following key question: How much crude oil coming into the Black Sea will exit via the Turkish Straits? This includes an analysis of oil production in the key Eurasian exporting countries (Russia, Kazakhstan, Azerbaijan, and Turkmenistan) out to 2030, analysis of crude oil demand in the region, and thus derived total crude oil export flows from the region. The analysis must also determine what proportion of that total amount will arrive in the Black Sea for shipping after considering export flows via other transportation routes.

3.1 EURASIAN CRUDE OIl PRODUCTION

Eurasia (meaning the countries of the FSU excluding the Baltic states), one of the world’s pre-eminent oil producers, is a major oil-exporting region as well. In 2010 Eurasian crude oil production was 655.7 mt (13.1 mbd), or about 16.8% of global oil production. The bulk of this output (98.5%) was produced within the Russian Federation and the three Caspian producing states of Kazakhstan, Azerbaijan, and Turkmenistan. Judging from the size of their remaining oil reserves, it is clear that the region will continue to be a major center of future oil production. These four countries were credited with proven reserves of 17.1 billion metric tons (124.8 billion barrels) in 2010, or about 9% of the world total, according to BP.*

3.1.1 Methodology for the Eurasian Oil Production Outlook

One of the most important tasks of this study is to provide an outlook for Eurasian oil production, a major factor in determining oil evacuation volumes from the Black Sea. IHS CERA has drawn on a wide and diverse set of sources for the crude oil production data provided below for the Eurasian countries. The historical data for 1990–2010 are relatively uncontroversial. Most of this data is authoritatively reported by government statistical agencies, although there are some question marks over some of the disaggregated (regional) numbers, where such official data are lacking in some countries.** As is the convention statistically, these production figures include both crude oil proper and gas condensate.

The outlook for Eurasia’s future liquid productive capacity presented here is based on direct observation of industry discovery and development activity similar to other regions of the

*See the BP Statistical Review of World Energy, 2011.**However, a problem for available Turkmenistan’s oil production figures has emerged in recent years. Turkmenistan no longer officially reports data on its oil and gas production after declaring such data to be confidential. As a result, Turkmen oil production figures now come from less reliable secondary sources. Furthermore, information on the disposition of crude oil (deliveries to the refineries, exports to various destinations) does not match reported production plus the small amount of imports from neighboring Uzbekistan. For example, in 2004 crude output was officially reported as 10.05 mt and refinery throughput as 6.83 mt; with imports of about 0.4 mt, this leaves about 3.6 mt available for export on a net basis. But we can only credibly identify about 1.0 mt of crude exports from Turkmenistan in 2004: 0.5 mt to Batumi, 0.4 mt to Iran, and 0.1 mt on other minor routes, including the Volga-Don Canal. This problem (which also exists in other years) is being reconciled in our balances by including a growing amount of crude within apparent domestic consumption above refinery requirements (i.e., field losses, stock changes). But the size of the discrepancy suggests that Turkmenistan may be deliberately overstating its crude production by a considerable margin.




world by IHS CERA. IHS CERA develops its overall supply outlooks from the field- or project-level upward based on three key elements:

Existing capacity.• IHS CERA tracks the industry’s recent and historical productive capacity and decline rates, and assesses its ability to stem declining production in existing areas.

Conversions for Metric Tons to Barrels

Because the eurasian countries use the metric system, all data regarding oil production volumes, refinery operations, and exports are officially reported in metric tons. However, since much of the global oil industry runs in barrels, in this study most of these figures are given in both metric tons and in equivalent barrels.

the conversion from tons to barrels, however, is not quite straightforward, as the conversion coefficient differs considerably from crude to crude and product to product, depending on the specific density (gravity) of each. Within eurasia, crude oil production occurs in many diverse basins and fields, where crude qualities differ greatly, including wide differences in densities or specific gravities as well as the content of other kee elements, such as sulfur and paraffin. eurasian crude qualities range from extremely heavy (or dense), such as the Yarega crude from the timan-pechora Basin that is literally mined, to very light, as some condensates associated with natural gas production that contain nearly as much light petroleum gases (propane and butanes) as heavier liquid fractions. But the main crudes produced within eurasia (and that figure significantly in the outlooks presented below) range from the heavy Mangyshlak and Buzachi crudes produced in western Kazakhstan (850–950 kilograms per cubic meter [kg per cm]), which convert at an average of about 6.95 barrels per metric ton, to light condensates, such as Karachaganak (795 kg per cm), which converts at about 8.33 barrels per metric ton, or West Siberian gas condensate, which converts at about 8.6 barrels per ton.

a common measure expressing the gravity or density of liquid petroleum products is an arbitrary scale developed by the american petroleum institute (api) expressed in degrees, which is sometimes referred to in the study. this is defined as:

Degrees api = 141.5/(specific gravity at 60oF/60oF) – 131.5

in this study, the conversion coefficients vary from crude to crude. When referring to specific producers or specific types of crude, we generally use the specific conversion coefficient for that crude, such as tengiz (7.95 barrels per ton) or West Siberian crude (7.45 barrels per ton). the national totals are often regional aggregates, so the figures cited in barrels per day for national output are often sums of the regional/project components. For individual pipelines or export routes that handle only a specific type of crude (such as the cpc pipeline, which handles only cpc Blend), a specific conversion is used. But usually when referring to broader aggregations that are blends or mixtures of various crude types, such as total national or regional exports or flows through the turkish Straits, we typically use an average conversion coefficient for eurasian (and Russian) crudes of 7.3 barrels per metric ton. this also happens to be the conversion coefficient for Urals Blend, Russia’s dominant export crude from the transneft pipeline system.

For refined products, unless otherwise specified, aggregate refined product volumes, like aggregate crude oil volumes, are converted from tons to barrels at the rate of 1 ton = 7.3 barrels; individual refined product volumes are converted at the rate of 1 ton of automobile gasoline = 8.5 barrels, 1 ton of diesel = 7.5 barrels, and 1 ton of fuel oil = 6.5 barrels.



17


New significant discoveries and developments.• IHS CERA monitors new field discoveries and major field developments of both conventional and unconventional oil, which together with existing capacity form the basis of the near- to mid-term outlook.

Future discoveries.• We include future discoveries on a region-by-region basis by projecting the historical pace and success of exploration activity and incorporate them into the longer-term outlook. The industry’s inability to find an amount of oil equal to what is extracted annually in a given basin, region, or country is a signpost for an eventual decline in productive capacity.

IHS CERA’s usual methodology traditionally gives a relatively heavy weight to the discovery and development of new fields, which has not been the principal driver of Russian growth over the past decade. Therefore, we employ an approach aimed at tracking the redevelopment of existing fields as well as the discovery and development of new fields.

For the forward-looking figures, the probability that IHS CERA attaches to its outlooks differs widely from producer to producer. This is explained below for the different aggregations for projecting oil production developments.

Caspian. Figures for major projects run by international companies in the region benefit from IHS CERA’s access to credible, probabilistic production outlooks from informed sources close to those projects. There is, of course, uncertainty attached to these production outlooks, but this derives from the inherent uncertainty of field development rather than from difficulties in access to information.

Caspian region projections for state-operated production (and for Turkmenistan practically in its entirety) are less certain. They are based on official outlooks when available, but filtered through IHS CERA’s own views of what may or may not be realistic given geological potential, capital availability, and other factors, such as logistics and politics.

For Caspian oil production, in our base case, IHS CERA has tried to approximate a P50 outlook; i.e., the actual results have an equal likelihood of being higher or lower than the base case projections. The high case figures are meant to approximate a P90 outlook (i.e., the actual results have a 90% probability that they will be lower than the outlook numbers). Similarly, the low case is intended to approximate a P10 outlook (i.e., the actual results have only a 10% probability that they will be lower than the outlook numbers). These probability figures are intended only as rough guides in interpreting the production outlooks.

Experience demonstrates that publicized development plans for relatively new, pioneering regions (such as the Caspian) tend to be optimistic with regard to timing—schedules often slip because of infrastructure constraints as well as disagreements that delay decision making—but at the same time, often turn out to be low with regard to ultimate production volumes, given what seems to be a natural inclination toward conservative estimates of well productivity and ultimate recoverable reserves at the outset. We have built these underlying issues into our outlooks from the beginning, and we have already seen this very situation emerge in Kashagan’s development: this large and complex project is coming on much later than initially planned, but the second phase (as announced, although the development has




yet to be officially sanctioned) is expected to produce at a much higher plateau level than initially envisioned.

In the base case scenario, existing development projects in the Caspian region proceed more or less as intended, but not entirely so—in this scenario, a variety of constraints and difficulties create small, but significant, delays and thus production shortfalls for particular years relative to what is currently envisioned. It is intended to be a P50 case, i.e., where the actual results are just as likely to be higher as lower than the projected amount. In the base case, total crude production in the three Caspian countries is projected to grow from 141.5 mt (2.94 mbd) in 2010 to 169.2.1 mt (3.53 mbd) in 2020 and reach 207.4 mt (4.35 mbd) in 2030 (see Figure III-1); this represents an average annual rate of growth of 2.0% over the 20-year outlook period. Aggregate regional growth is relatively low in the final decade of the outlook, reflecting a sizable decline in the absolute production volume within Azerbaijan.

In the high scenario, development is assumed to proceed more smoothly, without significant delays, and producers exceed their currently envisioned “probable” production profiles as a result of productivity that is slightly higher than initially expected. It is intended to approximate a P90 case, where actual results have only a 10% likelihood of being higher than the projected amounts. Total production in the three Caspian countries is projected to grow even more substantially under this scenario, from 141.5 mt (2.94 mbd) in 2010 to

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19


210.6 mt (4.4 mbd) in 2020 and reach a maximum of 265.8 mt (5.59 mbd) in 2030; this represents an average annual growth rate of 3.3% over the outlook period.

In the low scenario, development proceeds more slowly than in the base case because of more significant delays, so that production ends up being lower than in the base case over the outlook period. It is intended to approximate a P10 case, where actual results have only a 10% likelihood of being lower than the projected amounts. Total production in the three Caspian countries is projected to remain almost flat over the outlook period, with output declining slightly, falling from 141.5 mt (2.94 mbd) in 2010 to 140.8 mt (2.93 mbd) in 2020, and then 138.9 mt (2.9 mbd) in 2030.

There is, however, a major source of uncertainty in the Caspian production outlooks that should be flagged—the potential contribution of currently undeveloped or undiscovered fields, mainly offshore (several fields discovered in the past few years have now moved into the undeveloped category). IHS CERA has made assumptions about the contribution by 2030 of such fields that, while not overly pessimistic, are potentially conservative. It seems sensible from a general planning perspective not to build in huge amounts of undeveloped/undiscovered (and thus speculative) production. Thus by 2020 and especially by 2030, there is a growing gap between the three scenarios sketched in above and another alternative scenario in which there would be considerable exploration success offshore. The discovery and relatively rapid development of three or more sizeable fields in the post-Kashagan offshore area of Kazakhstan (or even two fields, if one were on the scale of Tengiz)—or indeed a significant oil discovery in the Azerbaijani offshore—could make even the high case outlook look quite low by 2025.

Russia. Russia’s future oil production, in IHS CERA’s view, remains more difficult to predict than that of the Caspian region; it is certainly more controversial. This is because, unlike the Caspian where production is driven by a relatively small number of major projects with international participation, Russian national output results from trends across a large number of developments in quite disparate regions and geological basins. Furthermore, the surge in Russian output in 1999–2004 was largely due to intensified operations at older (legacy) fields rather than new production developments, a rather unique situation that reflected the unusual opportunities resulting from the upstream oil development practices of the Soviet period. Three key areas of uncertainty are under debate: first, the potential for continued production growth from West Siberia through comprehensive application of international practices and technologies on older fields already in production; second, the potential for further discoveries in West Siberia in deeper horizons and in parts of the basin previously overlooked; and third, the prospectivity and commerciality of fields in inland East Siberia.

Another factor complicating production profiles for the Russian oil industry is that each of the six regional divisions we use to categorize Russian oil production (regional aggregations used are those that are relevant for subsequent oil transportation) are, in fact, composites of production from diverse fields and companies. Debates are currently under way regarding the production potential of West Siberia, East Siberia, and other Russian regions, and realities are far from clear. It is also evident that a major change in overall upstream development occurred in the aftermath of the Yukos affair. The impact of the loss of this company’s drive and innovation, and its replacement by what may be more conservative approaches to




upstream development, is yet to be fully determined. For the time being, Russian production is currently essentially stagnant (i.e., the base case scenario). Furthermore, the key factors determining Russian oil production are basically “aboveground” rather than issues relating to reserves or fields; these factors include the overall investment climate including tax policy, export and transportation policies; access to reserves by international companies; and other similar issues.

For the base case, IHS CERA has attempted to approximate a P50 outlook like the Caspian region outlook. The P50 outlook envisions a very slow expansion of production after a hiccup downward in 2008. We assume that some changes will occur in Russian upstream taxation that improve investment incentives in both the base and high scenarios. We do not assume that the current poor investment climate remains in effect and unaltered over the long term. However, we project that national output rises to only 531.7 mt (10.8 mbd) in 2020 and declines thereafter, falling to 518.0 mt (10.5 mbd) in 2030 (see Figure III-2).

For the high case, IHS CERA has used a series of more aggressive assumptions about the future of Russian oil production, particularly in West Siberia. The high case is intended to approximate a reasonable scenario in the P90 range, in keeping with our methodology for Caspian production. It envisions Russian oil production rising more rapidly in the earlier years of the outlook period, to reach 582.5 mt (11.8 mbd) in 2020, although the pace slows to just below zero in the final decade of the outlook to nudge 581.1 mt (11.8 mbd) in 2030.

In the low scenario, intended to approximate a P10 outlook, we use more pessimistic assumptions. It envisions a steady decline in Russian oil output from 2010 (averaging an

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average decline of about 0.9% per year over the 22-year period to 2030), with national output falling to 435.5 mt (8.9 mbd) by 2020 and then 387.7 mt (8.1 mbd) by 2030.

3.1.2 Oil Production in the Russian Federation

After a period of remarkable growth during 1999–2004, when crude output surged by over 50%, starting in 2005 Russian oil production began to increase at relatively slow annual rates and in 2008 declined by 0.6% (the first drop in a decade), to 488.5 mt (9.87 mbd) (see Table III-1). Since then, production has ticked upward again, reaching 505.1 mt (10.2 mbd) in 2010.

The drop in 2008 was fairly uniform across Russia’s major companies and regions. The chief exception to the production decline was Rosneft, the largest Russian producer, where output increased by 3.1% in 2008. Much of Rosneft’s jump in 2008 production was the effect of former Yukos assets in Tomsk and Samara it acquired in 2007. Rosneft has nevertheless also posted impressive organic growth, centered at its Yuganskneftegaz subsidiary (acquired in the 2004 Yukos bankruptcy auction), with production increasing by 8.7%. Nevertheless, Purneftegaz, Rosneft’s workhorse field prior to the Yukos auctions, registered a 9.6% drop in output in 2008, and its output also declined in 2009 and 2010.

In particular, production from Russia’s core West Siberian Basin declined for a second year in a row in 2008, to 332.8 mt (6.8 mbd) (see Table III-2). This trend has continued as well, with West Siberia posting a fourth year of decline in 2010, reaching 321.8 mt (6.6 mbd). What will be critical is whether any “new oil” projects have production sufficient to offset the gap from declining West Siberian output. Thus, the progress of a handful of major “new oil” projects will prove particularly critical to the rate of overall Russian oil production growth or decline in the near term. These include (in order of incremental growth in the first half of 2011 year on year) the currently producing Talakan, Verkhnechonskoye, Vankor, Sakhalin-1, and Uvat fields, as well as a few fields scheduled to come onstream over the next several years such as Prirazlomnoye (2012), Titov and Trebs (about 2013), Yurubcheno-Tokhomskoye (about 2014), and Filanovskoye (about 2015).

IHS CERA’s base case scenario envisions a slowly rising national production profile going forward from 2010. Several large, new projects are ramping up and should continue to offset declines in older fields in the near term. The issue for sustainability of a slow upturn is really longer term: Will the companies invest now to provide a stream of “new” oil several years in the future? We assume that changes will occur in Russian upstream taxation that include investment incentives in both the base and high scenarios. Russian output is projected to rise slowly through 2020 to reach 531.7 mt (10.8 mbd) in 2020 before declining to 518.0 mt (10.5 mbd) by 2030 (see Figure III-2).

IHS CERA has looked at the pattern of recent years and three major potential governing constraints on the oil companies’ investment and their contribution to the stagnation in Russian oil output: shortage of capital, shortage of upstream opportunities, and the challenge of rapidly changing conditions (the latter including surging costs as well as growing shortages of critical inputs and diminishing returns per unit of investment).




Tab

le II

I-1

His

tori

cal O

il B

alan

ce f

or

the

Rus

sian

Fed

erat

ion

(mill

ion

met

ric t

ons)

pct

. cha

nge

1990

19

91

1992

19

93

1994

19

95

1996

19

97

1998

19

99

2000

20

01

2002

20

03

2004

20

05

2006

20

07

2008

20

09

2010

20

09-2

010

cru

de

oil p

rod

uctio

n51

6.18

46

2.30

39

9.30

35

3.90

31

7.80

30

6.83

30

1.23

30

5.64

30

3.28

30

5.17

32

3.52

34

8.13

37

9.63

42

1.38

45

8.81

46

9.99

48

0.53

49

1.50

48

8.49

49

4.25

50

5.13

2.

20

Refi

nery

thr

ough

put

295.

50

286.

50

257.

20

220.

10

180.

60

179.

00

173.

80

176.

30

162.

92

170.

14

174.

13

178.

36

184.

96

189.

50

197.

16

207.

43

219.

58

228.

60

236.

30

235.

73

249.

95

6.03

D

irect

use

of c

rud

e/re

sid

ual1

10.5

0 20

.00

11.1

0 16

.70

15.0

2 12

.43

6.33

8.

60

9.66

6.

08

10.7

9 10

.25

12.5

2 14

.26

8.46

12

.52

14.8

3 7.

21

11.5

4 12

.91

9.57

(2

5.89

)

Refi

ned

pro

duc

ts c

onsu

mp

tion2

250.

60

228.

70

216.

47

176.

62

138.

73

137.

89

121.

25

121.

55

113.

25

120.

28

112.

64

107.

87

110.

08

111.

32

115.

76

110.

64

116.

32

117.

13

119.

54

112.

39

120.

01

6.78

oil

exp

orts

c

rud

e oi

l21

9.90

17

3.90

14

1.70

12

7.60

12

6.78

12

2.30

12

5.60

12

6.85

13

7.10

13

4.54

14

4.50

16

4.64

18

8.39

22

3.36

25

7.40

25

2.47

24

8.44

25

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23


Table III-2

Oil Production, Russian Federation: Base Scenario(million of metric tons [mt] per year)

east Siberia timan- West Volga- caspian RUSSiaand Sakhalin pechora1 Siberia Urals offshore other total

barrels per ton 7.45 7.37 7.45 7.15 7.75 7.30

(per metric ton)1990 2.0 15.8 375.7 112.9 9.8 516.21991 2.0 14.4 329.8 106.8 9.3 462.31992 1.8 12.7 278.9 97.5 8.4 399.31993 1.7 12.3 244.2 89.0 6.7 353.91994 1.8 10.0 219.4 81.7 4.9 317.81995 2.0 9.6 208.4 82.8 4.0 306.81996 1.9 10.4 203.4 81.5 4.0 301.21997 2.0 11.1 206.9 81.4 4.3 305.61998 2.0 11.4 203.9 81.5 4.5 303.31999 2.2 11.5 206.8 80.8 3.9 305.22000 3.9 12.7 220.4 82.6 4.0 323.62001 4.3 13.7 239.1 86.1 4.9 348.12002 3.8 14.7 265.1 90.5 5.5 379.62003 3.7 17.3 297.6 96.9 5.9 421.42004 4.1 20.8 327.4 101.0 6.0 459.32005 4.7 23.3 334.3 101.3 6.4 470.02006 6.8 24.6 338.6 103.5 7.0 480.52007 15.4 26.0 335.9 105.4 8.9 491.52008 13.9 27.6 332.8 106.7 7.5 488.52009 22.5 32.1 325.0 108.5 6.1 494.22010 34.4 31.0 321.8 114.6 0.1 3.3 505.12011 42.5 28.0 319.4 118.4 0.5 1.4 510.22012 47.4 29.7 317.9 116.4 1.0 1.3 513.82013 52.3 31.5 316.4 114.5 1.5 1.3 517.52014 57.2 33.2 315.0 112.5 2.0 1.2 521.12015 58.9 39.7 314.4 104.8 2.5 3.0 523.32016 62.2 40.5 313.5 102.7 3.1 3.0 525.02017 65.5 41.2 312.6 100.7 3.7 3.0 526.72018 68.7 42.0 311.8 98.6 4.3 2.9 528.32019 72.0 42.7 310.9 96.6 4.9 2.9 530.02020 75.3 43.5 310.0 94.5 5.5 2.9 531.72021 76.9 43.8 309.6 90.9 6.3 2.9 530.42022 78.6 44.1 309.2 87.3 7.1 2.9 529.12023 80.2 44.4 308.8 83.7 7.9 2.8 527.92024 81.9 44.7 308.4 80.1 8.7 2.8 526.62025 83.5 45.0 308.0 76.5 9.5 2.8 525.32026 84.5 45.6 306.8 73.7 10.7 2.6 523.82027 85.4 46.2 305.6 70.9 11.9 2.4 522.42028 86.4 46.8 304.4 68.0 13.1 2.2 520.92029 87.3 47.4 303.2 65.2 14.3 2.0 519.52030 88.3 48.0 302.0 62.4 15.5 1.8 518.0

Source: Reported historical production from Rosstat (Russian Statistical agency); projections by iHS ceRa. 1. includes offshore in the Barents Sea.




Broadly, we find that all three constraints have played some role, but capital constraints in conjunction with the challenge of changing conditions have emerged as increasingly important variables over time. Although as recently as 2004 a lack of attractive new fields appeared to be a greater constraint than lack of capital, by 2007 the situation had changed dramatically. Thanks to much higher oil prices by 2007, but also some significant new transportation possibilities (facilitating the marketing of oil from more remote fields), a wider range of new fields had become economic to develop. But despite higher profits and stagnating production, the oil companies are not rushing to develop them. One reason is that they are increasingly capital-constrained. In this environment, the program of tax holidays on the mineral resource extraction tax for specific regions, introduced by the government since 2007, has only a marginal impact on project economics (see the text box “Russian Government’s Tax Policies Threaten Future Oil Production Levels”).

How could the oil companies have become starved for capital when oil prices had tripled? The Russian oil companies over the past five to eight years have faced a dramatic deterioration in their operating environment, similar to that faced by international companies (much higher capital costs combined with a much higher tax take). Broadly, the pattern of behavior suggests that the Russian oil companies have resorted to near-term responses (primarily cutting costs and shortening decision-making horizons, together with mainly incremental innovation). Thanks to these efforts, they have been generally successful in containing lifting costs (which have remained surprisingly stable in the past few years), but they have not laid a strong basis for the next generation of production growth.

Although the state’s tax take is probably the greatest single constraint on the oil companies’ performance, other government policies have exacerbated the industry’s predicament, particularly by diverting the companies’ priorities away from significant remaining opportunities in established fields and regions, especially West Siberia. Since 2004, the government has pressed the oil companies to move to frontier areas, investing in projects with no ready infrastructure, and conservative policies pursued by state regulators have tended to discourage oil companies from seeking approval for new techniques in established producing areas.

West Siberia. West Siberia is the largest producing basin in Russia and will continue to be a dominant contributor to national supply going forward. The basin recently contained 23 giant producing fields as well as 8 of the country’s 10 largest producing fields. Further expansion in production probably can still occur as a result of investment in field maintenance and the development of smaller, more complex fields. Overall, moderate growth is expected from the various new projects in West Siberia. At the same time, investment in technology and reservoir management is helping to slow (or in some cases temporarily reverse) the decline rates of many mature fields.

Through 2004, much of the regional production growth came from the Khanty-Mansiysk Autonomous Okrug. This region forms the traditional core of the West Siberian oil industry, accounting for about 83% of the West Siberian total in 2010. But production in the Okrug was somewhat troubled during the recent economic crisis, falling by 2.5% in 2009 and by 1.7% in 2010.



25


Russian Government’s Tax Policies Threaten Future Oil Production levels

Russia’s tax relief provided to the oil industry beginning in 2007 through 2011 was essentially ad hoc, of short-term impact, and largely aimed at the problems of the moment (the financial crisis and oil price slump) rather than finding a sustainable balance between budgetary needs and the future development of the industry. these measures included

Raising the threshold price for the Mineral Resources Extraction Tax (MRET) on oil.• this went up from US$9 per barrel to US$15 per barrel (from January 1, 2009).

A variety of exemptions for various areas.• these include a 10-year exemption for holders of new production licenses and 15 years for holders of new combined exploration and production (e&p) licenses for frontier areas, including north of the arctic circle and continental shelf (but only the first 35 mt of oil production is eligible), while for the azov and caspian Seas the corresponding parameters are 10 mt and 7–12 years, and for the timan-pechora Basin and Yamal peninsula they are 15 mt and 7–12 years (from January 1, 2009),legislation approved in July 2011 establishes a zero MRet rate for Black Sea and Sea of okhotsk production for the first 20 mt and 30 mt, respectively.

A tax reduction.• the corporate profits tax rate was reduced from 24% to 20% (effective from January 1, 2009).

A special export duty regime for selected new fields in East Siberia and North Caspian.• this appears to be so quixotic that it probably has had little impact on sanctioning long-term upstream investment; the special export duty for crude oil was originally established as zero for 13 east Siberian fields in December 2009, with another 9 fields added to the list in January 2010; subsequently, in July 2010 the special export tax was changed from zero to a reduced tax at about half the usual rate: it is set at 45% of the difference between the export price and US$50 per barrel (effective from July 1, 2010); on January 1, 2011, two fields in the offshore North caucasus were added to the list of eligible fields; then, in May 2011 the three main east Siberian producing fields, Vankor, Verkhne-chonskoye, and talakan, were removed from the list of fields eligible for the reduced export tax; six additional east Siberian fields were dropped from the list eligible for this preferential rate (on august 1, 2011).

But in addition to these “temporary” measures, the Russian government also developed a more comprehensive anticrisis plan for the oil industry. as a result of an intensive, two-year long detailed examination of the finances and economics of the various industry segments, the government recognizes that the tax burden has become too heavy, partly because of rising costs; most new upstream “greenfield” projects are uneconomic under the current regime, and nearly a third of the oil from existing fields is produced at a loss. the centerpiece of the plan consists of tax changes intended to support oil production longer term, including an across-the-board reduction in the export duty rate on crude oil and introduction of a profits-based upstream tax for new oil fields instead of MRet. the uniform export duty would supplant the special export tax exemptions and the various mineral extraction tax holidays for new oil provinces.

a slight change in the refined product export tax system took effect in February 2011, pending a broader tax reform that is slated to begin in the fall of 2011. the changes introduced in February 2011 called for gradually closing the gap between rates for heavy and light products over three years. From February, rates were set at 67% and 46.7% of the crude export duty applied to light and heavy oil products, respectively, but on october 1, 2011, as part of “60-66”, this was changed to a uniform rate of 66%.




Russian Government’s Tax Policies Threaten Future Oil Production levels (continued)

the relevant Russian ministries continue to debate the final parameters of the new export tax rates as well as the implementation schedule for both crude and products. the first part of the reform plan, implementing the so-called 60-66 regime, went into effect on october 1, 2011. it dropped the marginal export tax on crude oil from the current 65% to 60% (on the difference between the oil price and $25per barrel) while applying a unified light and heavy products export tax at 66% of the crude tax (the 2010 average was 73% for light products and 38% for heavy products). However, the reduction of the marginal export tax rate to 60% is currently subject to a monthly review and sign-off by the prime minister. the timing of the implementation of the second part of the reform, to use a profits-based tax for new oil fields instead of MRet, remains uncertain, but it will not occur until 2012 at the earliest.

the lower export duty for crude oil raises upstream profitability by reducing the tax take on crude exports and by effectively increasing domestic prices on crude oil (because of the higher level of export parity), squeezing refiners on the cost side. it also makes product exports more costly under the unification in product duties, which will tend to substantially curtail products exports. on balance, while oil prices are below US$90 per barrel (US$657 per ton), this regime will keep the government budget whole, while transferring value from the downstream to the upstream.

this transitional export tax regime could have a significant impact on the volume and pattern of Russian oil exports:

A smaller refined product export stream.• Shrinking refining margins under the new tax regime will probably cause discretionary product exports to fall from the current 40–45 mt per year (0.8–0.9 mbd) to around 15–20 mt per year (0.3–0.4 mbd).

lightening the average refined product export barrel• . the new unified refined product export duty will chiefly undermine the profitability of heavy products exports (fuel oil and vacuum gas-oil [VGo]). those volumes will not drop instantly; some oil companies will choose to invest in refinery modernization to transform heavy residuals into light products instead of slashing refinery throughput.

Redirection of oil from Russian refineries to crude export markets• . as a result of the likely reduction in refining activity, some 15–20 mt per year (0.3–0.4 mbd) of oil will probably be redirected from Russian refineries to crude oil export markets.

the tax regime’s impact will, of course, greatly depend on global crude oil price trends. the measures implemented on october 1 will have a more profound effect on the Russian economy and the refining sector with a world oil price in the range of US$90–$100 per barrel (US$657–$730 per ton) over the medium term. if the oil price exceeds US$110 per barrel (US$803 per ton), then a modification, referred to as “55-86” (crude export duty reduced to 55% with a unified rate for products set at 86% of the crude export duty rate) may be applied.

However, these tax changes still do not provide sufficient incentives to bring onstream major new projects on the scale of the big-ticket greenfield ventures that have proved crucial to the stabilization of output in 2009–11. For this reason, a separate profits-based tax system is proposed for new projects, but the timing of its introduction remains uncertain.

even assuming a more usual decline rate at mature basins, the next generation of new fields must be sanctioned soon to avoid a relatively sharp decline in overall Russian oil output post-2015, as the current set of new fields reaches plateau. iHS ceRa’s base and high Russian oil production scenarios assume sufficient additional oil tax reforms by the Russian government to stimulate necessary investment in new production capacity. We assume



27


Two projects, Samotlor and Salym, illustrate the diverse trends at work. Samotlor, the largest field within West Siberia and Russia overall, continues to be a sizable producer in the Okrug even though it is well past its prime. Using modern technology, TNK-BP plans to stabilize Samotlor’s production at around 0.7 mbd (35 mt per year) over the next 20 years. An example of new field development is Salym. Production at the Salym group of fields (Zapadnoye Salymskoye, Verkhne-Salymskoye, and Vadelypskoye), under the leadership of Shell, was launched only in 2006. In 2010 production rose from the Salym group of fields (Zapadnoye Salymskoye, Verkhne-Salymskoye, and Vadelypskoye) in West Siberia to over 8.3 mt (165,300 bd). The project’s planned plateau production of 120,000 bd was easily surpassed in 2009.

The Yamal-Nenets Okrug lies to the north of Khanty-Mansiysk and was a fast-growing region for liquids production until 2005. Yamal-Nenets is heavily gas prone (accounting for nearly 90% of Russian natural gas production). Therefore, much of its liquid output is condensate instead of crude oil. In 2007 its liquids production was down by 9.9%, mainly because of warm winter weather at the beginning of the year that led to reduced gas production and therefore lower condensate output. But since then, other problems have emerged, mainly in the traditional oil-producing subsidiaries of Rosneft and Gazprom Neft located in the Okrug. Therefore, liquids output in the Okrug has continued to slide: output declined by 4.6% in 2008, 5.0% in 2009, and 11.4% in 2010.

From a 2010 production of 321.8 mt (6.6 mbd), in the base scenario, we project that West Siberian output will continue to slowly decline over the outlook period, to 302.0 mt (6.16 mbd) in 2030 (i.e., at an average annual rate of 0.3%) (see Figure III-3). This occurs as production from new fields in West Siberia (and from advanced recovery in old fields) falls short of making up for the decline of older fields. In IHS CERA’s high scenario, in contrast, steady growth in West Siberian production through 2030 is envisioned (albeit at a slowing

Russian Government’s Tax Policies Threaten Future Oil Production levels (continued)

that the changes would include a reduction in the overall level of the export tax (vis-à-vis international prices) combined with upstream taxes more sensitive to profitability, such as a windfall profits tax or a more flexible MRet. But it should be emphasized that plans for additional reforms outlined to date do not go far enough to ensure a production growth trajectory over the longer term.

Unfortunately, the improved financial outlook for the industry recently—following the partial rebound of world oil prices along with a partial ruble devaluation dividend (and corresponding reduction of upstream costs)—could close the window of opportunity for comprehensive Russian oil sector tax reform. of particular concern is the emphasis of state policies on “new” oil while the need for incentivizing production at the brownfields (concentrated primarily in West Siberia’s Khanty-Mansiysk okrug) has been put on the back burner, even though enhanced recovery at the brownfields probably gives more incremental oil per dollar invested than greenfield operations. From the state’s point of view, efforts to administer tax cuts at existing fields may open a pandora’s box of issues related to ringfencing and tax base manipulation. instead of dealing with the complexities of “old oil,” the government seems to be intent on moving in what it perceives to be the more straightforward direction of granting tax exemptions to specific “new oil” fields or development areas.




rate), to reach 340 mt (6.94 mbd) in 2025 before declining to 335 mt in 2030 (6.84 mbd) (see Table III-3). The low scenario also envisions a decline in regional output like the base case, but at a higher pace. Thus, West Siberian production is projected to decline to 250.2 mt (5.34 mbd) in 2030 (see Table III-4).

Volga-Urals. Current production in the region hovers around 2 mbd, which is considerably lower than the peak production of 4.5 mbd achieved in 1976. However, with its mature infrastructure, this basin has relatively low associated costs of development. Smaller fields can thus be developed quickly and brought onstream economically. It is the output from these fields and the giant Romashkinskoye (Romashkino) field in Tatarstan (with a production rate of about 380,000 bd) that has kept regional production relatively stable in recent years. However, Romashkino is quite mature—around 83% depleted—and production is declining at a rate of about 2% per year. Thus, most of the production from this field, and from the Volga-Urals Basin in general, is now achieved as a result of the application of enhanced recovery and reservoir diagnostics.

This older province is assumed in all scenarios to be close to reaching a (secondary) maximum, followed by a gradual decline. But each year, we end up being surprised, as output has tended to tip upward. From 2010 output of 114.6 mt (2.25 mbd) in the base scenario, regional production begins a slow decline, taking regional output down to 94.5 mt (1.85 mbd) in 2020 and 62.4 mt (1.22 mbd) in 2030. In the high scenario, an even more gradual decline is assumed, with output declining to 88.2 mt (1.73 mbd) by 2020 and 55.5

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29


Table III-3

Oil Production, Russian Federation: High Scenario(million metric tons [mt] per year)


barrels per ton 7.45 7.37 7.45 7.15 7.75 7.30

(per metric ton)1990 2.0 15.8 375.7 112.9 9.8 516.21991 2.0 14.4 329.8 106.8 9.3 462.31992 1.8 12.7 278.9 97.5 8.4 399.31993 1.7 12.3 244.2 89.0 6.7 353.91994 1.8 10.0 219.4 81.7 4.9 317.81995 2.0 9.6 208.4 82.8 4.0 306.81996 1.9 10.4 203.4 81.5 4.0 301.21997 2.0 11.1 206.9 81.4 4.3 305.61998 2.0 11.4 203.9 81.5 4.5 303.31999 2.2 11.5 206.8 80.8 3.9 305.22000 3.9 12.7 220.4 82.6 4.0 323.62001 4.3 13.7 239.1 86.1 4.9 348.12002 3.8 14.7 265.1 90.5 5.5 379.62003 3.7 17.3 297.6 96.9 5.9 421.42004 4.1 20.8 327.4 101.0 6.0 459.32005 4.7 23.3 334.3 101.3 6.4 470.02006 6.8 24.6 338.6 103.5 7.0 480.52007 15.4 26.0 335.9 105.4 8.9 491.52008 13.9 27.6 332.8 106.7 7.5 488.52009 22.5 32.1 325.2 108.5 5.9 494.22010 34.4 31.0 321.8 114.6 0.1 3.3 505.12011 42.5 28.0 319.4 118.4 0.5 1.4 510.22012 49.6 30.0 320.0 116.2 2.3 1.8 520.02013 56.8 32.0 320.7 114.0 4.1 2.3 529.82014 63.9 34.0 321.3 111.7 5.9 2.7 539.62015 70.1 41.0 325.0 103.5 9.0 5.5 554.12016 72.5 43.0 327.0 100.4 10.8 5.4 559.22017 74.9 45.0 329.0 97.4 12.6 5.3 564.22018 77.4 47.0 331.0 94.3 14.4 5.2 569.32019 79.8 49.0 333.0 91.3 16.2 5.1 574.32020 82.2 51.0 335.0 88.2 18.0 5.0 579.42021 84.5 51.2 336.0 85.1 18.4 4.9 580.02022 86.7 51.4 337.0 81.9 18.8 4.8 580.62023 89.0 51.6 338.0 78.8 19.2 4.7 581.32024 91.2 51.8 339.0 75.6 19.6 4.6 581.92025 93.5 52.0 340.0 72.5 20.0 4.5 582.52026 95.8 52.6 339.0 69.1 21.0 4.4 581.92027 98.1 53.2 338.0 65.7 22.0 4.3 581.32028 100.4 53.8 337.0 62.3 23.0 4.2 580.72029 102.7 54.4 336.0 58.9 24.0 4.1 580.12030 105.0 55.0 335.0 55.5 25.0 4.0 579.5





Table III-4

Oil Production, Russian Federation: low Scenario(million of metric tons [mt] per year)


barrels per ton 7.45 7.37 7.45 7.15 7.75 7.30

(per metric ton)1990 2.0 15.8 375.7 112.9 9.8 516.21991 2.0 14.4 329.8 106.8 9.3 462.31992 1.8 12.7 278.9 97.5 8.4 399.31993 1.7 12.3 244.2 89.0 6.7 353.91994 1.8 10.0 219.4 81.7 4.9 317.81995 2.0 9.6 208.4 82.8 4.0 306.81996 1.9 10.4 203.4 81.5 4.0 301.21997 2.0 11.1 206.9 81.4 4.3 305.61998 2.0 11.4 203.9 81.5 4.5 303.31999 2.2 11.5 206.8 80.8 3.9 305.22000 3.9 12.7 220.4 82.6 4.0 323.62001 4.3 13.7 239.1 86.1 4.9 348.12002 3.8 14.7 265.1 90.5 5.5 379.62003 3.7 17.3 297.6 96.9 5.9 421.42004 4.1 20.8 327.4 101.0 6.0 459.32005 4.7 23.3 334.3 101.3 6.4 470.02006 6.8 24.6 338.6 103.5 7.0 480.52007 15.4 26.0 335.9 105.4 8.9 491.52008 13.9 27.6 332.8 106.7 7.5 488.52009 22.5 32.1 325.2 108.5 5.9 494.22010 34.4 31.0 321.8 114.6 0.1 3.3 505.12011 42.5 28.0 319.4 118.4 0.5 1.4 510.22012 44.1 27.6 317.4 113.6 0.9 1.5 505.22013 45.7 27.2 315.5 108.8 1.4 1.7 500.22014 47.4 26.8 313.5 103.9 1.8 1.8 495.22015 42.5 29.0 312.0 90.5 2.3 3.9 480.22016 42.9 28.8 309.6 83.8 2.5 3.6 471.32017 43.3 28.6 307.2 77.1 2.8 3.3 462.32018 43.7 28.4 304.8 70.4 3.0 3.1 453.42019 44.1 28.2 302.4 63.7 3.3 2.8 444.42020 44.5 28.0 300.0 57.0 3.5 2.5 435.52021 44.9 28.8 296.0 54.6 4.4 2.4 431.12022 45.3 29.6 292.1 52.2 5.3 2.3 426.82023 45.7 30.4 288.1 49.8 6.2 2.2 422.42024 46.1 31.2 284.2 47.4 7.1 2.1 418.12025 46.5 32.0 280.2 45.0 8.0 2.0 413.72026 46.9 33.2 276.5 43.8 8.4 1.9 410.72027 47.3 34.4 272.7 42.6 8.8 1.8 407.62028 47.7 35.6 269.0 41.4 9.2 1.7 404.62029 48.1 36.8 265.2 40.2 9.6 1.6 401.52030 48.5 38.0 261.5 39.0 10.0 1.5 398.5




31


mt (1.1 mbd) by 2030. The low scenario envisages regional output falling more rapidly, at least initially, to 57.0 mt (1.16 mbd) by 2020 and 39.0 mt (0.8 mbd) by 2030.

Russian offshore Caspian. Reflecting the usual unknowns surrounding the development of a new oil province, considerable uncertainty is attached to estimates of future production from the Russian sector of the northern Caspian Sea. However, LUKOIL’s statements that its discoveries contain more gas than liquids have led IHS CERA to remain generally conservative in its outlook for liquids production, notwithstanding LUKOIL’s announcement of two large, new oil discoveries in 2005.

Production began at LUKOIL’s Korchagin field in the Russian sector of the Caspian in April 2010, with the first oil shipment from the offshore platform occurring in October 2010. The oil is evacuated by tanker to Makhachkala, where it is injected into the Transneft pipeline system and exported via Novorossiysk. Korchagin is the first of six offshore Caspian fields that LUKOIL eventually intends to bring onstream (the others are Filanovskoye, Khvalynskoye, Sarmatskoye, 170-kilometer, and Rakushechnoye). But the combination of the global economic recession in 2009 as well as uncertainties about the tax treatment for this offshore area caused LUKOIL to slow the development program.*

Currently, LUKOIL has sanctioned only one other offshore field development project, Filanovskoye, and now expects it to yield its first output only in 2015 after several tax breaks available to new field developments in East Siberia were extended to the North Caspian fields at the end of 2010. Earlier, LUKOIL had optimistically projected that output from a combination of several of these fields would yield up to 13 mt per year (around 280,000 bd) in 2015.

In IHS CERA’s base case scenario, production from the Russian sector of the Caspian reaches only 5.5 mt (117,000 bd) by 2020 and 15.5 mt (329,000 bd) in 2030. The high scenario envisions a more rapid ramp-up, reaching 18 mt (382,000 bd) in 2020 and 25 mt (531,000) in 2030. In the low scenario, Caspian offshore production reaches only 10 mt (212,000 bd) by 2030.

Perhaps the main challenge confronting LUKOIL in the north Caspian is monetizing the gas that would be produced along with the liquids. The company announced a major change in plans in 2009 for the location of the gas treatment plant. Initially planned for Kalmykia, where the gas would come ashore, it will now be built in Budennovsk, in Stavropol Kray, where LUKOIL already has a large petrochemical operation. As before, the dry gas stream from the plant would be injected into the Gazprom pipeline and sold to power plants belonging to TGK-8 (owned by LUKOIL), and the stream of light hydrocarbon fractions would go to LUKOIL’s neighboring petrochemical facility.

East Siberia and Sakhalin. IHS CERA’s base scenario projects production from these eastern regions growing steadily going forward after actually dropping in 2008. The 2008 decline was due to the lower output of Sakhalin-1 that was not offset by any new projects. But in 2009–10 a number of new projects were ramping up, including Sakhalin-2 as it changed

*At the end of 2010 the government finally agreed to impose the same special reduced export duty applied to East Siberian fields on oil production from the Korchagin and Filanovskoye fields as well as a zero mineral extraction tax.




over to year-round production operations, and Sakhalin-1 production has rebounded since the launch of the Odoptu field in September 2010. Output is projected to rise in the base case from 34.4 mt (702,000 bd) in 2010, reaching 75.3 mt (1.54 mbd) in 2020, and 88.3 mt (1.8 mbd) by 2030. These levels are achieved in the base scenario as both Sakhalin offshore development proceeds apace and inland East Siberian production expands at several key fields (e.g., Vankor, Talakan, and Verkhne-Chonskoye).

The low scenario for the region envisions output rising to 44.5 mt (908,000 bd) by 2020 and 48.5 mt (990,000 bd) in 2030. This relative stagnation is due to the failure of other new fields to be discovered and brought onstream to backfill those already producing as they reach maximum and decline.

In IHS CERA’s high scenario regional output is 82.2 mt (1.68 mbd) in 2020 and an astounding 105.0 mt (2.14 mbd) in 2030. In particular, Sakhalin production is assumed by 2020 to include production from perhaps as many as a half dozen offshore projects, but this is clearly dependent on some type of tax changes (such as a decision to proceed with new production-sharing agreements [PSAs]) to stir additional offshore development.

Timan-Pechora. The Timan-Pechora Basin in northern European Russia spans the broad borderland between the Komi republic and Nenets Autonomous Okrug along the Arctic Circle. Oil development has generally extended from the south, from the Komi republic, toward the north, into the newer fields of Nenets Okrug. The production contribution of the Nenets fields finally exceeded those of the Komi republic in 2004; the basin’s output in 2010 comprised 13.1 mt (265,000 bd) from the Komi republic and 17.9 mt (361,000 bd) in Nenets Okrug.

Production from this northern producing area had been steadily rising since the late 1990s from the general recovery of the Russian oil industry. Similar to the overall Russian trend, this reflected a combination of rebounding output in older, existing fields through the application of new approaches and technologies, as well as the contributions from a handful of new fields. But output in the basin declined in 2010 and is on pace to do so again in 2011. The recent decline is largely due to the unexpected failure of production at the South Khylchuyu field, one of the major new developments of recent years (it has been developed as a joint venture (JV) between LUKOIL and ConocoPhillips) to remain at plateau; instead, it has declined quite precipitously. However, output also contracted elsewhere as well in 2010, particularly in the older Komi fields.

In IHS CERA’s base scenario, production in Timan-Pechora rebounds and slowly rises over the outlook period, reaching 43.5 mt (878,000 bd) in 2020 and 48.0 mt (969,000 bd) in 2030, mainly as several new projects come onstream that more than offset declines at older fields, including Prirazlomnoye (the first offshore field to be developed in the Pechora Sea) and the new Titov and Trebs fields. The low scenario projects a continued decline in the medium term before turning around. It assumes that the new projects are delayed, and so do not offset the decline in existing fields for about a decade. Output falls to 28 mt (572,000 bd) in 2020 before rising to 38 mt (776,000 bd) in 2030. In the high scenario, oil production rebounds more quickly than in the base case, rising to 51 mt (1.0 mbd) in 2020 and 55 mt (1.11 mbd) in 2030.



33


3.1.3 Oil Production in Kazakhstan

Kazakhstan’s oil production has continued to ramp up, with output in 2010 reaching 79.7 mt (1.67 mbd), up by 4.2% from 2009 (see Table III-5). Kazakhstan’s crude production has more than doubled since 2000. Under all three scenarios, its oil production is projected to increase substantially over the outlook horizon to 2030 (see Figure III-4).

Under the base case, Kazakh oil production rises steadily to 110.1 mt (2.33 mbd) in 2020 and 153.3 mt (3.25 mbd) by 2030. In the low case, output reaches 103.5 mt (2.19 mbd) by 2030, while in the high case national output reaches 194.2 mt (3.91 mbd) in 2030. The principal Kazakh developments driving this are three mega projects: Tengiz, Karachaganak, and Kashagan. But it must be recognized that besides these three big projects, Kazakhstan’s oil development also is being driven by a host of smaller projects. In 2010 the smaller projects provided 42.4 mt (848,000 bd), or nearly 47%, of national output. However, their share is expected to decline to about 34% by 2030.

Tengiz. The mid-2008 completion by the JV developing the giant Tengiz field, TengizChevrOil (TCO), of the Sour Gas Injection and Second Generation Plant (SGI/SGP) projects has nearly doubled the production capacity at Tengiz to over 550,000 bd. Production rose from 17.3 mt (376,000 bd) in 2008 to 22.5 mt (491,000 bd) in 2009 and hit 25.9 mt (564,000 bd) in 2010.

Under the base scenario, TCO production continues to ramp up beyond 2010, expanding to reach 36.4 mt (793,000 bd) in 2020 and 42.0 mt (915,000 bd) in 2025 (see Table III-6). This is due to the so-called “FGP” (Future Growth Project), which is slated to add another 12 mt per year (260,000 bd) to the overall production capacity of the field. We project a decline in output after 2025, falling to 28.0 mt (610,000 bd) by 2030. In our view TCO production therefore does not exceed a reasonable P50 production outlook.

In the high (P90) scenario, TCO production pushes further toward a higher maximum, to 45.0 mt (980,000 bd) in 2025, followed by a decline to 38 mt (773,000 bd) by 2030 (see Table III-7). The low scenario projects TCO production rising to a maximum of 35.0 mt (762,000 bd) in 2025 before declining to 30.0 mt (653,000 bd) in 2030 (see Table III-8). In our view, TCO production therefore does not exceed a reasonable P50 production outlook.

Karachaganak. Karachaganak’s production basically held flat in 2007–10, with a (gross) output of 11.4–11.9 mt (260,000–271,000 bd). But good progress has been made installing Karachaganak’s fourth stabilization train (part of the project’s second phase of expansion), which took the project’s export capacity to international markets to 10.3 mt (235,000 bd) of liquids with the train’s completion. The partners developing the project decided to postpone launch of the project’s third stage, however, which was originally slated to be completed by the end of 2012. The third stage would lift production capacity up to 16.5 mt per year (377,000 bd) of liquids and 16 billion cubic meters (Bcm) per year of gas.

The Karachaganak field follows what we are taking to be a reasonable production profile in the base scenario, although reaching a higher output level with the sanctioning of a third phase of investment that entails drilling 120 additional wells, expanding rail export facilities, and using enhanced gas injection. Output rises to a plateau of about 16.5 mt (377,000 bd)




Tab

le II

I-5

His

tori

cal O

il B

alan

ce f

or

Kaz

akhs

tan

(mill

ion

met

ric t

ons)

p

ct. c

hang

e19

92

1993

19

94

1995

19

96

1997

19

98

1999

20

00

2001

20

02

2003

20

04

2005

20

06

2007

20

08

2009

20

10

2009

-201

0c

rud

e oi

l pro

duc

tion

25.8

0 23

.00

20.3

0 20

.60

23.0

0 25

.74

25.9

5 30

.13

35.3

2 40

.09

47.2

4 51

.28

59.1

7 61

.92

64.8

6 67

.13

70.6

2 76

.48

79.6

9 4.

19

ap

par

ent

dom

estic

cru

de

cons

ump

tion

17.0

0 13

.60

15.1

4 11

.40

11.3

8 10

.85

8.80

6.

43

6.98

10

.03

10.6

0 9.

63

10.0

0 13

.24

13.7

5 14

.03

14.4

6 14

.06

19.6

5 39

.78

Refi

nery

thr

ough

put

16.9

0 14

.80

11.7

7 10

.85

11.1

3 9.

19

8.60

5.

98

6.37

7.

61

7.80

8.

77

9.39

11

.15

11.6

6 12

.04

13.3

9 11

.67

13.6

8 17

.23

Dire

ct u

se o

f cru

de/

unid

entifi

ed*

0.10

(1

.20)

3.37

0.

55

0.26

1.

66

0.20

0.

45

0.61

2.

42

2.79

0.

86

0.61

2.

08

2.09

1.

99

1.07

2.

39

5.97

15

0.04

cru

de

oil e

xpor

ts20

.30

17.9

0 9.

86

12.6

0 14

.92

16.4

8 19

.42

24.4

8 29

.35

32.4

0 39

.27

44.3

4 52

.41

52.4

1 56

.81

60.8

0 62

.82

67.2

6 67

.47

0.30

o

utsi

de

the

Form

er S

ovie

t U

nion

6.50

6.

20

4.10

3.

70

6.61

6.

90

9.82

17

.28

21.3

0 23

.32

30.4

5 35

.19

47.1

0 49

.70

54.4

4 57

.97

59.8

8 64

.81

65.7

6 1.

47

v

ia R

ussi

an p

ipel

ine

syst

em (n

on-M

akha

chka

la)

6.50

6.

20

4.10

3.

70

6.01

4.

14

3.98

8.

07

10.6

4 11

.39

11.8

7 14

.20

15.6

0 14

.81

15.4

5 16

.05

16.2

8 22

.55

15.5

1 (3

1.22

)

via

cas

pia

n p

ipel

ine

con

sort

ium

--

--

--

--

--

--

--

--

--

1.80

12

.00

13.8

1 22

.37

28.2

3 24

.36

25.9

0 25

.84

27.6

3 27

.52

(0.3

7)

via

ata

su-a

lash

anko

u p

ipel

ine

--

--

--

--

--

--

--

--

--

--

--

--

--

--

2.16

4.

77

4.98

6.

20

9.06

46

.10

v

ia r

ailro

ad0.

60

1.90

3.

74

6.96

7.

24

5.10

3.

65

1.49

1.

23

1.21

2.

87

2.36

3.

72

4.12

5.

67

37.6

4

v

ia R

ussi

an r

ailro

ad (t

o Fi

nlan

d, e

tc.)

--

n

eg.

n

eg.

n

eg.

0.60

1.

90

3.64

6.

60

6.44

4.

10

2.79

0.

67

0.42

0.

42

1.36

1.

52

2.88

3.

28

5.67

72

.87

via

Kaz

akh

railr

oad

to

chi

na

-

-

-

-

-

-

-

-

-

-

-

-0.

10

0.36

0.

80

1.00

0.

86

0.82

0.

81

0.80

1.

51

0.84

0.

84

0.84

0.

00

(100

.00)

v

ia c

asp

ian

--

--

--

--

0.08

0.

93

2.20

2.

26

3.42

5.

04

5.47

5.

98

7.50

8.

11

9.59

8.

89

9.07

9.

27

9.32

0.

50

thr

ough

aze

rbai

jan/

Geo

rgia

--

--

--

--

0.08

0.

86

2.20

2.

26

2.45

2.

75

2.09

3.

57

3.40

0.

90

4.15

1.

70

2.57

2.

20

5.20

13

6.14

t

o B

tc0.

29

1.90

0.

00

(100

.00)

to

iran

(inc

lud

ing

dire

ct s

hip

men

ts b

y ra

il)

-

-

-

-

-

-

-

-

-

-0.

06

--

--

--

--

0.50

1.

25

1.90

1.

40

2.08

2.

90

1.70

0.

96

0.50

(4

7.77

)

t

o N

ovor

ossi

ysk

(via

Mak

hach

kala

)

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-0.

97

2.28

2.

88

3.00

2.

21

3.97

3.

36

4.29

4.

80

2.70

3.

62

34.1

5 F

orm

er S

ovie

t re

pub

lics

13.7

8 11

.70

5.76

8.

90

8.31

9.

58

9.60

7.

20

8.04

9.

08

8.83

9.

15

5.31

2.

70

2.37

2.

83

2.94

2.

45

1.71

(3

0.45

)

Rus

sia

10.7

0 10

.30

4.59

6.

86

4.50

6.

07

6.40

5.

60

6.12

5.

34

7.19

7.

55

4.21

2.

58

2.37

2.

69

2.53

1.

78

1.25

(3

0.16

)

v

ia K

arac

haga

nak-

ore

nbur

g p

ipel

ine

3.80

3.

50

1.70

2.

50

1.90

2.

30

2.10

3.

30

4.60

3.

40

4.50

4.

80

4.10

2.

62

2.37

2.

65

2.53

1.

78

1.25

(3

0.16

)

cru

de

oil i

mp

orts

11.5

0 8.

50

4.70

3.

40

3.30

1.

59

2.27

0.

78

1.01

2.

34

2.63

2.

69

3.25

3.

72

5.69

7.

70

6.66

4.

84

7.43

53

.63

out

sid

e th

e Fo

rmer

Sov

iet

Uni

on

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

- F

orm

er S

ovie

t re

pub

lics

11.5

0 8.

50

4.70

3.

40

3.30

1.

59

2.27

0.

78

1.01

2.

34

2.63

2.

69

3.25

3.

72

5.69

7.

70

6.03

4.

84

7.43

53

.63

R

ussi

a11

.50

8.50

4.

40

3.40

3.

20

1.58

2.

26

0.76

0.

94

2.34

2.

63

2.69

3.

15

3.72

5.

57

6.71

7.

07

6.34

7.

43

17.2

9

to

Kaz

akhs

tan-

chi

na p

ipel

ine

1.04

1.

50

2.60

73

.45

Del

iver

ies

of K

azak

h oi

l to

refin

erie

s5.

40

6.30

7.

07

7.45

7.

83

7.60

6.

33

5.20

5.

36

5.27

5.

17

6.07

6.

14

7.43

5.

97

4.34

7.

77

6.83

6.

25

(8.5

5)

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

and

exp

orts

from

Kaz

akhs

tan'

s S

tatis

tical

age

ncy,

sup

ple

men

ted

with

dat

a on

sp

ecifi

c ex

por

t ro

utes

from

Min

istr

y of

ene

rgy

(info

tek,

etc

.) 1.

Bal

anci

ng it

em.



35


in 2020–25 and then declines slowly thereafter. In the high scenario, the third phase is completed by 2015, with a higher peak production of 17.0 mt (388,000 bd) in 2020–25. A further (fourth) expansion phase of the project is being considered, so there is a possibility of upward revisions, especially in the high scenario. In the low scenario, the third phase is never implemented, so maximum production declines from current levels going forward. It should be pointed out that Karachaganak condensate loses approximately 18–19% of its volume in the process of stabilization undertaken at the field (or at Russia’s Orenburg gas processing plant).* This significantly reduces the volumes available to flow into pipelines or other export systems (hence, a separate column is included, showing stabilized liquids production).

Kashagan. Kashagan’s development plan is now experiencing another delay. First oil is expected from the offshore Kashagan field late in 2013 (some official Kazakh commentators still say in 2012, but some company sources say that this will slip into 2014). IHS CERA’s base case outlook estimates production of approximately 14.2 mt (302,000 bd) from the first phase of the project in 2015. However, output is expected to subsequently rise from first phase facilities (with additional investment) to about 21.2 mt (450,000 bd). But implementation of the second phase of the project (designed to yield about 600,000–800,000 bd) has been postponed to 2018–19. Therefore, after 2015 in the base case, production builds to 19.5 mt (414,000 bd) in 2020, 38.5 mt (817,000 bd) in 2025, and reaches 58 mt (1.23 mbd) in 2030 (see Figure III-5). In the high case, the buildup is somewhat more rapid and brings

*The stabilization that occurs outside Kazakhstan is excluded from the stabilized volumes shown.

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Tab

le II

I-6

Oil

Pro

duc

tio

n, K

azak

hsta

n: B

ase

Sce

nari

o(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

Kar

acha

gana

k

teng

izK

arac

haga

nak

(as

pro

duc

ed)

Kar

acha

gana

k (s

tab

ilize

d o

utp

ut)1

(am

t st

abili

zed

with

in

Kaz

akhs

tan)

turg

ayB

asin

2

akt

obe

ob

last

oth

er(J

Vs,

etc

.)W

est

Kaz

akhs

tan

Kas

haga

nN

ewo

ffsho

reK

aZ

aK

HS

taN

tota

lb

arre

ls

per

ton

7.95

8.33

7.86

7.70

7.70

7.00

6.95

7.75

7.75

(per

met

ric t

on)

1990

0.0

4.0

0.0

0.5

2.6

0.0

19.1

25.8

1991

0.0

4.5

0.0

1.2

2.8

0.0

18.3

26.6

1992

0.0

3.8

0.0

1.3

2.7

0.2

17.7

25.8

1993

0.9

3.5

0.0

1.7

2.6

0.2

14.2

23.0

1994

1.9

1.7

0.0

1.8

2.7

0.2

11.9

20.3

1995

2.5

2.5

0.0

1.3

2.6

0.3

10.7

20.6

1996

5.0

1.9

0.0

2.5

2.5

0.3

10.7

23.0

1997

6.9

2.3

0.0

2.6

2.6

0.4

10.8

25.7

1998

8.5

2.1

0.0

2.9

2.6

0.6

9.2

25.9

1999

9.6

3.4

0.0

3.6

2.3

0.9

10.4

30.0

2000

10.5

4.6

0.0

5.3

2.7

1.1

11.0

35.3

2001

12.5

4.0

0.5

6.2

3.4

1.6

12.5

40.0

2002

13.2

5.2

0.6

8.4

4.6

2.1

14.1

47.3

2003

12.7

5.9

1.0

9.9

5.6

2.2

15.1

51.5

2004

13.7

8.5

3.8

10.7

7.2

2.5

17.0

59.5

2005

13.6

10.3

6.7

9.0

8.0

3.1

18.0

61.9

2006

13.3

10.4

7.0

11.7

7.8

2.7

19.0

64.9

2007

13.9

11.6

7.8

11.7

7.6

3.6

18.8

67.2

2008

17.3

11.6

7.9

11.3

6.9

4.9

18.6

70.6

2009

22.5

11.9

8.8

11.2

7.2

5.2

18.5

76.5

2010

25.9

11.4

8.9

11.0

7.3

5.6

18.4

79.7

2011

26.5

12.2

9.8

10.9

7.8

6.8

17.8

82.0

2012

27.1

12.4

10.0

10.5

7.8

7.4

17.0

0.0

82.2

2013

27.7

12.6

10.3

10.1

7.9

7.9

16.1

0.1

82.5



37


Kar

acha

gana

k

teng

izK

arac

haga

nak

(as

pro

duc

ed)

Kar

acha

gana

k (s

tab

ilize

d o

utp

ut)1

(am

t st

abili

zed

with

in

Kaz

akhs

tan)

turg

ayB

asin

2

akt

obe

ob

last

oth

er(J

Vs,

etc

.)W

est

Kaz

akhs

tan

Kas

haga

nN

ewo

ffsho

reK

aZ

aK

HS

taN

tota

l20

1428

.412

.910

.59.

77.

98.

515

.36.

589

.120

1529

.012

.510

.19.

07.

58.

514

.214

.20.

094

.920

1630

.513

.310

.88.

97.

48.

913

.714

.30.

097

.020

1732

.014

.111

.58.

87.

29.

313

.314

.50.

099

.220

1833

.414

.912

.28.

77.

19.

712

.814

.60.

010

1.2

2019

34.9

15.7

12.9

8.6

6.9

10.1

12.4

18.0

0.0

106.

620

2036

.416

.513

.68.

56.

810

.511

.919

.50.

011

0.1

2021

37.5

16.5

13.5

8.4

6.7

10.7

11.6

23.3

1.6

116.

320

2238

.616

.413

.58.

36.

710

.911

.327

.13.

212

2.6

2023

39.8

16.4

13.5

8.2

6.6

11.1

11.1

30.9

4.8

128.

820

2440

.916

.313

.48.

16.

611

.310

.834

.76.

413

5.1

2025

42.0

16.3

13.4

8.0

6.5

11.5

10.5

38.5

8.0

141.

320

2639

.216

.013

.27.

96.

411

.610

.242

.410

.014

3.7

2027

36.4

15.8

13.8

7.8

6.2

11.7

9.9

46.3

12.0

146.

120

2833

.615

.513

.07.

76.

111

.89.

650

.214

.014

8.5

2029

30.8

15.3

12.8

7.6

5.9

11.9

9.3

54.1

16.0

150.

920

3028

.015

.012

.77.

55.

812

.09.

058

.018

.015

3.3

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

from

Kaz

akhs

tan'

s S

tatis

tical

age

ncy

and

Min

istr

y of

ene

rgy;

pro

ject

ions

by

iHS

ce

Ra

. 1.

als

o in

clud

es a

man

geld

y.

2. K

arac

haga

nak

cond

ensa

te lo

ses

abou

t 18

-19%

of i

ts v

olum

e d

urin

g th

e st

abili

zatio

n p

roce

ss; t

he d

ata

show

onl

y th

e vo

lum

es s

tab

ilize

d w

ithin

Kaz

akhs

tan

and

ava

ilab

le fo

r sh

ipm

ent

dom

estic

ally

; it

excl

udes

sta

bili

zatio

n ou

tsid

e K

azak

hsta

n (i.

e., a

t o

renb

urg)

.

Tab

le II

I-6

Oil

Pro

duc

tio

n, K

azak

hsta

n: B

ase

Sce

nari

o (c

ont

inue

d)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)




Tab

le II

I-7

Oil

Pro

duc

tio

n, K

azak

hsta

n: H

igh

Sce

nari

o(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

Kar

acha

gana

k

teng

izK

arac

haga

nak

(as

pro

duc

ed)

Kar

acha

gana

k (s

tab

ilize

d o

utp

ut)1

(am

t st

abili

zed

with

in

Kaz

akhs

tan)

turg

ayB

asin

2

akt

obe

ob

last

oth

er(J

Vs,

etc

.)W

est

Kaz

akhs

tan

Kas

haga

nN

ewo

ffsho

reK

aZ

aK

HS

taN

tota

lb

arre

ls

per

ton

7.95

8.33

7.86

7.70

7.70

7.00

6.95

7.75

7.75

(per

met

ric t

on)

1990

0.0

4.0

0.0

0.5

2.6

0.0

19.1

25.8

1991

0.0

4.5

0.0

1.2

2.8

0.0

18.3

26.6

1992

0.0

3.8

0.0

1.3

2.7

0.2

17.7

25.8

1993

0.9

3.5

0.0

1.7

2.6

0.2

14.2

23.0

1994

1.9

1.7

0.0

1.8

2.7

0.2

11.9

20.3

1995

2.5

2.5

0.0

1.3

2.6

0.3

10.7

20.6

1996

5.0

1.9

0.0

2.5

2.5

0.3

10.7

23.0

1997

6.9

2.3

0.0

2.6

2.6

0.4

10.8

25.7

1998

8.5

2.1

0.0

2.9

2.6

0.6

9.2

25.9

1999

9.6

3.4

0.0

3.6

2.3

0.9

10.4

30.0

2000

10.5

4.6

0.0

5.3

2.6

1.2

11.0

35.3

2001

12.5

4.0

0.5

6.1

3.3

1.6

12.5

40.0

2002

13.2

5.2

0.6

8.2

4.5

2.1

14.1

47.3

2003

12.7

5.9

1.0

9.7

5.1

3.0

15.1

51.5

2004

13.7

8.5

3.8

10.6

6.3

3.4

17.0

59.5

2005

13.6

10.3

6.7

9.0

7.1

3.9

18.0

61.9

2006

13.3

10.4

7.0

10.9

7.2

4.0

19.0

64.9

2007

13.9

11.6

7.8

11.7

7.1

4.1

18.8

67.2

2008

17.3

11.6

7.9

11.3

6.9

4.9

18.6

70.6

2009

22.5

11.9

8.8

11.2

7.2

5.2

18.5

76.5

2010

25.9

11.4

8.9

11.0

7.3

5.6

18.4

79.7

2011

26.5

12.2

9.8

10.9

7.8

6.8

17.8

82.0

2012

27.4

13.2

10.6

11.1

7.9

7.4

17.3

0.0

84.3



39


Kar

acha

gana

k

teng

izK

arac

haga

nak

(as

pro

duc

ed)

Kar

acha

gana

k (s

tab

ilize

d o

utp

ut)1

(am

t st

abili

zed

with

in

Kaz

akhs

tan)

turg

ayB

asin

2

akt

obe

ob

last

oth

er(J

Vs,

etc

.)W

est

Kaz

akhs

tan

Kas

haga

nN

ewo

ffsho

reK

aZ

aK

HS

taN

tota

l20

1328

.314

.211

.311

.38.

17.

916

.81.

588

.120

1429

.315

.312

.111

.58.

28.

516

.210

.599

.520

1530

.516

.512

.712

.08.

08.

515

.814

.510

5.8

2016

32.4

16.6

12.8

11.9

7.8

8.9

15.3

14.6

0.0

107.

520

1734

.316

.712

.911

.87.

69.

314

.714

.70.

010

9.1

2018

36.2

16.8

13.0

11.7

7.4

9.7

14.2

14.8

0.0

110.

820

1938

.116

.913

.011

.67.

210

.113

.617

.80.

211

5.5

2020

40.0

17.0

13.1

11.5

7.0

10.5

13.1

28.5

4.0

131.

620

2141

.017

.013

.111

.46.

911

.012

.833

.98.

214

2.1

2022

42.0

17.0

13.1

11.3

6.8

11.4

12.5

39.3

12.4

152.

720

2343

.017

.013

.111

.26.

711

.912

.144

.716

.616

3.2

2024

44.0

17.0

13.1

11.1

6.6

12.3

11.8

50.1

20.8

173.

820

2545

.017

.013

.111

.06.

512

.811

.555

.525

.018

4.3

2026

43.6

16.9

13.1

10.9

6.4

13.0

11.2

58.0

26.2

186.

320

2742

.216

.813

.110

.86.

313

.311

.060

.527

.418

8.3

2028

40.8

16.7

13.1

10.7

6.2

13.5

10.7

63.0

28.6

190.

220

2939

.416

.613

.110

.66.

113

.810

.565

.529

.819

2.2

2030

38.0

16.5

13.1

10.5

6.0

14.0

10.2

68.0

31.0

194.

2

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

from

Kaz

akhs

tan'

s S

tatis

tical

age

ncy

and

Min

istr

y of

ene

rgy;

pro

ject

ions

by

iHS

ce

Ra

. 1.

als

o in

clud

es a

man

geld

y.

2. K

arac

haga

nak

cond

ensa

te lo

ses

abou

t 18

-19%

of i

ts v

olum

e d

urin

g th

e st

abili

zatio

n p

roce

ss; t

he d

ata

show

onl

y th

e vo

lum

es s

tab

ilize

d w

ithin

Kaz

akhs

tan

and

ava

ilab

le fo

r sh

ipm

ent

dom

estic

ally

; it

excl

udes

sta

bili

zatio

n ou

tsid

e K

azak

hsta

n (i.

e., a

t o

renb

urg)

.

Tab

le II

I-7

Oil

Pro

duc

tio

n, K

azak

hsta

n: H

igh

Sce

nari

o (c

ont

inue

d)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)




Tab

le II

I-8

Oil

Pro

duc

tio

n, K

azak

hsta

n: l

ow

Sce

nari

o(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

Kar

acha

gana

k

teng

izK

arac

haga

nak

(as

pro

duc

ed)

Kar

acha

gana

k (s

tab

ilize

d o

utp

ut)1

(am

t st

abili

zed

with

in

Kaz

akhs

tan)

turg

ayB

asin

2

akt

obe

ob

last

oth

er(J

Vs,

etc

.)W

est

Kaz

akhs

tan

Kas

haga

nN

ewo

ffsho

reK

aZ

aK

HS

taN

tota

lb

arre

ls

per

ton

7.95

8.33

7.86

7.70

7.70

7.00

6.95

7.75

7.75

(per

met

ric t

on)

1990

0.0

4.0

0.0

0.5

2.6

0.0

19.1

25.8

1991

0.0

4.5

0.0

1.2

2.8

0.0

18.3

26.6

1992

0.0

3.8

0.0

1.3

2.7

0.2

17.7

25.8

1993

0.9

3.5

0.0

1.7

2.6

0.2

14.2

23.0

1994

1.9

1.7

0.0

1.8

2.7

0.2

11.9

20.3

1995

2.5

2.5

0.0

1.3

2.6

0.3

10.7

20.6

1996

5.0

1.9

0.0

2.5

2.5

0.3

10.7

23.0

1997

6.9

2.3

0.0

2.6

2.6

0.4

10.8

25.7

1998

8.5

2.1

0.0

2.9

2.6

0.6

9.2

25.9

1999

9.6

3.4

0.0

3.6

2.3

0.9

10.4

30.0

2000

10.5

4.6

0.0

5.3

2.6

1.2

11.0

35.3

2001

12.5

4.0

0.5

6.1

3.3

1.6

12.5

40.0

2002

13.2

5.2

0.6

8.2

4.5

2.1

14.1

47.3

2003

12.7

5.9

1.0

9.7

5.1

3.0

15.1

51.5

2004

13.7

8.5

3.8

10.6

6.3

3.4

17.0

59.5

2005

13.6

10.3

6.7

9.0

7.1

3.9

18.0

61.9

2006

13.3

10.4

7.0

10.9

7.2

4.0

19.0

64.9

2007

13.9

11.6

7.8

11.7

7.1

4.1

18.8

67.2

2008

17.3

11.6

7.9

11.3

6.9

4.9

18.6

70.6

2009

22.5

11.9

8.8

11.2

7.2

5.2

18.5

76.5

2010

25.9

11.4

8.9

11.0

7.3

5.6

18.4

79.7

2011

26.5

12.2

9.8

10.9

7.8

6.8

17.8

82.0

2012

26.9

12.2

9.8

10.2

7.6

7.3

16.8

81.0

2013

27.3

12.2

9.8

9.5

7.4

7.7

15.8

0.1

80.1



41


Kar

acha

gana

k

teng

izK

arac

haga

nak

(as

pro

duc

ed)

Kar

acha

gana

k (s

tab

ilize

d o

utp

ut)1

(am

t st

abili

zed

with

in

Kaz

akhs

tan)

turg

ayB

asin

2

akt

obe

ob

last

oth

er(J

Vs,

etc

.)W

est

Kaz

akhs

tan

Kas

haga

nN

ewo

ffsho

reK

aZ

aK

HS

taN

tota

l20

1427

.812

.39.

78.

87.

28.

214

.84.

083

.120

1528

.011

.58.

87.

56.

38.

013

.59.

584

.320

1629

.011

.28.

67.

46.

38.

212

.910

.585

.520

1730

.010

.98.

47.

36.

38.

412

.311

.586

.720

1831

.010

.68.

27.

26.

28.

611

.812

.587

.920

1932

.010

.38.

17.

16.

28.

811

.213

.50.

089

.120

2033

.010

.07.

97.

06.

29.

010

.614

.50.

090

.320

2133

.49.

77.

66.

96.

19.

210

.316

.00.

091

.620

2233

.89.

47.

46.

86.

09.

410

.017

.50.

092

.920

2334

.29.

17.

16.

76.

09.

69.

619

.00.

094

.220

2434

.68.

86.

86.

65.

99.

89.

320

.50.

095

.520

2535

.08.

56.

66.

55.

810

.09.

022

.00.

297

.020

2634

.08.

46.

56.

45.

610

.18.

823

.21.

898

.320

2733

.08.

36.

46.

35.

510

.28.

624

.43.

399

.620

2832

.08.

26.

36.

25.

310

.38.

425

.64.

910

0.9

2029

31.0

8.1

6.2

6.1

5.2

10.4

8.2

26.8

6.4

102.

220

3030

.08.

06.

16.

05.

010

.58.

028

.08.

010

3.5

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

from

Kaz

akhs

tan'

s S

tatis

tical

age

ncy

and

Min

istr

y of

ene

rgy;

pro

ject

ions

by

iHS

ce

Ra

. 1.

als

o in

clud

es a

man

geld

y.

2. K

arac

haga

nak

cond

ensa

te lo

ses

abou

t 18

-19%

of i

ts v

olum

e d

urin

g th

e st

abili

zatio

n p

roce

ss; t

he d

ata

show

onl

y th

e vo

lum

es s

tab

ilize

d w

ithin

Kaz

akhs

tan

and

ava

ilab

le fo

r sh

ipm

ent

dom

estic

ally

; it

excl

udes

sta

bili

zatio

n ou

tsid

e K

azak

hsta

n (i.

e., a

t o

renb

urg)

.

Tab

le II

I-8

Oil

Pro

duc

tio

n, K

azak

hsta

n: l

ow

Sce

nari

o (c

ont

inue

d)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)




production up to 68 mt (1.44 mbd) in 2030. In the low case, production reaches only 14.5 mt (308,000 bd) in 2020 and 28 mt (595,000 bd) in 2030.

Turgay Basin. The Turgay Basin refers to the region around the Kumkol field in south-central Kazakhstan. The region has a half dozen or so significant discovered fields (of which Kumkol is the largest) and a number of prospective structures as well. The liquids produced at the Amangeldy field in southern Kazakhstan are also included within this category because of its geographical location. The category now includes seven producing entities in the region (plus Amangeldy), the most important of which are

PetroKazakhstan Kumkol Resources (now a subsidiary of the state-owned Chinese •National Petroleum Company [CNPC] following the acquisition of the Canadian-based company formerly known as Hurricane Hydrocarbons, in the fall of 2005)

Turgay Petroleum (a JV between PetroKazakhstan and LUKOIL)•

Kazgermunay (now a 50:50 JV between PetroKazakhstan and KazMunayGaz •[KMG])

CNPC-owned CNPC AiDan Munay•

The small Kazakh independents Kuatamlonmunay, Sauts (South) Oil, KOR, and •Kumkol Transervis

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43


Production in the Turgay Basin has been somewhat volatile in recent years. It declined in 2005 because of the need to cut back oil production after a new government law restricted associated gas flaring and also a legal dispute between PetroKazakhstan and LUKOIL. Both situations were resolved with CNPC’s acquisition of PetroKazakhstan. Regional production rose in 2006 and held steady in 2007 at 11.7 mt (247,000 bd), but declined slightly in 2008, to 11.3 mt (239,000 bd). Output declined slightly again in 2009–10, with aggregate output for the region down to 11.0 mt (233,000 bd) in 2010.

In two of IHS CERA’s scenarios (the base case and the low case), production from the Turgay Basin declines from the current level of output. Only in the high case is production projected to expand. In the base case, which assumes a moderately pessimistic geological position, production in the Turgay Basin begins a slow decline, falling to 7.5 mt (158,000 bd) by 2030. In the low case, production declines more rapidly, to hit 6 mt (127,000 bd) by 2030. In contrast, the high case assumes that expansions at the producing fields are economically attractive to push to a somewhat higher maximum production level of 12.0 mt (253,000 bd) in 2015 before declining, falling to 10.5 mt (222,000 bd) by 2030.

Aktobe Oblast. Oil production in Aktobe Oblast traditionally comprised the output of one company, CNPC-Aktobemunaygaz, based on the Kenkiyak and Zhanazhol fields. This company has been owned and operated by the Chinese oil company CNPC for over a decade. CNPC investment has more than doubled production for the entity from its low point in 1999, with output in 2009–10 holding at 6.1 mt (128,000 bd). Another producer, Kazakhoil-Aktobe, went into operation in 2002, with others following in recent years, for a total of 12 producing companies in 2010. Kazakhoil-Aktobe was a JV between the national oil company in Kazakhstan, KMG, and an international independent, Nelson Resources. But Nelson Resources was acquired by the Russian oil major LUKOIL at the end of 2005.

Two of IHS CERA’s production cases assume that production continues to grow in the Aktobe region, while the low case envisions further decline. In the base case, production is projected to rise to a plateau of about 7.5–7.9 mt (158,000–165,000 bd) in 2010–15, while in the high case it rises to 8.0 mt (169,000 bd) in 2010. By 2030, production in the area is projected to have declined to 5.8 mt (122,000 bd) in the base case, 5.0 mt (105,000 bd) in the low case, or 6.0 mt (127,000 bd) in the high case.

Other western Kazakhstan. Production in West Kazakhstan is used here to cover the three long-existing producers of Uzenmunaygaz, Mangystaumunaygaz, and Embamunaygaz plus CNPC International/Buzachi Operating (previously owned by Texaco and Chevron but now jointly owned by CNPC and LUKOIL via its acquisition of Nelson Resources) and Karazhanbasmunay. These producers are grouped together because of their location (all are located in Mangistau Oblast except for Embamunaygaz) and similar crude quality (basically heavy Mangyshlak or Buzachi crude). Output by this group is assumed to begin a slow decline from 2006–07 in all three scenarios. Output in 2030 for the group is projected 9 mt (171,000 bd) in the base case, 10.2 mt (194,000 bd) in the high case, or 8 mt (152,000 bd) in the low case.

Other. Crude oil produced by the category “Other (JVs, etc.)” includes all onshore production from producers not already mentioned. This category comprises mainly small JVs, which




continue to proliferate, producing in western Kazakhstan (mainly in Atyrau and Mangistau oblasts). Their output is assumed in the base scenario to see moderate, steady growth, from 4.9 mt (108,000 bd) in 2010 to 10.5 mt (201,000 bd) by 2030 in the low case, or to 12.0 mt (211,000 bd) in the base case, or to 14.0 mt (268,000 bd) in the high case. This is based largely on the strength of relatively conservative estimates of production from this diverse set of operations.

Other offshore. Since production from other offshore fields will be driven largely by a combination of geology and investment conditions, the range of what is possible is very broad. Rather than exploring more extreme scenarios, IHS CERA has chosen to keep its outlooks for new developments in the Kazakh offshore within a relatively narrow band. The outlooks assume some significant exploration success, but assume no new discoveries are made on the scale of Kashagan.

The high scenario envisions the development of at least one new field starting in 2019, with commercial reserves of between 2 and 3 billion barrels (e.g., Kairan, Aktote, or Kalamkas, although some prospects within the AgipKCO contract area could fit this profile, as could Kurmangazy). But post-Kashagan E&P in the Kazakh offshore could move even more slowly, due to government inflexibility over commercial terms and a deficit of available equipment and services for post-Kashagan development. Thus, the base scenario envisions production starting in 2021, and the low scenario envisions production commencing only in 2025. The development of these other offshore fields is assumed to drive production upward to 8 mt (170,000 bd) by 2030 in the low case, 18 mt (382,000 bd) in 2030 in the base case, or 31 mt (658,000 bd) in 2030 in the high case.

3.1.4 Oil Production in Azerbaijan

Azerbaijan’s aggregate oil output in 2010 was reported as 50.8 mt (1.05 mbd), an increase of a mere 0.9% from 2009. But the reported production figures for the individual components add up to a slightly higher figure of 51.6 mt: State Oil Company of Azerbaijan Republic (SOCAR) at 9.1 mt, the Azeri-Chirag-Guneshli (ACG) project at 40.6 mt, and Shah Deniz condensate at 1.9 mt (see Table III-9). The international consortium (the Azerbaijan International Operating Company [AIOC]) operating the ACG project produced about 80% of Azeri oil last year, but output in the past few years has been well below the original target. The consortium planned to reach plateau output of about 50 mt per year (1 mbd) by the end of 2008, supported in part by the April 2008 startup of the first platform to tap the deepwater Guneshli structure, but has ended up well short of this because of a number of shortcomings and issues.

Both the AIOC consortium and SOCAR have lowered their long-term expectations for the ACG project. In IHS CERA’s base case scenario, ACG hit maximum production already in 2010 at only 823,000 bd or 40.6 mt. Thus with ACG production already post-peak, a decline in national output sets in as ACG production drifts downward. This is because all the other offshore projects have, at present, failed to make commercial discoveries of oil.

Overall output in Azerbaijan falls to 49.5 mt (1.0 mbd) in 2015 in the base scenario and then declines slowly to 40.8 (912,000 bd) by 2030. In the high scenario, peak output for



45


Tab

le II

I-9

His

tori

cal O

il B

alan

ce o

f A

zerb

aija

n(m

illio

n m

etric

ton

s)

per

cent

cha

nge

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2009

-201

0c

rud

e o

il:

pro

duc

tion

11.5

13.8

14.9

14.9

15.3

15.4

15.5

22.2

32.3

41.7

44.5

50.4

50.8

0.9

So

ca

R (i

nclu

din

g JV

s)11

.59.

09.

09.

08.

98.

99.

09.

09.

08.

89.

39.

19.

1-0

.1

offs

hore

7.6

7.5

7.7

7.4

7.4

7.2

7.3

7.3

7.2

7.1

7.7

7.3

7.3

-0.3

o

nsho

re3.

91.

51.

31.

61.

61.

71.

71.

71.

81.

71.

61.

81.

80.

6

a

ioc

2.4

4.8

5.7

5.9

6.4

6.5

6.6

13.2

23.3

32.9

33.3

40.3

40.6

0.7

Sha

h D

eniz

----

----

----

----

--0.

61.

81.

01.

989

.8

exp

orts

2.8

5.9

7.6

9.1

8.8

8.7

9.0

13.3

22.1

35.7

36.3

43.8

44.3

1.1

t

o no

n-c

iS c

ount

ries

2.6

5.7

7.4

9.1

8.8

8.7

9.0

13.3

22.1

35.2

36.3

43.8

44.3

1.1

V

ia "

nort

hern

rou

te"

to N

ovor

ossi

ysk

2.8

1.9

0.6

2.3

2.8

2.5

2.6

4.3

4.4

2.1

1.5

2.5

2.2

-9.6

V

ia "

wes

tern

rou

te"

to S

upsa

--4.

05.

15.

95.

96.

26.

47.

05.

60.

00.

64.

24.

20.

7

Via

Btc

----

----

----

--0.

68.

028

.431

.837

.637

.3-0

.7

oth

er (B

atum

i)--

----

0.9

0.1

0.0

0.0

2.0

4.2

4.7

2.2

1.5

0.7

-53.

3

iran

0.2

0.0

0.0

t

o c

iS c

ount

ries

0.2

0.2

0.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

im

por

ts0.

10.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0

Net

exp

orts

2.7

5.9

7.6

9.1

8.8

8.7

9.0

13.3

22.1

35.7

36.3

43.8

44.3

1.1

a

pp

aren

t co

nsum

ptio

n8.

87.

97.

35.

86.

56.

76.

68.

910

.16.

08.

26.

66.

5-0

.5

Refi

nery

thr

ough

put

8.3

7.9

8.2

6.2

6.3

6.3

6.3

7.4

7.5

7.5

7.3

6.0

6.2

3.1

Refi

ned

pro

duc

ts:

thro

ughp

ut (t

otal

)8.

37.

98.

26.

26.

36.

36.

37.

47.

57.

57.

36.

06.

23.

1a

pp

aren

t c

onsu

mp

tion

(all

pro

duc

ts)

6.3

5.7

6.2

3.9

3.6

4.7

4.1

5.1

4.4

4.5

4.6

3.6

4.0

12.0

exp

orts

tota

l (al

l pro

duc

ts)

2.3

2.5

2.1

2.3

2.7

1.6

2.5

2.7

3.2

3.1

2.8

2.5

2.2

-10.

0

c

iS c

ount

ries

0.9

0.5

0.3

0.4

0.5

0.5

0.6

0.5

0.5

0.3

0.5

0.3

0.2

-27.

1

N

on-c

iS1.

42.

01.

81.

92.

31.

41.

82.

22.

72.

82.

32.

22.

0-7

.4im

por

tsto

tal (

all p

rod

ucts

)0.

20.

30.

10.

00.

00.

00.

20.

40.

20.

10.

10.

10.

0-1

4.1

ciS

cou

ntrie

s0.

20.

00.

10.

00.

00.

00.

20.

30.

10.

10.

00.

00.

0-7

1.1

Non

-ciS

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

79.8

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

and

exp

orts

from

aze

rbai

jan'

s S

tatis

tical

age

ncy

and

So

ca

R; s

upp

lem

ente

d w

ith a

dd

ition

al in

form

atio

n on

exp

ort

rout

es fr

om c

omp

any

rep

orts

.




��

��

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Azerbaijan is still some years away at 61.3 mt (1.25 mbd) in 2020–25 before declining to 55.1 mt (1.14 mbd) by 2030. In the low scenario, Azerbaijani production also declines after 2010, but to only 26.7 mt (650,000 bd) by 2030 (see Figure III-6).

AIOC at ACG. IHS CERA now estimates in the base case that ACG production peaked already at 40.6 mt (823,000 bd) in 2010. We assume the realization of the extension at Chirag (a sixth platform) adds another 300–360 million barrels (41–49 mt) to total production for the project (a US$6 billion investment sanctioned in 2008), but this attenuates the rate of decline rather than adding to peak production. The high scenario envisions a slightly higher plateau production level of 48.5 mt in 2015 (983,000 bd).

Shah Deniz. Volumes of condensate produced at Shah Deniz are assumed to be constrained by limitations on access to markets for the field’s gas production. First liquids production began in early 2007. Production expands to a plateau of 3 mt per year (67,000 bd) in 2020–25 in the base case. An output of about 2.4 mt per year is now viewed as being commensurate with the Phase 1 production program that envisages gas output reaching a peak of 8.4 Bcm per year. In the low case, condensate production rises to a peak of 2 mt (45,000 bd) in 2015. In the high scenario, condensate production grows steadily to 4.5 mt (101,000 bd) in 2030 and 5 mt (112,000 bd) in 2035, reflecting the realization of a much larger volume of gas production and sales.

SOCAR. Production from SOCAR’s existing fields (including onshore JVs) amounted to 9.1 mt (183,000 bd) in 2010, about the same as in 2009. Output is assumed to remain in long-



47


term (albeit slow) decline, dropping to a range of 4.8 mt (97,000 bd) in the base scenario by 2020 and declining further to 2.3 mt (46,000 bd) by 2030. In the high scenario, output declines to 6.3 mt (127,000 bd) by 2020 and then 4.1 mt (82,000 bd) in 2030. In the low scenario, SOCAR’s legacy production drops to 4.5 mt (90,000 bd) in 2020 and to 1.4 mt (26,000 bd) by 2030.

Other offshore. Given the general pessimism regarding the oil prospectivity of remaining explored and unexplored structures offshore in the South Caspian Basin, IHS CERA has assumed no new offshore discoveries in the base scenario or low scenario. The high scenario, however, assumes one small oil discovery (approximately 1 billion barrels) or a large gas condensate discovery (such as Alov or Apsheron). In that scenario, liquids production begins in 2020 and rises slowly to 4.5 mt (101,000 bd) by 2030.

Kyapaz/Serdar. In the base and high scenarios, we assume that Azerbaijan and Turkmenistan eventually conclude a 50:50 joint development agreement for this field, with first oil produced in 2015 (high scenario) or before 2020 (base scenario). In the low scenario it is assumed that no agreement is signed. Production rises to 6 mt (122,000 bd) in total by 2020 in the base scenario and basically holds at this level through 2030. In the high scenario, maximum production is 7.6 mt (154,000 bd) in 2025. Production is assumed to be evenly split between the Azerbaijani and Turkmen sides.

3.1.5 Oil Production in Turkmenistan

According to indexes published by Turkmen statistical authorities, Turkmenistan’s oil production in 2010 amounted to 11.0 mt (0.22 mbd), an increase of 2.8% from the level of 2009 (see Table III-10). The principal increase in national output in recent years has come from several small projects being developed by international companies. Production by the state-owned entities (mainly Turkmenneft) has tended to decline.

IHS CERA takes a rather pessimistic view of future Turkmen liquids production. This is due to a dearth of condensate in the gas province of eastern Turkmenistan (although this could change if the development of the deeper reservoirs of the new discoveries of Osman and Yolotan is pressed successfully and reveals significant condensate content), difficult reservoirs in onshore western Turkmenistan, and an assumption of generally limited prospectivity in the Turkmen offshore sector of the Caspian.

Therefore, any significant expansion of Turkmen oil production depends on resolution of the dispute between Turkmenistan and Azerbaijan over ownership of the offshore field known as Kyapaz in Azerbaijan and Serdar in Turkmenistan. The reopening of the Turkmenistan embassy in Baku in 2007 raised hopes of a deal over South Caspian demarcation that would permit development of Kyapaz/Serdar, as the disagreement was one key reason for the embassy closure in 2001. However, Turkmenistan’s decision to sign a PSA covering the territory that includes the disputed field with Buried Hill Energy (Canada) renewed tension between the two countries, complicating efforts to achieve an overall settlement. We assume that Kyapaz/Serdar development proceeds as a 50:50 venture between Azerbaijan and Turkmenistan in the base case and high case, while in the low case there is no accommodation between the two countries (see above). In the base case, Kyapaz/Serdar provides a total production of




Tab

le II

I-10

His

tori

cal O

il B

alan

ce o

f Tu

rkm

enis

tan

(mill

ion

met

ric t

ons)

1990

199

1 19

92 1

993

1994

199

5 19

96 1

997

1998

199

9 20

00 2

001

2002

200

3 20

04 2

005

2006

200

7 20

08 2

009

2010

c

rud

e o

il: p

rod

uctio

n5.

6 5.

4 5.

4 4.

4 4.

3 4.

7 4.

3 4.

7 6.

3 6.

9 7.

2 8.

0 9.

0 10

.0

10.1

9.

5 9.

0 9.

8 10

.0

10.7

11

.0

exp

orts

0.3

0.0

0.1

0.4

0.1

0.5

0.2

0.3

1.6

1.9

1.7

2.3

2.4

1.8

1.0

1.5

1.4

2.0

2.0

2.4

2.4

im

por

ts0.

3 1.

7 1.

1 0.

4 0.

5 0.

4 0.

1 0.

7 0.

9 0.

6 0.

6 0.

5 0.

5 0.

4 0.

4 0.

4 0.

4 0.

3 0.

4 0.

3 0.

3 a

pp

aren

t co

nsum

ptio

n5.

6 7.

1 6.

4 4.

4 4.

7 4.

6 4.

3 5.

1 5.

6 5.

6 6.

1 6.

3 7.

1 8.

6 9.

5 8.

4 8.

0 8.

1 8.

4 8.

6 8.

9

pro

cess

ing

loss

es, e

tc.

0.2

(0.0

)0.

6 (0

.1)

0.0

0.4

(0.3

)0.

3 0.

3 1.

0 1.

2 1.

1 1.

3 1.

8 2.

6 1.

5 1.

1 0.

6 0.

4 0.

4 0.

4

Refi

nery

thr

ough

put

5.5

7.1

5.8

4.5

4.7

4.2

4.5

4.7

5.3

4.6

4.9

5.2

5.7

6.8

6.8

6.9

6.9

7.5

8.0

8.2

8.5

Net

exp

orts

(0.0

)(1

.7)

(1.0

)0.

0 (0

.4)

0.1

0.1

(0.4

)0.

6 1.

3 1.

1 1.

8 1.

9 1.

4 0.

6 1.

1 1.

0 1.

7 1.

6 2.

1 2.

1

Refi

ned

pro

duc

ts:

thro

ughp

ut (t

otal

out

put

)5.

5 7.

1 5.

8 4.

5 4.

7 4.

2 4.

5 4.

7 5.

3 4.

6 4.

9 5.

2 5.

7 6.

8 6.

7 6.

9 6.

9 7.

5 8.

0 8.

2 8.

5 a

pp

aren

t co

nsum

ptio

n (a

ll p

rod

ucts

)2.

0 2.

0 3.

0 2.

8 3.

0 2.

1 2.

6 2.

3 2.

3 2.

0 2.

2 2.

5 2.

8 2.

9 2.

5 3.

0 2.

6 2.

6 3.

4 3.

4 3.

5 e

xpor

ts (a

ll p

rod

ucts

)3.

4 5.

2 2.

8 1.

7 1.

8 2.

1 2.

0 2.

5 3.

1 2.

6 2.

7 3.

0 2.

9 3.

9 4.

3 3.

9 4.

2 4.

9 4.

6 4.

8 5.

0 im

por

ts (a

ll p

rod

ucts

)0.

0 0.

0 0.

0 0.

0 0.

1 0.

0 0.

1 0.

1 0.

0 0.

0 0.

0 0.

3 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 N

et e

xpor

ts (a

ll p

rod

ucts

)3.

4 5.

2 2.

8 1.

7 1.

7 2.

1 1.

9 2.

4 3.

1 2.

6 2.

7 2.

7 2.

9 3.

9 4.

3 3.

9 4.

2 4.

9 4.

6 4.

8 5.

0

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

and

exp

orts

from

tur

kmen

ista

n's

Sta

tistic

al a

genc

y w

here

ava

ilab

le; o

ther

wis

e fr

om p

ress

ann

ounc

emen

ts o

r es

timat

es b

y iH

S c

eR

a.



49


up to 6 mt per year (122,000 bd) by 2020, with first oil coming onstream before 2020. The total volume is split 50:50 between the two countries (see Tables III-11a, b, c).

Nonetheless, Turkmenistan’s oil potential has clearly emerged as a focus of renewed interest from foreign investors in the wake of the “thaw” under Turkmen President Gurbanguly Berdymukhammedov. A relatively recent entrant is India’s Oil and Natural Gas Corp. (ONGC), the state oil and gas company, which in October 2007 announced that its ONGC Mittal Energy Ltd JV had purchased a 30% stake in an offshore exploration block, joining a consortium that includes Denmark’s Maersk Oil (now 36%) and Germany’s Wintershall (now 34%). Eni’s US$3.58 billion acquisition of Burren Energy (United Kingdom) in late 2007 provided Eni with the rights to develop the onshore Nebit Dag acreage under terms of a 25-year PSA. The acquisition was done partly because of interest in Burren’s African holdings but also shows increasing interest by new players in post-Niyazov Turkmenistan. Other foreign investors with projects in Turkmenistan to date include Dragon Oil (United Arab Emirates), Mitro International (a Russian company registered in Panama), and Petronas (Malaysia), which began production at the Diyarbekir field in 2006.

Output for the country as a whole is projected to reach a maximum of 14.2 mt (287,000 bd) in 2020 in the base scenario or by 2025 in the high scenario with a maximum output of 17.8 mt (361,000 bd). Projections for the low scenario have maximum output at 11.2 mt (224,000 bd) in 2011 with output falling to 8.7 mt (174,000 bd) in 2030 (see Figure III-7).

3.2 EURASIAN CRUDE OIl CONSUMPTION

To avoid unnecessary complexity, IHS CERA employs only a single scenario for crude oil consumption and for refined product exports for both Russia and the Caspian states. The methodology begins with a consumption outlook for the four key products of gasoline, diesel fuel, mazut (residual fuel oil), and kerosene in each country. These projections are based on IHS CERA’s basic macroeconomic assumptions for the countries that comprise former Soviet economic space that affect other key drivers of demand, such as industrial output, agricultural activity, car ownership, trucking and freight transport, and air travel.

For Russia, following a decline in gross domestic product (GDP) of 7.9% in 2009 with the global Great Recession, GDP growth bounced back to 4.0% in 2010 and is projected to grow at an average annual rate of 3.2% over the outlook period between 2010 and 2035. In the Caspian region as a group, GDP declined by only 0.3 in 2009 and posted economic growth of 6.8% in 2010. The group of countries is expected to average 3.6% GDP growth per year during 2010–35. Azerbaijan’s average annual growth in GDP is expected to be 3.4% over this period; in Kazakhstan, 3.2%; and in Turkmenistan, 4.0%. The CIS countries as a group registered a 6.9% decline in 2009, while the average annual GDP growth over the outlook period through 2030 is projected at 3.1%. For all the countries in the region, the general assumption is of a gradually slowing pace of growth after recovering from the 2008–09 recession, reflecting their larger economic bases over time. From this general basis and related macroeconomic assumptions, projections are then made about shifting relative demand for different refined products. Internal demand developments for refined products also are assumed to be a key determinant of crude oil consumption in certain important




Tab

le II

I-11

a

Oil

Pro

duc

tio

n, S

out

h C

asp

ian

(Aze

rbai

jan/

Turk

men

ista

n): B

ase

Sce

nari

o(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

aZ

eR

Ba

iJa

NtU

RK

Me

NiS

taN

So

ca

RS

oc

aR

ac

GS

hah

oth

erK

yap

az/

tota

lK

yap

az/

Wes

tern

are

ae

aste

rn a

rea

tota

lo

ffsho

reo

nsho

re &

JV

s(a

ioc

)D

eniz

offs

hore

Ser

dar

(50%

)a

Ze

RB

aiJ

aN

Ser

dar

(50%

)(in

cl. o

ffsho

re)

(con

den

sate

)tU

RK

Me

NiS

taN

bar

rels

per

ton

7.35

7.35

7.40

8.20

8.20

7.40

7.40

7.30

8.20

(per

met

ric t

on)

1990

9.4

3.1

12.5

5.0

0.6

5.6

1991

9.0

2.7

11.7

4.8

0.6

5.4

1992

9.2

2.0

11.2

4.7

0.5

5.2

1993

9.3

1.0

10.3

4.3

0.5

4.8

1994

7.8

1.8

9.6

4.1

0.3

4.4

1995

7.5

1.7

9.2

4.3

0.2

4.5

1996

7.5

1.6

9.1

4.2

0.2

4.4

1997

7.4

1.6

0.1

9.0

4.9

0.1

5.0

1998

7.6

1.6

2.4

11.5

6.0

0.3

6.3

1999

7.5

1.5

4.8

13.8

6.7

0.2

6.9

2000

7.5

1.4

5.1

14.0

7.0

0.2

7.2

2001

7.5

1.5

5.9

14.9

7.8

0.2

8.0

2002

7.4

1.5

6.4

15.3

8.8

0.2

9.0

2003

7.3

1.6

6.5

15.4

9.8

0.2

10.0

2004

7.3

1.7

6.6

15.5

9.9

0.2

10.1

2005

7.4

1.7

13.2

22.2

9.3

0.2

9.5

2006

7.2

1.8

23.3

32.3

8.8

0.2

9.0

2007

7.0

1.8

32.9

0.6

41.7

9.6

0.2

9.8

2008

7.5

1.8

33.3

1.8

44.5

9.8

0.2

10.0

2009

7.3

1.8

40.3

1.0

50.4

10.5

0.2

10.7

2010

7.3

1.8

40.6

1.9

50.8

10.8

0.2

11.0

2011

7.2

1.7

39.9

2.0

0.0

50.8

0.0

11.3

0.3

11.6

2012

7.0

1.6

40.1

2.1

0.0

50.8

0.0

11.3

0.4

11.7

2013

6.8

1.5

40.0

2.2

0.0

50.5

0.0

11.4

0.4

11.8

2014

6.7

1.3

39.8

2.3

0.0

50.1

0.0

11.4

0.5

11.9

2015

6.4

1.2

39.5

2.4

0.0

49.5

0.0

11.0

0.5

11.5

2016

5.9

1.1

39.2

2.5

0.6

49.4

0.6

10.9

0.5

12.0

2017

5.4

1.0

38.9

2.6

1.2

49.2

1.2

10.8

0.6

12.6

2018

5.0

1.0

38.6

2.8

1.8

49.1

1.8

10.7

0.6

13.1

2019

4.5

0.9

38.3

2.9

2.4

48.9

2.4

10.6

0.7

13.7

2020

4.0

0.8

38.0

3.0

3.0

48.8

3.0

10.5

0.7

14.2

2021

3.8

0.7

37.4

3.0

3.0

48.0

3.0

10.4

0.7

14.2

2022

3.6

0.7

36.8

3.0

3.1

47.2

3.1

10.3

0.8

14.1

2023

3.4

0.6

36.2

3.0

3.1

46.3

3.1

10.1

0.8

14.1

2024

3.2

0.6

35.6

3.0

3.2

45.5

3.2

10.0

0.9

14.0

2025

3.0

0.5

35.0

3.0

3.2

44.7

3.2

9.9

0.9

14.0

2026

2.8

0.5

34.4

3.1

3.2

43.9

3.2

9.8

0.9

13.9

2027

2.6

0.4

33.8

3.2

3.1

43.1

3.1

9.7

0.9

13.7

2028

2.4

0.4

33.2

3.3

3.1

42.4

3.1

9.5

1.0

13.6

2029

2.2

0.3

32.6

3.4

3.0

41.6

3.0

9.4

1.0

13.4

2030

2.0

0.3

32.0

3.5

3.0

40.8

3.0

9.3

1.0

13.3

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

from

nat

iona

l sta

tistic

al a

genc

ies,

offi

cial

dat

a fr

om m

inis

trie

s, p

ress

ann

ounc

emen

ts, o

r es

timat

es b

y iH

S c

eR

a; p

roje

ctio

ns b

y iH

S c

eR

a.



51


Tab

le II

I-11

b

Oil

Pro

duc

tio

n, S

out

h C

asp

ian

(Aze

rbai

jan/

Turk

men

ista

n): H

igh

Sce

nari

o(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

aZ

eR

Ba

iJa

NtU

RK

Me

NiS

taN

So

ca

RS

oc

aR

ac

GS

hah

oth

erK

yap

az/

tota

lK

yap

az/

Wes

tern

are

ae

aste

rn a

rea

tota

lo

ffsho

reo

nsho

re &

JV

s(a

ioc

)D

eniz

offs

hore

Ser

dar

(50%

)a

Ze

RB

aiJ

aN

Ser

dar

(50%

)(in

cl.o

ffsho

re)

(con

den

sate

)tU

RK

Me

NiS

taN

bar

rels

per

ton

7.35

7.35

7.40

8.20

8.20

7.40

7.40

7.30

8.20

(per

met

ric t

on)

1990

9.4

3.1

12.5

5.0

0.6

5.6

1991

9.0

2.7

11.7

4.8

0.6

5.4

1992

9.2

2.0

11.2

4.7

0.5

5.2

1993

9.3

1.0

10.3

4.3

0.5

4.8

1994

7.8

1.8

9.6

4.1

0.3

4.4

1995

7.5

1.7

9.2

4.3

0.2

4.5

1996

7.5

1.6

9.1

4.2

0.2

4.4

1997

7.4

1.6

0.1

9.0

4.9

0.1

5.0

1998

7.6

1.6

2.4

11.5

6.0

0.3

6.3

1999

7.5

1.5

4.8

13.8

6.7

0.2

6.9

2000

7.5

1.4

5.1

14.0

7.0

0.2

7.2

2001

7.5

1.5

5.9

14.9

7.8

0.2

8.0

2002

7.4

1.5

6.4

15.3

8.8

0.2

9.0

2003

7.3

1.6

6.5

15.4

9.8

0.2

10.0

2004

7.3

1.7

6.6

15.5

9.9

0.2

10.1

2005

7.4

1.7

13.2

22.2

9.3

0.2

9.5

2006

7.2

1.8

23.3

32.3

8.8

0.2

9.0

2007

7.0

1.8

32.9

0.6

41.7

9.6

0.2

9.8

2008

7.5

1.8

33.3

1.8

44.5

9.8

0.2

10.0

2009

7.3

1.8

40.3

1.0

50.4

10.5

0.2

10.7

2010

7.3

1.8

40.6

1.9

50.8

10.8

0.2

11.0

2011

7.2

1.7

39.9

2.0

0.0

50.8

0.0

11.5

0.4

11.9

2012

7.1

1.6

41.5

2.2

0.0

0.0

52.4

0.0

11.8

0.5

12.4

2013

7.0

1.6

43.1

2.3

0.0

0.0

54.0

0.0

12.2

0.7

12.9

2014

6.9

1.5

44.6

2.5

0.0

0.0

55.5

0.0

12.5

0.8

13.4

2015

6.8

1.5

48.5

2.7

0.0

0.5

60.0

0.5

12.5

1.0

14.0

2016

6.5

1.4

48.2

2.9

0.0

1.1

60.2

1.1

12.6

1.0

14.7

2017

6.2

1.3

48.0

3.1

0.0

1.7

60.3

1.7

12.7

1.1

15.5

2018

5.8

1.3

47.7

3.4

0.0

2.3

60.5

2.3

12.8

1.1

16.2

2019

5.5

1.2

47.5

3.6

0.0

2.9

60.6

2.9

12.9

1.2

17.0

2020

5.2

1.1

47.2

3.8

0.5

3.5

61.3

3.5

13.0

1.2

17.7

2021

5.1

1.0

46.6

3.9

1.2

3.6

61.3

3.6

12.9

1.3

17.7

2022

4.9

1.0

45.9

4.0

1.9

3.6

61.3

3.6

12.8

1.3

17.7

2023

4.8

0.9

45.3

4.0

2.6

3.7

61.3

3.7

12.7

1.4

17.8

2024

4.6

0.9

44.6

4.1

3.3

3.7

61.3

3.7

12.6

1.4

17.8

2025

4.5

0.8

44.0

4.2

4.0

3.8

61.3

3.8

12.5

1.5

17.8

2026

4.3

0.8

42.9

4.3

4.1

3.7

60.1

3.7

12.2

1.6

17.5

2027

4.1

0.7

41.8

4.3

4.2

3.7

58.8

3.7

11.9

1.7

17.3

2028

3.9

0.7

40.7

4.4

4.3

3.6

57.6

3.6

11.6

1.8

17.0

2029

3.7

0.6

39.6

4.4

4.4

3.6

56.3

3.6

11.3

1.9

16.8

2030

3.5

0.6

38.5

4.5

4.5

3.5

55.1

3.5

11.0

2.0

16.5

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

from

nat

iona

l sta

tistic

al a

genc

ies,

offi

cial

dat

a fr

om m

inis

trie

s, p

ress

ann

ounc

emen

ts, o

r es

timat

es b

y iH

S c

eR

a; p

roje

ctio

ns b

y iH

S c

eR

a.




Tab

le 1

1c

Oil

Pro

duc

tio

n, S

out

h C

asp

ian

(Aze

rbai

jan/

Turk

men

ista

n): l

ow

Sce

nari

o(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

aZ

eR

Ba

iJa

NtU

RK

Me

NiS

taN

So

ca

RS

oc

aR

ac

GS

hah

oth

erK

yap

az/

tota

lK

yap

az/

Wes

tern

are

ae

aste

rn a

rea

tota

lo

ffsho

reo

nsho

re &

JV

s(a

ioc

)D

eniz

offs

hore

Ser

dar

(50%

)a

Ze

RB

aiJ

aN

Ser

dar

(50%

)(in

cl. o

ffsho

re)

(con

den

sate

)tU

RK

Me

NiS

taN

bar

rels

per

ton

7.35

7.35

7.40

8.20

8.20

7.40

7.40

7.30

8.20

(per

met

ric t

on)

1990

9.4

3.1

12.5

5.0

0.6

5.6

1991

9.0

2.7

11.7

4.8

0.6

5.4

1992

9.2

2.0

11.2

4.7

0.5

5.2

1993

9.3

1.0

10.3

4.3

0.5

4.8

1994

7.8

1.8

9.6

4.1

0.3

4.4

1995

7.5

1.7

9.2

4.3

0.2

4.5

1996

7.5

1.6

9.1

4.2

0.2

4.4

1997

7.4

1.6

0.1

9.0

4.9

0.1

5.0

1998

7.6

1.6

2.4

11.5

6.0

0.3

6.3

1999

7.5

1.5

4.8

13.8

6.7

0.2

6.9

2000

7.5

1.4

5.1

14.0

7.0

0.2

7.2

2001

7.5

1.5

5.9

14.9

7.8

0.2

8.0

2002

7.4

1.5

6.4

15.3

8.8

0.2

9.0

2003

7.3

1.6

6.5

15.4

9.8

0.2

10.0

2004

7.3

1.7

6.6

15.5

9.9

0.2

10.1

2005

7.4

1.7

13.2

22.2

9.3

0.2

9.5

2006

7.2

1.8

23.3

32.3

8.8

0.2

9.0

2007

7.0

1.8

32.9

0.6

41.7

9.6

0.2

9.8

2008

7.5

1.8

33.3

1.8

44.5

9.8

0.2

10.0

2009

7.3

1.8

40.3

1.0

50.4

10.5

0.2

10.7

2010

7.3

1.8

40.6

1.9

50.8

10.8

0.2

11.0

2011

7.2

1.7

39.9

2.0

0.0

50.8

11.0

0.2

11.2

2012

6.8

1.6

39.1

2.0

0.0

49.6

10.7

0.2

10.9

2013

6.5

1.6

38.2

2.0

0.0

48.3

10.4

0.2

10.6

2014

6.1

1.5

37.9

2.1

0.0

47.6

10.0

0.2

10.2

2015

5.5

1.5

37.5

2.0

0.0

46.5

0.0

9.2

0.2

9.4

2016

5.1

1.4

37.0

2.0

0.0

45.5

0.0

9.2

0.2

9.4

2017

4.7

1.3

36.5

2.0

0.0

44.5

0.0

9.1

0.2

9.3

2018

4.3

1.2

36.0

2.0

0.0

43.5

0.0

9.1

0.2

9.3

2019

3.9

1.1

35.5

2.0

0.0

42.5

0.0

9.0

0.2

9.2

2020

3.5

1.0

35.0

2.0

0.0

41.5

0.0

9.0

0.2

9.2

2021

3.2

0.9

33.6

1.9

0.0

39.6

0.0

8.9

0.2

9.1

2022

2.9

0.8

32.2

1.8

0.0

37.7

0.0

8.9

0.2

9.1

2023

2.5

0.7

30.8

1.8

0.0

35.8

0.0

8.8

0.2

9.0

2024

2.2

0.6

29.4

1.7

0.0

33.9

0.0

8.8

0.2

9.0

2025

1.9

0.5

28.0

1.6

0.0

32.0

0.0

8.7

0.2

8.9

2026

1.7

0.5

27.2

1.5

0.0

30.9

0.0

8.7

0.2

8.9

2027

1.6

0.4

26.4

1.5

0.0

29.9

0.0

8.7

0.2

8.8

2028

1.4

0.4

25.6

1.4

0.0

28.8

0.0

8.6

0.1

8.8

2029

1.3

0.3

24.8

1.4

0.0

27.8

0.0

8.6

0.1

8.7

2030

1.1

0.3

24.0

1.3

0.0

26.7

0.0

8.6

0.1

8.7

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

from

nat

iona

l sta

tistic

al a

genc

ies,

offi

cial

dat

a fr

om m

inis

trie

s, p

ress

ann

ounc

emen

ts, o

r es

timat

es b

y iH

S c

eR

a; p

roje

ctio

ns b

y iH

S c

eR

a.



53


crude-importing countries, such as Ukraine, Belarus, Lithuania, Poland, Hungary, Czech Republic, Slovakia, Romania, and Bulgaria.

Although nearly all the refineries in the FSU—most importantly in Russia—have received significant investment in upgrades in the past decade, the product slate produced is still skewed in favor of heavier products, chiefly mazut (residual fuel oil). In contrast, gasoline has traditionally been the “bottleneck” product on which crude runs are balanced nationally. To project crude consumption (refinery operations), we assume that enough crude oil is delivered to domestic refineries (in each country) such that gasoline demand (which also usually means total demand as well) can be met without resorting to imports, although each country typically still exports and imports some products because demand for the overall product slate is never perfectly balanced by refinery production.

IHS CERA’s fundamental assumption going forward is that the economics of investment in domestic refineries are improving to the point where the operating oil companies are going to spend significant capital on refinery modernization to lighten the product slate. This means that less crude needs to be refined to meet projected light product demand (particularly gasoline). Furthermore, within Russia the plan to unify export taxes between light and heavy products went into effect in October 2011, and the export tax formulae changed so that the relative difference between export duties on exported products and crude will be much less. Depending on the level of crude prices internationally and the exact tax formula, crude exports are likely to generate a higher export netback than the average barrel of refined products (with its large proportion of mazut). Thus the strong incentive that has been in place since 2005 to divert crude from the export stream into domestic refineries may no longer apply after 2011.

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Russia. Crude oil consumption in Russia amounted to 259.6 mt in 2010 (5.25 mbd), comprising 250.0 mt of refinery runs and 9.6 mt of “other” consumption (field losses, transport losses, direct consumption, etc.). This represents an increase of 26.3% from 2004 when the current tax incentives were instituted to divert crude into the domestic refineries. In 2010, Russia’s refined products exports amounted to 132.2 mt (2.64 mbd), of which 126.6 mt was exported outside the CIS (see Table III-1). Much of this comprised heavy, low-value products—54.5% of product exports in 2010 (72.0 mt) was mazut. This results in huge losses of potential export earnings for Russia (that is, compared with exporting these volumes as crude instead of as refined products) and also in export tax revenues for the government because of the much lower export tax on mazut compared with crude oil.

The Russian government is changing export policy so that export taxes on refined products will become much closer to those on crude, making netbacks on crude exports higher than on refined products again. In turn, this implies lower Russian refined product exports; overall refinery runs will decline to where gasoline production and consumption become balanced and the overall product mix shifts to become more closely aligned with domestic demand through modernization and investment. Even so, we expect that rationalization of refinery operations in Russia could be a slow, drawn-out process over many years.

Refinery runs within Russia apparently will peak in 2011. Total Russian crude consumption is expected to decline to 175.5 mt in 2020 and drop further to 175.0 mt by 2030. As a result, Russian exports of refined products will also decline over time. Our figures project that Russian exports to non–CIS countries peaked at 126.6 mt in 2010 and fall to 47.8 mt in 2020 (see Figure III-8 and Tables III-12). Refined products exports from Russia to the non-CIS are expected to decline further, to 42.6 mt by 2030. In the longer term Russia essentially is able to come closer to meeting the product mix set by demand with much lower refinery runs through rationalization of the refineries, with operations phased out or reduced at low-conversion facilities, together with upgrades at remaining refineries that improve the overall product slate.

The geographic distribution of Russian refined products exports is assumed to continue roughly according to recent patterns. The majority is expected to be exported from Baltic Sea terminals and most of the balance via the Black Sea.* Although we do expect slightly more products to be exported via the Pacific because of the planned expansion of Rosneft’s Komsomolsk refinery, we do not yet envisage the construction of a new export-oriented refinery on the Pacific coast. Because of the ongoing expansion of Baltic terminal capacity (especially at Ust-Luga) as well as the general regional location of the bulk of Russia’s refining capacity and potential Bosphorus congestion issues, the Baltic is expected to account for a rising proportion of Russia’s refined product exports over time, from 55.8% in 2010 to 65% in 2020, and 72% by 2030. Conversely, over the outlook horizon we assume that the share of the Black Sea ports drops from just over 21% of total Russian refined product exports to the non-CIS in 2010 to about 20% in 2030.

*The relatively small amount of overland shipments (by rail) is included in the same geographic regions. That is, direct overland shipments to Baltic countries such as Finland, Poland, and the Baltic states are included in the Baltic total, while shipments to non-CIS countries surrounding the Black Sea (e.g., Romania, Bulgaria, and Slovakia) are included in the Black Sea total, and overland shipments to countries such as Mongolia and China are included in the Asia–Far East (“Other Routes”). The purpose is to have the categories add up to 100% of exports rather than to perfectly reflect only seaborne shipments.



55


Caspian. Unlike in Russia, in Kazakhstan and Azerbaijan, crude consumption and refinery throughput are expected to remain more closely tied to developments in aggregate demand for refined products. Overall, the outlook is for relatively flat aggregate demand, but with a gradual shift in the structure of demand in favor of lighter products. When combined with ongoing refinery modernization, crude consumption trends in these countries should not really threaten export volumes (see Figure III-9, Table III-13, Figure III-10, and Table III-14).

In contrast, because of the lack of low-cost pipeline-based crude exports in Turkmenistan, it essentially makes no difference in transportation costs whether the country exports products or crude oil. Therefore, we expect that refinery runs will remain closely tied to crude production rather than to domestic demand. Because we have only a single scenario for consumption, the level of Turkmenistan’s refinery runs is keyed to the low scenario to avoid the need for crude imports. As a result, the base and high production scenarios show sizable crude exports because of surplus crude (see Table III-15).*

Caspian product exports are split between the Black Sea and other destinations, for instance to Iran or to Georgia, or overland to China or Afghanistan (from Kazakhstan and Turkmenistan) largely in accordance with existing patterns.

*This is logically consistent. The higher volumes of crude exports in the base and high production scenarios are likely to be largely produced by international companies. In turn, these companies would also be more likely to export their equity crude rather than to refine it domestically like Turkmenistan’s state-owned producers would.

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Tab

le II

I-12

Out

loo

k fo

r th

e O

il B

alan

ce f

or

the

Rus

sian

Fed

erat

ion

to 2

030

(Bas

e S

cena

rio

)(m

illio

n m

etric

ton

s)

2005

20

06

2007

20

08

2009

20

10

2015

20

20

2025

20

30

cru

de

oil p

rod

uctio

n47

0.0

480.

5 49

1.5

488.

5 49

4.2

505.

1 52

3.3

531.

7 52

5.3

518.

0

Refi

nery

thr

ough

put

207.

4 21

9.6

228.

6 23

6.3

235.

7 25

0.0

186.

5 17

5.5

172.

0 17

5.0

Dire

ct u

se o

f cru

de,

loss

es, c

hang

es in

sto

cks

12.5

14

.8

7.2

11.5

12

.9

9.6

10.2

9.

9 9.

3 8.

7 (

tota

l cru

de

cons

ump

tion)

220.

0 23

4.4

235.

8 24

7.8

248.

6 25

9.6

196.

7 18

5.4

181.

3 18

3.7

Refi

ned

pro

duc

ts c

onsu

mp

tion*

110.

6 11

6.3

117.

1 11

9.5

112.

4 12

0.0

124.

8 12

6.9

129.

2 13

1.6

oil

exp

orts

c

rud

e oi

l25

2.5

248.

4 25

8.4

243.

1 24

7.4

246.

8 32

7.7

347.

4 34

5.1

334.

9

o

utsi

de

the

Form

er S

ovie

t U

nion

206.

7 20

5.2

219.

0 20

2.7

207.

6 21

8.8

289.

8 30

8.4

306.

1 29

5.9

Form

er S

ovie

t re

pub

lics*

*45

.7

43.2

39

.4

40.4

39

.8

28.0

37

.9

39.0

39

.0

39.0

R

efine

d p

rod

ucts

97.0

10

3.5

111.

8 11

7.9

124.

4 13

2.2

62.7

48

.8

43.0

43

.6

out

sid

e th

e Fo

rmer

Sov

iet

Uni

on (N

on-c

iS)

93.1

97

.7

105.

1 10

7.6

115.

4 12

6.6

60.7

47

.8

42.0

42

.6

Form

er S

ovie

t re

pub

lics

(ciS

)3.

9 5.

8 6.

7 10

.3

9.0

5.6

2.0

1.0

1.0

1.0

oil

imp

orts

c

rud

e oi

l2.

4 2.

3 2.

7 2.

5 1.

8 1.

2 1.

0 1.

0 1.

0 0.

5

o

utsi

de

the

Form

er S

ovie

t U

nion

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Form

er S

ovie

t re

pub

lics

2.4

2.3

2.7

2.5

1.8

1.2

1.0

1.0

1.0

0.5

R

efine

d p

rod

ucts

0.2

0.2

0.3

1.1

1.1

2.3

1.0

0.2

0.2

0.2

out

sid

e th

e Fo

rmer

Sov

iet

Uni

on (N

on-c

iS)

0.2

0.2

0.3

0.3

0.3

0.4

0.2

0.2

0.2

0.2

Form

er S

ovie

t re

pub

lics

(ciS

)0.

0 0.

0 0.

1 0.

8 0.

8 1.

9 0.

8 0.

0 0.

0 0.

0

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

and

exp

orts

from

Ros

stat

(Rus

sian

Sta

tistic

al a

genc

y); p

roje

ctio

ns b

y iH

S c

eR

a.

Not

e: H

isto

rical

figu

res

thro

ugh

2010

. 1.

ap

par

ent

cons

ump

tion

(pro

duc

tion

min

us e

xpor

ts p

lus

imp

orts

). 2.

ciS

cou

ntrie

s p

lus

lith

uani

a.



57


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Tab

le II

I-13

Out

loo

k fo

r K

azak

hsta

n's

Cru

de

Oil

Bal

ance

to

203

0 (B

ase

Sce

nari

o)

(in m

illio

n m

etric

ton

s)

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

pro

duc

tion

61.9

64.9

67.1

70.0

76.5

79.7

94.9

110.

114

1.3

153.

3

tota

l exp

orts

52.4

56.8

60.8

64.0

67.3

67.5

85.4

100.

613

1.3

143.

2 e

xpor

ts a

bro

ad49

.754

.457

.560

.167

.669

.084

.499

.613

0.3

142.

7 e

xpor

ts t

o ot

her

rep

ublic

s2.

72.

43.

33.

12.

91.

91.

01.

01.

00.

5to

tal i

mp

orts

3.7

5.7

7.7

6.7

6.1

4.9

4.9

5.0

5.0

5.0

Fro

m R

ussi

a3.

75.

66.

76.

76.

14.

94.

95.

05.

05.

0 F

rom

oth

er (K

yrg.

, Uzb

.)0.

00.

11.

00.

00.

00.

00.

00.

00.

00.

0

Net

exp

orts

48.7

51.1

53.1

57.4

61.2

62.6

80.5

95.6

126.

313

8.2

con

sum

ptio

n (a

pp

aren

t)13

.213

.714

.012

.615

.317

.117

.517

.918

.417

.9 R

efine

ry t

hrou

ghp

ut11

.211

.712

.013

.412

.113

.714

.414

.515

.015

.1

pav

lod

ar3.

73.

94.

34.

14.

14.

84.

95.

05.

05.

0

Shy

mke

nt (c

him

kent

)3.

94.

04.

14.

34.

04.

65.

05.

56.

26.

5

aty

rau

(Gur

'yev

)3.

53.

73.

73.

94.

04.

34.

54.

03.

83.

6

oth

er fa

cilit

ies

--

--

1.2

--

--

--

--

--

--

oth

er c

onsu

mp

tion*

2.1

2.1

2.0

-0.8

3.2

3.4

3.1

3.4

3.4

2.8

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

and

exp

orts

from

Kaz

akhs

tan'

s S

tatis

tical

age

ncy,

ciS

Sta

tistic

s, a

nd M

inis

try

of e

nerg

y; p

roje

ctio

ns b

y iH

S c

eR

a.

1. B

alan

cing

item

; its

exa

ct c

omp

ositi

on is

unk

now

n, b

ut it

wou

ld in

clud

e fie

ld a

nd t

rans

por

tatio

n lo

sses

, cha

nges

in s

tock

s, d

irect

cru

de

use,

etc

.



59


Tab

le II

I-14

Out

loo

k fo

r th

e C

rud

e O

il B

alan

ce o

f A

zerb

aija

n to

203

0 (B

ase

Sce

nari

o)

(mill

ion

met

ric t

ons)

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

cru

de

oil:

p

rod

uctio

n22

.232

.341

.744

.550

.450

.849

.548

.844

.740

.8

So

ca

R9.

09.

08.

89.

39.

19.

17.

64.

83.

52.

3

o

ffsho

re7.

47.

27.

17.

07.

37.

36.

44.

03.

02.

0

o

nsho

re1.

71.

81.

81.

61.

81.

81.

20.

80.

50.

3

aio

c13

.223

.332

.933

.340

.340

.639

.538

.035

.032

.0

Sha

h D

eniz

----

0.6

1.8

1.0

1.9

2.4

3.0

3.0

3.5

R

efine

ry t

hrou

ghp

ut7.

47.

57.

57.

36.

06.

26.

06.

06.

36.

5

los

ses,

etc

. (re

sid

ual)

1.5

2.7

0.7

-0.8

0.5

0.4

0.4

0.3

0.3

0.3

ap

par

ent

cons

ump

tion

8.9

10.1

8.2

6.5

6.6

6.6

6.4

6.3

6.6

6.8

Net

exp

orts

13.3

22.1

35.7

36.3

43.8

44.3

43.1

42.5

38.1

34.0

exp

orts

13.3

22.1

35.7

36.3

43.8

44.3

43.1

42.5

38.1

34.0

im

por

ts0.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

and

exp

orts

from

aze

rbai

jan'

s S

tatis

tical

age

ncy,

ciS

Sta

tistic

s, a

nd S

oc

aR

; pro

ject

ions

by

iHS

ce

Ra

.




Tab

le II

I-15

Out

loo

k fo

r th

e C

rud

e O

il B

alan

ce o

f Tu

rkm

enis

tan

to 2

030

(Bas

e S

cena

rio

)(m

illio

n m

etric

ton

s)

2000

20

01

2002

20

03

2004

20

05

2006

20

07

2008

20

09

2010

20

15

2020

20

25

2030

c

rud

e o

il: p

rod

uctio

n7.

2 8.

0 9.

0 10

.0

10.1

9.

5 9.

0 9.

8 10

.0

10.7

11

.0

11.5

14

.2

14.0

13

.3

exp

orts

1.7

2.3

2.4

1.8

1.0

1.5

1.4

2.0

2.0

2.4

2.4

2.7

5.8

5.7

4.9

im

por

ts0.

6 0.

5 0.

5 0.

4 0.

4 0.

4 0.

4 0.

4 0.

4 0.

3 0.

3 0.

2 0.

2 0.

2 0.

1 a

pp

aren

t co

nsum

ptio

n6.

1 6.

3 7.

1 8.

6 9.

5 8.

4 8.

0 8.

2 8.

4 8.

6 8.

9 9.

0 8.

6 8.

5 8.

5

pro

cess

ing

loss

es, e

tc.

1.2

1.1

1.3

1.8

2.6

1.5

1.1

0.7

0.4

0.4

0.4

0.5

0.5

0.5

0.5

R

efine

ry t

hrou

ghp

ut4.

9 5.

2 5.

7 6.

8 6.

8 6.

9 6.

9 7.

5 8.

0 8.

2 8.

5 8.

5 8.

1 8.

0 8.

0 N

et e

xpor

ts1.

1 1.

8 1.

9 1.

4 0.

6 1.

1 1.

0 1.

6 1.

6 2.

1 2.

1 2.

5 5.

6 5.

5 4.

8

Sou

rce:

Rep

orte

d h

isto

rical

pro

duc

tion

and

exp

orts

from

tur

kmen

ista

n's

Sta

tistic

al a

genc

y w

here

ava

ilab

le; o

ther

wis

e fr

om p

ress

ann

ounc

emen

ts o

r es

timat

es b

y iH

S c

eR

a;

pro

ject

ions

by

iHS

ce

Ra

.



61


3.3 EURASIAN CRUDE OIl ExPORTS

It should be noted that for historical figures, the export totals emerging from the national overview balances do not always exactly match the total exports calculated by adding the data for the various export locations. This is not that unusual given the two types of data that must be blended together: national-level data on export trade are generated by customs-based statistics, while data on exports by individual routes are based on transportation and logistics statistics. This problem was particularly acute at the start of the 1990s when data collection and reporting were in flux and significant flows of crude oil went unreported.

In creating outlooks for Eurasian crude oil exports by location under the nine different combination scenarios, IHS CERA begins by looking at total crude oil exports individually for Russia, Kazakhstan, Azerbaijan, and Turkmenistan under the base, high, and low scenarios. These figures are calculated by subtracting projected consumption (i.e., deliveries of crude oil to domestic refineries and other crude consumption) from projected production.

Then, building on historical data, the projected exports for the years being analyzed are distributed among the various existing and expected future export locations. The distribution is done according to judgments about relative netbacks, available capacity, shipper intentions, government preferences, and similar factors. This produces low, base, and high export outlooks for each country.

Then these individual country outlooks are merged into the nine possible scenario permutations (e.g., base-base, high-high, low-low, base-high, high-base, etc.) as overall regional export outlooks. Typically, this process leads to anomalies (for instance, total exports from a particular export point in a given year might exceed the expected terminal throughput capacity). But such anomalies are removed or rectified through an iterative process, focusing on the target years of 2009, 2010, 2015, 2020, 2025, and 2030 (the intermediate years represent mostly data smoothing, so any discrepancies in these years are essentially ignored).

3.3.1 Russia’s Crude Oil Exports

Russia’s total crude oil exports in 2010 amounted to 246.9 mt (4.94 mbd), or about 49% of its crude oil production (see Table III-1). Russia’s crude oil exports declined very slightly in 2010, by 0.2%. The reason they remained practically flat despite an annual production increment of 10.9 mt (218,000 bd) in 2010 was mainly due to the continued tax incentives to export surplus oil in the form of refined products instead of crude oil (see above).

Exports to FSU countries have dropped dramatically during the transition period, from 120.6 mt (2.41 mbd) in 1990 (representing 54.8% of the entire Russian total) to only 28.0 mt (560,000 bd) in 2008 (11.3% of the total). This includes 26.3 mt (526,000 bd) to the CIS countries and 1.7 mt (34,000 bd) to Lithuania. The dramatic decline in FSU exports since 1990 reflects the considerable changes in oil demand in these countries as well as the commercial conditions for trade between Russia and the CIS. Russia still continues to export sizable volumes to Kazakhstan (for one of the Kazakh refineries in the northeast of the country) as well as to Ukraine and Belarus.




Russia’s crude oil exports outside the FSU (i.e., excluding Lithuania) amounted to 218.9 mt (4.38 mbd) in 2010, up by 5.5% compared with 2009. During Russia’s rapid production rebound (1998–2004), the increment in Russia’s non-FSU exports (96.6 mt, or1.93 mbd) represented about half of the overall increase in oil supply in the global oil market during the period.

Russian crude exports to the non-FSU are transported mainly via three main evacuation routes, accessed via the national pipeline system operated by state-owned Transneft:

Druzhba.• Russian (and other Eurasian) crude reaches markets in a number of Central European countries (Poland, Slovakia, Czech Republic, Hungary, and eastern Germany) directly via the Druzhba pipeline, as crude can access the Gdansk terminal on Poland’s Baltic coast as well. In 2010 exports of 55.5 mt (1.11 mbd) of crude via the Druzhba pipeline to the non-FSU accounted for 25.4% of Russia’s total crude exports to the non-FSU.

Baltic Sea.• Russian (and other Eurasian) crude is also exported via several marine terminals on the Baltic Sea. The largest is now Primorsk, which only went into operation in 2001. Other terminals connected to the Transneft system include Butinge (Lithuania) and Ventspils (Latvia), although both of these are no longer being used. Russia exported 71.7 mt (1.43 mbd) of crude through Baltic terminals in 2010 (not including Gdansk), representing 32.8% of its non-FSU crude exports.

Black Sea.• Russian (and other Eurasian) crude is exported via several Black Sea marine terminals. The Transneft pipeline system moves crude to four Black Sea terminals: Novorossiysk and Tuapse in Russia and Odessa and Pivdenniy in Ukraine. These four terminals dispatched 48.0 mt (960,000 bd) of Russian crude in 2008 but only 38.6 mt (772,000 bd) in 2010. Odessa stopped handling Transneft’s pipeline volumes at the end of 2008, and exports through Pivdenniy stopped at the end of 2010. In addition, several smaller terminals (handling rail and river shipments) and the CPC are also used to export Russian crude. Total 2010 Russian crude exports from Black Sea ports were 45.6 mt (912,000 bd), representing 20.8% of Russia’s overall total to the non-FSU. Russian Black Sea crude exports have been in decline for a number of years, mainly reflecting the opening of Primorsk on the Baltic Sea since 2001. Russia crude exports via the Black Sea peaked in 2003 at 64.2 mt (1.28 mbd), when these exports represented 35.8% of the Russian total to the non-FSU.

In addition to these three main evacuation routes, Russian crude has also been exported in much smaller volumes via a variety of other routes to international markets, often based on rail transport. These include exports via the Barents Sea (e.g., Murmansk, Varandey), rail to China (prior to the startup of the ESPO spur in January 2011), to Iran (via the Caspian Sea) prior to 2009, and via local infrastructure from Sakhalin (e.g., DeKastri, Prigorodnoye).

According to detailed Russian customs statistics (which in aggregate report Russia’s non-CIS crude exports) amounted to 224.1 mt in 2010; Western European countries received 128.6 mt (2.57 mbd) of Russian crude oil in 2010 (52.1% of the Russian reported total), while East European countries received 46.1 mt (0.92 mbd). Including Lithuania, European



63


countries in total received 176.4 mt (3.52 mbd) of Russian crude oil in 2010, representing 71.5% of Russia’s total crude exports to all countries or 78.7% of Russia’s non-CIS exports of crude.

Only 7.3 mt (146,000 bd) went to the United States and 0.9 mt (18,000 bd) went to Canada in 2010, while 9.1 mt (182,000 bd) went to Japan. These figures are all up considerably in the past few years, associated with the opening of the Kozmino terminal on the Pacific coast (see below). Of the remainder, the largest single recipient was China (together with Hong Kong) at 13.2 mt (264,000 bd), followed by South Korea at 10.1 mt (202,000 bd) and then Turkey at 2.9 mt (58,000 bd). But Russian trade statistics also show significant exports to various trade haven countries, such as Cyprus, Virgin Islands, Caymen Islands, Bahamas, etc., so the actual disposition of Russian crude oil in international markets among consuming countries ends up slightly different than the picture shown by Russian data; much of the amount shown as being delivered to these non-European havens probably ends up in Europe as well.

Over the outlook period, Russia’s crude oil exports in the base case are projected to increase to a maximum of 347.3 mt (6.95 mbd) in 2020 and then to drift slowly down to 334.8 mt (6.7 mbd) by 2030. At the same time, refined product exports outside the CIS are projected to decline to 47.8 mt (956,000 bd) in 2020 and to 42.6 mt (852,000 bd) by 2030. In the high case, Russian crude exports are projected to hit a maximum of 403.2 mt (8.1 mbd) in 2025, while in the low case, crude exports contract over the outlook period to only 224.1 mt (4.48 mbd) in 2030.

3.3.2 Kazakhstan’s Crude Oil Exports

Kazakhstan always has exported the bulk of its crude production (85% in 2010). Its total crude exports have increased from 20.3 mt (406,000 bd) in 1992 to 67.5 mt (1.35 mbd) in 2010, a more than threefold increase (see Table III-5).* In 2010, 65.6 mt (1.31 mbd) of the 67.5 mt (1.35 mbd) were exported to markets beyond the FSU, with the remainder (1.9 mt, or 38,000 bd) going to countries in the FSU, principally Russia.**

The principal export routes were as follows in 2010: 28.5 mt (570,000 bd) via CPC; 19.1 mt (382,000 bd) via Transneft, of which 15.5 mt (310,000 bd) went via the Atyrau-Samara pipeline and 3.6 mt (72,000 bd) went via Aktau to Makhachkala; 10.1 mt (202,000 bd) via pipeline to China; 0.5 mt (10,000 bd) went to Iran via Aktau; 5.7 mt (114,000 bd) went by rail (either via Russia to the Black Sea or Baltic ports or via Azerbaijan to Georgia after crossing the Caspian Sea); and 1.2 mt (24,000 bd) went to Russia (from Karachaganak to Orenburg). The total amount of crude oil shipped via Aktau (Kazakhstan’s Caspian port) in 2010 amounted to 9.32 mt (186,000 bd), of which 0.5 mt (10,000 bd) went to Neka in Iran, 3.6 mt (72,000 bd) went to Makhachkala, zero went across the Caspian into the BTC pipeline, and 5.2 mt (104,000 bd) went to the Black Sea ports of Batumi or Kulevi via rail in Azerbaijan and Georgia. Thus, a total of 48.8 mt (976,000 bd) of Kazakhstan crude ended up being exported via the Black Sea in 2010.

*During the Soviet period, all of Kazakhstan’s exports fed into the Russian pipeline system, and it was not credited with supplying any exports to the international market.**This includes 0.2 mt that was delivered to Ukraine from the Black Sea in 2010.




Traditionally, the bulk of Kazakh crude exports outside the FSU have been to countries in the Mediterranean (e.g., 79% in 2003 and 73% in 2005). But that share has been dropping recently. In 2010 only 49.5% of Kazakh crude exports to the non-FSU went to Mediterranean countries; since 2005 there has been significant growth in exports to non-Mediterranean European countries (i.e., Northwest Europe) and especially to China. The largest individual recipients by country in 2010 include Italy, China, France, Netherlands, and Romania.

Under whatever scenario Kazakh crude oil is produced, the Black Sea will remain a major export direction for incremental volumes. Kazakhstan continues to rely heavily on the CPC system terminating in the Black Sea for its exports, and in 2010 about 42% of the country’s total crude exports moved via CPC. CPC volumes currently exceed the nameplate capacity (below Kropotkin) of 28 mt per year (560,000 bd) due to the use of drag-reducing agents (DRAs). Expansion of CPC by 2015 (see below) is considered critical to accommodate estimated incremental Kazakh production of (9.2 mt [about180,000 bd]) by that time in the base scenario.

For Kazakhstan, Eurasia’s second largest oil exporter, crude exports are projected to rise over the outlook period for all three scenarios, driven upward by a combination of rising production and fairly modest oil consumption. In the base case scenario, Kazakhstan’s crude exports are projected to expand to 140.4 mt (2.81 mbd) by 2030, while in the high case, Kazakhstan’s crude exports rise to 182.0 mt (3.64 mbd) by 2030. In the low case, crude exports are much lower, at 90.6 mt (1.81 mbd) in 2030.

During the period before expanded CPC capacity becomes available, most Kazakh producers are focusing on the following routes:

Transneft system via Russia •

Atyrau-Samara. Volumes exiting via the Atyrau-Samara pipeline reached –17.5 mt (350,000 bd) in 2009, exceeding by a considerable margin the rated capacity for the pipeline. Capacity had been 15 mt per year (300,000 bd), but this was expanded by 0.5 mt (10,000 bd) in 2008 and another 0.5 mt (10,000 bd) in 2009, bringing total rated capacity to 16.5 mt (330,000 bd). Flow through the pipeline in 2010 was evidently only about 15.5 mt (310,000 bd). Kazakhstan has been pushing for expansion to 25 mt (500,000 bd), but this will not happen until it becomes expedient for Transneft to debottleneck the three routes out of Samara as well. At the moment, Russian producers are not clamoring for this additional capacity, so expansion plans for Kazakh crude into Samara still remain uncertain.

Odessa. Piped volumes going to Odessa were 7.1 mt (142,000 bd) in 2008, –but this dropped to 2.3 mt (46,000 bd) in 2009 and ceased altogether in 2010. It remains uncertain whether this flow will be restored longer term (this is assumed not to occur in any of IHS CERA’s scenarios).

Rail.• Rail is typically only a stopgap measure given the relatively high unit cost compared to pipelines. For example, TCO shipments by rail to Odessa recently cost up to US$60 per ton (about US$8 per barrel) compared with about US$38 per ton



65


(around US$5 per barrel) for CPC shipments. But it is being increasingly pressed into service again because of the shortage of pipeline capacity for Kazakh oil.

Kazakhstan-China oil pipeline.• For a smaller group of Kazakh producers, located largely in the Kumkol region (Turgay Basin), the Atasu-Alashankou pipeline route to China, available since 2006, represents an attractive alternative to traditional routes. But full-scale utilization of the pipeline depends on two factors. First, the pipeline must be extended to western Kazakhstan, a connection completed just in 2009. Second, more competitive prices will have to be negotiated at the Chinese border. For producers in western Kazakhstan, this route currently offers much lower netbacks than those for westward routes at prevailing transportation tariffs and prices.

Routes via Baku.• Another option remains increased trans-Caspian shipments and access to any spare capacity in the BTC pipeline as well as available capacity at Georgian Black Sea ports. TCO concluded a deal to ship via BTC in 2008–09 but stopped in 2010 because of a dispute over tariffs. Shipments of Kazakh oil across the Caspian and into the BTC might provide an incremental 4 mt (80,000 bd) by 2020 in IHS CERA’s base case.

Iran.• Kazakh crude exports to Iran declined steadily after 2007, falling to 1.7 mt (34,000 bd) in 2008, 1.0 mt (20,000 bd) in 2009, and only 0.5 mt (10,000 bd) in 2010 as they ceased altogether in mid-2010. This was evidently due to Iran’s inability to finance the swap arrangements underlying this trade because of international sanctions. But Iran has now signaled that it wishes to resume the swap arrangement, and volumes to Iran are likely to begin flowing again in the near term given the lack of alternatives (see Tables III-16–III-18).

3.3.3 Azerbaijan’s Crude Oil Exports

Following the launch of the AGC project in 1998, Azerbaijan has emerged as a significant crude oil exporter. Exports in 2010 amounted to 44.3 mt (886,000 bd), or over 87% of national production (see Table III-9). This is up from 2.8 mt in 1998, a nearly sixteenfold increase.

Azerbaijan’s crude exports move through several routes to international markets; the most important is the BTC pipeline that went into operation in 2006. The other routes include the Baku-Supsa pipeline, rail deliveries to Batumi, and the so-called northern route via the Transneft pipeline to Novorossiysk. The important consideration for the Turkish Straits is that the BTC pipeline delivers crude directly into the Mediterranean, while the other routes deliver Azeri crude into the Black Sea.

Given these export outlets, it is hardly surprising that practically all of Azerbaijan’s crude oil exports are delivered to countries in the Mediterranean (about 90–95% until very recently). This has also been the case even at Ceyhan, although the terminal has the capability to load VLCCs for improved economics for long-haul (ex-Mediterranean) shipments (see below).

But because of declining crude production over the outlook period, Azerbaijan’s crude exports also are expected to contract. In the base case scenario, Azerbaijan’s crude oil




Tab

le II

I-16

Kaz

akhs

tan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (B

ase

Sce

nari

o)

(mill

ion

of m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS21

.822

.622

.118

.310

.913

.615

.116

.420

.424

.529

.532

.141

.145

.052

.056

.556

.261

.563

.467

.771

.982

.397

.212

7.9

140.

4

Bla

cK

Se

a0.

00.

05.

05.

02.

32.

03.

74.

16.

813

.017

.619

.426

.729

.537

.143

.039

.640

.944

.145

.248

.863

.267

.979

.280

.0N

ovor

ossi

ysk

4.0

4.0

1.1

0.9

1.7

0.7

0.2

0.4

1.7

3.4

3.3

3.4

3.8

4.0

3.4

5.5

6.2

8.9

9.4

7.8

8.0

9.2

9.0

K

azak

h cr

ude

(via

Sam

ara)

4.0

4.0

1.1

0.9

1.7

0.7

0.2

0.4

0.7

1.1

0.4

0.4

1.6

0.0

0.0

1.2

1.4

5.2

5.8

3.8

4.0

4.2

4.0

K

azak

h cr

ude

(from

Mak

hach

kala

)1.

02.

32.

93.

02.

24.

03.

44.

44.

83.

73.

64.

04.

05.

05.

0o

des

sa1.

01.

01.

21.

12.

01.

51.

94.

88.

28.

17.

17.

27.

66.

56.

46.

67.

12.

30.

00.

00.

00.

00.

0p

ivd

enni

y (v

ia t

rans

neft

')0.

40.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0S

upsa

Bat

umi/K

ulev

i0.

92.

22.

42.

53.

72.

23.

63.

44.

14.

21.

62.

33.

25.

22.

02.

05.

05.

0c

pc

(Yuz

hnay

a o

zere

yevk

a)0.

712

.014

.822

.428

.224

.425

.925

.827

.628

.552

.456

.963

.065

.0R

ail e

xpor

ts v

ia R

ussi

a (to

var

ious

por

ts:

Feod

osiy

a, o

des

sa, e

tc.)

0.0

1.0

2.5

5.4

5.2

3.5

2.1

0.1

0.0

0.2

1.4

1.2

2.7

3.1

5.7

1.0

1.0

2.0

1.0

Ba

ltic

Se

a0.

60.

60.

70.

91.

10.

61.

00.

91.

55.

66.

98.

68.

08.

56.

84.

87.

44.

13.

87.

86.

8Ve

ntsp

ils0.

60.

60.

1B

utin

ge1.

2p

rimor

sk1.

01.

62.

73.

03.

63.

64.

04.

61.

82.

02.

02.

02.

0U

st-l

uga

(Bp

S-2

)0.

00.

03.

73.

0G

dan

sk (v

ia t

rans

neft

'; in

clud

ed a

s p

art

of p

olan

d u

ntil

2003

)3.

43.

84.

14.

44.

62.

50.

05.

22.

01.

71.

71.

5R

ail e

xpor

ts v

ia R

ussi

a (to

var

ious

por

ts:

Kal

inin

grad

, etc

.)0.

60.

91.

10.

61.

00.

90.

50.

60.

40.

30.

00.

30.

20.

20.

40.

10.

10.

40.

3

DR

UZ

HB

a p

ipe

liN

e (t

o e

aste

rn e

urop

e)0.

00.

03.

31.

62.

31.

62.

31.

81.

92.

81.

02.

13.

01.

20.

00.

00.

51.

02.

25.

42.

80.

40.

00.

00.

0p

olan

d0.

20.

20.

60.

50.

40.

50.

71.

70.

01.

02.

30.

90.

00.

00.

51.

01.

02.

02.

40.

40.

00.

00.

0G

erm

any

1.0

1.0

1.0

0.8

1.6

1.0

0.4

1.1

0.9

1.1

0.7

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

cze

ch R

epub

lic0.

20.

20.

30.

30.

20.

00.

0S

lova

kia

0.1

0.1

0.1

0.2

0.4

0.1

1.2

3.2

0.3

Hun

gary

0.1

0.2

0.0

aus

tria

om

isal

j ter

min

al

to R

US

Sia

18.8

19.9

10.7

10.3

4.6

6.9

4.5

6.1

6.7

5.5

7.2

5.0

6.0

5.1

4.2

2.6

2.4

2.6

2.5

1.8

1.2

1.0

1.0

1.0

0.5

to

Rus

sian

refi

nerie

s vi

a S

amar

a12

.212

.64.

34.

21.

32.

50.

51.

83.

50.

40.

80.

20.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0 t

o o

rsk

refin

ery

2.6

2.8

2.6

2.6

1.6

1.9

2.1

2.0

1.1

1.8

1.8

1.4

1.5

0.3

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

to

ore

nbur

g (c

ond

ensa

te)

4.0

4.5

3.8

3.5

1.7

2.5

1.9

2.3

2.1

3.3

4.6

3.4

4.5

4.8

4.1

2.6

2.4

2.6

2.5

1.8

1.2

1.0

1.0

1.0

0.5

to F

SU

Re

pU

Bli

cS

0.0

0.0

2.1

0.4

0.4

2.0

3.8

3.4

3.8

2.3

1.9

3.7

2.4

1.3

0.7

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Bel

arus

(dire

ct b

y p

ipe)

0.1

0.1

0.5

lith

uani

a (d

irect

by

pip

e)0.

20.

21.

80.

30.

10.

70.

1 U

krai

ne (d

irect

by

pip

e)1.

90.

30.

31.

82.

03.

13.

21.

61.

93.

72.

41.

30.

70.

0

iRa

N0.

00.

00.

00.

00.

00.

00.

00.

10.

00.

00.

00.

00.

61.

31.

91.

42.

12.

91.

71.

01.

21.

02.

02.

02.

8 K

azak

h cr

ude

0.1

0.6

1.3

1.9

1.4

2.1

2.9

1.7

1.0

1.2

1.0

2.0

2.0

2.8

b

y se

a0.

10.

61.

31.

51.

42.

12.

91.

71.

00.

51.

02.

02.

02.

8

by

rail

0.0

0.4



67


Tab

le II

I-16

Kaz

akhs

tan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (B

ase

Sce

nari

o) (

cont

inue

d)

(mill

ion

of m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

ea

St

aS

ia0.

00.

00.

00.

00.

00.

00.

00.

00.

10.

40.

81.

00.

90.

80.

90.

83.

75.

65.

87.

010

.111

.418

.520

.425

.0 K

azak

h cr

ude

to c

hina

(mai

nly

turg

ay

Bas

in)

0.1

0.4

0.8

0.5

0.4

0.8

0.8

0.8

3.7

5.6

5.8

7.0

7.5

11.4

18.5

20.4

25.0

R

ail

0.1

0.4

0.8

0.5

0.4

0.8

0.8

0.8

1.5

0.8

0.8

0.8

0.0

K

azak

hsta

n-c

hina

pip

elin

e2.

24.

85.

06.

27.

511

.418

.520

.425

.0 R

ussi

an c

rud

e (s

wap

ped

from

pav

lod

ar)

0.5

0.5

0.1

2.6

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.3

1.9

0.0

1.2

4.0

17.5

25.3

Kaz

akh

crud

e0.

31.

90.

01.

24.

017

.525

.3

to a

Ze

RB

aiJ

aN

2.5

2.2

1.0

0.9

0.7

0.5

0.0

0.0

0.0

to o

tHe

R R

ep

UB

lic

S0.

50.

50.

10.

10.

00.

00.

00.

00.

00.

00.

00.

00.

00.

30.

30.

00.

00.

00.

00.

70.

50.

00.

00.

00.

0 U

zbek

ista

n0.

50.

50.

30.

30.

70.

5 t

urkm

enis

tan

0.1

0.1

0.0

exp

orts

via

akt

au/K

uryk

por

t0.

00.

00.

00.

00.

00.

00.

10.

91.

82.

13.

34.

95.

36.

07.

18.

19.

68.

99.

19.

89.

38.

212

.029

.538

.1

exp

orts

via

aty

rau-

Sam

ara

pip

elin

e12

.212

.612

.610

.86.

58.

710

.59.

211

.210

.612

.715

.313

.915

.416

.414

.914

.817

.017

.317

.515

.58.

27.

711

.610

.5

Sou

rce:

tot

al e

xpor

ts r

epor

ted

by

cus

tom

s S

tatis

tics

(Kaz

akhs

tan'

s S

tatis

tical

age

ncy)

; sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.




Tab

le II

I-17

Kaz

akhs

tan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (H

igh

Sce

nari

o)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS21

.822

.622

.118

.310

.913

.615

.116

.420

.424

.529

.532

.141

.145

.052

.056

.556

.261

.563

.467

.771

.993

.012

4.3

167.

718

2.0

Bla

cK

Se

a0.

00.

05.

05.

02.

32.

03.

74.

16.

813

.017

.619

.426

.729

.537

.143

.039

.640

.944

.145

.248

.865

.386

.097

.495

.3N

ovor

ossi

ysk

4.0

4.0

1.1

0.9

1.7

0.7

0.2

0.4

1.7

3.4

3.3

3.4

3.8

4.0

3.4

5.5

6.2

8.9

9.4

7.7

8.5

13.0

13.0

K

azak

h cr

ude

(via

Sam

ara)

4.0

4.0

1.1

0.9

1.7

0.7

0.2

0.4

0.7

1.1

0.4

0.4

1.6

0.0

0.0

1.2

1.4

5.2

5.8

4.0

4.0

6.5

6.5

K

azak

h cr

ude

(from

Mak

hach

kala

)1.

02.

32.

93.

02.

24.

03.

44.

44.

83.

73.

63.

74.

56.

56.

5o

des

sa1.

01.

01.

21.

12.

01.

51.

94.

88.

28.

17.

17.

27.

66.

56.

46.

67.

12.

30.

00.

08.

59.

89.

2p

ivd

enni

y (v

ia t

rans

neft

')0.

40.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0S

upsa

Bat

umi/K

ulev

i0.

92.

22.

42.

53.

72.

23.

63.

44.

14.

21.

62.

33.

25.

24.

57.

59.

17.

1c

pc

(Yuz

hnay

a o

zere

yevk

a)0.

712

.014

.822

.428

.224

.425

.925

.827

.628

.551

.053

.065

.066

.0R

ail e

xpor

ts v

ia R

ussi

a (to

var

ious

por

ts:

Feod

osiy

a, o

des

sa, e

tc.)

0.0

1.0

2.5

5.4

5.2

3.5

2.1

0.1

0.0

0.2

1.4

1.2

2.7

3.1

5.7

2.1

8.5

0.5

0.0

Ba

ltic

Se

a0.

60.

60.

70.

91.

10.

61.

00.

91.

55.

66.

98.

68.

08.

56.

84.

87.

44.

24.

09.

66.

5Ve

ntsp

ils0.

60.

60.

1B

utin

ge1.

2p

rimor

sk1.

01.

62.

73.

03.

63.

64.

04.

61.

82.

22.

02.

02.

0U

st-l

uga

(Bp

S-2

)0.

00.

03.

62.

5G

dan

sk (v

ia t

rans

neft

'; in

clud

ed a

s p

art

of p

olan

d u

ntil

2003

)3.

43.

84.

14.

44.

62.

50.

05.

22.

02.

04.

02.

0R

ail e

xpor

ts v

ia R

ussi

a (to

var

ious

por

ts:

Kal

inin

grad

, etc

.)0.

60.

91.

10.

61.

00.

90.

50.

60.

40.

30.

00.

30.

20.

20.

40.

00.

00.

00.

0

DR

UZ

HB

a p

ipe

liN

e (t

o e

aste

rn e

urop

e)0.

00.

03.

31.

62.

31.

62.

31.

81.

92.

81.

02.

13.

01.

20.

00.

00.

51.

02.

25.

42.

80.

00.

00.

00.

0p

olan

d0.

20.

20.

60.

50.

40.

50.

71.

70.

01.

02.

30.

90.

00.

00.

51.

01.

02.

02.

40.

00.

00.

00.

0G

erm

any

1.0

1.0

1.0

0.8

1.6

1.0

0.4

1.1

0.9

1.1

0.7

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

cze

ch R

epub

lic0.

20.

20.

30.

30.

20.

00.

0S

lova

kia

0.1

0.1

0.1

0.2

0.4

0.1

1.2

3.2

0.3

Hun

gary

0.1

0.2

0.0

aus

tria

om

isal

j ter

min

al &

cro

atia

/Ser

bia

/S

love

nia

to R

US

Sia

18.8

19.9

10.7

10.3

4.6

6.9

4.5

6.1

6.7

5.5

7.2

5.0

6.0

5.1

4.2

2.6

2.4

2.6

2.5

1.8

1.2

2.0

2.0

2.0

1.5

to

Rus

sian

refi

nerie

s vi

a S

amar

a12

.212

.64.

34.

21.

32.

50.

51.

83.

50.

40.

80.

20.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0 t

o o

rsk

refin

ery

2.6

2.8

2.6

2.6

1.6

1.9

2.1

2.0

1.1

1.8

1.8

1.4

1.5

0.3

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

to

ore

nbur

g (c

ond

ensa

te)

4.0

4.5

3.8

3.5

1.7

2.5

1.9

2.3

2.1

3.3

4.6

3.4

4.5

4.8

4.1

2.6

2.4

2.6

2.5

1.8

1.2

2.0

2.0

2.0

1.5

to F

SU

Re

pU

Bli

cS

0.0

0.0

2.1

0.4

0.4

2.0

3.8

3.4

3.8

2.3

1.9

3.7

2.4

1.3

0.7

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Bel

arus

(dire

ct b

y p

ipe)

0.1

0.1

0.5

lith

uani

a (d

irect

by

pip

e)0.

20.

21.

80.

30.

10.

70.

1 U

krai

ne (d

irect

by

pip

e)1.

90.

30.

31.

82.

03.

13.

21.

61.

93.

72.

41.

30.

70.

0

iRa

N0.

00.

00.

00.

00.

00.

00.

00.

10.

00.

00.

00.

00.

61.

31.

91.

42.

12.

91.

71.

01.

22.

53.

04.

04.

0 K

azak

h cr

ude

0.1

0.6

1.3

1.9

1.4

2.1

2.9

1.7

1.0

1.2

2.5

3.0

4.0

4.0

b

y se

a0.

10.

61.

31.

51.

42.

12.

91.

71.

00.

52.

53.

04.

04.

0

by

rail

0.0

0.4



69


Tab

le II

I-17

Kaz

akhs

tan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (H

igh

Sce

nari

o) (

cont

inue

d)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

ea

St

aS

ia0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

4 0.

8 1.

0 0.

9 0.

8 0.

9 0.

8 3.

7 5.

6 5.

8 7.

0 10

.1

16.0

19

.3

25.0

30

.0

Kaz

akh

crud

e to

chi

na (m

ainl

y tu

rgay

B

asin

)0.

1 0.

4 0.

8 0.

5 0.

4 0.

8 0.

8 0.

8 3.

7 5.

6 5.

8 7.

0 7.

5 16

.0

19.3

25

.0

30.0

Rai

l0.

1 0.

4 0.

8 0.

5 0.

4 0.

8 0.

8 0.

8 1.

5 0.

8 0.

8 0.

8 0.

0 0.

0 0.

0 0.

0 0.

0

Kaz

akhs

tan-

chi

na p

ipel

ine

2.2

4.8

5.0

6.2

7.5

16.0

19

.3

25.0

30

.0

Rus

sian

cru

de

(sw

app

ed fr

om p

avlo

dar

)0.

5 0.

5 0.

1 2.

6

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.3

1.9

0.0

3.0

10.0

29

.7

44.7

K

azak

h cr

ude

0.3

1.9

0.0

3.0

10.0

29

.7

44.7

to a

Ze

RB

aiJ

aN

2.5

2.2

1.0

0.9

0.7

0.5

0.0

0.0

0.0

to o

tHe

R R

ep

UB

lic

S0.

5 0.

5 0.

1 0.

1 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

3 0.

3 0.

0 0.

0 0.

0 0.

0 0.

7 0.

5 0.

0 0.

0 0.

0 0.

0 U

zbek

ista

n (K

azak

h cr

ude)

0.5

0.5

0.3

0.3

0.7

0.5

tur

kmen

ista

n (K

azak

h cr

ude)

0.1

0.1

0.0

exp

orts

via

akt

au/K

uryk

por

t0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

9 1.

8 2.

1 3.

3 4.

9 5.

3 6.

0 7.

1 8.

1 9.

6 8.

9 9.

1 9.

8 9.

3 13

.7

25.0

49

.3

62.3

exp

orts

via

aty

rau-

Sam

ara

pip

elin

e12

.2

12.6

12

.6

10.8

6.

5 8.

7 10

.5

9.2

11.2

10

.6

12.7

15

.3

13.9

15

.4

16.4

14

.9

14.8

17

.0

17.3

17

.5

15.5

8.

2 16

.5

25.9

22

.2

Sou

rce:

tot

al e

xpor

ts r

epor

ted

by

cus

tom

s S

tatis

tics

(Kaz

akhs

tan'

s S

tatis

tical

age

ncy)

; sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.




Tab

le II

I-18

Kaz

akhs

tan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (l

ow

Sce

nari

o)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS21

.822

.622

.118

.310

.913

.615

.116

.420

.424

.529

.532

.141

.145

.052

.056

.556

.261

.563

.467

.771

.971

.777

.483

.690

.6

Bla

cK

Se

a0.

00.

05.

05.

02.

32.

03.

74.

16.

813

.017

.619

.426

.729

.537

.143

.039

.640

.944

.145

.248

.844

.349

.253

.459

.6N

ovor

ossi

ysk

4.0

4.0

1.1

0.9

1.7

0.7

0.2

0.4

1.7

3.4

3.3

3.4

3.8

4.0

3.4

5.5

6.2

8.9

9.4

9.0

6.3

6.0

6.0

K

azak

h cr

ude

(via

Sam

ara)

4.0

4.0

1.1

0.9

1.7

0.7

0.2

0.4

0.7

1.1

0.4

0.4

1.6

0.0

0.0

1.2

1.4

5.2

5.8

5.0

3.0

3.0

3.0

K

azak

h cr

ude

(from

Mak

hach

kala

)1.

02.

32.

93.

02.

24.

03.

44.

44.

83.

73.

64.

03.

33.

03.

0o

des

sa1.

01.

01.

21.

12.

01.

51.

94.

88.

28.

17.

17.

27.

66.

56.

46.

67.

12.

30.

00.

00.

00.

00.

0p

ivd

enni

y (v

ia t

rans

neft

')0.

40.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0S

upsa

Bat

umi/K

ulev

i0.

92.

22.

42.

53.

72.

23.

63.

44.

14.

21.

62.

33.

25.

23.

11.

51.

00.

5c

pc

(Yuz

hnay

a o

zere

yevk

a)0.

712

.014

.822

.428

.224

.425

.925

.827

.628

.532

.241

.446

.453

.1R

ail e

xpor

ts v

ia R

ussi

a (to

var

ious

por

ts:

Feod

osiy

a, o

des

sa, e

tc.)

0.0

1.0

2.5

5.4

5.2

3.5

2.1

0.1

0.0

0.2

1.4

1.2

2.7

3.1

5.7

Ba

ltic

Se

a0.

60.

60.

70.

91.

10.

61.

00.

91.

55.

66.

98.

68.

08.

56.

84.

87.

44.

80.

00.

00.

0Ve

ntsp

ils0.

60.

60.

1B

utin

ge1.

2p

rimor

sk1.

01.

62.

73.

03.

63.

64.

04.

61.

82.

00.

00.

00.

0U

st-l

uga

(Bp

S-2

)1.

30.

00.

00.

0G

dan

sk (v

ia t

rans

neft

'; in

clud

ed a

s p

art

of p

olan

d u

ntil

2003

)3.

43.

84.

14.

44.

62.

50.

05.

21.

00.

00.

00.

0R

ail e

xpor

ts v

ia R

ussi

a (to

var

ious

por

ts:

Kal

inin

grad

, etc

.)0.

60.

91.

10.

61.

00.

90.

50.

60.

40.

30.

00.

30.

20.

20.

40.

5

DR

UZ

HB

a p

ipe

liN

e (t

o e

aste

rn e

urop

e)0.

00.

03.

31.

62.

31.

62.

31.

81.

92.

81.

02.

13.

01.

20.

00.

00.

51.

02.

25.

42.

80.

00.

00.

00.

0p

olan

d0.

20.

20.

60.

50.

40.

50.

71.

70.

01.

02.

30.

90.

00.

00.

51.

01.

02.

02.

40.

00.

00.

00.

0G

erm

any

1.0

1.0

1.0

0.8

1.6

1.0

0.4

1.1

0.9

1.1

0.7

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

cze

ch R

epub

lic0.

20.

20.

30.

30.

20.

00.

0S

lova

kia

0.1

0.1

0.1

0.2

0.4

0.1

1.2

3.2

0.3

Hun

gary

0.1

0.2

0.0

aus

tria

om

isal

j ter

min

al

to R

US

Sia

18.8

19.9

10.7

10.3

4.6

6.9

4.5

6.1

6.7

5.5

7.2

5.0

6.0

5.1

4.2

2.6

2.4

2.6

2.5

1.8

1.2

1.5

1.0

1.0

1.0

to

Rus

sian

refi

nerie

s vi

a S

amar

a12

.212

.64.

34.

21.

32.

50.

51.

83.

50.

40.

80.

20.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

0 t

o o

rsk

refin

ery

2.6

2.8

2.6

2.6

1.6

1.9

2.1

2.0

1.1

1.8

1.8

1.4

1.5

0.3

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

to

ore

nbur

g (c

ond

ensa

te)

4.0

4.5

3.8

3.5

1.7

2.5

1.9

2.3

2.1

3.3

4.6

3.4

4.5

4.8

4.1

2.6

2.4

2.6

2.5

1.8

1.2

1.5

1.0

1.0

1.0

to F

SU

Re

pU

Bli

cS

0.0

0.0

2.1

0.4

0.4

2.0

3.8

3.4

3.8

2.3

1.9

3.7

2.4

1.3

0.7

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Bel

arus

(dire

ct b

y p

ipe)

0.1

0.1

0.5

lith

uani

a (d

irect

by

pip

e)0.

20.

21.

80.

30.

10.

70.

1 U

krai

ne (d

irect

by

pip

e)1.

90.

30.

31.

82.

03.

13.

21.

61.

93.

72.

41.

30.

70.

0

iRa

N0.

00.

00.

00.

00.

00.

00.

00.

10.

00.

00.

00.

00.

61.

31.

91.

42.

12.

91.

71.

01.

21.

02.

02.

02.

0 K

azak

h cr

ude

0.1

0.6

1.3

1.9

1.4

2.1

2.9

1.7

1.0

1.2

1.0

2.0

2.0

2.0

b

y se

a0.

1 0.

6 1.

3 1.

5 1.

4 2.

1 2.

9 1.

7 1.

0 0.

5 1.

0 2.

0 2.

0 2.

0

by

rail

0.0

0.4

0.0

0.0

0.0

0.0



71


Tab

le II

I-18

Kaz

akhs

tan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (l

ow

Sce

nari

o) (

cont

inue

d)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

ea

St

aS

ia0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

4 0.

8 1.

0 0.

9 0.

8 0.

9 0.

8 3.

7 5.

6 5.

8 7.

0 10

.1

15.6

18

.5

20.0

20

.0

Kaz

akh

crud

e to

chi

na (m

ainl

y tu

rgay

B

asin

)0.

1 0.

4 0.

8 0.

5 0.

4 0.

8 0.

8 0.

8 3.

7 5.

6 5.

8 7.

0 7.

5 15

.6

18.5

20

.0

20.0

Rai

l0.

1 0.

4 0.

8 0.

5 0.

4 0.

8 0.

8 0.

8 1.

5 0.

8 0.

8 0.

8 0.

0

Kaz

akhs

tan-

chi

na p

ipel

ine

2.2

4.8

5.0

6.2

7.5

15.6

18

.5

20.0

20

.0

Rus

sian

cru

de

(sw

app

ed fr

om p

avlo

dar

)0.

5 0.

5 0.

1 2.

6

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.3

1.9

0.0

4.5

6.7

7.2

8.0

Kaz

akh

crud

e0.

3 1.

9 0.

0 4.

5 6.

7 7.

2 8.

0

to a

Ze

RB

aiJ

aN

2.5

2.2

1.0

0.9

0.7

0.5

0.0

0.0

0.0

to o

tHe

R R

ep

UB

lic

S0.

5 0.

5 0.

1 0.

1 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

3 0.

3 0.

0 0.

0 0.

0 0.

0 0.

7 0.

5 0.

0 0.

0 0.

0 0.

0 U

zbek

ista

n (K

azak

h cr

ude)

0.5

0.5

0.3

0.3

0.7

0.5

tur

kmen

ista

n (K

azak

h cr

ude)

0.1

0.1

0.0

exp

orts

via

akt

au/K

uryk

por

t0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

9 1.

8 2.

1 3.

3 4.

9 5.

3 6.

0 7.

1 8.

1 9.

6 8.

9 9.

1 9.

8 9.

3 12

.6

13.5

13

.2

13.5

exp

orts

via

aty

rau-

Sam

ara

pip

elin

e12

.2

12.6

12

.6

10.8

6.

5 8.

7 10

.5

9.2

11.2

10

.6

12.7

15

.3

13.9

15

.4

16.4

14

.9

14.8

17

.0

17.3

17

.5

15.5

9.

3 3.

0 3.

0 3.

0

Sou

rce:

tot

al e

xpor

ts r

epor

ted

by

cus

tom

s S

tatis

tics

(Kaz

akhs

tan’

s S

tatis

tical

age

ncy)

; sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.




exports decline to 34 mt (680,000 bd) by 2030. In the high case, Azerbaijan’s exports hold up and still remain at 48.3 mt (966,000 bd) in 2030, while in the low case they fall to only 19.9 mt (398,000 bd).

BTC. The BTC pipeline reached its design capacity of 50 mt per year (1 mbd) in April 2007. In 2010 the BTC consortium expanded the pipeline’s effective capacity by 10 mt per year (200,000 bd) using DRAs. Further capacity expansion, albeit involving much greater expenditures, is possible.

The availability of BTC capacity helped Azeri exports surge by nearly 60 percent in 2007, to 35.2 mt (704,000 bd), with 28.4 mt (568,000 bd) (80%) exported via the BTC. The pipeline was handling about 850,000 bd prior to the explosion on August 5, 2008, in Turkey that disabled the pipeline, and following repairs, loadings have rebounded to about 870,000 bd. Azeri volumes in BTC amounted to 37.6 mt (752,000 bd) in 2009 and 37.3 mt (746,000 bd) in 2010.

Azeri crude (mainly from ACG) will continue to constitute the bulk of throughput in the near term, but Kazakh volumes entered in 2008 (0.3 mt, or 6,000 bd) and 2009 (1.9 mt, or 38,000 bd), and this stream is expected to grow to 4 mt per year (80,000 bd) by 2020, expanding substantially as Kashagan output ramps up, to reach over 25 mt per year (500,000 bd) by 2030. While Kazakh injections ceased in 2010, Turkmen crude entered BTC for the first time in 2010. By 2030 the BTC pipeline is projected to be carrying over 56 mt in the base case scenario, of which 28.5 mt (570,000 bd) (50.6%) is expected to be Azeri crude, 25.3 mt (506,000 bd) (44.9 %) is expected to the Kazakh crude, and 2.5 mt (50,000 bd) (4.4%) is expected to be Turkmen crude.

The volume of Azeri crude oil exported via other available routes will also play a key role in determining the overall level of BTC utilization (and hence availability of any spare capacity for non-Azeri crude). Two of these are via pipeline to the Black Sea: Baku-Novorossiysk and Supsa.

Baku–Novorossiysk pipeline. Azeri volumes in 2010 (2.2 mt, or 44,000 bd) were only about half of what they had been in 2005–06 before the opening of the BTC pipeline. The route has a capacity of about 7.5 mt per year (150,000 bd). SOCAR currently has a limit of 5 mt per year (100,000 bd), but with actual shipments running only 2.0–2.5 mt per year (40,000–50,000 bd), Transneft wants to reduce SOCAR’s allocation to 3.0–3.5 mt per year (60,000–70,000 bd), so that capacity can be freed up to handle LUKOIL’s production from the offshore Caspian longer term (see above). Azeri volumes access the line under a government-to-government agreement that sets tariffs and throughput conditions. A dispute between SOCAR and Transneft over the long-term tariff rate for the Baku-Novorossiysk pipeline led to a temporary cessation of all SOCAR shipments via the pipeline in January 2008 when that agreement expired. But the two sides have since agreed to continue shipments in line with the previous terms on a month-to-month basis. We assume that longer term, Azeri exports via this route are gradually phased out, mainly because of the decline in overall Azeri crude oil exports.



73


Baku–Supsa pipeline. The Baku-Supsa route was reactivated following 18 months of repairs in summer 2008, but the AIOC, which owns and operates the pipeline, closed the pipeline again as a security precaution during the August Georgian-Russian crisis. It has since reopened, carrying about 0.6 mt (12,000 bd) in 2008, 4.2 mt (84,000 bd) in 2009, and 4.0 mt (80,000 bd) in 2010. Following the repairs, its nameplate capacity is about 8 mt per year (160,000 bd). SOCAR approached the AIOC consortium to use this line for SOCAR exports, but the AIOC consortium seems unlikely to agree to this (see Tables III-19–III-21).

Georgian ports. Some Azeri crude (mainly some of ExxonMobil’s equity crude in the ACG project) has been exported via Batumi. The volume was relatively large earlier (4.7 mt, or 94,000 bd in 2007), but shipments have been declining with the availability of pipeline transport. Combined, the three Georgia terminals—Batumi, Kulevi, and Poti—loaded about 6.3 mt of crude (126,000 bd) and 4.2 mt of products in 2010, or 10.5 mt total, up from 9.3 mt in 2009. The higher volumes in 2010 were mainly because of higher Tengiz (TCO) supplies as well as the diversion of Turkmen crude from Iran (see below).

One new potential route for oil exports from Azerbaijan is the Kulevi terminal on the Georgian Black Sea coast, which like Batumi is linked to Baku by rail. It is now owned and controlled by SOCAR. The port has combined crude and product capacity of about 10 mt per year (200,000 bd), including handling capacities of 3 mt for crude oil (60,000 bd), 3 mt (62,000 bd) for diesel, and 4 mt (71,000 bd) for fuel oil. The inauguration of the terminal in 2008 (although it closed temporarily because of the August Georgian-Russian crisis) marked the culmination of a major investment drive by SOCAR, which purchased a 51% stake in the terminal in late 2006. A US$500 million three-year loan obtained by SOCAR in early 2008 from an international bank syndicate, the largest unsecured loan ever made to an Azeri company, was intended in part to complete the Kulevi facilities, which had been under construction since the 1990s. Kulevi loaded its first crude oil in May 2010. SOCAR might achieve maximum crude throughput rates at Kulevi by reallocating some of its own output from other routes (mainly BTC, Novorossiysk, and Batumi), but for the time being the only crude being handled by Kulevi is from TCO.

A challenge for SOCAR is finding the crude and refined product supplies needed to operate the terminal near its full capacity from sources other than Azerbaijan. Kazakhstan is one possible source of crude for Kulevi in the near term, but Astana would naturally prefer to supply Kazakh crude to the Batumi terminal, which is now controlled by KMG.

KMG assumed full ownership of the Batumi terminal in 2007 by buying out the 50% share that previously belonged to Greenoak and other shareholders (for up to US$500 million according to one estimate). Shortly after completing the purchase, KMG announced that the terminal, with combined crude and product loading capacity of over 15 mt per year (300,000 bd), would be managed by Rompetrol, in which KMG holds a 75% stake. Rompetrol’s other assets include Romanian terminal facilities and a refinery, Petromidia, that are a logical destination for some share of the crude exiting Batumi. Batumi handled a combined 6.1 mt of crude and products in 2010, although volumes have been declining from the record 11.7 mt throughput of 2006.




Tab

le II

I-19

Aze

rbai

jan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (B

ase

Sce

nari

o)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS (n

et)

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.1

2.8

5.9

5.7

8.3

8.8

9.0

9.3

14.0

22

.2

35.4

36

.3

46.1

44

.2

43.1

42

.5

38.1

34

.0

Bla

cK

Se

a0.

1 2.

8 5.

9 5.

7 8.

3 8.

8 9.

0 9.

3 13

.4

14.2

6.

9 4.

3 8.

6 6.

9 7.

0 6.

0 5.

5 5.

5 N

ovor

ossi

ysk

0.1

2.8

1.9

0.6

2.3

2.8

2.6

2.8

4.3

4.4

2.2

1.5

2.5

2.2

1.5

0.5

0.0

0.0

Sup

sa4.

0 5.

1 5.

9 5.

9 6.

2 6.

4 7.

0 5.

6 0.

0 0.

6 4.

2 4.

0 4.

5 4.

5 4.

5 4.

5 B

atum

i/Kul

evi

0.1

0.1

0.2

0.1

2.1

4.2

4.7

2.2

1.9

0.7

1.0

1.0

1.0

1.0

cp

c (Y

uzhn

aya

oze

reye

vka)

iRa

N0.

2 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 a

zerb

aija

ni c

rud

e0.

2 0.

0 0.

0 0.

0 0.

0 0.

0

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.6

8.0

28.4

31

.8

37.6

37

.3

36.1

36

.5

32.6

28

.5

aze

rbai

jani

cru

de

0.6

8.0

28.4

31

.8

37.6

37

.3

36.1

36

.5

32.6

28

.5

Sou

rce:

tot

al e

xpor

ts r

epor

ted

by

cus

tom

s S

tatis

tics

(aze

rbai

jan’

s S

tatis

tical

age

ncy)

; sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.



75


Tab

le II

I-20

Aze

rbai

jan’

s C

rud

e O

il E

xpo

rts

by

loca

tio

n (H

igh

Sce

nari

o)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS (n

et)

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.1

2.8

5.9

5.7

8.3

8.8

9.0

9.3

14.0

22

.2

35.4

36

.3

46.1

44

.2

53.6

55

.0

54.7

48

.3

Bla

cK

Se

a0.

1 2.

8 5.

9 5.

7 8.

3 8.

8 9.

0 9.

3 13

.4

14.2

6.

9 4.

3 8.

6 6.

9 8.

6 9.

5 8.

5 7.

0 N

ovor

ossi

ysk

0.1

2.8

1.9

0.6

2.3

2.8

2.6

2.8

4.3

4.4

2.2

1.5

2.5

2.2

2.0

1.0

0.5

0.0

Sup

sa4.

0 5.

1 5.

9 5.

9 6.

2 6.

4 7.

0 5.

6 0.

0 0.

6 4.

2 4.

0 4.

5 5.

0 5.

0 5.

0 B

atum

i/Kul

evi

0.1

0.1

0.2

0.1

2.1

4.2

4.7

2.2

1.9

0.7

2.1

3.5

3.0

2.0

cp

c (Y

uzhn

aya

oze

reye

vka)

iRa

N0.

2 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 a

zerb

aija

ni c

rud

e0.

2 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.6

8.0

28.4

31

.8

37.6

37

.3

45.0

45

.5

46.2

41

.3

aze

rbai

jani

cru

de

0.6

8.0

28.4

31

.8

37.6

37

.3

45.0

45

.5

46.2

41

.3

Sou

rce:

tot

al e

xpor

ts r

epor

ted

by

cus

tom

s S

tatis

tics

(aze

rbai

jan’

s S

tatis

tical

age

ncy)

; sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.




Tab

le II

I-21

Aze

rbai

jan’

s C

rud

e O

il E

xpo

rts

By

loca

tio

n (l

ow

Sce

nari

o)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS (n

et)

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.1

2.8

5.9

5.7

8.3

8.8

9.0

9.3

14.0

22.2

35.4

36.3

46.1

44.2

40.6

35.2

25.4

19.9

Bla

cK

Se

a0.

12.

85.

95.

78.

38.

89.

09.

313

.414

.26.

94.

38.

66.

96.

04.

54.

54.

5 N

ovor

ossi

ysk

0.1

2.8

1.9

0.6

2.3

2.8

2.6

2.8

4.3

4.4

2.2

1.5

2.5

2.2

1.5

Sup

sa4.

05.

15.

95.

96.

26.

47.

05.

60.

00.

64.

24.

04.

04.

54.

54.

5 B

atum

i/Kul

evi

0.1

0.1

0.2

0.1

2.1

4.2

4.7

2.2

1.9

0.7

0.5

cp

c (Y

uzhn

aya

oze

reye

vka)

iRa

N0.

20.

00.

00.

00.

00.

00.

0 a

zerb

aija

ni c

rud

e0.

20.

00.

00.

00.

00.

00.

0

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.6

8.0

28.4

31.8

37.6

37.3

34.6

30.6

20.8

15.4

aze

rbai

jani

cru

de

0.6

8.0

28.4

31.8

37.6

37.3

34.6

30.7

20.9

15.4

Sou

rce:

tot

al e

xpor

ts r

epor

ted

by

cus

tom

s S

tatis

tics

(aze

rbai

jan’

s S

tatis

tical

age

ncy)

; sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.



77


Iran. A small amount of Azeri crude was also diverted to Iran for the first time ever in 2008 but only for a short period. This was the result of the Georgian-Russian crisis that closed off the evacuation routes across Georgia.

3.3.4. Turkmenistan’s Crude Oil Exports

Turkmenistan’s crude oil exports remain fairly small: less than 2.4 mt per year (48,000 bd) in recent years (see Table III-10). This is because only international companies export crude oil; crude produced by the state-owned companies is directed into the country’s refineries, for export as refined products. In contrast, the international companies export the bulk of their crude production rather than refine it domestically.

Turkmenistan’s crude exports are entirely seaborne (via the Caspian); only refined products are exported by rail. Turkmen crude exports traditionally originated at two oil loading terminals on the Caspian Sea: Aladzha (located 40 km south of Turkmenbashi on the Cheleken Peninsula) or Okarem (located about 250 km south of Turkmenbashi). Dragon Oil has operated the Aladzha facility since 1997. The port has a capacity of 2.4 mt per year (48,000 bd) and can handle 5,000-ton vessels. The Okarem (Ekerem) facility has a capacity of 2 mt per year (40,000 bd) and includes storage facilities with a capacity of at least 10,000 cubic meters. The terminal can handle 7,000-ton tankers, and one of the piers at the port can load two tankers simultaneously. The launch of production by Petronas in 2007 at its offshore field has introduced another new source of crude exports. Petronas exports crude directly from its offshore platform (Oguzkhan) to both Neka and to Baku/Batumi.

However, Caspian crude exporters halted supplies to Iran after June 2010 when Iran cancelled the swap deals. The major factor in Iran’s somewhat surprising decision was evidently problems in financing the swap transactions caused by international sanctions. But the government may also have been concerned about the vulnerabilities of its domestic gasoline supplies if international sanctions suddenly disrupted the swaps. However, before the complete cessation of trade was announced on June 1, in March 2010, Nico, the trading arm of Iran’s state-owned NIOC and swap operator, announced that it was increasing the swap fee to US$5.20–$5.50 per barrel (US$38.70–$41.00 per ton). This had the effect of substantially undermining the profitability of the swap arrangement for the key shippers well before the final cut-off. In March, Iran also informed the Caspian suppliers that they would have to begin selling the swapped crude in the Gulf on their own, which also diminished the overall attractiveness of the route. As a result, several shippers had already begun to shift to alternative export routes well before the actual termination of the swap deals on June 30, 2010.

In 2010, Turkmenistan exported 2.4 mt (48,000 bd) of crude. Only 0.7 mt (14,000 bd) of this went to Iran (all in the first half), with the remainder (1.7 mt, or 34,000 bd) shipped west, across the Caspian, to Baku. The bulk of the westward flow (1.3 mt, or 26,000 bd) went into the BTC, under a contract between the Turkmen producer, Dragon Oil, and SOCAR, while about 0.4 (8,000 bd) went by rail to Batumi.

Turkmenistan’s crude exports are also expected to remain fairly small in the future. In the high scenario, they are projected at 8–9 mt per year (160,000–180,000 bd) between 2020




and 2030, while in the base case they are projected at 5–6 mt (25,000–30,000 bd). In the low case, they reach less than 1 mt (20,000 bd) per year.

Although Iran suspended the swap arrangements for Caspian crude from mid-2010, we assume that this suspension will eventually be revoked and that trade will resume within a few years (as early as 2012 in our high scenario and by 2015 in our low scenario). Already negotiations are under way for this to happen as soon as January 2012, because economically, the swap arrangement is hugely beneficial for both Iran and the Caspian shippers. In IHS CERA’s base scenario, trade is assumed to resume in 2014 and bounce back to 1.8 mt (16,000 bd) in 2015. In the low scenario, the swap arrangement does not resume until 2015, at 1.0 mt (20,000 bd), while in the high scenario, the swap trade resumes in 2012 and reaches 3.7 mt (74,000 bd) by 2015 (see Tables III-22–III-24).

3.4 EURASIAN PIPElINE DEvElOPMENTS AND ExPORT CAPACITy

Some of the most critical assumptions intrinsic to the overall analysis concern new pipeline construction and expansion of crude oil export capacity, highlighted in this section of the report (see Figure III-11). The most important of these include our expectations for the timing of CPC expansion, Russia’s ESPO pipeline, and the second Baltic pipeline (BPS-2). Some affect crude flowing into the Black Sea directly (CPC), while the impact of the others is more indirect by creating alternative export routes to Black Sea evacuation.

CPC. A key development was the agreement signed in December 2008 by CPC shareholders to expand the pipeline from the current nameplate capacity of 28 mt per year (560,000 bd) to 67 mt per year (1.34 mbd).* At that time, a technical agreement on BP’s sale of its stake in LUKARCO was signed; it was necessary to approve BP’s withdrawal from the consortium and to facilitate signing of the agreement on pipeline expansion. The expansion agreement had been long anticipated, practically since the initial phase of the pipeline was completed in 2001. Furthermore, the need for the expansion had been growing ever more urgent as regional production has increased and as time ran out for the authorized period of validity for the first feasibility study. Since 2005 actual throughput has exceeded rated capacity on parts of the pipeline, emphasizing the need for expansion. Expansion discussions were held up by disagreements among Russia and the other shareholders over tariff levels, debt repayment conditions, personnel changes, and other issues. Construction on the expansion program was finally launched in July 2011.

The expansion plans call for an initial phase of construction that includes upgrading five existing pumping stations. The full-phase expansion will involve construction of 10 new pumping stations, a third tanker-loading buoy (single-point mooring [SPM]) at the Black Sea terminal, additional tankage (storage capacity at the tank farm at Yuzhnaya Ozereyevka will be expanded from 210,000 metric tons to 640,000 metric tons), and replacement of approximately 88 km of pipeline within Kazakhstan. Completion of the three phases of

*CPC shareholders currently include Russian Federation with 31% (held by Transneft with 24% and CPC Company with 7%); Republic of Kazakhstan (KazMunayGaz) with 19%; Chevron Caspian Pipeline Consortium Company with 15%; LUKARCO B.V. with 12.5%; Mobil Caspian Pipeline Company with 7.5%; Rosneft-Shell Caspian Ventures Limited with 7.5%; BG Overseas Holding Limited with 2%; Eni International N.A. N.V. with 2%; Kazakhstan Pipeline Ventures LLC with 1.75%; and Oryx Caspian Pipeline LLC with 1.75%.



79


Tab

le II

I-22

Turk

men

ista

n’s

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(Bas

e S

cena

rio

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS0.

3 0.

0 0.

1 0.

4 0.

1 0.

5 0.

2 0.

3 1.

6 1.

9 1.

7 2.

3 2.

4 1.

8 1.

0 1.

5 1.

4 2.

0 2.

1 2.

4 2.

4 2.

7 5.

8 5.

7 4.

9

Bla

cK

Se

a0.

0 0.

0 0.

0 0.

2 0.

0 0.

2 0.

1 0.

1 0.

4 1.

3 1.

2 1.

6 2.

2 1.

3 0.

6 1.

0 0.

3 0.

4 0.

4 0.

2 0.

4 0.

4 1.

8 1.

5 0.

8 N

ovor

ossi

ysk

(via

Mak

hach

kala

)0.

7 0.

2 0.

0 0.

5 0.

4 V

olga

-Don

can

al/R

ussi

an r

ail

0.2

0.1

0.1

0.1

0.3

0.0

0.1

0.0

0.0

0.0

0.1

0.4

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Bat

umi/K

ulev

i0.

1 0.

1 0.

6 0.

9 1.

6 1.

7 0.

9 0.

5 0.

6 0.

3 0.

4 0.

4 0.

2 0.

4 0.

4 1.

8 1.

5 0.

8

iRa

N0.

3 0.

0 0.

1 0.

2 0.

1 0.

3 0.

1 0.

2 1.

2 0.

6 0.

5 0.

7 0.

2 0.

5 0.

4 0.

5 1.

1 1.

6 1.

7 2.

3 0.

7 0.

8 2.

0 2.

0 1.

6 t

urkm

en c

rud

e0.

3 0.

1 0.

2 0.

1 0.

3 0.

1 0.

2 1.

2 0.

6 0.

5 0.

7 0.

2 0.

5 0.

4 0.

5 1.

1 1.

6 1.

7 2.

3 0.

7 0.

8 2.

0 2.

0 1.

6

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

1.3

1.5

2.0

2.2

2.5

tur

kmen

cru

de

1.3

1.5

2.0

2.2

2.5

imp

orts

from

oth

er F

SU

rep

ublic

s0.

3 1.

7 1.

1 0.

4 0.

5 0.

4 0.

1 0.

7 0.

9 0.

6 0.

6 0.

5 0.

5 0.

5 0.

4 0.

3 0.

3 0.

3 0.

4 0.

3 0.

3 0.

2 0.

2 0.

2 0.

1

Sou

rce:

tot

al e

xpor

ts fo

r so

me

year

s re

por

ted

by

cus

tom

s S

tatis

tics

(tur

kmen

ista

n’s

Sta

tistic

al a

genc

y); b

ut la

rgel

y p

rovi

ded

by

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es;

pro

ject

ions

by

iHS

ce

Ra

.




Tab

le II

I-23

Turk

men

ista

n’s

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(Hig

h S

cena

rio

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS0.

3 0.

0 0.

1 0.

4 0.

1 0.

5 0.

2 0.

3 1.

6 1.

9 1.

7 2.

3 2.

4 1.

8 1.

0 1.

5 1.

4 2.

0 2.

1 2.

4 2.

4 5.

2 9.

3 9.

5 8.

1

Bla

cK

Se

a0.

0 0.

0 0.

0 0.

2 0.

0 0.

2 0.

1 0.

1 0.

4 1.

3 1.

2 1.

6 2.

2 1.

3 0.

6 1.

0 0.

3 0.

4 0.

4 0.

2 0.

4 0.

5 2.

5 2.

6 2.

0 N

ovor

ossi

ysk

(via

Mak

hach

kala

)0.

7 0.

2 0.

0 0.

5 0.

4 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 V

olga

-Don

can

al/R

ussi

an r

ail

0.2

0.1

0.1

0.1

0.3

0.0

0.1

0.0

0.0

0.0

0.1

0.4

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Bat

umi/K

ulev

i0.

1 0.

1 0.

6 0.

9 1.

6 1.

7 0.

9 0.

5 0.

6 0.

3 0.

4 0.

4 0.

2 0.

4 0.

5 2.

5 2.

6 2.

0

iRa

N0.

3 0.

0 0.

1 0.

2 0.

1 0.

3 0.

1 0.

2 1.

2 0.

6 0.

5 0.

7 0.

2 0.

5 0.

4 0.

5 1.

1 1.

6 1.

7 2.

3 0.

7 1.

2 3.

1 3.

3 2.

9 t

urkm

en c

rud

e0.

3 0.

1 0.

2 0.

1 0.

3 0.

1 0.

2 1.

2 0.

6 0.

5 0.

7 0.

2 0.

5 0.

4 0.

5 1.

1 1.

6 1.

7 2.

3 0.

7 1.

2 3.

1 3.

3 2.

9

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

1.3

3.5

3.7

3.6

3.2

tur

kmen

cru

de

1.3

3.5

3.7

3.6

3.2

imp

orts

from

oth

er F

SU

rep

ublic

s0.

3 1.

7 1.

1 0.

4 0.

5 0.

4 0.

1 0.

7 0.

9 0.

6 0.

6 0.

5 0.

5 0.

5 0.

4 0.

3 0.

3 0.

3 0.

4 0.

3 0.

3 0.

2 0.

2 0.

2 0.

1

Sou

rce:

tot

al e

xpor

ts fo

r so

me

year

s re

por

ted

by

cus

tom

s S

tatis

tics

(tur

kmen

ista

n’s

Sta

tistic

al a

genc

y); b

ut la

rgel

y p

rovi

ded

by

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es;

pro

ject

ions

by

iHS

ce

Ra

.



81


Tab

le II

I-24

Turk

men

ista

n’s

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(lo

w S

cena

rio

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS0.

3 0.

0 0.

1 0.

4 0.

1 0.

5 0.

2 0.

3 1.

6 1.

9 1.

7 2.

3 2.

4 1.

8 1.

0 1.

5 1.

4 2.

0 2.

1 2.

4 2.

4 0.

6 0.

8 0.

6 0.

3

Bla

cK

Se

a0.

0 0.

0 0.

0 0.

2 0.

0 0.

2 0.

1 0.

1 0.

4 1.

3 1.

2 1.

6 2.

2 1.

3 0.

6 1.

0 0.

3 0.

4 0.

4 0.

2 0.

4 0.

6 0.

8 0.

6 0.

3 N

ovor

ossi

ysk

(via

Mak

hach

kala

)0.

7 0.

2 0.

0 0.

5 0.

4 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 V

olga

-Don

can

al/R

ussi

an r

ail

0.2

0.1

0.1

0.1

0.3

0.0

0.1

0.0

0.0

0.0

0.1

0.4

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Bat

umi/K

ulev

i0.

1 0.

1 0.

6 0.

9 1.

6 1.

7 0.

9 0.

5 0.

6 0.

3 0.

4 0.

4 0.

2 0.

4 0.

6 0.

8 0.

6 0.

3

iRa

N0.

3 0.

0 0.

1 0.

2 0.

1 0.

3 0.

1 0.

2 1.

2 0.

6 0.

5 0.

7 0.

2 0.

5 0.

4 0.

5 1.

1 1.

6 1.

7 2.

3 0.

7 0.

0 0.

0 0.

0 0.

0 t

urkm

en c

rud

e0.

3 0.

1 0.

2 0.

1 0.

3 0.

1 0.

2 1.

2 0.

6 0.

5 0.

7 0.

2 0.

5 0.

4 0.

5 1.

1 1.

6 1.

7 2.

3 0.

7 0.

0 0.

0 0.

0 0.

0

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

1.3

0.0

0.0

0.0

0.0

tur

kmen

cru

de

1.3

0.0

0.0

0.0

0.0

imp

orts

from

oth

er F

SU

rep

ublic

s0.

3 1.

7 1.

1 0.

4 0.

5 0.

4 0.

1 0.

7 0.

9 0.

6 0.

6 0.

5 0.

5 0.

5 0.

4 0.

3 0.

3 0.

3 0.

4 0.

3 0.

3 0.

2 0.

2 0.

2 0.

1

Sou

rce:

tot

al e

xpor

ts fo

r so

me

year

s re

por

ted

by

cus

tom

s S

tatis

tics

(tur

kmen

ista

n’s

Sta

tistic

al a

genc

y); b

ut la

rgel

y p

rovi

ded

by

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es;

pro

ject

ions

by

iHS

ce

Ra

.




the expansion project is expected by 2015. The total costs are authorized at US$5.4 billion (some cost overruns have already been encountered), and consortium members have agreed to finance much of this from their own resources. They have agreed to reduce debt payments (current debt is approximately US$5 billion) and begin putting funds toward the expansion project. However, if necessary, the consortium could seek small amounts of external financing, though given the current economic downturn this may prove challenging.

Exports through the CPC pipeline are expected to remain well beyond the initial design capacity of 28 mt (560,000 bd) through the use of DRAs in the immediate future, followed by expanded capacity later on in the high and base case scenarios. In the low scenario, capacity does not reach 67 mt per year (1.34 mbd) until 2020. The base scenario assumes that CPC capacity expands beginning in 2011 and by 2015 reaches 67 mt per year (1.34 mbd). The high scenario assumes that the expansion is completed slightly sooner, with the

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83


pipeline reaching its full design capacity of 67 mt per year (1.34 mbd) by 2014. DRAs could lift the eventual capacity of the pipeline to as much as 76 mt per year (1.6 mbd).

ESPO pipeline. The first phase of the ESPO pipeline (from Taishet to Skovorodino) was completed at the end of 2009; rail shipments were launched from Skovorodino to Kozmino (the new marine terminal on the Pacific coast) at that time, amounting to 15.3 mt (306,000 bd) during 2010. The initial section of the pipeline (between Taishet and Talakan) was put into operation in October 2008; the flow was temporarily reversed until the end of 2009 (taking the oil westward to Taishet) and delivered via the existing Transneft system to Angarsk for further shipment by rail. The spur line to China from Skovorodino (the end point of the first phase of the ESPO pipeline) was completed at the end of 2010 and became operational in January 2011. As a result, oil is now flowing via ESPO to both China and Kozmino from Skovorodino. ESPO phase 1 section has an initial capacity of 30 mt per year (600,000 bd), delivering 15 mt (300,000 bd) to China and 15 mt (300,000 bd) to Kozmino. This is expected to ramp up to 50–60 mt per year (1.0–1.2 mbd) to support the phase 2 extension to the Pacific coast and ultimately to reach 80 mt per year (1.6 mbd).

In our scenarios the crude for this pipeline comes from currently producing fields in East Siberia (mainly Talakan and Verkhne-Chonskoye), augmented with oil from West Siberia (including Vankor). The pipeline’s phase 2 extension to the Pacific coast is keyed to the buildup of East Siberian production and occurs in 2015 in the high scenario and not until 2020 in the base scenario; it is never realized in the low scenario. In the base case, we do not see the need for ESPO capacity to exceed 60 mt per year (1.2 mbd), whereas in the high case it expands to 80 mt (1.6 mbd). The Russian prime minister is already proposing that a second ESPO string be constructed, but this is not envisioned in even the high IHS CERA scenario.

Baltic Sea. The BPS that leads to Primorsk was expanded several times, to reach 75 mt per year (1.5 mbd) in 2006. IHS CERA now holds Primorsk’s capacity at 75 mt (1.5 mbd) for the remainder of the outlook period in all three scenarios. At one time, Transneft announced plans for further expansion of Primorsk to 120 mt per year (2.4 mbd) or even 150 mt (3.0 mbd), but this was part of an earlier plan for the announced BPS-2 pipeline to terminate at Primorsk.

Construction on the BPS-2 pipeline that bypasses Belarus was launched in mid-2009. With the pipeline laying completed, linefill began on August 1, 2011, and export operations are expected to begin in early 2012. The 998 km pipeline extends from the Unecha junction on the Druzhba pipeline near the border with Belarus to a new terminal at Ust-Luga (on the south coast of the Gulf of Finland).* The pipeline (and terminal) will have a carrying capacity of about 30 mt per year (600,000 bd) initially, but ultimately is planned to expand to about 50 mt per year (1 mbd) (although 12 mt [240,000 bd] of this is supposed to be reserved for deliveries to the Kirishi refinery, so only 38 mt [760,000 bd] would be available for exports via Ust-Luga). In the low scenario, we assume that capacity remains at the initial phase of 30 mt per year (600,000 bd), while the other two scenarios assume that capacity is gradually expanded to 50 mt per year (1 mbd). We do not assume a major diversion of

*The new crude oil export facility is adjacent to a refined product terminal at Ust-Luga that started up in January 2011, handling refined products (mainly mazut) shipped in by rail.




existing Druzhba volumes from Eastern Europe to fill the pipeline, although obviously this depends largely on the behavior of Belarus (see below).

Russia’s expansion of its Baltic oil export infrastructure with this new pipeline represents a strategic initiative to establish “spare” export capacity.* The net result of the construction of the approximately US$3.1 billion BPS-2 will be significant growth in regional Russian crude and product export capacity, which will serve to reduce Russian oil exporters’ dependence on crude oil pipelines transiting Belarus and on product pipeline and rail routes terminating at non-Russian Baltic ports (in Estonia, Latvia, and Lithuania).

Given the insecurity of the Belarusian crude oil transit route in particular and the burden on Russia of an annual multibillion dollar subsidy to Belarus in the form of preferential oil trade terms, Russia’s underlying rationale for BPS-2 is clear. Overall, the BPS-2 and Ust-Luga development appears to be intended primarily to create a strategic crude oil export capacity “reserve” available to be used in case of transit disputes or other disruptions. An important issue for this study is that the BPS-2’s available “spare” capacity can also be pressed into service seasonally by shippers to divert incremental crude volumes from the Black Sea and into the Baltic in cases where wintertime congestion arises or even threatens to emerge in the Turkish Straits.

The key elements regarding the construction of BPS-2 include:

Strategic drivers of Russia’s Baltic oil export capacity expansion have become •increasingly dominant. The current BPS-2 and Ust-Luga development comes against a backdrop of weaker outlooks for crude production growth and refined product exports than during earlier waves of Russian regional infrastructure expansion since 2000. Thus full-scale utilization of the planned new facilities probably depends more than ever on diversion of crude and product flows away from competing routes.

The Russia-Belarus January 2010 oil trade dispute underscores Russia’s continued •incentive to diversify export options but also indicates that the risk of such bilateral conflict affecting wider European oil flows may have lessened. The continuing tension in Russia-Belarus oil trade underscores the continuing salience of the issues underlying the earlier January 2007 crisis (when Russian oil exports via Belarus were interrupted for several days), particularly the contentious issue of how quickly and to what extent historical price discounts on Russia’s oil exports to Belarus (in aggregate, amounting to a massive Russian subsidy of the Belarusian economy) should be reduced. But in marked contrast to 2007, the Russia-Belarus dispute in 2010 (which was settled following a framework agreement reached in late January 27 governing oil trade issues) did not directly affect oil flows transiting Belarusian territory, only shipments going directly to the Belarusian refineries. After the Russian-Ukrainian gas dispute of 2009, it appears that neither side wanted to be responsible for another disruption of Russian energy flows to the European Union.

Only marginal changes in Druzhba exports flows to Eastern Europe are expected •as a result of BPS-2, since the Druzhba business remains uniquely advantageous

*See the IHS CERA Decision Brief Russia’s New Baltic Pipeline and Terminal More than Just an Export Project.



85


for both exporters and importers. Alternative supply options are relatively expensive for importers, while Russian exporters risk losing some Druzhba markets entirely if the government insists on large-scale diversion of flows to BPS-2 (i.e., importers may seek to diversify away from reliance on the Druzhba route as well as on Russia’s Urals Blend itself). Other factors mitigating against the full-scale utilization of the BPS-2 infrastructure include the competition for West Siberian oil from Russia’s new ESPO pipeline; and as a quid pro quo for membership in the World Trade Organization (WTO), there is growing pressure on Russia to eliminate preferential tariffs on rail shipments of products to Russian terminals compared to non-Russian ports.

Elsewhere in the Baltic, exports from Ventspils (which in 2003–06 were delivered entirely by rail) are not assumed to resume by pipeline, even in the high case, because of Russia’s own Baltic outlets.* The Butinge terminal in Lithuania is now being used as an import facility for the Maizeikiai refinery, and just as for Ventspils, we assume that the pipeline to Lithuania that has been closed since mid-2006 is not restored to operation to allow direct shipments of Russian crude for export to resume to the Butinge terminal or to the Lithuanian refinery.**

Druzhba Pipeline. Despite the availability of the BPS-2 bypass that could potentially largely idle the Druzhba pipeline from 2012, we assume that Druzhba will remain a major export route for deliveries to Eastern Europe, provided that relations with Belarus remain reasonably cordial. Therefore, exports of Russian crude (along with some Kazakh and Belarusian volumes) via the Druzhba pipeline are projected to stay within a comparatively narrow range in all scenarios. This is because these numbers are calculated from demand projections for each importing country, with varying assumptions about the extent to which other sources of crude make small inroads into some markets (notably Poland).

It also appears that there remains sufficient capacity in the single southward-flowing pipeline string on the southern segment of the Druzhba between Mozyr and Brody (following the reversal of the other string in 2011 to carry Azeri oil north) to meet the current level of oil demand (i.e., about 17.5 mt per year or 1.4–1.5 mt per month, or 350,000 bd) by East European refineries; i.e., Slovakia, Hungary, Bosnia, and the Czech Republic.*** However, we assume that sometime before 2015, Belarus ceases to use Azeri oil internally because it is relatively higher cost than Russia crude.

*But Ventspils may continue to be used as an aggregation point for smaller cargoes delivered by tanker from Kaliningrad. LUKOIL began using Ventspils to aggregate crude oil produced and shipped from Kaliningrad into larger cargo sizes to save on lower transport costs in 2006. Oil produced in Kaliningrad is exported from one of the Kaliningrad terminals in small vessels and taken to Ventspils where it is aggregated for shipment in larger tankers. This volume is not taken into consideration to avoid double-counting the export volumes.**Direct pipeline deliveries of crude oil to the Maizeikiai refinery are assumed to resume by 2015 only in the high case because of Russia’s need for incremental export capacity, but not in the base case or low case. The Lithuanian government recently submitted an official request for Russia to repair the pipeline and restore it to operation, which was turned down. Transneft is still using the segment of the problematic pipeline from Unecha, but only to supply the Novopolotsk refinery in Belarus at reduced pressures. After the start-up to BPS-2, Transneft plans to shut the pipeline segment down altogether and deliver crude to Novopolotsk via the new pipeline (from the Andreapol pumping station) as well as the existing pipeline route from Yaroslavl.***That is, monthly flows on the southern Druzhba to these countries in 2011 have been about the same as in 2010 before the reversal of one pipeline string.




Therefore, with sufficient capacity likely to be available on the southern Druzhba longer term, we still add Austria as a destination for Druzhba deliveries from Russia beginning before 2015 in the high scenario and after 2015 in the base case, but it plays no part in the low scenario. This assumes that a short pipeline between Slovakia’s Slovnaft refinery and OMV’s Schwechat refinery is eventually completed. Small amounts of Caspian oil also are assumed to be delivered to Austria via rail across Ukraine (as well as to other East European destinations, such as the Czech Republic and Poland) under certain scenario cases.

Russian crude exports from the Omisalj terminal in Croatia via the Druzhba system materialize only in the high scenario. But some crude deliveries are assumed to occur to Balkan refineries (several are now owned by Russian companies) via the Druzhba-Adria route in the base and low cases.

Kazakhstan-China Pipeline. The Kazakhstan-China pipeline has been developed incrementally. Initial pipeline deliveries to China began in mid-2006 using the completed pipeline segment from Atasu to the Alashankou/Druzhba border point. In 2009 a link connected western Kazakhstan with the eastern pipeline system (between Kenkiyak and Kumkol), followed by the reversal of the existing Kenkiyak-Atyrau pipeline sometime after 2010, which allowed the Kazakhstan-China pipeline to access crude from the main oil-producing area in northwest Kazakhstan near the Caspian Sea. Some Russian crude (about 1 mt per year, or 20,000 bd) has flowed into Kenkiyak-Atyrau pipeline (which started up in 2008), but this is expected to cease following the advent of Russia’s own eastern pipeline and because of Kazakhstan’s growing needs for export capacity over time. Initial pipeline capacity of 10 mt per year (200,000 bd) has been increased to 20 mt (400,000 bd). Total shipments in the pipeline are projected to reach up to 30 mt (600,000 bd) by about 2030 in both the base case and high cases, so it assumes that the existing nameplate capacity can be expanded further through various means, such as DRAs.

Barents Sea pipelines. The only significant pipeline developments included in the scenarios are extensions of LUKOIL’s existing pipeline system that feeds the Varandey terminal to other fields. A transcontinental pipeline project to Murmansk has not been considered a likely prospect for a considerable number of years now given pipeline politics and the Russian government’s decision to construct ESPO and BPS-2. In addition, the slowing pace in Russian oil production has removed much of the pressure for additional export capacity. Even the Kharyaga-Indiga regional pipeline (to move only Timan-Pechora crude) now seems quite unlikely even in the high case.

LUKOIL now plans to expand its existing Varandey terminal and construct a 160 km pipeline to link the Kharyaga field to the Varandey terminal. Several other companies developing upstream projects in the region, including Rosneft, Zarubezhneft, and Bashneft, have announced that they plan to use the Varandey terminal for exports. They are developing proposals for various pipelines for their fields to Varandey and are in negotiations with LUKOIL on access terms. In all three scenarios, however, a transshipment terminal is maintained at Murmansk (albeit a fairly sizable one) that handles several crude streams originating at northern ports such as Arkhangelsk or Varandey.



87


Iran. Iran suspended swap arrangements for Caspian crude in mid-2010. However, we assume that this suspension will eventually be revoked and that trade resumes within a few years.* But the closure of this route in the near term pushes the small volume of Turkmen crude exports west, to Baku and to the Georgian ports, and for Kazakhstan, the diversion is to a more diversified set of export routes, although the Baku-Georgian route is the principal beneficiary.

In the low scenarios, the current relatively small export volumes of Caspian crude increase slowly. But even in the high scenario combinations, the projected volumes on the Neka-Tehran pipeline that takes the Caspian crude from the Caspian port of Neka to the Tehran refinery remain well below its full design capacity of about 18 mt per year (360,000 bd) (although the flow goes up to as much as 7–8 mt, or 140–160,000 bd, in 2035 in both the base-base and high-high scenario combinations). The bulk of this volume is sourced from Kazakhstan.

Russian Far East. In all scenarios, Russian crude oil production from Sakhalin (minus a small offtake by local Russian refineries that grows over time) is assumed to be exported to Asia Pacific markets through its own set of infrastructure. For Sakhalin oil, this is likely to remain the DeKastri terminal on the mainland (used by Sakhalinmorneftegaz and the Sakhalin-1 project consortium) as well as the new terminal constructed on southern Sakhalin Island at Prigorodnoye by the Sakhalin-2 project consortium after 2009 (supplanting summertime shipments of oil directly from an offshore platform).

BTC. The BTC pipeline began regular operations in June 2006. Throughput is assumed to continue to ramp up to reach the initial design capacity of about 50 mt (1 mbd) as early as 2015 or as late as 2025, depending on the scenario combination (i.e., 2025 in the base case, 2015 in the high case, while flows in the low case reach only 41 mt (820,000 bd). Projected volumes are mostly Azerbaijani crude, although moderate amounts of Kazakh crude and some Turkmen crude (mainly from Kyapaz/Serdar) are included. But this is dependent on a reasonable accommodation for third-party shippers and also for the Kazakh-Caspian Transportation System (KCTS) developing into a major export route for Kazakh oil across the Caspian.

Both of these issues at present remain uncertain. After using the BTC for export flows in 2008 and 2009, TCO suspended injections in 2010 because of an unattractive tariff relative to other export routes available for Tengiz crude. It is entirely possible that no Kazakh producer will use BTC until a significant production level is achieved at Kashagan. Furthermore, the construction of the KCTS, comprising mainly a 750-km pipeline between Eskene and a new marine terminal on the Caspian Sea at Kuryk, has been officially delayed to 2018. KMG does not expect enough crude to be available to warrant an earlier launch to KCTS.

The IHS CERA base case assumes that an accommodation with Kazakh producers will be reached in the next few years, allowing a steadily rising volume of Kazakh oil to access BTC. BTC throughputs are projected in the base case to be only above 50 mt per year (about 1 mbd) after 2025 as Kazakh oil offsets the decline in Azeri oil shipments. Non-

*Exports of Turkmen crude to Iran reportedly resumed in July 2011, when seven cargoes containing oil produced by Burren Energy from Okarem were dispatched to Neka; the total shipments amounted to about 37,000 metric tons.




Azerbaijani volumes (mainly Kazakh but also some Turkmen crude) are expected to account for over half of the pipeline’s total throughput volume by 2030 in the base case and high case scenarios. In the high case, throughput in the BTC pipeline is projected at over 80 mt (1.6 mbd), obviously with the help of DRAs and some engineering expansions. In the low case, throughput drops to only about 30 mt per year (600,000 bd) in the second decade of the outlook period.

3.5 BlACK SEA OIl BAlANCES

3.5.1 Methodology Underlying IHS CERA’s Black Sea Oil Flows Scenarios

The analysis takes into account all sources of oil coming into the Black Sea, as well as all indigenous demand on the Black Sea littoral. It also considers all the possible and potential alternative export routes for Eurasian oil from the Black Sea. The outlooks cover three alternative scenarios (high, base, and low) that allow volume sensitivities to be tested under a range of different production and transport conditions.

3.5.2 Eurasian Crude Oil Arriving in the Black Sea

Approximately 101.7 mt (2.03 mbd) of Eurasian crude oil reached the Black Sea in 2010, according to IHS CERA’s calculations. This amount was a 9.8% decline from the maximum level achieved so far, in 2005, of 112.7 mt (2.25 mbd), which in turn was a six-fold increase over volumes reaching the Black Sea in 1991 (18.5 mt, or 370,000 bd) at the end of the Soviet era. Of the 2010 total, about 44.8% (45.6 mt, or 912,000 bd) came from Russia, 48.0% (48.8 mt, or 976,000 bd) came from Kazakhstan, and 7.2% was from Azerbaijan and Turkmenistan. Five years earlier, in 2005 the volumes arriving in the Black Sea had been almost evenly split between Russia and the Caspian.

Russian crude volumes to the Black Sea have been declining since the 2003 peak of 64.2 mt (1.28 mbd) and are projected to continue to decline going forward, not only in the base case but the other cases as well. This is a function of relatively flat and then declining Russian oil production, growing domestic crude oil consumption longer term, and the continuing emergence of alternative crude export routes—notably, the ESPO route and an additional Russian Baltic Sea outlet with construction of BPS-2 (see below) (see Figure III-12 and Tables III-25–III-27).

These emerging routes essentially serve as alternative “Bosphorus bypasses” for Russian oil. In sum, there is no guarantee that crude needed to fill any planned new Black Sea terminal capacity (e.g., Novorossiysk and Tupse) will necessarily arrive in the region.

The Eurasian crude reaches the Black Sea via pipeline and rail to a number of marine terminals (see Figure I-1). The principal pipeline routes include the CPC; Transneft’s pipelines to Novorossiysk, Tuapse, Odessa, and Pivdenniy; and the Baku-Supsa pipeline from Azerbaijan.



89


Novorossiysk. Novorossiysk is currently the largest of the Black Sea oil terminals; its current crude oil export capacity is listed as 50 mt per year (1 mbd).* Crude oil exports from Novorossiysk amounted to 44.4 mt (888,000 bd) in 2009 and 42.0 mt (840,000 bd) in 2010 of which 30.4 mt (608,000 bd) was Russian crude, 9.4 mt (188,000 bd) was Kazakh crude, and 2.2 mt (44,000 bd) was Azerbaijani crude. The maximum achieved so far was 49.1 mt, or 982,000 bd, in 2004).

Most of the crude oil that arrives at Novorossiysk’s Sheshkaris oil-loading terminal is via the Transneft pipeline system, with a small amount arriving by rail (1.46 mt in 2008, 1.3 mt in 2009 and 2010). Novorossiysk also handled 12.7 mt of refined product exports in 2010, mostly comprising gasoil and delivered to the port via rail.

The oil terminal loads crude oil and products at six different berths. Only one (No.1) can load large tankers of over 100,000 dwt (Suezmaxes) (see Table III-28). In 2010, 23.1 mt (462,000 bd) of crude was loaded onto Suezmaxes (55.0% of the total), 17.1 mt (342,000

*Total freight capacity of the 100 mt per year Novorossiysk Commercial Sea Port is slated to be increased to 112 mt per year by 2012. Novorossiysk has 43 ship berths, ranging in draft from 4.5 m to 24 m. This reconstruction and expansion program is expected to add 15 mt of oil-handling capacity (crude and products combined), raising the capacity of Sheshkaris to 65 mt per year. The key expansion on the product side is a new mazut outlet to come online in 2012, with an initial capacity of 4 mt per year (with eventual expansion of up to 13 mt per year). The project involves the expansion and upgrading of Berths 25 and 25A to handle 40,000–47,000 dwt tankers. Novorossiysk’s oil export capacity total includes both the Sheshkaris (which handles crude and products) and the Importpicheprom (IPP ) terminals. The latter (operated by Palmpoint), which handles only products, has a capacity of about 5 mt per year and specializes mostly in gasoil. IPP uses Berth 5.

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Tab

le II

I-25

Rus

sian

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(Bas

e S

cena

rio

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS22

1.8

166.

115

0.5

113.

612

7.0

122.

512

5.8

128.

213

7.2

134.

414

4.8

161.

318

8.8

225.

925

3.7

249.

224

7.5

258.

223

8.4

247.

324

8.0

327.

634

7.3

345.

033

4.8

Bla

cK

Se

a40

.2

18.5

23

.9

26.6

39

.5

39.9

43

.9

44.3

44

.4

42.5

43

.2

45.3

53

.6

64.2

59

.4

55.7

55

.6

60.4

53

.8

53.7

45

.6

45.0

42

.8

40.3

36

.5

Nov

oros

siys

k30

.9

14.9

21

.6

20.9

28

.9

28.1

30

.0

30.3

29

.9

30.1

34

.9

36.0

38

.8

41.7

42

.5

40.6

38

.3

36.5

35

.0

33.0

30

.4

32.0

31

.0

31.3

28

.5

tuap

se5.

5 0.

6 2.

1 3.

0 4.

4 4.

4 4.

7 4.

8 6.

1 5.

1 5.

7 5.

4 5.

0 4.

9 4.

8 4.

9 5.

1 4.

4 4.

5 4.

2 4.

8 5.

0 5.

0 5.

0 4.

0 o

des

sa (R

ussi

an e

xpor

ts)

3.8

3.0

0.2

2.7

6.2

7.4

8.2

8.7

8.2

5.5

2.5

3.2

3.3

2.2

1.4

0.4

2.1

2.8

0.8

0.0

0.0

0.0

0.0

0.0

0.0

piv

den

niy

(Yuz

hniy

)0.

9 1.

9 5.

7 3.

7 9.

9 7.

7 9.

5 3.

4 0.

0 0.

0 0.

0 0.

0 c

pc

(Yuz

hnay

a o

zere

yevk

a)0.

3 2.

3 6.

3 6.

7 5.

6 6.

9 6.

4 6.

5 5.

8 4.

0 4.

0 R

ail e

xpor

ts (v

ia v

ario

us p

orts

: Feo

dos

iya,

K

avka

z, e

tc.)

1.0

0.5

0.2

1.8

0.1

0.7

6.5

11.3

5.

0 1.

3 0.

2 0.

1 0.

2 0.

1 0.

6 1.

5 1.

0 0.

0 0.

0 R

iver

exp

orts

3.2

3.5

0.4

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Ba

ltic

Se

a13

.0

7.2

8.3

8.7

11.0

11

.5

16.0

16

.1

16.4

16

.7

22.8

26

.7

36.7

51

.0

68.2

73

.0

72.4

79

.3

73.3

76

.8

73.4

10

9.0

103.

0 91

.4

80.8

Ve

ntsp

ils13

.0

7.2

8.3

8.7

11.0

11

.5

14.3

14

.6

14.6

13

.0

13.6

15

.0

7.4

3.3

1.6

0.2

1.2

0.8

0.7

0.5

0.0

0.0

0.0

0.0

0.0

But

inge

0.6

3.1

5.2

5.6

10.8

6.

8 5.

3 2.

9 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 p

rimor

sk0.

2 11

.2

16.0

41

.9

54.4

62

.5

74.2

69

.9

70.2

70

.0

74.0

71

.5

69.1

65

.0

Ust

-lug

a (B

pS

-2)

30.0

30

.0

21.3

15

.3

Gd

ansk

(inc

lud

ed a

s p

art

of p

olan

d u

ntil

2003

)4.

4 5.

8 5.

2 4.

2 2.

8 1.

9 4.

6 1.

7 3.

5 0.

0 0.

0 0.

0 R

ail e

xpor

ts (v

ia v

ario

us p

orts

: Kal

inin

grad

, e

ston

ia, e

tc.)

1.7

1.5

1.8

3.1

6.1

6.3

12.5

16

.5

12.1

8.

0 1.

6 1.

6 0.

8 1.

6 1.

7 1.

5 1.

5 1.

0 0.

5

DR

UZ

HB

a p

ipe

liN

e (e

aste

rn e

urop

e)45

.8

25.0

34

.5

25.8

38

.9

39.8

41

.4

42.9

49

.3

50.5

52

.5

54.0

52

.2

54.6

56

.3

56.4

58

.6

55.4

51

.8

49.2

53

.8

59.6

63

.0

66.1

66

.8

pol

and

11.4

5.

4 4.

5 3.

5 6.

1 7.

3 9.

2 10

.2

13.6

14

.6

17.8

18

.4

16.3

17

.0

16.9

17

.3

19.0

18

.2

19.0

15

.8

19.4

20

.0

20.0

21

.0

21.0

G

erm

any

15.8

9.

1 12

.8

9.5

16.3

15

.0

16.1

15

.7

18.5

19

.4

19.5

20

.0

20.4

21

.5

21.7

22

.3

21.8

20

.6

16.9

19

.2

17.9

21

.0

22.0

23

.0

23.0

c

zech

Rep

ublic

5.3

3.3

4.6

3.1

6.3

6.9

5.7

5.8

5.3

4.8

3.7

3.7

3.6

3.9

4.4

5.1

5.2

4.6

4.8

5.0

4.6

5.4

5.5

5.5

5.5

Slo

vaki

a7.

7 4.

7 6.

6 4.

5 4.

9 5.

0 5.

2 5.

1 5.

3 5.

6 5.

4 5.

9 5.

5 5.

8 6.

0 5.

2 5.

9 5.

5 4.

5 2.

6 4.

9 6.

0 6.

2 6.

3 6.

3 H

unga

ry4.

8 2.

5 6.

0 5.

2 5.

3 5.

6 5.

2 6.

1 6.

6 6.

1 5.

7 5.

5 6.

2 5.

7 6.

1 6.

4 6.

8 6.

5 6.

6 6.

4 6.

6 6.

6 6.

8 6.

8 6.

5 a

ustr

ia0.

0 0.

0 2.

0 3.

0 4.

0 o

mis

alj t

erm

inal

/cro

atia

-Ser

bia

-Slo

veni

a-B

osni

a0.

8 0.

4 0.

5 0.

2 0.

6 1.

1 0.

0 0.

0 0.

0 0.

0 0.

3 0.

6 0.

6 0.

5 0.

5 0.

5

FSU

Re

pU

Bli

cS

#10

8.9

100.

5 72

.3

42.1

33

.1

27.7

19

.5

21.0

22

.6

21.4

20

.6

27.5

35

.4

40.1

45

.8

42.5

36

.0

29.5

27

.3

27.8

18

.8

27.0

26

.0

26.0

26

.0

Bel

arus

37.4

33

.7

19.7

12

.4

11.0

11

.1

10.1

10

.5

9.6

9.8

11.8

11

.8

13.6

14

.7

17.3

19

.3

20.4

19

.9

21.1

21

.4

12.9

17

.0

16.0

16

.0

16.0

l

ithua

nia

(dire

ct b

y p

ipe)

9.7

11.5

4.

3 5.

1 3.

7 3.

2 1.

9 4.

7 6.

3 3.

8 4.

7 6.

4 6.

0 5.

2 8.

6 8.

6 5.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 U

krai

ne53

.7

49.7

41

.5

19.9

15

.7

13.2

7.

5 5.

8 6.

7 7.

8 4.

1 9.

3 15

.8

20.2

19

.9

14.6

10

.6

9.6

6.2

6.3

6.0

10.0

10

.0

10.0

10

.0

oth

er R

epub

lics

(exc

lud

ing

Kaz

akhs

tan)

8.1

5.6

6.8

4.7

2.7

0.2

to K

aZ

aK

HS

taN

(pav

lod

ar r

efine

ry)

13.3

13

.9

11.5

8.

5 4.

4 3.

4 3.

2 1.

6 2.

3 0.

7 0.

9 2.

2 2.

7 2.

7 3.

1 3.

7 5.

6 6.

7 6.

0 4.

8 7.

4 4.

9 5.

0 5.

0 5.

0

iRa

N0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

9 1.

9 0.

5 0.

4 0.

1 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 fr

om a

stra

khan

' and

Mak

hach

kala

0.1

0.9

1.9

0.5

0.4

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Ba

Re

NtS

Se

a0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

3 0.

3 3.

3 6.

3 9.

9 6.

5 4.

5 4.

7 5.

3 10

.4

10.3

19

.5

23.7

25

.2

28.0

R

ussi

an c

rud

e (v

ia v

ario

us R

ussi

a p

orts

: a

rkha

ngel

'sk,

Mur

man

sk, V

itino

, Va

rand

ey, i

ndig

a et

c.)

0.1

0.3

0.3

3.3

6.3

9.9

6.5

4.5

4.7

5.3

10.4

10

.3

19.5

23

.7

25.2

28

.0



91


Tab

le II

I-25

Rus

sian

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(Bas

e S

cena

rio

) (co

ntin

ued

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

ea

St

aS

ia0.

6 1.

0 0.

0 1.

9 0.

1 0.

2 1.

8 2.

3 2.

2 2.

6 4.

4 5.

4 4.

8 6.

2 9.

0 11

.0

14.5

22

.0

20.8

24

.7

38.6

62

.6

83.8

91

.0

91.7

R

ussi

an c

rud

e (fr

om S

akha

lin/e

ast

Sib

eria

)0.

4 0.

8 0.

0 1.

7 0.

1 0.

1 1.

5 2.

0 2.

0 2.

2 3.

8 4.

0 2.

8 2.

7 3.

2 3.

1 4.

2 13

.0

10.8

14

.1

26.8

45

.6

60.3

68

.1

73.2

Sak

halin

infr

astr

uctu

re (D

eKas

tri,

Vity

az,

prig

orod

noye

, etc

.)0.

4 0.

8 0.

0 1.

7 0.

1 0.

1 1.

5 2.

0 2.

0 2.

2 3.

8 4.

0 2.

8 2.

7 3.

2 3.

1 4.

2 13

.0

10.6

13

.8

13.5

22

.0

26.0

31

.5

34.2

eas

t S

iber

ia-p

acifi

c c

oast

(eS

po

) pip

elin

e0.

2 0.

3 13

.3

23.6

34

.3

36.6

39

.0

Rus

sian

cru

de

exp

orts

(fro

m W

est

Sib

eria

)0.

2 0.

2 0.

0 0.

2 0.

0 0.

1 0.

3 0.

3 0.

2 0.

4 0.

6 1.

4 2.

0 3.

5 5.

9 7.

9 10

.3

9.0

10.0

10

.5

11.8

17

.0

23.5

22

.9

18.5

Rai

l0.

2 0.

2 0.

0 0.

2 0.

0 0.

1 0.

3 0.

3 0.

2 0.

4 0.

6 1.

4 2.

0 3.

5 5.

9 7.

9 10

.3

9.0

8.9

9.0

9.2

0.0

0.0

0.0

0.0

e

ast

Sib

eria

-pac

ific

coa

st (e

Sp

o) p

ipel

ine

0.0

0.0

2.6

17.0

23

.5

22.9

18

.5

eas

t S

iber

ia-p

acifi

c c

oast

(eS

po

) pip

elin

e (to

tal)

0.2

0.3

15.9

40

.6

57.8

59

.5

57.5

K

ozm

ino

(exp

orts

via

pac

ific

coas

t te

rmin

al)

15.3

25

.6

42.8

44

.5

42.5

S

kovo

rod

ino

(exp

orts

via

chi

na p

ipel

ine

spur

)0.

6 15

.0

15.0

15

.0

15.0

K

azak

hsta

n-c

hina

pip

elin

e1.

0 1.

5 0.

0 0.

0 0.

0 0.

0 0.

0 e

aS

teR

N p

ipe

liN

eS

(tot

al)

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

1.3

1.8

15.9

40

.6

57.8

59

.5

57.5

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Rus

sian

cru

de

0.0

0.0

0.0

0.0

0.0

S

ourc

e: t

otal

exp

orts

rep

orte

d b

y c

usto

ms

Sta

tistic

s (R

osst

at);

sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.




Tab

le II

I-26

Rus

sian

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(Hig

h S

cena

rio

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS22

1.8

166.

115

0.5

113.

612

7.0

122.

512

5.8

128.

213

7.2

134.

414

4.8

160.

918

8.8

225.

225

2.9

248.

124

7.5

258.

623

8.4

247.

324

8.0

359.

439

6.0

403.

239

7.3

Bla

cK

Se

a40

.218

.523

.926

.639

.539

.943

.944

.344

.442

.543

.245

.353

.664

.259

.455

.755

.660

.453

.853

.745

.658

.054

.049

.445

.5N

ovor

ossi

ysk

30.9

14.9

21.6

20.9

28.9

28.1

30.0

30.3

29.9

30.1

34.9

36.0

38.8

41.7

42.5

40.6

38.3

36.5

35.0

33.0

30.4

39.0

34.0

33.0

33.0

tuap

se5.

50.

62.

13.

04.

44.

44.

74.

86.

15.

15.

75.

45.

04.

94.

84.

95.

14.

44.

54.

24.

86.

05.

05.

05.

0o

des

sa (R

ussi

an e

xpor

ts)

3.8

3.0

0.2

2.7

6.2

7.4

8.2

8.7

8.2

5.5

2.5

3.2

3.3

2.2

1.4

0.4

2.1

2.8

0.8

0.0

0.0

0.0

0.0

0.0

0.0

piv

den

niy

(Yuz

hniy

)0.

91.

95.

73.

79.

97.

79.

53.

40.

00.

00.

00.

0c

pc

(Yuz

hnay

a o

zere

yevk

a)0.

32.

36.

36.

75.

66.

96.

48.

010

.08.

06.

0R

ail e

xpor

ts (v

ia v

ario

us p

orts

: Fe

odos

iya,

Kav

kaz,

etc

.)1.

00.

50.

21.

80.

10.

76.

511

.35.

01.

30.

20.

10.

20.

10.

64.

04.

02.

61.

0R

iver

exp

orts

3.2

3.5

0.4

0.0

0.0

0.0

0.0

0.0

1.0

1.0

0.8

0.5

Ba

ltic

Se

a13

.07.

28.

38.

711

.011

.516

.016

.116

.416

.722

.826

.736

.750

.267

.471

.872

.479

.773

.376

.873

.410

2.0

120.

311

8.0

100.

4Ve

ntsp

ils13

.07.

28.

38.

711

.011

.514

.314

.614

.613

.013

.615

.07.

43.

31.

60.

21.

21.

20.

70.

50.

00.

50.

50.

50.

5B

utin

ge0.

63.

15.

25.

610

.86.

85.

32.

90.

00.

00.

00.

00.

00.

00.

00.

0p

rimor

sk0.

211

.216

.041

.954

.462

.574

.269

.970

.270

.070

.572

.672

.068

.7U

st-l

uga

(Bp

S-2

)26

.040

.541

.030

.2G

dan

sk (i

nclu

ded

as

par

t of

pol

and

un

til 2

003)

4.4

5.8

5.2

4.2

2.8

1.9

4.6

1.7

4.0

2.0

2.0

0.0

Rai

l exp

orts

(via

var

ious

por

ts:

Kal

inin

grad

, est

onia

, etc

.)1.

71.

51.

83.

16.

16.

312

.515

.811

.36.

81.

61.

60.

81.

61.

71.

04.

72.

51.

0

DR

UZ

HB

a p

ipe

liN

e (e

aste

rn e

urop

e)45

.825

.034

.525

.838

.939

.841

.442

.949

.350

.552

.554

.052

.254

.656

.356

.458

.655

.451

.849

.253

.863

.567

.268

.876

.0p

olan

d11

.45.

44.

53.

56.

17.

39.

210

.213

.614

.617

.818

.416

.317

.016

.917

.319

.018

.219

.015

.819

.419

.020

.020

.024

.0G

erm

any

15.8

9.1

12.8

9.5

16.3

15.0

16.1

15.7

18.5

19.4

19.5

20.0

20.4

21.5

21.7

22.3

21.8

20.6

16.9

19.2

17.9

20.0

21.0

22.0

25.0

cze

ch R

epub

lic5.

33.

34.

63.

16.

36.

95.

75.

85.

34.

83.

73.

73.

63.

94.

45.

15.

24.

64.

85.

04.

65.

05.

55.

55.

5S

lova

kia

7.7

4.7

6.6

4.5

4.9

5.0

5.2

5.1

5.3

5.6

5.4

5.9

5.5

5.8

6.0

5.2

5.9

5.5

4.5

2.6

4.9

6.0

6.2

6.3

6.5

Hun

gary

4.8

2.5

6.0

5.2

5.3

5.6

5.2

6.1

6.6

6.1

5.7

5.5

6.2

5.7

6.1

6.4

6.8

6.5

6.6

6.4

6.6

6.5

7.5

8.0

8.0

aus

tria

0.0

5.0

5.0

5.0

5.0

om

isal

j ter

min

al/c

roat

ia-S

erb

ia-

Slo

veni

a-B

osni

a0.

80.

40.

50.

20.

61.

10.

00.

00.

00.

00.

30.

62.

02.

02.

02.

0

FSU

Re

pU

Bli

cS

110

8.9

100.

572

.342

.133

.127

.719

.521

.022

.621

.420

.627

.535

.440

.145

.842

.536

.029

.527

.327

.818

.841

.044

.044

.043

.0 B

elar

us37

.433

.719

.712

.411

.011

.110

.110

.59.

69.

811

.811

.813

.614

.717

.319

.320

.419

.921

.121

.412

.918

.018

.017

.017

.0 l

ithua

nia

(dire

ct b

y p

ipe)

9.7

11.5

4.3

5.1

3.7

3.2

1.9

4.7

6.3

3.8

4.7

6.4

6.0

5.2

8.6

8.6

5.0

0.0

0.0

0.0

0.0

8.0

8.0

9.0

9.0

Ukr

aine

53.7

49.7

41.5

19.9

15.7

13.2

7.5

5.8

6.7

7.8

4.1

9.3

15.8

20.2

19.9

14.6

10.6

9.6

6.2

6.3

6.0

15.0

18.0

18.0

17.0

oth

er R

epub

lics

(exc

lud

ing

Kaz

akhs

tan)

8.1

5.6

6.8

4.7

2.7

0.2

to K

aZ

aK

HS

taN

(pav

lod

ar r

efine

ry)

13.3

13.9

11.5

8.5

4.4

3.4

3.2

1.6

2.3

0.7

0.9

2.2

2.7

2.7

3.1

3.7

5.6

6.7

6.0

4.8

7.4

4.9

5.0

5.0

5.0

iRa

N0.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

10.

91.

90.

50.

40.

10.

00.

00.

00.

00.

00.

00.

0fr

om a

stra

khan

' and

Mak

hach

kala

0.1

0.9

1.9

0.5

0.4

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Ba

Re

NtS

Se

a0.

00.

00.

00.

00.

00.

00.

00.

00.

00.

10.

30.

33.

36.

39.

96.

54.

54.

75.

310

.410

.321

.530

.031

.032

.0 R

ussi

an c

rud

e (v

ia v

ario

us R

ussi

a p

orts

: ark

hang

el's

k, M

urm

ansk

, V

itino

, Var

and

ey, i

ndig

a, e

tc.)

0.1

0.3

0.3

3.3

6.3

9.9

6.5

4.5

4.7

5.3

10.4

10.3

21.5

30.0

31.0

32.0



93


Tab

le II

I-26

Rus

sian

Cru

de

Oil

Exp

ort

s B

y lo

cati

on

(Hig

h S

cena

rio

) (co

ntin

ued

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

ea

St

aS

ia0.

61.

00.

01.

90.

10.

21.

82.

32.

22.

64.

45.

04.

86.

29.

111

.014

.522

.020

.824

.738

.668

.575

.587

.095

.4 R

ussi

an c

rud

e (fr

om S

akha

lin/e

ast

Sib

eria

)0.

40.

80.

01.

70.

10.

11.

52.

02.

02.

23.

84.

02.

82.

73.

23.

14.

213

.010

.814

.126

.852

.163

.776

.386

.0

Sak

halin

infr

astr

uctu

re (D

eKas

tri,

Vity

az, p

rigor

odno

ye, e

tc.)

0.4

0.8

0.0

1.7

0.1

0.1

1.5

2.0

2.0

2.2

3.8

4.0

2.8

2.7

3.2

3.1

4.2

13.0

10.6

13.8

13.5

22.7

28.0

35.5

39.5

e

ast

Sib

eria

-pac

ific

coa

st (e

Sp

o)

pip

elin

e0.

20.

313

.329

.435

.740

.846

.5 R

ussi

an c

rud

e ex

por

ts (f

rom

Wes

t S

iber

ia)

0.2

0.2

0.0

0.2

0.0

0.1

0.3

0.3

0.2

0.4

0.6

1.0

2.0

3.5

5.9

7.9

10.3

9.0

10.0

10.5

11.8

16.4

11.8

10.7

9.4

R

ail

0.2

0.2

0.0

0.2

0.0

0.1

0.3

0.3

0.2

0.4

0.6

1.0

2.0

3.5

5.9

7.9

10.3

9.0

8.9

9.0

9.2

0.0

0.0

0.0

0.0

e

ast

Sib

eria

-pac

ific

coa

st (e

Sp

o)

pip

elin

e0.

00.

02.

614

.411

.810

.79.

4 e

ast

Sib

eria

-pac

ific

coa

st (e

Sp

o)

pip

elin

e (to

tal)

0.2

0.3

15.9

43.8

47.5

51.5

55.9

Koz

min

o (e

xpor

ts v

ia p

acifi

c co

ast

term

inal

)15

.328

.832

.536

.540

.9

S

kovo

rod

ino

(exp

orts

via

chi

na

pip

elin

e sp

ur)

0.6

15.0

15.0

15.0

15.0

Kaz

akhs

tan-

chi

na p

ipel

ine

1.0

1.5

0.0

2.0

0.0

0.0

0.0

ea

Ste

RN

pip

eli

Ne

S (t

otal

)0.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

00.

01.

31.

815

.945

.847

.551

.555

.9

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Rus

sian

cru

de

0.0

0.0

0.0

0.0

0.0

Sou

rce:

tot

al e

xpor

ts r

epor

ted

by

cus

tom

s S

tatis

tics

(Ros

stat

); su

pp

lem

ente

d w

ith d

ata

on e

xpor

t ro

utes

from

Min

istr

y of

ene

rgy

(info

tek,

tsD

U) a

nd o

ther

sou

rces

; pro

ject

ions

by

iHS

ce

Ra

. 1.

Doe

s no

t in

clud

e ex

por

ts t

o K

azak

hsta

n.




Tab

le II

I-27

Rus

sian

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(lo

w S

cena

rio

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

tota

l e

Xp

oR

tS22

1.8

166.

115

0.5

113.

612

7.0

122.

512

5.8

128.

213

7.2

134.

414

4.8

160.

918

8.8

225.

225

2.9

248.

124

7.5

258.

623

8.4

247.

324

8.0

283.

224

9.8

233.

722

4.1

Bla

cK

Se

a40

.2

18.5

23

.9

26.6

39

.5

39.9

43

.9

44.3

44

.4

42.5

43

.2

45.3

53

.6

64.2

59

.4

55.7

55

.6

60.4

53

.8

53.7

45

.6

44.0

33

.2

29.5

15

.2

Nov

oros

siys

k30

.9

14.9

21

.6

20.9

28

.9

28.1

30

.0

30.3

29

.9

30.1

34

.9

36.0

38

.8

41.7

42

.5

40.6

38

.3

36.5

35

.0

33.0

30

.4

34.0

28

.2

25.5

12

.2

tuap

se5.

5 0.

6 2.

1 3.

0 4.

4 4.

4 4.

7 4.

8 6.

1 5.

1 5.

7 5.

4 5.

0 4.

9 4.

8 4.

9 5.

1 4.

4 4.

5 4.

2 4.

8 6.

0 4.

0 4.

0 3.

0 o

des

sa (R

ussi

an e

xpor

ts)

3.8

3.0

0.2

2.7

6.2

7.4

8.2

8.7

8.2

5.5

2.5

3.2

3.3

2.2

1.4

0.4

2.1

2.8

0.8

0.0

0.0

0.0

0.0

0.0

0.0

piv

den

niy

(Yuz

hniy

)0.

9 1.

9 5.

7 3.

7 9.

9 7.

7 9.

5 3.

4 0.

0 0.

0 0.

0 0.

0 c

pc

(Yuz

hnay

a o

zere

yevk

a)0.

3 2.

3 6.

3 6.

7 5.

6 6.

9 6.

4 4.

0 1.

0 0.

0 0.

0 R

ail e

xpor

ts (v

ia v

ario

us p

orts

: Fe

odos

iya,

Kav

kaz,

etc

.)1.

0 0.

5 0.

2 1.

8 0.

1 0.

7 6.

5 11

.3

5.0

1.3

0.2

0.1

0.2

0.1

0.6

0.0

0.0

0.0

0.0

Riv

er e

xpor

ts3.

2 3.

5 0.

4 0.

0 0.

0 0.

0 0.

0 0.

0

Ba

ltic

Se

a13

.0

7.2

8.3

8.7

11.0

11

.5

16.0

16

.1

16.4

16

.7

22.8

26

.7

36.7

50

.2

67.4

71

.8

72.4

79

.7

73.3

76

.8

73.4

81

.9

63.0

54

.8

57.7

Ve

ntsp

ils13

.0

7.2

8.3

8.7

11.0

11

.5

14.3

14

.6

14.6

13

.0

13.6

15

.0

7.4

3.3

1.6

0.2

1.2

1.2

0.7

0.5

0.0

0.0

0.0

0.0

0.0

But

inge

0.6

3.1

5.2

5.6

10.8

6.

8 5.

3 2.

9 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 p

rimor

sk0.

2 11

.2

16.0

41

.9

54.4

62

.5

74.2

69

.9

70.2

70

.0

68.4

51

.0

43.8

47

.7

Ust

-lug

a (B

pS

-2)

12.5

12

.0

11.0

10

.0

Gd

ansk

(inc

lud

ed a

s p

art

of p

olan

d u

ntil

2003

)4.

4 5.

8 5.

2 4.

2 2.

8 1.

9 4.

6 1.

7 0.

8 0.

0 0.

0 0.

0 R

ail e

xpor

ts (v

ia v

ario

us p

orts

: K

alin

ingr

ad, e

ston

ia, e

tc.)

1.7

1.5

1.8

3.1

6.1

6.3

12.5

15

.8

11.3

6.

8 1.

6 1.

6 0.

8 1.

6 1.

7 0.

2 0.

0 0.

0 0.

0

DR

UZ

HB

a p

ipe

liN

e (e

aste

rn e

urop

e)45

.8

25.0

34

.5

25.8

38

.9

39.8

41

.4

42.9

49

.3

50.5

52

.5

54.0

52

.2

54.6

56

.3

56.4

58

.6

55.4

51

.8

49.2

53

.8

55.6

50

.9

50.7

51

.2

pol

and

11.4

5.

4 4.

5 3.

5 6.

1 7.

3 9.

2 10

.2

13.6

14

.6

17.8

18

.4

16.3

17

.0

16.9

17

.3

19.0

18

.2

19.0

15

.8

19.4

18

.0

13.5

13

.2

13.0

G

erm

any

15.8

9.

1 12

.8

9.5

16.3

15

.0

16.1

15

.7

18.5

19

.4

19.5

20

.0

20.4

21

.5

21.7

22

.3

21.8

20

.6

16.9

19

.2

17.9

19

.0

18.9

19

.5

20.0

c

zech

Rep

ublic

5.3

3.3

4.6

3.1

6.3

6.9

5.7

5.8

5.3

4.8

3.7

3.7

3.6

3.9

4.4

5.1

5.2

4.6

4.8

5.0

4.6

5.4

5.5

5.5

5.5

Slo

vaki

a7.

7 4.

7 6.

6 4.

5 4.

9 5.

0 5.

2 5.

1 5.

3 5.

6 5.

4 5.

9 5.

5 5.

8 6.

0 5.

2 5.

9 5.

5 4.

5 2.

6 4.

9 6.

2 6.

3 6.

3 6.

5 H

unga

ry4.

8 2.

5 6.

0 5.

2 5.

3 5.

6 5.

2 6.

1 6.

6 6.

1 5.

7 5.

5 6.

2 5.

7 6.

1 6.

4 6.

8 6.

5 6.

6 6.

4 6.

6 6.

8 6.

5 6.

0 6.

0 a

ustr

ia0.

0 0.

0 0.

0 0.

0 0.

0 o

mis

alj t

erm

inal

/cro

atia

-Ser

bia

-S

love

nia-

Bos

nia

0.8

0.4

0.5

0.2

0.6

1.1

0.0

0.0

0.0

0.0

0.3

0.6

0.2

0.2

0.2

0.2

FSU

Re

pU

Bli

cS

*10

8.9

100.

5 72

.3

42.1

33

.1

27.7

19

.5

21.0

22

.6

21.4

20

.6

27.5

35

.4

40.1

45

.8

42.5

36

.0

29.5

27

.3

27.8

18

.8

21.5

21

.5

22.5

21

.0

Bel

arus

37.4

33

.7

19.7

12

.4

11.0

11

.1

10.1

10

.5

9.6

9.8

11.8

11

.8

13.6

14

.7

17.3

19

.3

20.4

19

.9

21.1

21

.4

12.9

12

.5

11.5

10

.5

10.0

l

ithua

nia

(dire

ct b

y p

ipe)

9.7

11.5

4.

3 5.

1 3.

7 3.

2 1.

9 4.

7 6.

3 3.

8 4.

7 6.

4 6.

0 5.

2 8.

6 8.

6 5.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 U

krai

ne53

.7

49.7

41

.5

19.9

15

.7

13.2

7.

5 5.

8 6.

7 7.

8 4.

1 9.

3 15

.8

20.2

19

.9

14.6

10

.6

9.6

6.2

6.3

6.0

9.0

10.0

12

.0

11.0

o

ther

Rep

ublic

s (e

xclu

din

g K

azak

hsta

n)8.

1 5.

6 6.

8 4.

7 2.

7 0.

2

to K

aZ

aK

HS

taN

(pav

lod

ar r

efine

ry)

13.3

13

.9

11.5

8.

5 4.

4 3.

4 3.

2 1.

6 2.

3 0.

7 0.

9 2.

2 2.

7 2.

7 3.

1 3.

7 5.

6 6.

7 6.

0 4.

8 7.

4 4.

9 5.

0 5.

0 5.

0

iRa

N0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

9 1.

9 0.

5 0.

4 0.

1 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 fr

om a

stra

khan

' and

Mak

hach

kala

0.1

0.9

1.9

0.5

0.4

0.1

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Ba

Re

NtS

Se

a0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

1 0.

3 0.

3 3.

3 6.

3 9.

9 6.

5 4.

5 4.

7 5.

3 10

.4

10.3

12

.5

13.0

14

.0

15.0

R

ussi

an c

rud

e (v

ia v

ario

us R

ussi

a p

orts

: a

rkha

ngel

'sk,

Mur

man

sk, V

itino

, Va

rand

ey, i

ndig

a et

c.)

0.1

0.3

0.3

3.3

6.3

9.9

6.5

4.5

4.7

5.3

10.4

10

.3

12.5

13

.0

14.0

15

.0



95


Tab

le II

I-27

Rus

sian

Cru

de

Oil

Exp

ort

s b

y lo

cati

on

(lo

w S

cena

rio

) (co

ntin

ued

)(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2015

2020

2025

2030

ea

St

aS

ia0.

6 1.

0 0.

0 1.

9 0.

1 0.

2 1.

8 2.

3 2.

2 2.

6 4.

4 5.

0 4.

8 6.

2 9.

1 11

.0

14.5

22

.0

20.8

24

.7

38.6

62

.8

63.2

57

.2

59.0

R

ussi

an c

rud

e (fr

om S

akha

lin/e

ast

Sib

eria

)0.

4 0.

8 0.

0 1.

7 0.

1 0.

1 1.

5 2.

0 2.

0 2.

2 3.

8 4.

0 2.

8 2.

7 3.

2 3.

1 4.

2 13

.0

10.8

14

.1

26.8

38

.5

42.0

43

.2

45.5

Sak

halin

infr

astr

uctu

re (D

eKas

tri,

Vity

az, p

rigor

odno

ye, e

tc.)

0.4

0.8

0.0

1.7

0.1

0.1

1.5

2.0

2.0

2.2

3.8

4.0

2.8

2.7

3.2

3.1

4.2

13.0

10

.6

13.8

13

.5

22.3

23

.5

24.7

26

.0

e

ast

Sib

eria

-pac

ific

coa

st (e

Sp

o)

pip

elin

e0.

2 0.

3 13

.3

16.2

18

.5

18.5

19

.5

Rus

sian

cru

de

exp

orts

(fro

m W

est

Sib

eria

)0.

2 0.

2 0.

0 0.

2 0.

0 0.

1 0.

3 0.

3 0.

2 0.

4 0.

6 1.

0 2.

0 3.

5 5.

9 7.

9 10

.3

9.0

10.0

10

.5

11.8

24

.3

21.2

14

.0

13.5

Rai

l0.

2 0.

2 0.

0 0.

2 0.

0 0.

1 0.

3 0.

3 0.

2 0.

4 0.

6 1.

0 2.

0 3.

5 5.

9 7.

9 10

.3

9.0

8.9

9.0

9.2

0.0

0.0

0.0

0.0

e

ast

Sib

eria

-pac

ific

coa

st (e

Sp

o)

pip

elin

e0.

0 0.

0 2.

6 24

.3

21.2

14

.0

13.5

e

ast

Sib

eria

-pac

ific

coa

st (e

Sp

o)

pip

elin

e (to

tal)

0.2

0.3

15.9

40

.5

39.7

32

.5

33.0

K

ozm

ino

(exp

orts

via

pac

ific

coas

t te

rmin

al)

15.3

25

.5

24.7

17

.5

18.0

S

kovo

rod

ino

(exp

orts

via

chi

na

pip

elin

e sp

ur)

0.6

15.0

15

.0

15.0

15

.0

Kaz

akhs

tan-

chi

na p

ipel

ine

1.0

1.5

0.0

0.0

0.0

0.0

0.0

ea

Ste

RN

pip

eli

Ne

S (t

otal

)0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 0.

0 1.

3 1.

8 15

.9

40.5

39

.7

32.5

33

.0

Ba

KU

-ce

YH

aN

pip

eli

Ne

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Rus

sian

cru

de

0.0

0.0

0.0

0.0

0.0

S

ourc

e: t

otal

exp

orts

rep

orte

d b

y c

usto

ms

Sta

tistic

s (R

osst

at);

sup

ple

men

ted

with

dat

a on

exp

ort

rout

es fr

om M

inis

try

of e

nerg

y (in

fote

k, t

sDU

) and

oth

er s

ourc

es; p

roje

ctio

ns b

y iH

S c

eR

a.

1. D

oes

not

incl

ude

exp

orts

to

Kaz

akhs

tan.

2.

incl

udes

(in

2001

-200

2 an

d 2

006-

2007

) vo

lum

es d

eliv

ered

to

pav

lod

ar o

r S

hym

kent

via

sw

ap a

rran

gem

ent

for

onw

ard

exp

ort

to c

hina

.




bd) (40.7%) on Aframax tankers (65,000–80,000 dwt), and 1.8 mt (32,000 bd) on smaller tankers.

A new berth, known as 1A, opposite Berth 1, opened in mid-2011 to allow Berth 1 to close for 6–12 months for a major overhaul. The new berth will take the large vessels normally handled by Berth 1 in the interim. Longer term, the new berth will allow two large tankers to be accommodated at the same time. However, this will not double the effective capacity, since the two berths share much of the existing infrastructure; the new berth will take the pressure off Berth 1, which according to port officials has been operating at 36% above its rated capacity.

Crude oil volumes flowing through Novorossiysk are projected to remain less than 50 mt (1 mbd) for all scenario combinations going forward, although the Novorossiysk port authorities speak of expanding capacity up 65 mt (1.3 mbd) (30%) by 2012. There are several reasons for the conservative outlook. First, any expanded crude deliveries to Novorossiysk must be viewed in the context of Russia’s overall oil balance and available export supplies. Second, effective use of the expanded terminal capacity for crude oil would require expansion of pipeline capacity (through looping) on the stretch of Transneft pipeline from Tikhoretsk to Novorossiysk, which is not a high priority project for Transneft at the current time. But in the near term, of course, any expanded deliveries of crude to Novorossiysk beyond the current level of 50 mt (1 mbd) could be done by rail.

CPC. The CPC currently is the second-largest crude oil export terminal in the Black Sea, but if current expansion plans come to fruition, it will eventually surpass Novorossiysk. Crude exports via the CPC edged up slightly again in 2010, reaching 34.9 mt (760,000 bd). Of this, 28.5 mt (570,000 bd) was Kazakh crude and 6.4 mt (128,000 bd) was Russian crude. A link between the Transneft system and CPC materialized in the second half of 2004 (involving rail shipments in the North Caucasus between Tikhoretsk and Kropotkin),

Table III-28

Berths at Novorossiysk's Oil Port

Berth Number product(s)

tankers (thousand DWt)

tanker length (m) Draft (m)

loading Rate (tons/hr)

1 crude oil 120-250 258-320 23.41 10,000 1a crude oil 120-251 258-320 23.41 10,000

2crude oil, diesel,

fuel oil 40-90 up to 250 14.5 up to 6,000

3crude oil, diesel,

fuel oil 10-302 up to 205 11.5 up to 3,000

6-7crude oil, diesel,

fuel oil 15-653 up to 250 13.5 up to 6,000 5-8 diesel, fuel oil 3.3-12 up to 146 12.0 up to 900

Source: Novorossiysk commercial port. 1. Navigable draft of the approach channel is 19 meters. 2. can accommodate 33,000 DWt tankers under certain circumstances. 3. tankers



97


allowing access of Russian crude/condensate into the CPC system. The Russian allocation is for up to 15 mt per year (300,000 bd) when CPC expands to its full design capacity of 67 mt per year (1.34 mbd).

Crude oil (known as CPC Export Blend) is loaded from the CPC onto tankers from two single-point mooring buoys (SPMs), with a loading rate of 12,700 metric tons per hour each. They are located in water depths of over 50 m (56 m and 54 m, respectively), and so the terminal has the capability (theoretically) of loading 300,000 dwt tankers (VLCCs). But because of size limitations in the Turkish Straits (see below), the largest tankers loaded are Suezmaxes (that is, 100,000–160,000 dwt). Of 2010 total 34.9 mt (698,000 bd) of crude dispatched from the CPC marine terminal (Yuzhnaya Ozereyevka), the bulk (70.5%) was on Suezmax tankers, 24.6 mt (492,000 bd), with the remainder (10.3 mt, or 206,000 bd) loaded onto Aframax tankers (65,000–80,000 dwt).

Construction on the CPC expansion program was finally launched in July 2011 (see above). The full-phase expansion includes 10 new pumping stations, a third tanker-loading buoy (SPM) at the Black Sea terminal, additional tankage, and approximately 88 km of pipeline replaced within Kazakhstan. Completion of the three phases of the expansion project is expected by 2015. The total costs are authorized at US$5.4 billion.

Exports through the CPC pipeline are expected to remain well beyond the initial design capacity of 28 mt (560,000 bd) through the use of DRAs in the immediate future, followed by expanded capacity later on. In the low scenario, capacity is assumed to not reach 67 mt per year (1.34 mbd) until 2020. The base scenario assumes that CPC capacity expands beginning in 2011, reaching 67 mt per year (1.34 mbd) by 2015. The high scenario assumes that the expansion is completed slightly sooner, with the pipeline reaching its full design capacity of 67 mt per year (1.34 mbd) by 2014. DRAs could lift the eventual capacity of the pipeline to as much as 76 mt per year (1.6 mbd) if necessary.

As a result, exports through the CPC pipeline are expected to drive upward; as CPC is one of the lowest cost export options for Kazakhstan’s oil exports. Maximum throughput of 69 mt per year (1.38 mbd) in expected in the base-base scenario combination in 2030, and a maximum of 73 mt (1.46 mbd) is expected in the high Russia-high Caspian scenario in 2025. In the low-low scenario, throughput reaches 53.1 mt (1.06 mbd) in 2030.

However, incremental throughput for CPC is not necessarily incremental volumes in terms of Black Sea evacuation. A key element of CPC expansion is that it allows the consolidation of export flows into this single route from various producers (especially TCO) that currently already reach the Black Sea, such as rail-based exports to Ukrainian ports or Georgian ports.

Other Black Sea ports. The other key Black Sea ports that handle Eurasian crude oil include Tuapse, Pivdenniy, Odessa, Supsa, Feodosiya, Batumi, Kulevi, and, prospectively, Taman. A number of other smaller ports, which mainly handle refined products, also have handled rail-delivered crude oil in the past, including Kavkaz. Developments at the other key ports are discussed individually below.




Tuapse.• The Tuapse terminal is the only port in the Russian sector of the Black Sea through which producers of West Siberian crude (Siberian Light) can currently export their oil directly, avoiding mixture with higher-sulfur Russian crude streams. The terminal has a nameplate capacity of 5 mt per year (100,000 bd) for crude oil.* In 2010 Tuapse handled 4.8 mt (96,000 bd) of Russian crude oil exports and dispatched 9.0 mt of refined product exports. Crude oil exports from Tuapse do not vary radically in any of the scenarios, remaining at about 3–5 mt per year (60.000–100,000 bd) over the outlook horizon (originating only in Russia). We see Tuapse remaining a crude oil export point, although long-term plans announced by Rosneft call for it to be expanded and converted into a specialized product export port, with a substantial expansion and modernization of Rosneft’s Tuapse refinery. This discrepancy is rooted in different views about the long-term sustainability of a substantial tax break for refined products in the overall Russian export tax scheme. Because of Rosneft’s planned refinery expansion at Tuapse, a project is already under way, to be completed by 2012, to expand the Tikhoretsk-Tuapse pipeline to 12 mt per year (240,000 bd) by Transneft (although Rosneft is paying for it via a special “investment” tariff). The oil terminal at the port comprises two berths (No. 1 and No. 2) which can handle crude oil and three berths (Nos. 3–6) that handle only products (see Table III-29). The port approaches are deep enough to handle only 80,000 dwt tankers, although port facilities themselves are capable of handling 100,000 dwt. Most crude tankers loading at Tuapse are typically 70,000–80,000 dwt.

Odessa and Pivdenniy.• In all three scenarios, the Ukrainian terminals at Pivdenniy (Yuzhniy) and Odessa (Odesa) no longer are used for Russian or Kazakh piped exports flowing south, even following our expected cessation of the flow of Azeri north via the terminal to Belarus by 2015. Negotiations, in fact, already are under way between Russian and Ukraine about resuming southward export flows through Pivdenniy. However, Odessa is expected to remain a significant destination for rail-based crude exports from Kazakhstan in the future.

Odessa. – Ukraine’s Odessa oil terminal has a crude-oil handling capacity of 11 mt per year (220,000 bd) for piped deliveries. Total oil-handing capacity (crude and products; piped and railed) is reported as 25.5 mt per year (510,000 bd), of which 16.3 mt (326,000 bd is its total capacity for crude).** The oil terminal at the port comprises six berths, which can accommodate 260 m tankers with drafts up to 13 m (see Table III-29). Odessa’s oil harbor generally accepts vessels of 80,000–90,000 dwt, although berth No. 2 can handle 100,000 dwt tankers.

Pivdenniy. – The Pivdenniy (Yuzhniy) terminal was designed by Ukraine as the starting point of the Odessa-Brody (Bosphorus bypass) pipeline

*Prior to 2001 before the launch of Primorsk, throughput at Tuapse regularly exceeded 5 mt per year, hitting a maximum of 6.1 mt in 1998. The capacity of Tuapse’s total oil-loading capacity (crude and products) is reported at 18 mt per year.**Maximum deliveries of piped crude occurred in 2001, when Odessa handled 11.3 mt (226,000 bd) of Transneft-supplied crude. In 2010 Odessa received no piped crude but did export 3.7 mt of refined products and 4.4 mt (88,000 bd) of crude delivered to the port by rail. A decade ago, Odessa typically handled about 10–11 mt of refined product export per year as well as 10–11 mt (200,000–220,000 bd) of crude.



99


Table III-29

Oil-loading Berths at Major Ports in the Black Sea Handling Crude Oil

crude oil StorageBerth Number product(s)

tankers (thousand DWt)

tanker length (m) Draft (m)

crude oil loading Rate (tons/hr)

No. Reservoirs

total (cubic meters)

tuapse (Russia): 76,000

1crude oil, diesel,

fuel oil 100 up to 250 13.0 1800 (crude) 2 diesel, fuel oil 20-30 up to 170 11.5

3gasoline, diesel,

fuel oil 90 up to 188 9.8

4gasoline, diesel,

fuel oil 30-40 up to 195 11.5

5gasoline, diesel,

fuel oil 30-40 up to 213 12.0

6gasoline, diesel,

fuel oil 90 up to 167 9.75

Kavkaz (Russia): 8 30,000

8light products, heavy products 6 up to 91 4.5

9 crude oil 6 up to 50 6.0 1,000-2,000

odessa (Ukraine): 12 120,000 1 crude oil, fuel oil 86 up to 230 12.5 2,000

2crude oil, fuel oil,

vacuum gasoil 86 up to 270 12.5 2,000

4

diesel, fuel oil, vacuum gasoil,

lpG 80 up to 120 9.8

5

crude oil, gasoline, diesel, fuel oil, vacuum gasoil, base oil 86 up to 240 11.2

6 gasoline, diesel, 50 up to 150 4.77 lpG 10 up to 175 8.4

pivdenniy (Ukraine): 10 200,000 3H crude oil 100 up to 362 15.0 12,000 5B diesel, fuel oil 40 up to 230 12.6

Feodosiya (Ukraine): 7 112,600

North

crude oil, light products, base

oil 13.5-17 900-1,000

South

crude oil, light products, base

oil 12.5-15 900-1,000




Batumi (Georgia): 530,000 1 50 up to 200 11.0 2,000 2 15-25 up to 140 9.83 15-26 up to 165 9.8SpM 105 up to 250 13.5-20

Supsa (Georgia): 4 250,000 SpM 160 up to 250 50.0

Kulevi (Georgia): 320,000 1 105 15.0

Source: infotek Report, priportovyye neftyanyye terminaly Rossii, Baltii, Stran SNG i Finlandii, 2009.

Table III-29

Oil-loading Berths at Major Ports in the Black Sea Handling Crude Oil (continued)

and was intended to carry Caspian oil westward into Central Europe (see below). The terminal started operations in 2003, but because of the lack of contracts with Caspian producers, it carried Russian oil in “reverse” mode; i.e., delivered from the pipeline branching off the Druzhba at Brody to the Black Sea.* The terminal itself has a rated capacity of 14.5 mt per year of crude oil (290,000 bd) and 1.4 mt of refined products.** The terminal can handle 100,000 dwt tankers, with plans to deepen the draft from 15 m to allow 150,000 dwt tankers to load.

Supsa.• Georgia’s Supsa terminal, operated by the AIOC, was built to handle “early oil” from the ACG project. The terminal shut down in October 2006 for about 18 months owing to technical problems in the pipeline, reopening in summer 2008 after extensive repairs. Supsa has a nameplate capacity of about 7 mt per year (140,000 bd).*** The throughput for the Baku-Supsa pipeline and Supsa terminal is projected to remain more or less steady at 4.5–5.0 mt per year (90,000–100,000 bd) depending on

*However, in early 2011, Belarus implemented a swap agreement with Azerbaijan for its Venezuelan crude. The arrangement calls for Azeri crude procured in the Black Sea to be shipped north to Belarus via the Pivdenniy-Brody pipeline and southern Druzhba pipeline operating in reverse mode. Azerbaijan agreed to supply crude oil to Belarus on behalf of Venezuela, while the Latin American country will provide oil for Azerbaijan to export to the United States. Ukrainian pipeline operator Ukrtransnafta began pumping Azeri crude north to Brody in February and then reversed the flow on one of the southern Druzhba pipeline strings between Mozyr and Brody, to deliver the crude to the Mozyr refinery in Belarus. The agreement calls for 4 mt per year (80,000 bd) of oil to be transported by Ukrtransnafta, the Ukrainian oil pipeline operator, under a “pump or pay” arrangement. Belarus needs to acquire about four 80,000 metric ton cargoes per month of Azeri crude, which is evacuated via Supsa. This volume may be difficult for SOCAR, as Supsa only loads about five cargoes per month, and SOCAR is not the only Azeri shipper using Supsa. Because of the much higher costs involved in acquiring crude for the Belarusian refineries via this method from the Black Sea compared with Russian crude, however, we assume that this swap arrangement will be eventually abandoned.**Peak crude throughput was in 2007 at 9.9 mt (198,000 bd). However, the Pivdenniy terminal has handled less than 1 mt per year of refined product exports since it opened.***This is the capacity of the pipeline, which is also reported as being 8 mt per year (160,000 bd). The marine terminal itself is an SPM with a capacity of 14 mt per year (280,000 bd) and can load tankers up to 160,000 dwt.



101


the scenario, and with only Azerbaijani crude using this particular route. We do not envision the construction of a new pipeline between Azerbaijan and Georgia along this route for Kazakh crude, although this has been proposed and may yet emerge as a realistic export option. Supse is much less expensive to use than BTC for AIOC crude, and therefore despite the continued overtures from Kazakhstan to also use this route, we think it more likely that Kazakh crude would be directed into either BTC or Kulevi-Batumi.

Georgian ports (Batumi/Kulevi).• In contrast to the other major Black Sea ports, there is no pipeline link to Batumi or Kulevi, and all crude shipments are by rail. Out of 6.3 mt (126,000 bd) of crude exports going to Batumi or Kulevi in 2010, 5.2 mt (104,000 bd) were from Kazakhstan, 0.4 mt (8,000 bd) were from Turkmenistan, and 0.7 mt (14,000 bd) were from Azerbaijan. Both Batumi and Kulevi are relatively high-cost export destinations for many of the Kazakh and Turkmen shippers (because of rail and Caspian tanker expenses), so their utilization depends largely on the availability (or nonavailability) of alternative (cheaper) routes. Nonetheless, Batumi/Kulevi remain an important export destination. Depending on the scenario, Batumi and Kulevi are projected to handle up to 7.5 mt (150,000 bd) in 2025 in the base scenario, 14.7 mt per year (294,000 bd) in 2025 in the high scenario, or as little as 1–2 mt per year (20,000–40,000 bd) in the low scenario in 2020–30.

Batumi. – The Batumi terminal on the Georgian coast of the Black Sea and now owned by KazMunayGaz has a capacity of about 15 mt (crude and products). The port accommodates 30,000–90,000 dwt tankers at four berths, including a SPM buoy for 80,000–119,000 dwt Aframaxes.

Kulevi. – The Kulevi terminal, also located on the Georgian coast of the Black Sea, is majority owned by SOCAR. It opened in May 2008, with a capacity of 5 mt per year, but did not load its first crude tanker until May 2010. It has three berths in operation—two for loadings and one for the fleet service. Berth No. 2 is 230 m long, went from loading 10,000 dwt tankers in water depth of only 3.0–3.5 to accommodating 40,000 dwt tankers after dredging was completed in May 2011.. Berth No. 1 is 350 m in length, with a water depth of 15 m and can now reportedly accommodate up to 105,000 dwt tankers.

Rail-based crude oil exports.• Railed-based exports of crude oil to other Black Sea ports (e.g., Odessa, Feodosiya) were 6.3 mt (126,000 bd) in 2010, nearly double volumes in 2008–09. The bulk of these exports are now from Kazakhstan, bound for either Odessa or Feodosiya.* Earlier (in 2003–04), these exports were mostly Russian. Longer term, high-cost railed exports of crude oil to these other Black Sea ports (potentially including the new terminal under construction on the Taman Peninsula) generally decline over time because of the increased availability of pipeline transportation. But they can

*Feodosiya, on the eastern side of the Crimean Peninsula, has an oil-handling capacity of 10 mt per year. It has mostly handled refined products, but it was used extensively for crude by Yukos prior to 2004 and recently is being used heavily again as a destination for railed crude by TCO. In 2010 the port exported 1.5 mt of crude oil, nearly all of which (1.3 mt) was Kazakh in origin. It handled 809,000 metric tons of refined product exports and 674,000 metric tons of imports in 2008, but the volume of refined products has dropped off sharply in recent years.




remain at relatively high levels because of the lack of alternate export possibilities for Eurasia as a whole, especially in the high production scenarios, where they rise to 12.5 mt (250,000 bd) in 2020 before dropping off to 1 mt (20,000 bd) by 2030. In the base-base scenario, they remain in the range of 2–2.5 mt per year (40–50,000 bd) over the outlook horizon.

3.5.3 Outlook for Offshore Developments in the Turkish Black Sea

None of Turkey’s oil refineries have any crude offtake in the Black Sea. Turkey’s existing crude oil transport infrastructure supplies all its refineries below the Bosphorus (Istanbul) Strait, including the Izmit refinery near Istanbul. Therefore, although Turkey will continue to consume crude oil moving from the Black Sea (as it does now), these quantities do not reduce the Black Sea crude oil surplus which has to be transported either through the Bosphorus Straits or through any of the projected bypass pipelines.

But Turkish crude oil production does figure in the overall amount of Black Sea evacuation. It seems prudent to assume some success in ongoing exploration activities in the Turkish section of the Black Sea. We assume that the activity results in commercial discoveries that are developed, resulting in a moderate level of production that evacuates the Black Sea to reach Turkish refineries (or the broader Mediterranean oil market). Turkish Black Sea oil production is assumed to begin no sooner than 2015, rising to 1.2 mt (24,000 bd) in 2020 and 2.5 mt (50,000 bd) by 2030.

3.5.4 Offtake volumes of Crude by Countries along the littoral of the Black Sea

This part of the overall analysis generates a balance number that reflects the necessary adjustment to total flows of oil (crude and products) arriving at (or targeting) the Bosphorus Strait after considering various offtakes and additions in the Black Sea. This includes the crude oil imports and small volumes of refined product exports of four Black Sea littoral states: Ukraine, Romania, Bulgaria, and Turkey and various transit flows as well.

Romanian and Bulgarian refineries import significant volumes of crude oil. Their future crude oil import requirements are generated as a function of projections of indigenous crude oil production (essentially for Romania; Bulgaria’s own indigenous production is practically negligible) and domestic consumption (of refined products) with some allowance for generating exports of refined products.

During the 1990s, much of this crude oil was sourced from the Mediterranean Sea (chiefly from Persian Gulf exporters), meaning that these imports increased rather than decreased the volumes passing through the Bosphorus. As far as these two states are concerned, a fundamental assumption is that an increasing proportion of their crude oil imports will come from Russia and the Caspian region via the Black Sea—a trend that has been very much in evidence since the mid-1990s. Bulgaria sources virtually all of its crude imports (94%–96%) from Black Sea (Russian) suppliers, and this is assumed to move to 100% by 2015. The picture is similar for Romania, which in 2005 met 56% of its crude import requirements with Russian crude (delivered via the Black Sea) and only about 40% from crude sourced in the Mediterranean Sea. By 2010 this had shifted to about 70% from the Black Sea and



103


30% from elsewhere (Mediterranean). The percentage of Romania’s crude supplies sourced in the Mediterranean is assumed to decline to 15% by 2015, 10% by 2020, and then cease altogether by 2025. This has the effect of pulling more crude from the Black Sea and reducing the volumes that must pass through the Bosphorus.

Within Ukraine, despite the enthusiasm of the Ukrainian government (and currently announced initiatives), we do not believe that the Pivdenniy terminal is going to be used for Caspian oil transit from the Black Sea to the Baltic Sea via a new pipeline through Poland. IHS CERA assumes that long-term plans to extend the Pivdenniy (Odessa)-Brody pipeline to Plock in Poland and then to Gdansk do not materialize. We do assume that Pivdenniy is going to be used for some Azeri crude shipments north to Belarus for a few years. But for all three scenarios, we assume that the Ukrainian terminals at Pivdenniy (Yuzhniy) and Odessa no longer are used for Russian or Kazakh piped exports flowing south over the outlook period, even following the expected cessation of the flow of Azeri north via the terminal to Belarus by 2015.

But we do assume that Ukrainian rail is used to transit some Caspian crude northward to Austria, the Czech Republic, and Poland (and perhaps Lithuania), reaching about 1 mt per year (20,000 bd) in 2010–15 before tapering off. Similarly in the Russian low and base scenarios, we assume that Ukraine will import a small amount of Caspian crude from the Black Sea for use in certain of its (unsophisticated) refineries in western Ukraine and Kremenchug. We have the amount holding steady at 2 mt (40,000 bd) after 2015. In 2008–09 Ukraine imported a small amount of Iraqi crude for use in the Kremenchug refinery. In 2009–10, Kremenchug shifted its purchases to include small amounts of Azeri and Kazakh crude (in the Black Sea).

Outlooks for the refined product balances of Ukraine, Romania, and Bulgaria imply continuing exports of those products in surplus. Refined product exports from these three countries hit a peak of 15.1 mt in 2004. In the high case scenario, they rise back to 14.9 mt in 2025, while in the base scenario reach of maximum of 11.9 mt in 2025. In the low case, they remain in the range of only 2–3 mt per year. This total is largely due to contributions from Ukraine rather than Romania or Bulgaria. It is assumed that 90% of these exported products end up transiting the Bosphorus, with the other 10% delivered to countries surrounding the Black Sea.

3.5.5 volume of Crude Oil Needing Evacuation from the Black Sea

The estimated figures for 2010 show total flows of oil (crude and products combined) through the Bosphorus (in both directions) at 134.7 mt (2.7 mbd), a decline of about 11.2% from the 151.6 mt estimated for 2005, when such flows hit a peak. In addition to Eurasian crude oil flows (discussed above), the total in 2010 includes 33.0 mt (660,000 bd) of refined products. In 2005, when peak flow occurred, refined product evacuation from Eurasia amounted to 32.1 mt (642,000 bd).

The central (“P50”) prediction (Russian base–Caspian base) calls for a general drift downward in total flows through 2015, bringing the total down to 129.2 mt. Overall flows targeting the Bosphorus are then projected to rebound through 2025 to reach 135.9 mt (2.72 mbd),




but to decline thereafter, falling to 131.4 mt (2.63 mbd) by 2030. In the high-high (P90) scenario, flows targeting the Bosphorus are projected to rise steadily, reaching a new peak of 173.9 mt (3.48 mbd) in 2025, while in the low-low (P10) scenario the peak is projected to have already occurred in 2005 at 151.6 mt (3.03 mbd), with flows declining to 89.0 mt (1.78 mbd) by 2030.

But outbound (westbound) Eurasian crude oil shipments, as opposed to total oil flows, are increasingly the key concern. This is because they move mainly in the large tankers that are affected by the transit regime in the Turkish Straits (see below) and also because crude oil makes up the target volumes for any of the proposed bypass pipelines. These volumes, representing the total amount of Eurasian crude arriving in the Black Sea less offtakes in the Black Sea, dropped in 2006–08, to 92.5 mt (1.85 mbd) in 2008 from an all-time high of 102.0 mt (2.04 mbd) in 2005. These shipments rose in 2009 but dropped again in 2010, falling back to 92.4 mt (1.85 mbd).

However, Eurasian crude oil volumes are projected to rise in our central prediction (Russian Base–Caspian Base), up to 101.5 mt in 2015, and then reach a maximum of 112.1 mt (2.24 mbd) in 2025, about 10% higher than the previous peak hit in 2005 (see Table III-30). In the low-low (P10) scenario, Eurasian crude oil shipments are projected to have peaked in 2005 at 102.0 mt (2.04 mbd), and decline steadily over the outlook period, to only 61.8 mt (1.24 mbd) in 2030. In the high-high (P90) scenario, a rising trend is expected to 2025, reaching a peak of 142.7 mt (2.85 mbd), and still remaining at nearly that level (134.5 mt [2.69 mbd]) in 2030 (see Figure III-13).



105


Tab

le II

I-30

Flo

ws

of

Eur

asia

n C

rud

e O

il T

hro

ugh

the

Bo

spho

rus

by

Sce

nari

o(m

illio

n m

etric

ton

s [m

t] p

er y

ear)

(Rus

sia

Hig

h-c

asp

ian

Hig

h S

cena

rio)

(Rus

sian

Hig

h-c

asp

ian

Bas

e S

cena

rio)

(Rus

sia

Bas

e-c

asp

ian

Hig

h S

cena

rio)

(Rus

sia

Bas

e-c

asp

ian

Bas

e S

cena

rio)

(Rus

sia

Hig

h-c

asp

ian

low

S

cena

rio)

(Rus

sia

Bas

e-c

asp

ian

low

S

cena

rio)

(Rus

sia

low

-c

asp

ian

Hig

h S

cena

rio)

(Rus

sia

low

-c

asp

ian

Bas

e S

cena

rio)

(Rus

sia

low

-c

asp

ian

low

S

cena

rio)

1990

29.9

29

.9

29.9

29

.9

29.9

29

.9

29.9

29

.9

29.9

19

9115

.0

15.0

15

.0

15.0

15

.0

15.0

15

.0

15.0

15

.0

1992

26.8

26

.8

26.8

26

.8

26.8

26

.8

26.8

26

.8

26.8

19

9330

.5

30.5

30

.5

30.5

30

.5

30.5

30

.5

30.5

30

.5

1994

41.2

41

.2

41.2

41

.2

41.2

41

.2

41.2

41

.2

41.2

19

9541

.8

41.8

41

.8

41.8

41

.8

41.8

41

.9

41.9

41

.9

1996

44.9

44

.9

44.9

44

.9

44.9

44

.9

44.9

44

.9

44.9

19

9743

.7

43.7

43

.7

43.7

43

.7

43.7

43

.7

43.7

43

.7

1998

49.7

49

.7

49.7

49

.7

49.7

49

.7

49.7

49

.7

49.7

19

9957

.0

57.0

57

.0

57.0

57

.0

57.0

57

.0

57.0

57

.0

2000

59.8

59

.8

59.8

59

.8

59.8

59

.8

59.8

59

.8

59.8

20

0167

.2

67.2

67

.2

67.2

67

.2

67.2

67

.2

67.2

67

.2

2002

83.6

83

.6

83.6

83

.6

83.6

83

.6

83.6

83

.6

83.6

20

0393

.6

93.6

93

.6

93.6

93

.6

93.6

93

.6

93.6

93

.6

2004

95.2

95

.2

95.2

95

.2

95.2

95

.2

95.2

95

.2

95.2

20

0510

2.0

102.

0 10

2.0

102.

0 10

2.0

102.

0 10

2.0

102.

0 10

2.0

2006

99.5

99

.5

99.5

99

.5

99.5

99

.5

99.5

99

.5

99.5

20

0798

.8

98.8

98

.8

98.8

98

.8

98.8

98

.8

98.8

98

.8

2008

92.5

92

.5

92.5

92

.5

92.5

92

.5

92.5

92

.5

92.5

20

0998

.1

98.1

98

.1

98.1

98

.1

98.1

98

.1

98.1

98

.1

2010

92.4

92

.4

92.4

92

.4

92.4

92

.4

92.4

92

.4

92.4

20

1188

.4

88.5

87

.6

87.7

88

.5

87.7

86

.9

87.0

87

.0

2012

99.2

99

.3

90.8

90

.9

94.6

86

.2

89.7

89

.8

85.1

20

1310

5.5

99.3

99

.2

93.0

91

.2

84.8

97

.7

91.5

83

.3

2014

110.

3 10

3.9

101.

2 94

.7

92.5

83

.4

99.3

92

.8

81.5

20

1511

6.8

115.

5 10

5.3

101.

5 95

.8

85.8

10

3.3

99.5

79

.8

2016

123.

0 11

5.5

109.

3 10

1.8

93.9

84

.2

105.

6 98

.1

76.5

20

1712

6.6

115.

4 11

3.3

102.

1 93

.9

84.6

10

7.9

96.7

75

.2

2018

136.

3 12

1.4

117.

4 10

2.5

100.

0 85

.1

110.

2 95

.3

73.9




Tab

le II

I-30

Flo

ws

of

Eur

asia

n C

rud

e O

il T

hro

ugh

the

Bo

spho

rus

by

Sce

nari

o (c

ont

inue

d)

(mill

ion

met

ric t

ons

[mt]

per

yea

r)

(Rus

sia

Hig

h-c

asp

ian

Hig

h S

cena

rio)

(Rus

sian

Hig

h-c

asp

ian

Bas

e S

cena

rio)

(Rus

sia

Bas

e-c

asp

ian

Hig

h S

cena

rio)

(Rus

sia

Bas

e-c

asp

ian

Bas

e S

cena

rio)

(Rus

sia

Hig

h-c

asp

ian

low

S

cena

rio)

(Rus

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low

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asp

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cena

rio)

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low

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Bas

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rio)

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sia

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134.

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4 10

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4. THE BOSPHORUS BOTTlENECK: PUSHING TOwARD OR AwAy FROM THE CONGESTION THRESHOlD?

The Turkish Straits present an impediment to the flow of oil tankers; the buildup of wintertime queues at either end of the straits is common when daylight hours diminish. These narrow straits (Bosphorus [referred to as the Istanbul strait locally] and Dardanelles [Canakkale]), separated by the Sea of Marmara, constitute the only passage for ships either entering or exiting the Black Sea; i.e., going to or from the Mediterranean Sea (Aegean Sea) (see Figures IV-1– IV-3).

This includes not only the flow of oil and refined products of prime interest in this study but also all seaborne cargoes. The Black Sea provides the only (or most important) access to the world’s oceans for international trade for a number of countries on the Black Sea littoral, including Russia, Ukraine, Romania, Bulgaria, Moldova, and Georgia, as well as many landlocked countries in the Caspian region and Central Asia, such as Azerbaijan,

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109


Armenia, Kazakhstan, Kyrgyzstan, Uzbekistan, Tajikistan, and Turkmenistan. Because of this, the Turkish Straits are one of the world’s busiest waterways. Furthermore, the Bosphorus slices through the heart of one of the world’s largest cities, Istanbul (with about 13.3 million inhabitants in the metropolitan area), which adds considerably to the overall traffic in the waterway from numerous ferries and small boats.

For decades the Turkish Straits have been considered to be the easiest, most logical, and therefore most common export alternative for oil evacuation from the Black Sea, and they will probably remain so for the foreseeable future. A key point to consider, however, is that

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111


unlike many other types of goods transiting the Turkish Straits, crude oil can potentially be shifted to alternative modes and routes, namely through pipelines around the bottleneck, such as the BTC pipeline.

Because of the importance of the Turkish Straits in international seaborne trade, international passage through them has long been governed by international treaties between Europe’s “Great Powers” and Turkey in the modern era, including treaties signed in 1856, 1871, and 1878, as well as the Treaty of Lausanne in 1923. The latest of these is the 1936 Montreux Convention, a multilateral international treaty, which confirmed the international status of the straits and the general regulatory regime governing vessels passing through the straits. The treaty explicitly guarantees international freedom of passage for commercial vessels through the Turkish Straits during peacetime.*

Although the Turkish Straits are an internationally open waterway for commercial traffic, Turkish opposition to any large-scale increase in oil tanker traffic through them, especially the crowded Bosphorus, has long been obvious. It has been a long-standing goal of Turkish policy to reduce oil transiting the straits, and with the opening of the Caspian region’s oil resources to international development following the dissolution of the USSR, Turkish policymakers became determined to prevent the Turkish Straits from becoming the primary conduit for the flow of this oil to international markets. This concern has been one of the key drivers behind Turkish support for various bypass pipeline schemes, especially those through Turkish territory, such as the BTC pipeline or Samsun-Ceyhan (Trans-Anatolian Pipeline [TAP]).

As part of this effort, the Turkish government also has attempted to exert more national control over Straits transit since the 1990s. In some cases, this has been explicitly aimed at rolling back the perceived “loss of sovereignty” embodied by the Montreaux Convention. This is somewhat a revisionist view of history, as convening the negotiations that led to the Montreaux Convention was actually at the explicit request of Turkey. The goal was to obtain the right to regulate the passage of warships through the straits while establishing a regime that would foster the “development of commercial navigation between the Mediterranean and the Black Sea,” according to the Turkish foreign minister at the time.

4.1 KEy ElEMENTS OF THE BOSPHORUS BOTTlENECK

4.1.1 Geographic and Meteorological Restrictions Affecting the Turkish Straits

The Turkish Straits, like many other narrow straits around the world, are challenging to navigate nautically owing to a combination of factors. The Bosphorus is far more difficult in this respect than the Dardanelles. The Strait of Istanbul (Bosphorus) forms a winding and quite narrow geographical structure with a length of 18 nautical miles (about 19 statute

*Section 1, Article 2 of the Convention states: “In time of peace, merchant vessels shall enjoy complete freedom of transit and navigation in the straits, by day and by night, under any flag and with any kind of cargo, without any formalities, except as provided in Article 3 below. No taxes or charges other than those authorized by Annex I to the present Convention shall be levied by the Turkish authorities on these vessels when passing in transit without calling at a port in the straits.” Article 3 allows for sanitary control of ships passing through the straits “as prescribed by Turkish law within the framework of international sanitary regulations.” Annex I establishes fees and charges for sanitary control, lighthouses, navigation buoys, and life-saving services.




miles, or 31 km) (see Figure IV-2). The average width of the Bosphorus is only 1.5 km, but it is a mere 750 m across at its narrowest point (between Balta Limani and Kanlica). While making the passage through the Bosphorus, ships are required to make at least 12 course corrections, including two of 45 degrees or more. For example, at the narrowest point (Kandilli), ships are required to make one of the 45 degree course corrections. Furthermore, the Bosphorus has powerful and rapid currents, variable countercurrents, and submerged eddies capable of dragging ships off course and off anchor. Importantly, the surface current flows south, into the Sea of Marmara, while an undercurrent flows north into the Black Sea. Thus, because of the current, an oil-laden tanker coming from the Black Sea, moving with sufficient speed to provide steerage, has a much higher speed relative to the shore than an empty one inbound. The depth of the Bosphorus varies from 120 feet (36.6 m) to 408 feet (124.4 m) in midstream. Owing to two bridges that cross the Bosphorus, the maximum air draft permitted is 58 m.* In terms of weather, the Bosphorus is heavily affected by strong northern winds, heavy rain, and intensive fog (with sometimes zero visibility), particularly in spring and autumn. Weather conditions also can change rapidly. In short, transiting the Bosphorus in a large oil tanker (over 150 m in length) is challenging due to narrow traffic lanes, sharp turns, strong currents, and variable weather conditions.

The Canakkale (Dardanelles) is much wider and not nearly as winding as the Bosphorus, so it does not require the same kind of changes in course (see Figure IV-3). From a pure technical standpoint, it does not present nearly the impediment to shipping as the Bosphorus does. At its narrowest point, the Dardanelles is about a mile (1.6 km) across, and it averages about 3–4 miles (5–6 km) wide. But at 37 miles (60 km), it is longer than the Bosphorus. Its average depth is about 200 feet (61 m), and like the Bosphorus it has difficult currents: the surface current flows toward the Aegean Sea, while the undercurrent flows east, into the Sea of Marmara. However, these pose less of a problem than they do in the Bosphorus, and the Canakkale has never been closed to shipping because of current conditions alone. Furthermore, a large metropolis does not sit astride the Canakkale as is the case for the Istanbul Strait.

4.1.2 Historical Trends in vessel Traffic and vessel Size

The Montreaux Convention was written at a time when an average of 15 ships, weighing an average of 13 tons each, navigated the straits every day (i.e., about 5,500 ships per year). But in 2010 a total of 69,338 vessels passed through the Bosphorus, according to Automatic Identification System (AIS) statistics (see below), more than 12 times as many.** This is an average of 190 ships per day (in both directions). Much of this increase has occurred since 1991, when the Soviet Union collapsed, the Cold War ended, and the former Soviet countries became more closely integrated with the global economy. In 1991, 24,285 vessels

*Officially, vessels with an air draft of 58 m or more may not pass through the Bosphorus. But a height of over 54 m requires special permission for passage that effectively makes this the real height limit.*Technically, these are not recorded passages as such but rather the number of ships entering a defined geographic area (see below). According to statistics on ship passages through the Turkish Straits compiled by GAC (Gulf Agency Company), a global shipping and logistics company headquartered in Dubai, the total number of passages in 2010 (in both directions) through the Bosphorus was 52,313. This included 5,254 passages by oil tankers (10.0% of the total) and 4,640 passages by gas and chemical tankers (8.9% of the total). Thus, all types of tankers represented 9,894 passages, or 18.9% of the total.



113


passed through the Bosphorus; compared with 69,338 in 2010, this represents an increase of 2.9 times.

Of the total number of ship transits recorded by AIS in 2010, only 14.7% (10,226) were by all tanker types (see Table IV-1). This included 2,239 crude oil tankers, 1,487 products tankers, and 6,500 tankers carrying chemicals, gas, or other products.

Turkish statistics break down vessel traffic (and their cargoes) into somewhat different categories. An important distinction in the traffic regulation regime for the straits is that pertaining to so-called hazardous cargo (see section 4.1.3 Administrative Restrictions on Tankers). According to Turkish statistics for the most recent year reported, in 2007 the transit volume of so-called hazardous cargo through the Bosphorus amounted to 143.9 mt, including 95.3 mt (1.91 mbd) of crude oil, 40.3 mt (806,000 bd) of refined products, 4.2 mt (134,000 bd) of liquefied petroleum gases (LPGs), and 4.2 mt of chemicals (mainly ammonia). Between 1996 and 2007 the amount of such hazardous cargoes transiting the Bosphorus increased 2.4-fold (rising from 60.1 mt to 143.9 mt), with a similar increase in the aggregate number of ships carrying hazardous cargo, from 4,248 to 10,054 (see Figure IV-4). In terms of passages, vessels carrying so-called hazardous cargo reportedly constituted 17.8% of the overall total in the Bosphorus, as reported by the vessel tracking system (VTS) operator for 2007.

In 2010, based on AIS statistics, on average 28 tankers (of all types, but carrying mostly oil and refined products) went through the Bosphorus each day (in both directions). But half of these passages would be empty (i.e., on the inbound voyage), and the other half were ships carrying oil (and other products) outbound from the Black Sea. Still, most of these passages tend to be by relatively small vessels, as the average shipment size for all types of tankers combined (i.e., calculated by dividing total shipments by the number of outbound voyages) was only about 26,000 tons. In terms of crude tankers alone, the aggregate figures indicate that only six tankers on average went through the Bosphorus each day (in both directions).

By IHS CERA’s count (based upon loading schedules for each of the individual ports in the Black Sea), a total of 939 tankers left Eurasian Black Sea ports loaded with crude oil in 2010, carrying 93.9 mt (1.88 mbd) of crude (see Figure IV-5 and Table IV-2).* So-called Aframax tankers (65–80,000 dwt) still accounted for the majority of vessels loaded in the Black Sea, at 52.5%, but the share of the largest vessels (>100,000 dwt) jumped considerably, to 41.4%, in 2010. In terms of shipment volumes (as opposed to the number of vessels), the share of the largest tankers (>100,000 dwt) increased to 54.8% by 2010, while the share of Aframaxes contracted to 42.0%. Thus, the average crude oil tanker loading has increased slightly over the years, rising to 99,400 tons (about 726,000 barrels) in 2010. Not all of this

*The decline in Russian crude shipments via various smaller Black Sea ports (e.g., Kerch, Kavkaz, and Feodosiya) reflects changing Russian oil production and export dynamics. Such terminals were pressed into service during the years of the Russian oil production “boom” (2000–04), when crude oil exports were surging and pipeline export capacity was limited. But since that time, Russian production has basically flattened, the Primorsk export alternative on the Baltic has ramped up to full capacity, and changes in the export tax structure have increased Russian companies’ incentives to export products rather than crude (see above). This resulted in a substantial reduction in Russian crude exports through these smaller ports. Feodosiya has made something of a comeback lately, but this is due to special circumstances (i.e., Tengiz crude has returned because of the delay in CPC expansion).




Tab

le Iv

-1

Num

ber

of

Shi

p P

assa

ges

per

Six

-Mo

nth

Per

iod

Thr

oug

h M

ajo

r H

igh-

Traf

fic

Str

aits

pct

. c

hang

ep

ct. o

f ta

nker

s in

tot

alR

egio

nty

pe

2009

:1H

2009

:2H

2010

:1H

2010

:2H

2011

:1H

2009

2010

2009

-10

2009

2010

Bos

pho

rus

cru

de

oil t

anke

rs1,

494

1,24

71,

143

1,09

692

32,

741

2,23

9(1

8.3)

pro

duc

ts t

anke

rs1,

054

819

749

738

746

1,87

31,

487

(20.

6) c

hem

ical

/Gas

/oth

er t

anke

rs3,

778

3,34

73,

301

3,19

93,

238

7,12

56,

500

(8.8

)to

tal t

anke

rs6,

326

5,41

35,

193

5,03

34,

907

11,7

3910

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(12.

9)17

.8

14.7

o

ther

shi

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24,5

1529

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29,0

0530

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25,1

6854

,148

59,1

129.

2 to

tal S

hip

s30

,841

35,0

4634

,198

35,1

4030

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65,8

8769

,338

5.2

Dan

ish

Str

aits

cru

de

oil t

anke

rs1,

686

1,63

21,

568

1,63

21,

537

3,31

83,

200

(3.6

) p

rod

ucts

tan

kers

1,36

71,

179

1,09

91,

068

1,09

82,

546

2,16

7(1

4.9)

che

mic

al/G

as/o

ther

tan

kers

7,19

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413

7,08

67,

603

7,14

714

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14,6

890.

6 to

tal t

anke

rs10

,247

10,2

249,

753

10,3

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782

20,4

7120

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shi

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24,2

9221

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22,7

5523

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22,0

2446

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46,0

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tota

l Shi

ps

34,5

3932

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32,5

0833

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31,8

0666

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66,0

56(1

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Mal

acca

Str

ait

cru

de

oil t

anke

rs3,

300

3,57

93,

631

3,74

73,

755

6,87

97,

378

7.3

pro

duc

ts t

anke

rs2,

229

2,11

02,

098

2,17

92,

283

4,33

94,

277

(1.4

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ical

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rs4,

943

5,09

95,

019

5,56

05,

387

10,0

4210

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tota

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kers

10,4

7210

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10,7

4811

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11,4

2521

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22,2

344.

6 33

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32.6

o

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20,8

9622

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22,2

9023

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23,0

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45,8

706.

6 to

tal S

hip

s31

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32,9

1833

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35,0

6634

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64,2

8668

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5.9

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of H

orm

uz c

rud

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3,73

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3,80

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149

4,22

77,

567

7,94

95.

0 p

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1,00

81,

073

1,05

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170

1,11

72,

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2,22

87.

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hem

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rs3,

849

4,14

94,

313

4,87

84,

759

7,99

89,

191

14.9

to

tal t

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rs8,

595

9,05

19,

171

10,1

9710

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17,6

4619

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9.8

48.9

52

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oth

er s

hip

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640

8,77

28,

480

8,75

98,

574

18,4

1217

,239

(6.4

)to

tal S

hip

s18

,235

17,8

2317

,651

18,9

5618

,677

36,0

5836

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1.5

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rce:

aiS

dat

a, a

ggre

gate

d a

nd c

omp

iled

by

iHS

Fai

rpla

y.



115


crude loaded in the Black Sea passed through the Bosphorus, however, as some crude (9.8 mt, or 196,000 bd) was delivered to Romania and Bulgaria (and other destinations) within the Black Sea (see Figure IV-6).

An important overall trend had been that the share of crude moved by Suezmax tankers declined slightly after 2005 (before reversing in 2010), while the proportion carried on Aframaxes tended to rise. But the reversal of this trend in 2010, toward a rising share of larger vessels in the overall totals, is expected to continue going forward. This has important implications for the oil (and freight) carrying capacity of the Turkish Straits, as the limits are on the number of passages (or “slots”) available to large ships rather than the physical amount of oil actually carried (see below).

Refined products add to the overall oil volumes transiting the Turkish Straits but do not really play a central role, because of both the much lower volumes involved compared

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with crude and the types of tankers used. We estimate that evacuation of refined products through the Bosphorus in 2010 amounted to 33.0 mt (660,000 bd), a decline of 13% from 38.1 mt (762,000 bd) in 2009. We also project that evacuation of refined products from the Black Sea will decline by about 50% from the current level during the outlook period (see above).

The movement of these products generated 1,487 passages through the Bosphorus in 2010 (see Table IV-1), representing an average of about 4 passages per day. The average tanker size involved in these movements was only 25,000 dwt (see Table IV-3), and therefore for the most part product tankers are not included in the restrictions on large ships (see below). However, about a third of the total product tanker passages were reportedly in tankers over 150 m LOA, and about 16% of the total were over 200 m LOA, so refined product flows are not entirely immune.

4.1.3 Administrative Restrictions on Tankers

Turkey is required to keep the Bosphorus open to all commercial ship traffic under the Montreux Convention of 1936 (see above). But the emergence of the large tankers and container ships that dominate international seaborne trade today was almost unimaginable at the time the treaty was signed. With these changes in vessel size, Turkish authorities have moved to address the safety problem that large vessels pose in transiting the challenging

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117


waters of the straits. Over the years, various restrictions on vessels moving through the straits, ostensibly with the goal of improving safety, have been instituted by the Turkish authorities. By and large, these measures have been tacitly accepted by the shipping community. However, some parties consider even these regulations to be a violation of the original Montreaux Convention.*

In 1982 the Turkish authorities introduced new traffic regulations to conform with the 1972 International Regulations for Preventing Collisions at Sea.** The main thrust of these regulations was to establish the principle of keeping to the right-hand side of the channel. Previous to this, traffic on the Bosphorus navigated on the left-hand side of the channel. In addition, the new regulations stressed that no vessel should overtake another during the passage unless absolutely necessary and imposed a speed limit of 10 nautical miles per hour (knots) through the water.

*See S. Andrew Scharfenberg, “Regulating Traffic Flow in the Turkish Straits: A Test for Modern International Law,” http://www.law.emory.edu/EILR/volumes/spring96/scharfen.html.**“New Traffic Order for Bosphorus Conforming with the 1972 International Regulations for Preventing Collisions at Sea,” Coastal Safety Administration of Turkey May 1, 1982.

Table Iv-2

Distribution of Black Sea Crude Oil Tankers and Flows by vessel Size: 2003–2010(percent of annual totals)

i. Distribution of crude oil tankers leaving Black Sea ports by Vessel Size

tanker Size, DWt 2003 2004 2005 2006 2007 2008 2009 2010total Vessels (number) 944 1,036 922 1,156 1,175 1,108 1,060 939

100-160,000 33.5 36.0 42.5 34.6 30.0 26.6 33.5 41.465-80,000 47.6 51.0 50.5 54.5 57.6 56.9 56.6 52.550-65,000 16.3 10.4 5.6 7.2 8.6 11.5 7.0 4.0<50,000 2.8 2.6 1.4 3.7 3.8 5.0 2.9 2.2

ii. Distribution of crude oil Flows from Black Sea ports by Vessel Size

tanker Size, DWt 2003 2004 2005 2006 2007 2008 2009 2010total loadings (million tons) 86.63 99.05 93.28 109.22 107.28 99.93 104.38 93.29

100-160,000 48.9 50.5 55.1 46.4 43.2 39.6 46.8 54.865-80,000 39.9 42.2 41.0 47.9 49.8 51.0 47.9 42.050-65,000 10.1 6.2 3.3 4.3 5.5 7.5 4.3 2.3<50,000 1.1 1.0 0.6 1.4 1.5 1.9 1.1 0.8

average Size loading (thousand tons) 91.8 95.6 101.2 94.5 91.3 90.2 98.5 99.4

Source: calculated by iHS ceRa from published monthly loading schedules/actuals for the major Black Sea ports; schedules subsequently corrected to actual shipments for each major port.




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In 1994 the Turkish authorities introduced another set of regulations for vessel traffic.* These were also said to be aimed at “further reducing risks of accidents in the Strait of Istanbul (Bosphorus), the Marmara Sea and the Strait of Canakkale (Dardanelles).” One of these rules was to introduce officially a traffic separation scheme for ships traveling in opposite directions; the ships were required to keep to the right in either direction within specific traffic lanes. When introducing the regulations, Turkey widely adopted IMO rules, particularly Rule No. 10 of the 1972 Convention on the International Regulations for Preventing Collisions at Sea (COLREGs). Rule No. 10 concerns the movement of vessels in traffic separation schemes and states that ships crossing traffic lanes are required to do so “as nearly as practicable at right angles to the general direction of traffic flow.” This reduces confusion to other ships as to the crossing vessel’s intentions and course and at the same time enables that vessel to cross the traffic lane as quickly as possible. It is in applying the IMO recommendations that Turkey claimed authorization to temporarily close the straits to other traffic in cases where a large vessel might cross into the oncoming traffic lane during passage. This is because large ships could not remain in the traffic separation lane while altering course. For example, a

*The regulations in their present form were issued in the “Official Gazette” of November 6, 1998 (No. 23515). It is the Turkish Navy’s Department of Navigation, Hydrography, and Oceanography, Istanbul, that is the responsible official authority.



119


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collision becomes unavoidable if another large ship comes from the opposite direction at the same time at critical points in the Bosphorus passage.

Thus, the Turkish authorities also issued “recommendations” for all large vessels and any hampered vessels. More specifically, large vessels over 150 m LOA and/or with a draft of 15 m are required to submit a Type 1 sailing plan (containing information such as ship’s name, type, and size, air and sea draft, cargo carried, and destination) 24 hours before entering the Turkish Straits; vessels 200–300 m LOA and/or with a draft in excess of 15 m are required to submit a Type 2 sailing plan (providing more information) 48 hours before entering the Turkish Straits.* For vessels in excess of 300 m in length, the owner/operator must provide the Turkish authorities with information on the vessel and its cargo much earlier, during the planning phase of the journey.**

Based on such information, the Traffic Control Center for each of the two straits, and if necessary the higher level administration, shall inform the vessel’s owner/operator/captain of any requirements and recommendations to ensure the vessel’s safe passage through the straits. Each vessel is essentially considered on its own merits, and Turkish authorities then decide individually whether any special conditions are to apply.

Much of these additional Turkish regulations relate specifically to ships carrying so-called hazardous cargo. This is defined to include civilian nuclear-powered engines, crude oil, petroleum products and LPGs, certain chemicals, and other substances declared dangerous by international conventions and domestic legislation, such as certain types of hazardous, toxic, or nuclear materials. Most importantly for this study, the special regulations that apply to hazardous cargo carriers, such as tankers that carry crude oil and refined products, are in effect regardless of whether the ships are carrying cargo or not.

Another of the IMO COLREGs to be invoked during this period was Rule No. 9, which applies to ship movements in narrow waterways. Rule No. 9 calls for only one-way traffic in narrow waterways to avoid collisions, and from 1998, one-way traffic through the straits was applied to ships of over 250 LOA carrying “hazardous cargo”; that is, the straits were closed to all traffic from the opposite direction during the passage of such ships. Eventually, one-way traffic for extended periods of each day (with the length of operation and flow dependent upon the number of arrivals for the duration of the one-way flows) became a more general practice for all traffic in the straits, more or less stemming from the launch of the so-called Marmaray rail tunnel project under the Bosphorus.***

*Tankers longer than 150 m are not necessarily large in terms of capacity. For example, several vessels owned by the Novorossiysk Shipping Company are tankers with an LOA of 151.5 m, and are therefore subject to the respective restrictions, but have a relatively small capacity of only 16,226 dwt.*Because of this, although they are not technically prohibited, in actual practice most vessels in excess of 300 m in length are not allowed to transit the Turkish Straits.*Construction on the Maramara rail (“Marmaray”) project, which includes a rail tunnel under the Bosphorus, began in May 2004. The project, for both freight and passenger trains, includes 13.6 km of tunnels and the upgrade of 63 km of suburban train lines. The Bosphorus (Istanbul Strait) itself was crossed by a 1.4 km–long earthquake-proof immersed tube, assembled from 11 sections, forming the world’s deepest undersea immersed tube tunnel. Construction of the Marmaray tunnel was completed on September 23, 2008, with a formal ceremony to mark completion on October 13. Completion of the overall project has been repeatedly delayed and is now slated for October 2013.



121


Further restrictions on passage through the Turkish Straits were introduced in 2002. In October 2002, with little advance notice, Turkey introduced a more restrictive set of rules for passage through the straits, affecting mostly large tankers carrying crude oil. These changes included the following provisions:

All large ships (150 m LOA) must give 24 hours’ advance notice; since 1998, this •had applied only to 250 m vessels with hazardous cargo;

One-way traffic only is mandated when these larger tankers are transiting, with a •90-minute gap between such vessels, which has become less (75 minutes) sometimes in actual practice. What has been clearly demonstrated in the period since 2002 is the extreme sensitivity of the amount of backups, congestion, and delays to the staggered times between large vessels.

Just as important, these more restrictive transit rules were extended to the Dardanelles (Canakkale) in October 2002. Although the Canakkale is less restricted geographically than the Bosphorus, it is much longer and therefore takes more time for large ships to transit. A typical passage through the Bosphorus takes about 1.5–2.0 hours, whereas for the Canakkale, it is about 3–4 hours. Because other traffic essentially stops during the passage of each large tanker, the Canakkale has now become the key bottleneck for the passage of large ships through the Turkish Straits rather than the Bosphorus.

The application of these rules also included an informal practice that tankers and cargo carriers going to ports in the Marmara Sea (Turkish ports) are given priority over other shipping. Initially, this was meant to be applied only to vessels carrying liquefied natural gas (LNG) bound for the Ereglisi terminal on the Marmara Sea and was deemed to be necessary because of Turkey’s lack of gas storage and the need to maintain gas deliveries to households and other uninterruptible consumers.* But this practice has since been widened to include other cargoes as well. This informal arrangement adds to the overall difficulty for large oil tankers transiting the straits because ships on their way to Turkish ports can essentially “jump the queue.”

Therefore, for large vessels (150 m LOA) transiting the Bosphorus carrying “hazardous cargo” (i.e., oil tankers), the following conditions have come to be generally applicable:

The Bosphorus is closed to all other large vessels during the ship’s passage (allowing •for a 90-minute gap).**

*Turkish LNG imports amounted to 6.6 Bcm in 2009 and 7.7 Bcm in 2010. Imported LNG volumes for Turkey are expected to expanded to 9.8 Bcm in 2015 in IHS CERA’s base case for Turkish gas supply and then remain at about that level through 2030. The 2010 import volumes translate into about 48 inbound tanker passages per year (or about 96 in total), or an average of about 1 every four days. The projected import volumes from 2015 on average amount to about 120 passages per year (in both directions), or an average of about 1 every three days. Therefore the number of LNG passages remains a small portion of the overall passages in the Dardanelles. But by extending the special treatment to all Marmara-bound ships, a problem is created that probably violates both Turkey’s WTO commitments and the Montreaux Convention. According to the data compiled by GAC, the total number of ships passing through the straits calling on Marmara ports amounted to 16,769 vessels in 2010, or about 32% of the overall total passages, a rather significant number of potential “queue jumpers.”**Previously, when two-way traffic was the norm, during the passage of smaller “hazardous cargo” carriers (100–150 m LOA), other vessels of >100 m LOA were prohibited from moving through the strait in the opposite direction and no other “hazardous cargo” carrier was accepted from the opposite direction regardless of size.




Escort tugs are in attendance for ships over 250 m LOA•

A patrol boat proceeds ahead of the vessel (when available)•

Passage must take place only during daylight hours (between sunrise and sunset) for •ships over 200 m LOA

Passage is subject to good weather (see below)•

Pilotage is recommended but not compulsory*•

Essentially, when a large vessel carrying “hazardous cargo” enters either of the two straits, essentially no other vessel with the same characteristics is permitted to enter until the first vessel has exited the strait (defined as passing the Istanbul Bogazi bridge [when entering from the north in the case of the Bosphorus] or the Hamsi Burnu-Fil Burnu line [when entering from the south]). In the Canakkale (Dardanelles), this rule applies until the first vessel has left the Nara Burnu region.

Restrictions during adverse weather conditions. When the surface current speeds in the straits exceed 4 nautical miles (knots) per hour or when northerly surface currents are caused by southerly winds, vessels carrying hazardous cargo, large vessels (over 150 m LOA), and deep-draft vessels with a speed of 10 knots or less may not enter the straits. They are required to wait until current speeds have dropped to 4 knots or less, or northerly currents have ceased. Other vessels, however, may transit by obtaining the tugboat(s) necessary, as determined by the respective Traffic Control Center, in accordance with their tonnage.

When the surface current speeds in the Straits of Istanbul and Canakkale exceed 6 knots, or when strong northerly currents are caused by southerly winds, vessels carrying hazardous cargo, large vessels (over 150 m LOA), and deep-draft vessels (regardless of their speed) are not permitted to enter the straits. They are required to wait until current speeds are less than 6 knots or the strong northerly currents have ceased. Such conditions typically occur about 25 days per year, leading to a closure of the straits.

When visibility is 2 nautical miles or less, anywhere in the straits, transiting vessels are required to keep their radars turned on constantly to provide radar readings. On vessels with two radars, one must be assigned for the pilot’s use. When visibility is 1 nautical mile or less anywhere in the straits, vessels carrying hazardous cargo, large vessels, and deep-draft vessels are not permitted to enter the straits. When visibility anywhere in the strait is less than 0.5 nautical miles, all traffic is halted. This typically occurs for about 5–6 days each year.

Restrictions for special events. The Turkish authorities also reserve the right to close the straits to traffic for special events, such as sports matches. This may occur for 5–6 days per year.

***Among the rules introduced in 1994 was a requirement for pilots on all Turkish-flagged vessels passing the straits; this rule was omitted in the 1998 revision, making Turkish-flagged vessels no different in this regard from foreign-flagged ones.



123


Implications for oil tankers. These various restrictions mean that Turkey effectively limits transit via the Bosphorus and Canakkale to “Suezmax” tankers (maximum of about 160,000 dwt), as such vessels are typically about 295 m in length, 45 m in width, and have a draft of about 17 m. Most importantly, large tankers (over 200 m LOA) are allowed to pass only during daylight hours. This essentially means that these regulations effectively limit passage in the Turkish Straits (Bosphorus/Canakkale) to no more than about 7 large tankers per day in winter and about 10 per day in summer.

The rules are less restrictive for bulk carriers with nonhazardous cargo (e.g., ships carrying grains or ores), even if they are over 200 m LOA. Most importantly, such large bulk carriers are allowed to transit during the night. However, any time such a bulk carrier passes through one of the straits during daylight hours, transit of a “hazardous cargo” carrier (e.g., oil tanker) is stopped. Essentially, if a large bulk carrier passes during the day, it takes up the passage time (an available slot) that would otherwise have been available for an oil tanker.

The total number of all large ships (>200 m LOA) going through the Bosphorus was 7,763 in 2009 and 7,599 in 2010 (according to AIS data), or an average of about 21 vessels per 24-hour period (see Table IV-4). The passages of large bulk carriers or container ships over 200 m LOA amounted to 4,409 in 2009 and 4,103 in 2010, or an average about 11–12 per day. Passages of large tankers (>200 m LOA) amounted to 3,354 in 2009 and 3,496 in 2010, or an average of 9–10 per day. In terms of ship passages, in 2010, 93.4% of all crude tankers going through the Bosphorus were in the category of over 200 m LOA, with another 5.5% in the 150–200 m LOA category. Thus, 98.9% of all the crude tankers passing through the Bosphorus in 2010 were affected by the restrictions on large vessels (>150 m LOA).

VTS introduction. The changes noted above in administrative rules were also coincident with the start-up of the new vessel tracking system in the Turkish Straits from the end of 2003, divided into two areas: one covering the Istanbul Strait and the other covering Canakkale. This involves a combination of sensors to track vessel traffic in the straits. Information on vessel traffic is obtained from microwave radar, cameras (closed-circuit television/infrared cameras), radio equipment (very high frequency [VHF]/direction finding [DF]), and ship-based differential global positioning system (dGPS) transponders. The main constituents of the system are

2 Vessel Traffic Control Centers (VTC), 1 each in Istanbul and Canakkale•

13 unmanned Remote Sensor Stations (RSS), 8 in Istanbul and 5 in Canakkale VTS •Areas

2 dGPS Reference Stations, 1 in Istanbul and 1 in Canakkale VTS Areas, and 50 •dGPS transponders

4 VHF/DG stations, 2 in Istanbul and 2 in Canakkale VTS Areas•

5 Racon stations, 4 in Istanbul and 1 in Canakkale VTS Areas•



IHS CERA Special ReportTa

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Num

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of

Pas

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125


Can Changes in the Distribution of vessel Size Ease the Transit Restrictions?

one way of getting around the straits navigation restrictions would be for shippers to increase the use of smaller tankers. But this involves distinct risks and trade-offs that may easily outweigh those commonly associated with using larger tankers. in particular,

By using small tankers to avoid loa restrictions, the movements effectively undermine •the goal of improving overall safety. in particular, smaller tankers tend to be older, and in poorer condition, and therefore involve a higher risk for accidents. it would also require a larger number of passages to carry the same amount of oil. thus, from sheer numbers alone, the risk of accidents could increase considerably. Furthermore, it is unlikely in the near term that sufficient numbers of tankers are available in the smaller sizes to move all the needed volumes of oil. While this deficit could be rectified longer term by investment in smaller tankers and their subsequent construction if real demand were to emerge for such an option, this is actually an uneconomic solution.

the use of small tankers usually means a substantially higher per-unit cost for shipments •compared with larger tankers. Furthermore, using smaller tankers diminishes the prospects for long-haul markets for Black Sea crude, so there is an additional cost to the shippers from lower prices/netbacks longer term.

But what about the opposite, using a higher proportion of the largest tankers to reduce the number of passages needed to move crude oil through the straits?

in recent years, the distribution of tanker passages through the straits has been about 35–40% Suezmaxes and about 50–55% aframaxes, but if the share of Suezmaxes were increased to 50% and the share of aframaxes reduced to 40%, the volume of crude carried in 2010 would have required about 80 fewer passages (in both directions) through the straits on an annual basis.

this is clearly something that would be useful to do, particularly during the winter when the available slots for large tankers are limited. cpc and Novorossiysk do implement a noticeable seasonal shift to maximize the use of available slots. For example, in January, February, and March, about two-thirds of the tankers that are loaded by cpc are Suezmaxes, whereas in the summer months it is about 50:50 between Suezmaxes and aframaxes. the majority of Novorossiysk loadings are aframaxes throughout the year, but in winter the share of Suezmaxes tends to be much higher (closer to 50% of the total).

there does not seem to be constraint in acquiring a greater number of Suezmaxes to make such a shift possible. But there are market limitations on how much can be loaded in Suezmaxes. Not all consumers (refineries/terminals) are capable of handling Suezmaxes, especially within the Mediterranean. also, many refineries actually prefer to receive crude in smaller parcels than Suezmaxes, since many have tankage and blending issues. But one advantage of Suezmaxes over aframaxes is lower costs per ton or barrel on long-haul (ex-Mediterranean) shipments to markets.

to a certain extent, there will be a consolidation of crude shipments into larger ships in the Black Sea regardless of any explicit changes in loading programs at Novorossiysk or cpc. this is due simply to the expected changes in loadings among the Black Sea ports following cpc expansion. in particular, we project a secular decline in shipments from smaller ports (e.g., rail-based exports) and greater concentration at the larger ones, such as the cpc. thus, by 2015, 87% of crude oil loadings in the Black Sea are projected to be at Novorossiysk and cpc (in the base case) versus 76% in 2010 and 71% in 2005. We project that because of this shift, by 2015, 49% of Black Sea crude tankers heading for the turkish Straits will be Suezmaxes; in turn, these tankers will load 63% of Black Sea crude oil. this has the effect of raising the average size of a crude tanker shipment slightly, to 101,600 tons in 2015, from 99,400 tons in 2010.




4 automatic weather stations (AWS), 3 in Istanbul and 2 in Canakkale VTS Areas•

5 Surface Water Measurement Sensors (SWMS), 3 in Istanbul and 2 in Canakkale •VTS Areas

3 Salinity Temperature Profilers (STP), 2 in Istanbul and 1 in Canakkale VTS Areas•

14 Doppler Current Sensor Stations (DCS), 9 in Istanbul and 5 in Canakkale VTS •Areas

4.1.4 The “Perfect Storm” of the winter of 2003/04: A One-Off Event or Glimpse of the Future?

The administrative restrictions imposed upon tanker passage essentially establish differential “capacity” limits for the straits that depend largely on the time of year. In the winter months, the effective carrying capacity of the straits decreases by 36% on average compared with the summer months because of the reduced number of daylight hours. This is also the time of year when weather conditions tend to limit the time available for passage of ships. Effectively, these regulations limit passage to no more than about seven large vessels (including tankers) per day in winter.

A combination of factors in the winter of 2003/04 led to huge delays for large cargoes of Urals Blend (and other Eurasian) crude oil transiting the Turkish Straits.* One factor was that Eurasian oil volumes transiting the Turkish Straits had grown rapidly over the previous three years (2000–03): total oil transit (crude and products combined) jumped during this period by nearly 63%, from 83.9 to 136.4 mt. At about the same time, changes in Turkish transit regulations were introduced (see above), and the use of the new VTS was launched.** Combined with a bout of bad weather, and inexperience among the Turkish traffic system operators with the new system, the result was a significant decline in the number of tankers transiting the straits and dramatically lengthening ship transit times through the Turkish Straits. Long queues of ships waiting to transit formed at both ends of the straits. The average transit time jumped from 5 days in September 2003 to 33 days in January 2004. Average transit times typically rise during winter because fewer daylight hours limit the time available for large ships, but the average transit time had been only 7.5 days in January 2003 and 16 days in February 2003, so the jump in January–February 2004 was unprecedented. This had the effect of driving up demurrage and other costs substantially. The delays affected mostly larger ships, not smaller ones, because of restrictions on night passage for larger ships.

The additional costs to the Eurasian oil industry of the huge delays in the winter of 2003/04 have been estimated by various sources at between US$600 million and US$1 billion. IHS CERA’s estimate for the additional costs is US$884 million (see Figure IV-7). The extra costs in 2004 averaged US$8.65 per ton (US$1.18 per barrel) for crude oil shipments for the entire year, or US$16.86 per ton (US$2.31 per barrel) if considering just the winter period shipments. Based upon their relative share of crude shipments, Russian shippers incurred

*See the IHS CERA Insight Mediterranean Refiners Confront Worsening Bosphorus Delays.*The new VTS, or Vessel Traffic Management Information System (VTMIS), was installed in stages over several years beginning in late 2003.



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about 55% of the total congestion costs for 2004. This corroborates an estimate by the Russian Ministry of Transport that Russian shippers paid an additional US$400 million to transit the Turkish Straits in the winter of 2003/04.

IHS CERA’s estimated costs of Bosphorus congestion to the Eurasian oil industry in 2004 consist of several major components:

Direct demurrage costs •

Calculated as the daily tanker charge for each type of vessel times extra –number of days required for passage

Delays in tanker passage times through straits; mostly waiting time at –entrance to straits, plus tanker delays on way back to loading points

Freight rate effect•

Freight costs also become higher in winter (average daily tanker freight –rates), owing largely to loss of overall carrying capacity from tankers tied up in queues at straits




Diversion of exports to avoid congestion in Turkish Straits•

Exports diverted to alternative (lower-priced) markets –

Exports diverted to alternative (higher-cost) export routes –

Shut-in production•

Crude not produced due to congestion and delays in Turkish Straits –

Additional storage investment •

Additional capital spent on storage because of congestion (on producers’ –side, not consumers’, which also added storage)

The largest component of the extra costs during the winter of 2003/04 (46%) was due to the freight rate effect, followed by direct demurrage costs (32%); the other components of the additional costs (e.g., additional storage, diversion of exports to more expensive routes, etc.) were relatively minor (see Figure IV-8). Besides demurrage and the freight rate effect, the other cost components are also more ambiguous in their size and overall causality. For example, a potential “big ticket” item (in terms of costs) would be if any Eurasian producers had to shut in crude production during the winter of 2003/04 strictly because of transit delays in the Turkish Straits. There was little evidence that this occurred to any significant degree. In terms of diversion of crude exports to alternative routes/markets, it also appears that this occurred, but the additional costs (lower netbacks from higher transportation costs

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or lower realized prices) were also relatively small. This conclusion comes from comparing planned quarterly export schedules for Black Sea ports with the actual results.

Congestion delays since 2003/04. In the winters since 2003/04, the congestion (and resulting delays in the Turkish Straits) have not been nearly as bad. One factor is that transit volumes have remained relatively flat or declined in the years since. But it also appears that traffic management by the Turkish authorities has been much better as they have gained operational experience with the new VTMIS system.

Tanker delays during winter have been generally falling since 2003/04. The average number of “extra” days (i.e., those beyond the usual 48 hours needed for passage) during the winter period between October and March each year involved in transiting the Turkish Straits (either from entering the Bosphorus to exiting the Canakkale or vice versa) declined to only 6.4 days in the winter of 2010/11, from a high of 10.1 extra days in the winter of 2006/07 (see Figure IV-9). In fact, in the latter part of the winter of 2010/11, the delays fell to an all-time low (see Figure IV-10). This evidently occurred in response to a sizable backlog of ships that had developed in November–December 2010, mainly as a result of poor weather and a higher number of priority (Marmara) vessel transits than usual; the backlog was cleared and then remained low in January–February-March 2011 by minimizing the reversal time of the change in one-way traffic and especially by reduced spacing between large vessels. An important point is that such relatively minor changes in traffic control, particularly reducing the staggered times between large vessels, did not compromise safety at all.




One way of applying reduced intervals with relatively little risk to safety would be to dispatch inbound, empty tankers at reduced intervals (say 30–40 minutes) instead of the current practice of 75–90 minutes. The empty tankers have high power-to-displacement ratios and head against the oncoming current, which provides good steerage and control. Similarly, if the large tankers were dispatched during the early part of each one-way transit program, the accumulation of large ships at the straits entrances, which remains a safety concern, can be reduced. Also, this should reduce the problem of faster and more powerful ships overtaking slower vessels during transit. The reduced interval is still sufficient for emergency anchorage between transiting tankers if necessary during an emergency.

Based upon applicable average daily rates for tankers, the winter delays described above translate into an average demurrage (or congestion) cost of only about US$0.3 per barrel of crude oil (US$2.2 per ton) in 2010/11, versus US$0.7 per barrel (US$5.2 per ton) in 2005/06.

These rather significant improvements in delay times are another indicator that transit through the Turkish Straits was probably quite close to the congestion threshold in 2004/05, as relatively small changes in volumes have made a big difference in backups and overall congestion costs since then. Most importantly, it appears that traffic volumes in the Bosphorus are moving away from the congestion threshold rather than toward it. So a key question remains: was the winter of 2003/04 a one-off event or a harbinger of the future?

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In Addition to “Normal” Costs, Should a “Risk Premium” Be Considered in Calculating the Costs of Using the Turkish Straits?

an additional major item that needs to be discussed when adding up the costs involved in using the straits is this: does an annual “risk premium” also need to be considered to cover (hidden) additional congestion costs? this would be an annual “risk factor” that would reflect the costs that would stem from a major accident that would close the straits to traffic for an extended period (say, two weeks to one month) at some time in the future (i.e., above and beyond the immediate costs of direct accident mitigation). the costs involved could be significant, although clearly they are much less now than they would have been several years ago. the impact upon eurasian oil exports from a complete closure of the turkish Straits for such an extended period would be difficult but actually manageable, although obviously the degree of disruption would depend upon the time of year. this is because

Sufficient flexibility exists to handle an extended hypothetical Bosphorus closure for •2–4 weeks without shutting in crude production (especially in summer because of low storage), avoiding by far the largest component of potential losses; the extra transportation costs involved would be relatively minor (involving only a few tens of millions of dollars), with total costs of probably less than US$100 million. this is because of possibilities to divert Black Sea exports flows elsewhere in an emergency situation, especially within Russia, but this would require cooperation between government, the oil companies, and transneft. Kazakhstan has much less flexibility in export routes than Russia, but its export flexibility has increased considerably in recent years, with some spare capacity now available on several routes (e.g., Btc, china, iran, transneft, and rail).

comprehensive and official data are lacking, but actual historical frequencies for •major accidents in the straits indicate that the rate of accidents is relatively low (per transit or per ton) compared with other busy waterways, so an appropriate annual “risk premium” to reflect the probability of a major accident would therefore be quite low as well.*

*according to one count, between 1953 and 2002 a total of 461 significant maritime incidents occurred in the istanbul Strait or in its southern entrance at the Marmara Sea; the majority were collisions between ships (see Necmettin akten (istanbul University, engineering Faculty, Dept. of Maritime transport and Management/engineering), “Shipping accidents: a Serious threat for the Marine environment [Gemi kazaları: deniz çevresi için ciddi bir tehdit],” Journal of Black Sea/mediterranean environment, Vol. 12, 2006, pp. 269–304.




4.2 COMPARISON wITH OTHER HIGH-TRAFFIC STRAITS

This section of the report compares ship traffic in the Turkish Straits (Bosphorus) with three other important straits where tanker traffic is relatively high: Danish Straits, Strait of Malacca, and Strait of Hormuz.* These four straits are among the most important “chokepoints” found in global sea routes.** These places are considered a critical part of global energy security owing to the high volume of oil that transits through them.*** These chokepoints are narrow channels along widely used global sea routes, several so narrow that the size of vessel that can navigate through them is restricted.

The data on ship movements presented in this section are compiled using AIS data collected from all individual ships in the world fleet via satellite.**** The data are collected and stored once every hour and contain information about the time, the ship, and its position, speed, and heading. The data are then aggregated and combined with the IHS Fairplay ships database to identify the type and size of ships passing through each of the specific areas analyzed in this section of the study. This has the advantage of employing a single source of data on ship passages which allows consistent comparisons between the areas.***** Aggregate figures on the total number of ships passing through each of the individual traffic areas per six-month period since 2009 are given in Table IV-1.

According to these data, the total number of ships passing through the Bosphorus in 2010 was 69,338, an increase of 5.2% from 2009 (see Table IV-1).****** For total ship passages, the number through the Bosphorus is roughly on the same order of magnitude (i.e., in the range of 65,000–70,000 per year) as total ship passages through two of the other straits of interest here—Danish Straits and Malacca—but well ahead of total passages through the Strait of Hormuz, where they amount to only 35,000–36,000 per year.

According to these figures, tanker traffic in the Bosphorus represented only about 15% of the total number of ship passages through the strait in 2010, down from about 18% in 2009, a proportion that was fairly typical over the past decade or so, according to Turkish VTS statistics (see above). But in the other three straits of interest, tanker traffic constitutes a more significant part of the overall ship traffic than in the Bosphorus. In the Danish Straits, tankers make up just over 30% of the total traffic, and in the Malacca Strait, the share of tanker traffic is slightly higher, at about a third of the total traffic. In the Strait of Hormuz,

*The data used for this section were compiled by IHS Global Limited (IHS Fairplay).**The other narrow passages usually identified as important oil chokepoints are the Suez Canal, Panama Canal, and the Strait of Bab el-Mandad (between the Red Sea and Gulf of Oman/Arabian Sea).***See Daniel Yergin, The Quest: Energy, Security and the Remaking of the Modern World, Penguin, September 2011; also see World Oil Transit Chokepoints; http://www.eia.gov/countries/regions-topics.cfm?fips=WOTC.****The AIS is an automated tracking system used on ships and by VTS for identifying and locating vessels by electronically exchanging data with other nearby ships and VTS stations. AIS information supplements marine radar, which continues to be the primary method of collision avoidance for water transport. AIS is used for all seagoing cargo vessels larger than 300 gross tons and for all passenger vessels.*That is, other sources of statistics generated by the individual authorities or agencies monitoring and regulating ship movements in the individual straits (such as vessel traffic control) may vary from area to area in definitions and coverage and typically do not match the locally generated data. Unfortunately, comprehensive data from AIS for all the straits are available only from January 2009. For some areas, such as the Danish Straits and Strait of Hormuz, good coverage is available from early 2006, but for Malacca and the Bosphorus, consistent coverage only began in late 2008.**Although different, these figures are generally consistent with Turkish VTS statistics and compilations by GAC (see above).



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the tanker share of total traffic is even higher, at about half of the total. In fact, the tanker share through Hormuz rose from 49% in 2009 to 53% in 2010.

In the number of tanker passages alone, all the other straits are much busier than the Bosphorus; annual passages through them are about two times greater than through the Bosphorus (i.e., 22,324 for Malacca, 19,368 for Hormuz, and 20,056 for the Danish Straits in 2010, versus 10,226 for the Bosphorus). Also, whereas tanker traffic declined significantly through the Bosphorus in 2010 versus 2009 (-12.9%) and also declined in the Danish Straits (-2.0%), tanker passages increased significantly in the Malacca Strait (+4.6%) and especially in the Strait of Hormuz (+9.8%). This probably reflects the more rapid economic rebound in the Asian region compared with other regions of the world economy and its impact upon regional oil demand.

Table IV-3 displays the total deadweight tonnage of tankers passing through each of these major straits, as well as the calculated average size of the vessels. In total deadweight tonnage for all tankers, the amount going through the Bosphorus, 438.2 million dwt in 2010, was down 15.7% from 2009 (see Table IV-3). Furthermore, this total was far less than for any of the other major straits of interest here. The total for the Danish Straits in 2010, 654.5 million dwt, was about 50% more than for the Bosphorus. And the total tanker tonnage passing through the Bosphorus is, in turn, dwarfed by the tanker tonnage passing through the Strait of Malacca (2,029.4 million dwt) and the Strait of Hormuz (2,762.4 million dwt). The latter carry about six times as much tanker tonnage as the Bosphorus.

Size restrictions on vessels for each of the straits (and the Panama and Suez Canal) are listed in Table IV-5. These vessel size limitations create an upper limit to the cargo-carrying capacity of the vessels passing through each of these individual areas.

The Strait of Hormuz and the Malacca Strait can both accommodate even the largest of tankers, although for Malacca the draft restriction to 21 m makes it a tight fit for VLCCs. Still, both Hormuz and Malacca serve as major thoroughfares for VLCC vessels. The average size of

Table Iv-5

Ship Size limitations for Key Global Shipping Chokepoints(meters)

length overall (loa) Beam Draft Height

panama canal 294 32 12.0 61.3Malacca Strait none none 21.0 noneSuez canal none none 20.1 68.0Strait of Hormuz 345 54 none 34.7Great Belt (Danish Straits) none none 15.4 noneBosphorus 300 none 15.0 58.0

Source: iHS Fairplay.




crude oil tankers passing these two straits is more than 200,000 dwt, indicating that a large part of the tanker traffic in these areas is made up of these large or very large ships.

The size restrictions in the Bosphorus and Danish Straits essentially preclude the use of VLCCs. Thus, the average size of crude oil tankers passing those areas tends to be much smaller: 120,000 dwt for the Bosphorus and 104,000 dwt for the Danish Straits (see Table IV-3). For the Bosphorus, these data indicate that the average size crude oil tanker was 120,000 dwt; for product tankers, 25,000 dwt; and for chemical/gas/other tankers, 20,000 dwt (see Table IV-3). For other cargo ships (nontankers), the average vessel size was only 16,000 dwt.

4.2.1 Turkish Straits: Bosphorus

As described above, the Bosphorus and Dardanelles together form the Turkish Straits, dividing Europe from Asia (see Figure IV-1). The Bosphorus connects the Black Sea with the Sea of Marmara, and the Dardanelles links the Sea of Marmara with the Aegean and Mediterranean seas. The Bosphorus is one of the busiest waterways in the world (measured in total ship passages). Furthermore, mainly because of its narrow and winding form, which makes it necessary to change direction frequently, it has a reputation as a difficult strait to navigate (see above). Added to this, of course, are ferry services between the European and Asian parts of Istanbul and numerous private motor yachts and pleasure vessels which aggravate the overall traffic situation.

The largest ships that are allowed to pass the Bosphorus have a length of 300 m, draft of 15 m, and a height of 58 m (see Table IV-5). Large vessels (200 m or more in length) are allowed to transit the strait only in daylight hours and are strongly recommended to take a pilot for safety purposes (see above).

In 2009–10, the only traffic segment to show an increase in Bosphorus passages was the category “Other Ships,” which increased by 9.2% (see Table IV-1). This was sufficient to offset the declines in all categories of tanker traffic and generated an overall increase in total ship passages through the strait (see Figure IV-11).

4.2.2 Malacca

The Strait of Malacca, located between Indonesia, Malaysia, and Singapore, links the Indian Ocean to the South China Sea and Pacific Ocean (see Figure IV-12). Malacca is the shortest sea route between the Persian Gulf’s oil supplies and Asian markets, including the Pacific rim countries—notably China, Japan, and South Korea. It is therefore the key chokepoint in Asia, with an estimated flow of about 14.6 mbd of oil in 2010, up substantially from 13.6 mbd in 2009 and surpassing the previous peak of about 14 mbd achieved in 2007.

At its narrowest point off Singapore, Malacca is only 2.7 km wide, creating a natural bottleneck. Although a traffic separation scheme is in effect for two-way traffic, the narrow passage increases the risk for collisions, groundings, and oil spills. Piracy also is a constant threat to tankers in the Strait of Malacca, although the number of attacks has dropped after the Indonesian, Malaysian, and Singaporean navies have stepped up their patrols of the area. Another risk is the annual onset of haze and fog, caused by bush fires in Sumatra.



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It can reduce visibility to 200 m, forcing ships to slow down during their passage through the strait.

The only limitation on vessels in the Malacca Strait is a maximum draft of 21 m. This is near the limit for fully laden VLCCs, so essentially tidal conditions must be right for them to pass through. Vessels with a draft of 15 m or more are strongly recommended to take a pilot for safety purposes. But even this recommendation is suspended for masters who have successfully completed the port familiarization course and practical training on ship simulators. Pilotage exemptions also apply to ships of less than 5,000 (gross) tons, and therefore masters of the larger ships need to be aware that there are a number of small ships in the passage maneuvering without a pilot.

Total and tanker traffic in the Malacca Strait has generally been on the upswing, reflecting the recovery of the global economy, and especially the Asian economies, from the Great Recession. But July 2010 and January 2011 were particularly weak months for crude oil tankers and chemical/gas/other tankers (see Figure IV-13).

4.2.3 Strait of Hormuz

Located between Oman and Iran, the Strait of Hormuz connects the Persian Gulf with the Gulf of Oman and the Arabian Sea (see Figure IV-14). Hormuz probably is the world’s most important chokepoint for oil trade. It is the only sea passage to the open ocean for much of the petroleum produced in the Persian Gulf. About 22 tankers pass through the strait per day on average, but about half of these would be empty (inbound) passages. The outbound tankers carry about 825–850 mt per year (16.5–17.0 mbd) through Hormuz. This




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represents about 40% of the world’s seaborne oil shipments and about 20% of all world oil shipments.

Ships moving through the strait follow a traffic separation scheme that separates inbound from outbound traffic to reduce the risk of collision. The traffic lane is six miles (10 km) wide, including two 2-mile (3 km)-wide traffic lanes, one inbound and one outbound, separated by a 2-mile (3 km)-wide separation median. The strait, however, is deep and wide enough to handle the world’s largest crude oil tankers, with about two-thirds of oil shipments carried by tankers in excess of 150,000 dwt. The biggest tanker that has passed through the Strait of Hormuz is reported as being 345 m in length with a beam of 53.8 m and a height of 34.7 m.

Tanker traffic in the Strait of Hormuz has grown recently, with the strongest growth for chemical, gas, and other tankers, reflecting the recent expansion of LNG trade, particularly from Qatar (see Figure IV-15). Oil tanker traffic has expanded as well, with monthly crude oil tanker traffic growing 15% over January 2009–June 2011, and products tanker traffic growing by 19%.

4.2.4 Danish Straits

The Danish Straits comprise several routes through the Danish islands. The most important are two parallel passages between the Baltic Sea and the Kattegat/North Sea: the Great Belt (Storebælt in Danish) and the Sound (Øresund). The Sound lies between Copenhagen and Sweden, while the Great Belt is to the west, between several of the Danish islands (see Figure IV-16). The Sound, about 225 nautical miles in length, is the shortest route from the

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Baltic to the North Sea. But maximum guaranteed draft is only 7.7 m, so it is used mainly by smaller vessels and empty tankers heading into the Baltic ports for loading. The Great Belt is about 390 nautical miles in length, and vessels with drafts of up to 15 m can pass through safely. This includes fully laden 80,000–100,000 dwt Aframaxes, normally used for crude exports from Primorsk, as well as partly loaded 100,000–160,000 dwt Suezmaxes and even 200,000–320,000 dwt VLCCs on occasion.*

*The main tankers used for crude exports from Baltic ports are <100,000 dwt Aframaxes. But underloaded Suezmaxes (with about 17 m draft when fully loaded) and VLCCs (21 m draft) can pass through the Great Belt when the tide is right. These tankers are then topped up with additional oil at the anchorage off Denmark’s Frederikshavn port to improve the economics of long-haul shipments to the Asian market. Smaller tankers—mostly carrying products—are also topped off after passing through the Danish Straits, but usually at the Kalundborg bay anchorage, where the maximum draft is only 11.5 m. Kalundborg is popular in winter because it is sheltered.

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Total ship passages through the Danish Straits dropped by 1.0% in 2010, to 66,056, according to AIS data, and total tanker passages dropped by 2.0%, to 20,056 (see Table IV-1).* Overall, crude oil and products tanker traffic has remained fairly level the past two years, whereas traffic of chemical, gas, and other tankers was 15% lower in June 2011 compared with January 2009 (see Figure IV-17).

In deadweight tonnage, total tanker volumes dropped in 2010, including all three categories: crude oil, products, and chemicals/gas/other (see Table IV-3). The Danish Straits have become an increasingly important route for Russian oil exports to Europe. Russia has increasingly been shifting its crude oil exports to its Baltic ports, especially the relatively new port of Primorsk (see above). As a result, oil shipments through the Danish Straits have risen significantly during the past decade, and crude shipments at least (perhaps not products) are likely to rise further in the coming years with the completion of the BPS-2 pipeline to Ust-Luga (see above).

According to Danish authorities, crude and product shipments through the straits amounted to 170 mt per year (in both directions) in 2007, compared with only 80 mt in 2000 (see Table IV-6). Total oil volumes through the Danish Straits reportedly dropped to 157 mt in 2010.

*These figures cover all the passages in the Danish Straits: Great and Little Belt, the Sound, and Fehmarn Belt, where ships have to pass to get to the Kiel Canal from the Baltic Sea. There is tanker traffic through nearly all these passages, and all ships must pass through the same lanes either before or after they pass Denmark.

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These reported trends in Danish statistics are consistent with those for total oil evacuation from Eurasia. Loadings of crude oil at Primorsk (not all of which leaves the Baltic Sea) amounted to 71.7 mt (1.43 mbd) in 2010, and total Eurasian crude loadings at Baltic ports were 80.8 mt (1.62 mbd) in 2010, along with 79.6 mt of refined products. Total oil evacuation (crude and products combined) from Eurasia into the Baltic increased from 73.8 mt in 2000 to a maximum of 161.9 mt in 2009 and then dropped to 160.4 mt in 2010.

The Danish Maritime Authority (DMA), which monitors ship passages through the Danish Straits, issues its own statistics on shipments (see Table IV-7). The most recent data, issued in 2011, are for passages in 2009. Combined for the Great Belt and Sound, these figures show a total of 58,048 ship passages, of which 13,342 (23%) were tankers.* In the Great Belt, a total of 26,474 ship passages occurred in 2009, of which 8,246 were by tankers. The average size tanker passing through the Great Belt was 41,589 dwt, whereas combined for both the Sound and Great Belt it was 32,168 dwt. AIS data report more passages in total through the Danish Straits than DMA because the coverage is wider than just the Sound and Great Belt.

The Danish Straits, like the Turkish Straits, are an international waterway regulated by international agreements. The principal international agreement is the Copenhagen Treaty of 1857. Navigation is also covered by IMO regulations, as well as Danish and Swedish national law. This international status was arrived at as part of a voluntary surrender of sovereignty by the Danish government. From 1429, during the reign of King Eric of

*The compilation of all the various data into the aggregates shown in the annual reports is still under way for 2010. However, the simple measure of ship passages measured at Skagen (at the tip of the Jutland Peninsula where the Kattegat joins the Skagerak) can be used as a general indicator of total passages through the Danish Straits, and this gives some indication of traffic trends in 2010. In 2010 ship passages at Skagan amounted to a total of 60,740: 30,636 inbound (from the North Sea) and 30,104 outbound (from the Baltic Sea). This was 1.8% higher than the 59,687 total passages recorded at Skagen in 2009, a figure close to the aggregate total compiled by the DMA for both the Sound and Great Belt for 2009 (see Table IV-7).

Table Iv-6

Oil and Products Traffic in the Danish Straits

Year Volume (mt)2000 802001 812002 842003 1082004 1292005 1442006 1512007 1712008 n.d.2009 1662010 157

Source: admiralty Danish Fleet. n.d. = data not reported. Note: carried by tankers in both directions; oil flows mainly through the Great Belt.




Tab

le Iv

-7

Shi

p P

assa

ges

Thr

oug

h th

e D

anis

h S

trai

ts

2000

20

01

2002

20

03

2004

20

05

2006

20

07

2008

20

09

Shi

p p

assa

ges

thro

ugh

the

Dan

ish

Str

aits

(Gre

at B

elt

+ S

ound

):

tota

l pas

sage

s, a

ll sh

ips

24,

527

23,

524

58,

576

62,

142

63,

211

60,

069

60,

909

61,

202

61,

467

58,

048

tota

l DW

t (th

ousa

nds)

, all

ship

s -

3

15,4

19

580

,853

6

11,4

24

677

,135

7

38,5

12

761

,861

7

67,9

12

775

,731

7

93,4

41

ave

rage

ves

sel s

ize

(DW

t) -

1

3,40

8 9

,916

9

,839

1

0,71

2 1

2,29

4 1

2,50

8 1

2,54

7 1

2,62

0 1

3,66

9

tota

l pas

sage

s, t

anke

rs 5

,166

5

,166

1

0,59

3 1

1,22

2 1

1,45

3 1

1,49

7 1

1,89

2 1

2,24

5 1

3,20

0 1

3,34

2 to

tal D

Wt

(thou

sand

s), t

anke

rs 1

49,0

00

165

,229

2

45,7

56

270

,724

3

33,3

46

374

,986

3

77,6

60

403

,553

4

07,6

79

429

,191

a

vera

ge t

anke

r si

ze (D

Wt)

28,

842

31,

984

23,

200

24,

124

29,

106

32,

616

31,

757

32,

957

30,

885

32,

168

Shi

p p

assa

ges

thro

ugh

the

Gre

at

Bel

t:

tota

l pas

sage

s, a

ll sh

ips

24,

527

23,

524

20,

928

23,

240

23,

745

24,

324

24,

722

25,

769

29,

293

26,

474

tota

l DW

t (th

ousa

nds)

, all

ship

s 3

15,4

19

346

,554

3

74,3

14

421

,611

4

70,0

31

473

,648

5

13,8

42

535

,940

5

37,6

47

ave

rage

ves

sel s

ize

(DW

t) -

1

3,40

8 1

6,55

9 1

6,10

6 1

7,75

6 1

9,32

4 1

9,15

9 1

9,94

0 1

8,29

6 2

0,30

8

tota

l pas

sage

s, t

anke

rs 5

,166

5

,166

5

,170

5

,509

5

,876

6

,076

6

,247

6

,865

8

,301

8

,246

to

tal D

Wt

(thou

sand

s), t

anke

rs 1

49,0

00

165

,229

1

86,9

23

210

,077

2

62,5

54

296

,157

2

87,8

50

322

,405

3

31,7

80

342

,947

a

vera

ge t

anke

r si

ze (D

Wt)

28,

842

31,

984

36,

155

38,

133

44,

682

48,

742

46,

078

46,

964

39,

969

41,

589

Shi

p p

assa

ges

thro

ugh

the

Sou

nd:

tota

l pas

sage

s, a

ll sh

ips

37,

648

38,

902

39,

466

35,

745

36,

187

35,

433

32,

174

31,

574

tota

l DW

t (th

ousa

nds)

, all

ship

s 2

34,2

99

237

,110

2

55,5

24

268

,481

2

88,2

13

254

,070

2

39,7

91

255

,794

a

vera

ge v

esse

l siz

e (D

Wt)

6,2

23

6,0

95

6,4

75

7,5

11

7,9

65

7,1

70

7,4

53

8,1

01

tota

l pas

sage

s, t

anke

rs 5

,423

5

,713

5

,577

5

,421

5

,645

5

,380

4

,899

5

,096

to

tal D

Wt

(thou

sand

s), t

anke

rs 5

8,83

3 6

0,64

7 7

0,79

2 7

8,82

9 8

9,81

0 8

1,14

8 7

5,89

9 8

6,24

4 a

vera

ge t

anke

r si

ze (D

Wt)

10,

849

10,

616

12,

694

14,

541

15,

910

15,

083

15,

493

16,

924

Sou

rce:

ann

ual R

epor

ts, D

anis

h M

artim

e a

utho

rity.

N

ote:

VtS

Gre

at B

elt

regi

ster

s al

l shi

p p

assa

ges

over

50

gros

s re

gist

ered

ton

s (G

Rt)

; for

the

Sou

nd, a

vera

ge D

Wt

per

pas

sage

is c

alcu

late

d fr

om p

assa

ges

with

a r

egis

tere

d t

onna

ge.



143


Pomerania, the Danish government had received a large part of its income by levying the so-called Sound Dues toll on international merchant ships passing through the Sound. Non-Danish vessels were forbidden to use any other waterways but the Sound. Transgressing vessels were confiscated or sunk. But by the middle of the nineteenth century this practice became a diplomatic and trade liability, so the Danish government agreed to terminate it in exchange for international financial compensation. Danish waterways were consequently opened to foreign shipping.

Navigation in the Danish Straits is quite complicated, partly because of strong currents and poor weather. But the passage is also difficult geographically: despite broader expanses of water than in the Bosphorus, for example, recommended routes providing sufficient depth are quite narrow and often close to rocky areas, and vessels have to make 70–80 degree turns in some places. There is little room for maneuver, increasing the risk of collision or running aground. The Great Belt divides into the East Channel and the West Channel. Both are traversed by the Great Belt Bridge, and a tunnel also runs under the East Channel. The traffic in this particular part of the passage is also fairly intense. Groundings are one of the biggest problems in the Great Belt, due to navigational hazards such as shallow water and narrow sea lanes with sufficient depth. Chokepoints are of particular concern where the passage becomes quite narrow or severe turns are required. Two narrow spots are at the Great Belt Bridge, where the distance is only about 1.6 km between the pillars, and at the northern (western) entrance to the Sound between Denmark and Norway, where the water expanse is 4 km wide but the passage area is much less.

Still, the only restriction on vessels for the Great Belt passage is that no vessels with a draft of more than 15.4 m can pass through. Even so, according to the Danish Maritime Authority depths can change significantly depending on weather conditions, so safe passage is guaranteed for only 15 m draft, although sometimes it can be sufficient for 15.5 m. A traffic separation scheme is employed that allows two-way traffic throughout the straits, but no special measures are implemented to prevent large ships going in opposite directions from meeting each other at the chokepoints, as the individual pilots work it out so that this can be avoided. Most importantly, despite the fact that in many respects passage through the Great Belt appears at least as difficult as through the Bosphorus, transit of large vessels/tankers is not restricted to only daylight hours.

For ships in international transit, use of a pilot is only recommended; it is not compulsory under the conditions of the Copenhagen Treaty. According to Danish Pilot Act No. 567, there is an obligation for ships to use a pilot in internal and external territorial waters (i.e., if they are entering a Danish port) if they are carrying oil or have uncleaned cargo tanks that have not been rendered safe with inert air, are carrying chemicals, are carrying gases, have more than 5,000 tons of bunker oil onboard, or are carrying highly radioactive material. Still, the Danish Maritime Authority recommends that masters of all vessels with a draft of over 11 m use pilots. In recent years, 96–98% of vessels in this category have done so while passing through the Great Belt. None of the stranded vessels in the passage in 1997–2005 had a pilot on board, indicating that pilot usage is an important contributor to overall safety.




4.3 CONGESTION MODEl FOR THE TURKISH STRAITS

This section of the overall analysis provides an outlook of the cost dynamics of Bosphorus congestion going forward, based on IHS CERA’s long-term projections of evacuation volumes (see above). A key point to keep in mind is that hypothetical congestion modeling of transportation flows, such as volumes of ship traffic in the Bosphorus, shows that a “congestion point” is reached well before traffic reaches the level of available capacity.* Once volumes exceed this congestion point, even relatively small incremental increases in oil flows through the Turkish Straits would increase direct demurrage costs considerably, which potentially could reach billions of dollars over a period of several years (see below).

For purposes of this study, we have created a model for calculating future congestion costs. Our analysis covers the period through 2030 and focuses essentially on trends in the largest cost contributors in congestion costs, namely direct demurrage (and the associated freight rate effect).

4.3.1 Methodological Approach and Assumptions

IHS CERA’s methodological approach to projecting the direct demurrage/congestion cost is based on the following differential equation, based upon projected monthly crude flows to the Bosphorus from the Black Sea:

d/dt (derivative of time) x(t) = p(t) - q(t)

where:

p(t) equals the oil flow coming to the Bosphorus in a day

q(t) equals the oil flow leaving the Turkish Straits on the other side in a day

t equals time, in days

If p(t)<q(t), then x(t) will decrease until it reaches zero. From that point there is no queue (of waiting oil/ships). Conversely, in the case where p(t)>q(t), then x(t) is increasing, indicating that a queue is forming of oil (and tankers) waiting to move through the Bosphorus. The average tanker waiting time is equal to:

T (waiting time) (t) = x(t)/q(t)

And the number of waiting tankers is equal to:

N tankers (t) = x(t)/dwt, where dwt is the size (in deadweight tons) for an average tanker

*See, for example, the modeling undertaken in Dagobert L. Brito, “Congestion of the Turkish Straits: A Market Alternative,” Rice University, February 1999. Traffic levels in a transportation system like the Bosphorus can be partitioned into three regions: first, a region where traffic is not congested and additional traffic does not create delays; second, a region where traffic becomes congested because additional traffic creates substantial delays; and third, a region where additional traffic is infeasible because capacity has been reached. Professor Brito identifies the congestion point, or the boundary between the first and second regions, as the point where additional traffic reduces the overall flow. His modeling suggests that this occurs at 83% of available capacity in the case of the Bosphorus.



145


The direct demurrage cost (t) = (T waiting time) multiplied by (N tankers) multiplied by (DEM per unit), where DEM per unit equals the average demurrage cost per tanker per day. Integration of the differential equation above can be conducted using the method of finite differences.

For the purposes of this analysis, we also make the following assumptions:

The current restrictions on passage of large tankers (of more than 200 m LOA) through •the Turkish Straits will remain essentially unchanged in the period to 2030.

The general structure of the tanker fleet currently used to move oil from the Black •Sea and through the Turkish Straits will remain about the same through 2030, so that the average tanker shipment (for all large ships [200–300 m LOA] affected by the administrative measures) remains around 100,000 tons.*

The monthly distribution of each year’s crude oil exports is assumed to remain about •the same through 2030 as it was in 2007–10.

The amount of the demurrage cost per tanker per day in 2010–30 is assumed to be •about 75% of the average level in 2004–08 (i.e., about US$58,000 per day in the future, versus an average of about US$78,000 per day for 2004–08).**

4.3.2 Nominal and Real Capacity of the Turkish Straits

As applied by Turkish authorities from October 2002, the restrictions on passage through the straits enshrine differential capacity limits depending on the time of year. In winter months the capacity of the straits decreases by about 36% compared with the summer months because of the reduced number of daylight hours (and on a monthly basis, capacity in May, July, or August is more than double that of February because of the number of days in the various months). Based upon the transit restrictions currently in place, the hypothetical maximum capacity of the Bosphorus can be calculated for each month. On an annual basis, this figure amounts to about 164.4 mt (i.e., for movements in large tankers). This hypothetical calculation assumes the current structure of large tankers (resulting in an average size oil shipment of about 100,000 tons), streaming through the straits at perfect 90-minute intervals during available daylight hours and no weather-related delays or other closures of the straits to large tanker traffic. The annual nominal calculation would be as follows:

12 (average annual daylight hours per day) x 365 (days per year) = 4,380 (total annual •daylight hours)

4380 / 1.33 (minimum passage time per ship through Bosphorus) = 3,288 (total •possible passages) / 2 = 1,644 (maximum possible outbound [loaded] tankers per year) x 100,000 (average tons carried per tanker)

*But the shift in the general tanker configuration expected with a shift in loadings among the Black Sea ports for large tankers is taken into account, with about 60% of oil shipments expected to occur in Suezmaxes and about 40% in Aframaxes.*This is based upon the outlook for tanker freight rates; average freight rates are projected to be much lower over the 2010–30 period than for the recent historical period (2004–08), when the tanker market was relatively tight because of the phaseout of single-hulled tankers.




But this is only a hypothetical maximum, and actual operations cannot match this, especially during the winter navigation periods, when inclement weather conditions and other factors cause the actual carrying capacity of the straits to decrease substantially. Actual operable (or real effective) capacity is much lower than this.

Weather plays an important part in the situation, significantly affecting the capacity of the straits. This factor has to be taken into account explicitly when projecting demurrage costs. In calibrating our congestion model, IHS CERA assumes that for the outlook period, average capacity losses as a result of bad weather and other factors will be 20% in winter months, including October and November, and 5% in summer months, including April, May, and September (these averages are based upon actual results for the recent historical period). We assume that the average large tanker shipment leaving the Black Sea edges up to just over 100,000 tons of oil. We also assume that at least one of the slots available during daylight hours available to large ships (200 m LOA) is taken by a bulk carrier rather than a tanker. Thus, the effective (but still hypothetical) maximum “operating” capacity for the straits on an annual basis is reduced to about 132.4 mt of oil (crude and products) moving in large tankers (see Figure IV-18). This number would apply to both crude and any products carried in large tankers (over 200 m LOA), but for all intents and purposes it really means just crude. This is because most of the crude oil passing through the Turkish Straits is carried in large tankers, whereas most of the products are not (see above). But clearly, the carrying capacity for crude oil is highly dependent upon the amount of products that also passes through the straits, particularly what proportion of the products moves in large tankers that take up available passage slots.

The only other study that we are aware of in which Turkish Straits carrying capacity has been explicitly estimated is a study conducted in 2001 by ILF Consulting Engineers (ILF). In that study, ILF estimated total Bosphorus capacity for crude and products (carried in large tankers) to be only about 100 mt per year.* The latter calculation was based largely upon observed results for 2000–01, when the total amount of oil (crude and products) moving through the straits was around 85 mt per year.** This previous ILF calculation assumed an average of about 330 days per year of available transit time (at an average of 12 hours per day), giving an average of 7.5 daily transits for large vessels (of over 200 m) for a total of 2,475 transits of large vessels per year. Of this, about one-fifth was assumed to be bulk carriers, leaving a total of about 1,980 transits for oil (i.e., 990 loaded outbound).

The critical difference between the two calculations about total available capacity lies in the underlying assumptions about when the reduced carrying capacity for the straits (owing to weather and other factors) occurs: in the previous ILF calculation the reduction was applied more or less uniformly throughout the year, whereas in the IHS CERA calculation it is applied more selectively, with the largest reduction occurring in the winter when carrying capacity is already smaller because of fewer daylight hours.

*ILF Consulting Engineers, Burgas-Alexandroupolis Crude Oil Pipeline 2nd Stage Study (Basic Design), Market Analysis Report (II-TN-NA-NA-018003-7), February 5, 2002; pp. 124–130.**The total has since been observed to exceed 150 mt per year (in 2005), of which about 102 mt (2.04 mbd) was crude oil. This aggregate amount is probably quite close to the real operable annual capacity for straits transit.



147


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4.3.3 Modeling Results

This section summarizes the implications for Bosphorus congestion and demurrage charges of different combinations of IHS CERA’s Eurasian crude production and export scenarios, but it is the results of the central (Base Russia/Base Caspian) and two extreme cases (Low Russia/Low Caspian and High Russia/High Caspian) that are mainly highlighted below (see Figure IV-19). The congestion model is mainly concerned with crude flow volumes rather than products. For simplification in modeling, we essentially assume that all crude is shipped in large tankers (over 200 m LOA) and all products are shipped in smaller tankers (less than 200 m LOA), and are therefore unaffected by the transit restrictions.

In the Base Russia/Base Caspian case (IHS CERA’s central prediction), projected export volumes from the Black Sea exceed the effective Bosphorus passage capacity during winter months from 2012, but projected monthly volumes needing evacuation remain much less than the available capacity during the summer months. Projected volumes for total evacuation flows edge back up to reach 135.9 mt per year in 2025 (less than the level achieved in 2005) (see Figure IV-19), and crude exports also remain well below the hypothetical maximum (i.e., volumes reach only 112.1 mt, or 2.24 mbd, in 2025). Backed-up crude (in the queue waiting to transit the Bosphorus) exists but remains fairly moderate: it is projected to grow from 1.5 mt (10.95 million barrels) in February 2012 to a maximum of 9.8 mt (71.54 million




barrels) by March 2025 (see Figure IV-20). The projected maximum number of tankers in the queue reaches 96 in March 2025, with tanker waiting times remaining quite modest, never exceeding 15 days, even in 2025 (see Figure IV-21). Total demurrage charges are estimated at US$66.9 million in 2012 (an annual average of US$0.72 per ton, or US$0.10 per barrel) and rise thereafter to reach a maximum of US$740.9 million in 2025 (see Figure IV-22 and Table IV-8). A critical threshold that is never reattained is that annual demurrage charges never exceed those incurred during the winter of 2003/04.

In the Low Russia/Low Caspian case, which projects a sizable decline in crude oil volumes requiring evacuation via the Bosphorus, demurrage charges remain almost negligible (US$42 million for the entire 2012–30 period), clearly demonstrating that shippers can easily do without a bypass pipeline. This is because the projected monthly shipments seldom exceed available operable capacity in the straits. Because of the projected decline in overall export volumes flowing from the Black Sea, all large tankers slated to transit the Bosphorus can be accommodated relatively easily. Delays peak at only about 1.3 days in early January 2012, and the waiting time declines to zero after January 2014. Projected annual demurrage charges decline steadily, falling to zero after 2016 (see Figure IV-22).

At the other extreme in projected flow volumes from the Black Sea, the High Russia/High Caspian scenario involves congestion levels and demurrage charges that are extremely high in comparison. The situation reflects a classic congestion pattern: once the Bosphorus has

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already more or less reached its effective maximum capacity, each incremental unit attempting to exit the Black Sea increases the demurrage (congestion) penalty quite substantially.

In the High Russia/High Caspian case (which envisages a substantial increase in the volumes of crude arriving at the Black Sea ports and needing to be evacuated via the Bosphorus), total demurrage charges for 2012–30 are projected at US$126.8 billion (see Figure IV-22 and Table IV-8). In the High Russia/High Caspian case, projected volumes of crude (shipped in large tankers) begin to exceed Bosphorus capacity on an annual basis starting in 2018, and therefore after 2017 backups occur even in the summer months. The backed-up crude (in the queue waiting to enter the Bosphorus) grows rapidly, climbing from 3.0 mt (21.90 million barrels) in March 2012 to 23.4 mt (170.82 million barrels) in March 2020 and 54.1 mt (394.93 million barrels) in April 2025. The maximum number of tankers waiting in queue is projected to reach an incredible 527 in April 2025. The extra waiting time by 2030 amounts to 152 days (see Figure IV-21). In this scenario, annual demurrage charges also climb sharply, reaching US$3.4 billion by 2020 and US$16.3 billion in 2030. Clearly, under this scenario demurrage charges would be unacceptably high, necessitating construction of a bypass pipeline or other measures to relieve congestion.

Greater seasonal use of BPS-2. One of the options available to “bypass” the Bosphorus from early 2012 and to potentially reduce winter congestion and delays even further is to




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151


Tab

le Iv

-8

Pro

ject

ed A

nnua

l Co

nges

tio

n/D

emur

rag

e C

harg

es f

or

Tank

ers

Tran

siti

ng T

urki

sh S

trai

ts f

rom

Bo

spho

rus

Co

nges

tio

n M

od

el, 2

012–

2030

a. M

illio

n D

olla

rsB

lack

Sea

exp

ort

Sce

nario

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Sum

Bas

e R

ussi

a-B

ase

cas

pia

n67

102

135

267

345

357

369

381

441

481

529

593

663

741

738

699

660

627

593

8,79

0H

igh

Rus

sia-

Hig

h c

asp

ian

171

389

591

885

1,28

11,

648

2,50

02,

784

3,40

14,

417

5,66

77,

218

9,07

611

,249

13,1

1114

,532

15,5

2616

,107

16,2

8912

6,84

0lo

w R

ussi

a-lo

w c

asp

ian

2213

52

00

00

00

00

00

00

00

042

Bas

e R

ussi

a-B

ase

cas

pia

n (s

easo

nal B

pS

-2)

4959

6411

213

514

114

715

318

922

428

035

442

950

852

150

148

146

344

35,

252

B. U

SD

/ton

Bas

e R

ussi

a-B

ase

cas

pia

n0.

72

1.08

1.

40

2.58

3.

33

3.43

3.

53

3.63

4.

12

4.47

4.

84

5.35

5.

88

6.48

6.

50

6.20

5.

90

5.65

5.

39

Hig

h R

ussi

a-H

igh

cas

pia

n1.

70

3.63

5.

27

7.45

10

.25

12.8

0 18

.05

20.4

5 24

.32

31.4

8 40

.05

50.5

9 63

.09

77.5

6 91

.45

102.

56 1

10.8

8 11

6.42

119

.17

low

Rus

sia-

low

cas

pia

n0.

25

0.15

0.

06

0.03

0.

00

0.00

0.

00

0.00

0.

00

0.00

0.

00

0.00

0.

00

0.00

0.

00

0.00

0.

00

0.00

0.

00

Bas

e R

ussi

a-B

ase

cas

pia

n (s

easo

nal B

pS

-2)

0.54

0.

64

0.70

1.

17

1.40

1.

46

1.51

1.

57

1.90

2.

23

2.73

3.

38

4.02

4.

66

4.80

4.

64

4.48

4.

33

4.17

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make greater use of the “spare” capacity of the BPS-2 pipeline on a seasonal basis. In the analysis above, we assume that the monthly distribution of projected annual exports via BPS-2 was similar to more general oil exports; that is, generally conforming to the historical pattern established for 2004–08. But instead, what if we assume that our projected annual BPS-2 shipments are concentrated more heavily in the winter months; that is, shipments are expanded when congestion and high demurrage charges in the Turkish Straits occur or are threatened to develop (see Table III-25)?

In a sensitivity analysis based upon the Base Russian/Base Caspian scenario, this practice, even when employed only fairly modestly (and the opportunity exists for a more severe shift if necessary), has the effect of reducing the projected delays in Eurasian crude oil transit via the Bosphorus in the critical winter months. Backed-up crude (in the queue waiting to transit the Bosphorus) still occurs but is reduced by about half compared with the “normal” central case presented above: such backups are projected to remain negligible until after 2015, reaching a maximum of only 7.4 mt (54.02 million barrels) by March 2025. As a result, the projected total demurrage charges are much lower as well, estimated to reach a maximum of US$521.0 million (US$4.66 per ton) in 2025.

4.4 MARITIME SAFETy ISSUES

This section of the report addresses general maritime safety issues in the Turkish Straits. These include an overview of where the major risks for accidents actually lie for ship passages through the straits and areas that can be changed to significantly improve maritime safety there, including improving pilot usage and boarding, improving the use of escort tugs, and using standard tanker and ship vetting procedures.

4.4.1 where the Major Safety Risks lie

It has been largely axiomatic, at least for most Turkish officials (as well as many other casual observers) that the major safety risks involved in overall seaborne shipments of cargoes through the Turkish Straits are concentrated in crude oil shipments in large tankers. Therefore the public policy goal for the Turkish government has been to remove crude oil flows altogether (or reduce them as much as possible) from the Turkish Straits. This view is clearly expressed in overall policies related to ship transits through the straits (see above) as well as various programmatic statements made by Turkish politicians. For example, in his recent visit to Russia (in September 2011), Turkish President Abdullah Gul said in an interview about the need to build the Samsun-Ceyhan bypass pipeline:

“The important thing is ensuring the Bosphorus’s environment safety … the economic aspect of building the pipeline is secondary. There is intensive moment of tankers carrying dangerous cargo … (so building the pipeline) will be a large plus in reducing the burden on … the Bosphorus. An accidental catastrophe could have very serious consequences.”

But as indicated above, this is one of the major misconceptions relating to safety and environmental issues in the Turkish Straits. Overall oil shipments (crude and products combined) represented only 5.4% of total ship passages through the Bosphorus in 2010, and



153


crude oil passages alone a mere 3.2% (see Table IV-1). Even when measured in tonnage, oil-related shipments remain quite modest in the overall total volume passing through the Bosphorus. In 2010 total oil-related cargo amounted to 307.9 million dwt, accounting for only 22.7% of the overall total of 1,359.0 million dwt passing through the Bosphorus.

Thus, the vast bulk of ship traffic in the straits is related to non-oil cargoes: 94.6% of total passages in 2010 and 77.3% of total deadweight tons. All else being equal, such passages should be considered at least as risky as those relating to oil. In fact, most of the maritime accidents recorded in the Bosphorus have not involved crude oil tankers, but rather bulk carriers and some product tankers.*

More importantly, these other issues are not equal and actually make non-oil traffic a riskier endeavor in general. One key aspect is the average age of the vessels involved. This is only a general indicator of the quality of the vessel and is not an exact means of evaluation, but it is still nonetheless quite telling. For crude oil tankers going through the Bosphorus in 2010, 78.2% have been in service for less than 10 years, with 41.0% in the youngest category of 0–4 years of age (see Table IV-9). Products tankers tend to be somewhat older, with only 44.5% of such vessels passing through the Bosphorus in 2010 less than 10 years old. But for general cargo vessels (other ships), which contributed 80.4% of all passages, only 23.2% of all vessels were less than 10 years old, while 60.7% were in the oldest category, of 20+ years old.

Thus, an interesting sidelight to the ongoing debate about maritime safety is the likely shift in the share of crude oil moving in large tankers in the future from CPC expansion. Because the share of crude moved by Suezmax tankers will rise, this actually enhances the overall level of safety rather than decreasing it, as some would suggest. This is for two reasons: the larger ships tend to be safer vessels overall; and the increased use of larger tankers reduces the number of passages needed to move a given volume of oil through the straits.

What is also often overlooked is that all general cargo vessels also carry a significant load of bunker fuel that could be spilled in the event of an incident. One of the major misconceptions about relative risks is that only tankers can cause a large oil spill. Such a catastrophe by nontankers was not even covered by international agreements until 2008. Pollution damage from fuel oil carried on ships (as fuel) is now covered with entry into force of the international bunkers liability and compensation convention in November 2008. This closed the last significant gap in the international regime for compensating victims of oil spills from ships. Previously, the international regimes covering oil spills did not include damage from oil spills from vessels other than tankers.

Another issue relating to the general safety standards of the ships passing through the Bosphorus is their country of registry. Safety standards vary considerably from country to country, and shipowners often resort to registering older vessels in so-called black list

*A notable exception was the collision in March 1994 between the crude oil tanker Nassia, which was carrying 98,500 tons of Russian crude outbound, and the bulk carrier Shipbroker, which was inbound. Importantly, it was the Shipbroker that caused the accident when it lost power and could no longer steer and crashed into the Nassia. Both of the vessels were Cyprus registered. Shipbroker burned completely, and the Nassia ended up as a total loss. As a result of the collision, 27 people lost their lives, 9,000 tons of oil spilled, and 20,000 tons of oil burned for four days, while traffic in the strait was suspended for several days.




Tab

le Iv

-9

Num

ber

of

Pas

sag

es T

hro

ugh

the

Bo

spho

rus,

by

vess

el T

ype

and

Ag

e

per

cent

per

cent

typ

eS

hip

age

Grp

2009

-1H

2009

-H2

2010

-1H

2010

-2H

2011

-H1

2009

2010

2009

2010

a c

rud

e oi

l tan

kers

a 0

-4yr

s63

465

452

169

044

31,

288

1,21

143

.141

.0B

5-9

yrs

497

482

557

542

515

979

1,09

932

.837

.2c

10-

14yr

s18

018

116

019

213

836

135

212

.111

.9D

15-

19yr

s11

311

014

710

249

223

249

7.5

8.4

e 2

0+yr

s70

6635

1036

136

454.

61.

5a

cru

de

oil t

anke

rs t

otal

1,49

41,

493

1,42

01,

536

1,18

12,

987

2,95

610

0.0

100.

0B

pro

duc

ts t

anke

rsa

0-4

yrs

235

249

241

293

248

484

534

22.1

24.4

B 5

-9yr

s20

721

822

621

321

442

543

919

.420

.1c

10-

14yr

s61

8288

9211

514

318

06.

58.

2D

15-

19yr

s12

311

611

011

195

239

221

10.9

10.1

e 2

0+yr

s42

946

741

939

327

589

681

241

.037

.1B

pro

duc

ts t

anke

rs t

otal

1,05

51,

132

1,08

41,

102

947

2,18

72,

186

100.

010

0.0

c c

hem

/gas

/oth

er

tank

ers

a 0

-4yr

s1,

573

1,73

91,

728

1,96

31,

590

3,31

23,

691

41.8

43.8

B 5

-9yr

s73

978

695

096

31,

013

1,52

51,

913

19.2

22.7

c 1

0-14

yrs

366

429

344

420

461

795

764

10.0

9.1

D 1

5-19

yrs

240

358

365

267

211

598

632

7.5

7.5

e 2

0+yr

s86

183

374

168

269

81,

694

1,42

321

.416

.9c

che

m/g

as/o

ther

ta

nker

s to

tal

3,77

94,

145

4,12

84,

295

3,97

37,

924

8,42

310

0.0

100.

0

D o

ther

Shi

ps

a 0

-4yr

s3,

549

4,72

93,

869

4,72

33,

561

8,27

88,

592

15.7

15.4

B 5

-9yr

s1,

769

1,98

22,

089

2,27

52,

364

3,75

14,

364

7.1

7.8

c 1

0-14

yrs

2,01

92,

278

2,26

62,

216

1,73

04,

297

4,48

28.

18.

0D

15-

19yr

s2,

127

2,37

62,

182

2,30

51,

869

4,50

34,

487

8.5

8.0

e 2

0+yr

s15

,049

16,9

1117

,160

16,6

8814

,450

31,9

6033

,848

60.5

60.7

D o

ther

Shi

ps

tota

l24

,513

28,2

7627

,566

28,2

0723

,974

52,7

8955

,773

100.

010

0.0

Gra

nd t

otal

30,8

4135

,046

34,1

9835

,140

30,0

7565

,887

69,3

38

Sou

rce:

aiS

dat

a, a

ggre

gate

d a

nd c

omp

iled

by

iHS

Fai

rpla

y.



155


countries to avoid retiring them or spending significant amounts of money on maintenance and repairs when such vessels fail to meet safety standards in their home countries.* Most importantly, none of the crude oil tankers of over 200 m LOA that passed through the Bosphorus in 2010 were flagged in such “black list” countries. In contrast, this is not the case for any of the other major categories of vessels, particularly the general category of other ships (nontankers).

It is also a common misconception that oil evacuation through the Turkish Straits will continue to rise. Instead, this study shows that the number of oil-related passages has been declining in recent years, and according to the projections presented in this study, total oil shipments through the straits are likely to remain flat or decline further going forward. Although we are projecting a rise in crude oil evacuation volumes (+10.3% by 2025) for passages, we are projecting that even for crude oil these will decline because of a shift to larger vessels, to about 1,062 needed passages outbound (or 2,124 in total) at the peak in 2025. Product passages will decline significantly because of the reduction in the overall volume.

In contrast, general cargo passages through the Bosphorus rose substantially in 2010 (+9.2%), and will probably continue to rise in the future, concomitant with overall economic growth in the Black Sea region as a whole.

4.4.2 Improving Pilot Usage and Pilot Boarding

Use of pilots for ships passing through the challenging waters of the Turkish Straits remains noncompulsory (see above). But as shown above in the case of the Danish Straits, the use of knowledgeable pilots in narrow and difficult passages does improve overall safety. Therefore, a major goal for shippers, ship operators, and the Turkish government would be to increase the use of pilots on ships going through the Turkish Straits. This would have to be through voluntary rather than compulsory means, such as public education.

The overall figure for use of pilots by ships passing through the Bosphorus in 2010 was 51.6%, which includes all ships, including those bound for Turkish ports, where the use of pilots is mandatory. For ships passing through the Bosphorus in international transit in 2010, the share using a pilot was much lower: only 28.8%. But for large crude tankers (and for all ships >200 m LOA), pilotage is virtually 100%. This is a result of a concerted effort by oil shippers to improve safety in the areas of responsibility that they control. But given these figures, this means that use of pilots by general shipping through the straits remains very low. This is yet another indication of why general cargo traffic in the straits must be considered a higher-risk operation than crude oil shipments.

Another issue relating to use of pilots is the pilot boarding location. Outside of each entrance to the straits a designated pilot boarding location has been marked on the navigation chart. This location has been agreed with the IMO as having the proper distance to allow the joining pilot and vessel master to conduct a proper master-pilot information exchange. The extra distance also allows the vessel to abort the passage should the pilot have difficulty

*The “black,” “grey,” and “white” lists maintained by the Paris MOU on Port State Control are considered to be the worldwide index for “flag” performance and quality shipping. As of 2010, 42 flags (countries) were on the white list (see Paris MOU, 2010 Annual Report).




boarding the vessel. But actual practice has become lax over time, and pilots typically board in protected water (probably because it is easier), but this means the hand-over occurs only after the vessel has physically entered the strait.

4.4.3 Improving Use of Escort Tugs

The current practice is for an escort tug to accompany a ship carrying so-called hazardous cargo during its passage if it is over 250 m LOA. Nominally, the escort tug might be able to push other vessels out of the way in case of an emergency, but the current procedure fails to promote safety to the fullest extent possible. This is because the escort tug is not tethered to the vessel. As a result, the escort tug is essentially useless if the vessel should lose steering or power. A better procedure, and one that has proved its effectiveness elsewhere, would be for the tug to be tethered where it could be more effectively employed in the event of an emergency. A certified escort tug tethered to a vessel can provide both arresting and steering force. A certified escort tug has proved to be the single most effective tool for reducing groundings and collisions.

4.4.4 vessel vetting Standards

Oil shippers have had a major impact upon improving safety, including tanker passages in the Turkish Straits, through the widespread use of vetting procedures for the tankers that they allow to load their oil. Ship/vessel vetting is the process by which a shipper determines whether a vessel is suitable to be chartered. Ports, terminals, insurers, and other maritime industry operators also vet ships to identify and manage risks, and many shipowners and ship managers use ship vetting services to monitor information about their own vessels. Unlike certification or classification, vetting is a voluntary system that operators may use to help them choose a particular vessel from among all of the certified vessels available and to manage their risks. Vetting inspections help ensure that the vessel complies with applicable rules and regulations.

Ship vetting in its current form first appeared in 1993, when the Ship Inspection Report (SIRE) database was created for use by oil companies. For each voyage, the vetting department assesses the vessel to be used, relying in particular on inspection results. The results of inspections carried out by oil companies that are members of the Oil Companies International Marine Forum (OCIMF) are shared via the joint SIRE database. Oil companies perform inspections according to a standard report format developed by the OCIMF. These reports become available to all OCIMF members via the SIRE database, which provides each company’s vetting department with the information it needs to apply its own internal criteria without having to inspect each vessel itself.

Dry bulk and container ships can also be vetted. Systems for such vetting were developed after SIRE had proved valuable for the oil industry and in recognition that substandard ships remained a major risk for the shipping industry. But vetting for dry vessels remains less structured than in the oil industry and is not as universally used, although acceptance has risen significantly, especially through the growth of accessible online vetting services.



157


Structured vetting procedures are not widely practiced yet at Black Sea ports/oil terminals. But they are used at CPC and Supsa, the two Black Sea terminals operated by international companies.

One way of further improving safety on ships passing through the Turkish Straits would be for the Black Sea countries to act as a group in implementing a uniform set of standards or implementing a standard vetting procedure for all ships that are allowed to call (and load or discharge) at Black Sea ports. This could lead to a type of certificate for transit through the Turkish Straits that would be similar to what is in place for the Malacca Strait. It is in the interest of all the Black Sea littoral states to upgrade and improve standards, so that safety can be enhanced and the risk of accidents reduced.




5. STATUS OF TURKISH STRAITS ByPASS PROPOSAlS

Misconceptions about oil transport via the Turkish Straits have led to a variety of options and proposals for bypasses to remove oil from the Turkish Straits. One such pipeline, the BTC pipeline, already exists. But the competition to build the next Bosphorus bypass pipeline, specifically aimed at diverting crude flows already leaving Black Sea ports, largely became a “two-project” race a couple of years ago; many of the myriad other proposed projects have fallen by the wayside for one reason or another. Aside from the Burgas-Alexandroupolis pipeline (BAP), the chief alternative option still in active play is the project to build the Samsun-Ceyhan (or TAP) pipeline across Turkey. Other options, all involving multiple transit states, face an even greater uphill struggle in competition for oil and markets with BAP and TAP. However, plans for the Odessa-Brody-Gdansk route remain active following a revived initiative by the Ukrainian government to reverse the direction of flows in the Odessa-Brody pipeline. Moreover, at least two other potential bypass pipelines remain formally on the agenda: the AMBO and Constanta-Trieste routes. The proposed Istanbul sea-level canal can be considered as another alternative to transit through the Turkish Straits.

IHS CERA’s analysis of Black Sea evacuation volumes and Bosphorus congestion costs indicates that from an economic perspective, it remains challenging to develop a business case for a bypass pipeline given the myriad uncertainties involved in projecting Black Sea evacuation volumes, the mixture of crude to products in the overall total, the structure of the tanker fleet used to move oil from the Black Sea, annual weather patterns in the straits, and Turkish transit rules. Furthermore, it is unlikely that more than one such bypass would be needed, at least from an economic perspective, because of the substantial drop in potential congestion (and related costs) that result from greatly reduced flow volumes that would follow the completion of an initial pipeline. This means that the realization of one pipeline system would likely prevent the realization of any of the others.

But it is an entirely different question if the goal is to remove oil transit (particularly crude in large tankers) from the Turkish Straits altogether, or at least reduce it dramatically. This is primarily a political question and could require renegotiation of the Montreaux Convention or at least a very radical (and revised from long-standing historical practice) interpretation of what constitutes “hazardous cargo.” But with crude oil flows projected to be over 100 mt per year (2 mbd) in all but the lowest scenario combinations, theoretically there is more than sufficient oil to fill two bypass pipelines.

This section examines the above-noted alternative bypass pipeline options, focusing on the chief project parameters, key advantages and disadvantages, leading supporters and opponents, and the current status of the projects. For a comparative overview of the routes and specifications (see Figure V-1 and Table V-1).

5.1 BURGAS-AlExANDROUPOlIS

The BAP pipeline project is based on a March 2007 intergovernmental agreement among Russia, Greece, and Bulgaria. Key elements of the planned transportation system include a 285 km pipeline from Burgas (Bulgaria) to a deepwater port at Alexandroupolis (Greece). BAP would have initial capacity of 35 mt per year (700,000 bd) and might eventually be



159


Table v-1

Key Parameters of leading Bypass Options

Route length (km) capacity (mt per year)

Reported construction cost estimate (billion USD)

Burgas-alexandroupolis 285 35–50 1.4Samsun-ceyhan (calik-eNi) 550 50–75 1.5-2odessa-Brody-plock-Gdansk 490* 25 0.7Burgas-Vlore (aMBo) 890 35 1.5-1.8constanta-trieste ~1,300-1,400 90 2-3.5istanbul canal 45-50 all tanker traffic 10

Source: compiled by iHS ceRa from participant announcements; other sources. 1. New pipeline; i.e., Brody-plock segment.

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expanded to 50 mt per year (1 mbd). The latest announced cost estimate is about €1 billion (about US$1.4 billion), but the actual cost is more likely to be around US$2.5 billion. Transneft has provisionally estimated the BAP pipeline tariff rate at US$8–$12 per ton (US$1.10–$1.64 per barrel), but this may also need to be revised upwards, depending on the final construction cost, among other factors.

Altogether three state-controlled Russian companies have a 51% stake in the pipeline company, TransBalkan Pipeline BV (TBP), which was formed in 2008 to implement the intergovernmental accord. Russia’s shareholding is divided among Transneft, the project coordinator and future pipeline operator, with a 33.34% stake; Rosneft (33.33%); and Gazprom Neft (33.33%). The other partners in the consortium, Greece and Bulgaria, hold stakes of 24.5% each. Germany’s ILF has been hired as technical advisor.

At one point Russia sought to link completion of BAP to approval of CPC expansion to 67 mt per year (1.34 mbd), but Russia subsequently claimed it would be able to fill phase 1 of BAP without diverting any CPC flows. Russia nevertheless appeared to be counting on Kazakh oil to help fill BAP. A May 2008 Russian-Kazakh agreement calls for 17.5 mt per year (350,000 bd) of Kazakh crude (i.e., half of the initial throughput volume) to be pumped through BAP.

Early BAP construction plans, announced in March 2009, envisioned a mid-2010 construction start, with commissioning slated for 2012. But later in 2009 a new Bulgarian government, under Prime Minister Boiko Borisov, announced a “review” of all Russian-Bulgarian pipeline projects, including BAP. Since then, the Bulgarian government has missed several required project payments, and Bulgaria’s debt to the project amounted to an estimated at €7.3 million, or about US$10 million, in mid-2011. But the Bulgarian government did approve payment of its contribution to the project in July 2011 through the issuance of bonds that would be acquired by the Bulgarian Ministry of Finance.

Key advantages and disadvantages

Advantages

BAP is probably the best overall candidate among the bypass projects when considering •all the relevant factors: logistics, market issues, construction costs, terrain and environmental impact, and general political and strategic considerations.

As the route traditionally favored by Russia, BAP is least likely to experience a •shortage of crude supplies, given Transneft’s ability to channel significant Russian oil (and probably Caspian oil as well) into the pipeline.

Disadvantages

The potential transit state risk involved in the BAP option has been illustrated by •the ability of one party to the intergovernmental agreement to effectively delay BAP construction for several years.



161


Our long-term outlook calls for continuation of much lower tanker rates than was the •case during the period of tight tanker markets in the lead-up to the formation of TBP, greatly diminishing BAP’s potential cost advantage over routes to market that rely more heavily on tankers.

leading Supporters and opponents

Supporters.• The Russian government and Russian state-owned companies with a controlling interest in the TBP consortium have been leading supporters of the project from the start. Greece has also repeatedly reaffirmed its support for BAP.

Opponents.• The Bulgarian government has emerged as a key opponent, with resistance led by Prime Minister Borisov along with the Bulgarian Environment Ministry. Bulgarian public opinion appears more divided, with opposition among the populace largely centered in Burgas and Sozopol, which voted against BAP in local referendums in spring 2008.

latest developments

In June 2011 for the third time Bulgaria delayed approval of the pipeline on environmental grounds, with the Bulgarian Environment Ministry demanding further work on the environmental impact study, to be presented on September 30. A key problem for the Bulgarians is that the project promises relatively little financial benefit if it is to remain competitive. In September 2011 Transneft Vice President Michail Barkov said that BAP will not be revived until there is a change of government in Bulgaria and announced a freeze on all preparatory work on the project in October–November. Transneft has also expressed interest in the possibility of a pipeline bypassing Bulgaria, but without specifying the potential route.

5.2 SAMSUN-CEyHAN

The planned 550-km Samsun-Ceyhan pipeline, also known as the TAP, would run exclusively on Turkish territory, between Samsun on the Black Sea coast and Ceyhan on the Mediterranean (partly following the BTC corridor) and would have an initial capacity of 50 mt per year (1 mbd), possibly rising to 75 mt per year (1.5 mbd). The project includes construction of a new Samsun terminal and tank farm, as well as four pump stations, a pressure-reducing station, and additional crude storage facilities at Ceyhan. Total construction costs were initially announced as US$1.5–$2.0 billion, but this would appear to be an underestimate given inflation in the current costs of pipe, labor, and equipment for such an ambitious undertaking. In April 2009 a Reuters report put the estimated pipeline construction cost at US$4 billion, citing the estimate of an anonymous source within the ENI-Calik consortium.

Italy’s Eni and Turkey’s Calik each hold 50% in the Trans-Anatolian Pipeline Company (Tapco), established to design, construct, and operate the pipeline. The license for the project was awarded by the Turkish government in June 2006 to Calik but has since been transferred to Tapco. Calik began technical and commercial studies in 2003 and formed its partnership with Eni in 2004. The two companies have agreed in principle to reduce their shareholdings in equal amounts so that other companies may join, and discussions have reportedly been




held with a variety of players including the Indian Oil Corporation, Shell, Mitsubishi, and Total. There appears to be a possibility of Russian companies joining the consortium after a high-level protocol was signed between Russia and Turkey that covers several projects and initiatives, including the Samsun-Ceyhan oil pipeline (see below).


Advantages

The key advantage of TAP is that only one country (Turkey) is involved, thus avoiding •the need for intergovernmental agreements and various “transit state” risks as well as problems of multinational coordination.

It has synergies with existing Turkish facilities, particularly the BTC pipeline (from •Sariz to Ceyhan, the pipeline would follow BTC’s general right of way) and the Ceyhan terminal.

Environmental conditions are well known, and the pipeline route traverses a sparsely •populated area, facilitating land acquisition and construction activities.

Disadvantages

The pipeline route is mountainous, with an uphill section of 430 km that reaches an •elevation of over 2,000 m.

Sources of oil have yet to be pinpointed, although Transneft-provided Russian oil •could be a possibility or the Kashagan project could ultimately contribute substantial volumes to the extent that these arrive in the Black Sea.

There are comparatively few regional marketing opportunities en route to the export •terminal (only the Kirikkale refinery), leaving shippers almost entirely dependent on overseas markets (although plans exist to construct at least one new refinery at Ceyhan).*


Supporters.• The Turkish government is considered a strong supporter, given its views of the environmental risks relating to oil traffic in the Turkish Straits as well as the prospect of large foreign investment in connection with TAP construction and the importance of the project in realizing Turkey’s potential as an East-West energy corridor. Calik remains the chief sponsor.

Opponents.• Environmentalists in the Black Sea region have been among the most vocal opponents, just as they are against other regional pipelines. For example, in March 2007 a wide-ranging coalition of regional environmental groups led by the

*Turkey has given provisional permission for four refineries to be built at Ceyhan, but only two of these—a Calik-led joint venture (with an international oil company) and another to be built by Turkey’s Petrol Ofisi and Austraian OMV—have so far been given the go-ahead for construction. The other proposals include one by Socar/Turcas Energy and by the Cehavir Group. It remains uncertain if any of these will be built in the current economic environment.



163


Russia-based Environmental Watch on North Caucasus called for rejection of TAP on the grounds that the proposal to alleviate environmental threats to the Bosphorus by constructing bypass oil pipelines “creates comparably serious threats for the Black Sea ecosystems and the well-being of the inhabitants of its coastal zone.”

latest developments

Notwithstanding the ground-breaking ceremony near Ceyhan on April 24, 2007, marking the “official launch” of the project, at last report construction had not yet begun and no starting date had been set. In June 2008 Calik acknowledged that the 2011–12 TAP commissioning target was unlikely. In April 2009 Eni stated that it would finance a Samsun-Ceyhan pipeline engineering study, expected to be completed in 2010, after which an investment decision would be made. But the results of this study, if complete, remain unknown.

In a dramatic change in Russian policy, in Ankara on August 6, 2009, Russian Prime Minister Vladimir Putin and Turkish Prime Minister Tayip Erdogan signed a series of protocols on energy sector collaboration, including an agreement to form a joint working group to examine possible crude sources and routes for the TAP pipeline. This development has led to speculation of a strategic reorientation on Russia’s part toward TAP as the preferred Bosphorus bypass route instead of BAP. However, Putin himself has claimed that there is enough Russian and Caspian oil to fill both BAP and TAP. This was followed by the signing of a memorandum of understanding on October 19, 2009, between Russia, Turkey, and Italy, supporting the pipeline. On October 22, 2009, Kazakhstan’s government announced its interest in joining the project.

But more broadly, IHS CERA concludes that the Ankara protocol on TAP is best understood as a tactical maneuver on Russia’s part designed to achieve several goals simultaneously, without really committing Russia to the TAP project yet:*

Quid pro quo for Turkish support for South Stream.• The key purpose of the Ankara protocol was evidently to bring Turkey on board the South Stream gas pipeline project, but TAP is just one of several joint energy projects mentioned in the August protocol that may serve the same purpose (e.g., planned collaboration on nuclear power may turn out to be a more substantive area of partnership).

Bargaining chip vis-à-vis new Bulgarian government.• By signaling its interest in TAP, Russia has put additional pressure on Bulgaria to stay with BAP as the new Sofia government rethinks its energy sector collaboration with Russia.

Designed to increase Russian leverage with Eni.• The Ankara protocol is part of Russia’s delicate balancing act with Eni, given that company’s pivotal role in both South Stream and Samsun-Ceyhan.

Positions Russia to compete more effectively for Caspian oil transit business.• Similar to BAP, construction of TAP could serve to direct Caspian oil flows through

*See the IHS CERA Decision Brief Will Turkey’s New Energy Diplomacy Enable a Grand Bargain with Russia?




Russia (or Russian-owned pipelines) and away from routes competing with Russian pipelines (particularly BTC).

But the bottom line is that the Russia-Turkish protocol does not remove any of the key disadvantages of the Samsun-Ceyhan route noted above. Earlier this year Transneft made clear that it considers TAP at most a second-best bypass option, after BAP. In June 2011 Sergey Khodyrev, Transneft’s head of foreign economic relations, was quoted at the Moscow Oil and Gas Congress as saying, “We have not abandoned that project [Samsun-Ceyhan] but it is in a deeper freeze than Burgas-Alexandroupolis.” For Russia, an overriding negative of TAP is the high transportation tariff—estimated at US$19–$20 per ton (US$2.59–$2.73 per barrel) according to some press reports, compared with less than half this amount for the BAP pipeline.* Another factor in Russia’s dwindling enthusiasm for TAP may be the failure of its TAP working group participation to yield concrete benefits in terms of the other above-noted Russian priorities. In particular, Turkey has yet to agree to a South Stream route through Turkish territorial waters.

Meanwhile, Turkey’s own commitment to TAP has come into question following Prime Minister Erdogan’s April 2011 call for an Istanbul canal project that might make all bypass pipeline projects obsolete (see below).

5.3 ODESSA-BRODy-GDANSK

The Odessa-Brody-Gdansk pipeline initiative of recent years revives and extends the original concept of the Odessa-Brody pipeline, which was completed in 2001 together with the Pivdenniy (Yuzhniy) marine terminal complex near Odessa, with the idea of moving Caspian oil westward. After sitting idle for several years, under an agreement with Russian companies in 2004 it began serving as an export channel for Russian oil to the Black Sea. In early 2011, however, flows in the Odessa-Brody pipeline were reversed to carry Azeri oil to Belarus as part of a swap agreement, but the longer-term outlook for implementation of this accord is clouded (see above).

Kiev has expanded the original Odessa-Brody concept to include an extension to Poland’s Gdansk oil terminal on the Baltic coast. Specifically, the Ukrainian government seeks to construct a new 490 km pipeline between Brody (in western Ukraine) and Plock (Poland’s largest refinery), where the new segment would connect with the existing pipeline between Plock and Gdansk. A more recent alternative is to construct the extension pipeline between Brody and Adamovo (on the Polish-Belarusian border where the Druzhba Pipeline enters Poland) rather than to Plock. This is an easier route, as it avoids a protected area. Total capacity has been estimated at 25 mt per year (500,000 bd). The cost has been estimated at around US$700 million.

*The calculations of hypothetical tariffs on projects that are still in the planning stages must be viewed as inexact. What is clear is that given the significantly greater length of TAP compared to BAP—550 km versus 285 km—it can be safely assumed that TAP will have a significantly higher tariff on a cost-recovery basis.



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Advantages

Required investment is smaller than in the case of the other planned bypasses since •comparatively more of the necessary infrastructure is already in place.

Of the proposed bypasses, this route offers direct access to inland markets in Central •and Eastern Europe as well as other markets (such as Northwest Europe via Gdansk), the advantage being that these inland markets have tended to grow more quickly compared with those in Western Europe more generally (at least prior to the 2008–09 recession).

Disadvantages

Uncertainties surrounding sources of crude for sustained operations of the pipeline •remain a major concern. In particular, producers in Kazakhstan and Azerbaijan, the main potential suppliers of crude for the pipeline, have yet to make long-term throughput guarantees. The Kazakh government has linked such commitment to receivership guarantees and has also called for inclusion of Russian companies in the project.

Export shipments via Gdansk also confont potential problems with the Danish Straits, •which limit the size of tanker loads in much the way as the Bosphorus Straits and pose similar environmental issues.


Supporters.• The Ukrainian government, together with the Ukrainian national oil company, Naftogaz Ukrainy, apparently remains the chief driver. Certain other regional governments (e.g., Poland) and the United States and European Union have expressed support, with the latter providing grants for economic and technical studies.

Opponents.• Russian opposition may remain a complicating factor.

latest developments

Plans for the pipeline to move Caspian oil to European markets appeared to move closer to realization with the May 2007 Krakow (Poland) summit, at which leaders of Poland, Ukraine, Georgia, Azerbaijan, and Lithuania agreed to form a company to carry out the project. A year later, at the May 2008 Kiev summit, the Ukrainian government announced plans to begin pumping Caspian oil westward to the Czech Republic in July 2008. In signs of Kiev’s seriousness, Ukraine’s Ukrtransnafta pipeline operator was ordered to procure 485,000 tons (about 3.5 million barrels) of linefill and to pump 7 mt (140,000 bd) to Czech refineries in 2008. In the event, no Caspian oil flowed through Odessa-Brody that year. These Ukrainian initiatives ran into problems on both the supply and market sides. In particular, even assuming a secure source of Caspian crude, Czech refineries are physically unable to take more than 100–200,000 tons per month (around 24–48,000 bd) of Caspian crude via Ukraine at most.




More recently, Belarus’s efforts to seek alternatives to traditional Russian sources of crude oil supply have given this bypass project new life, but it is unlikely that the Belarusian initiative will serve to fill the pipeline with Caspian oil in the longer term (see below).

At last report, Belarus intended to import 26 mt (520,000 bd) of crude oil this year, up 77% over 2010 volumes. The aim is apparently both to permit recovery of domestic oil consumption, following a drastic reduction of imports from Russia in 2010 in connection with a dispute over oil trade terms, and to maintain a fairly high level of refined product exports. Although Belarus intends to source 22 mt (440,000 bd) of its imports from Russia this year, it has also announced plans to import another 4–8 mt (400-800,000 bd) from Venezuela via a swap deal with Azerbaijan.

On February 13, 2011, Ukrtransnafta began filling the Odessa-Brody line with Azeri Light crude destined for the Mozyr refinery in Belarus. However, full-scale realization of Belarus’s ambitions appears implausible for several reasons. One issue is that total annual refining capacity of the country’s two refineries is only about 22 mt per year (440,000 bd). Therefore, although Belarus claims that it will refine all its imports, the country will probably need to scale back announced import volumes. Unless Belarus becomes enmeshed in another dispute with Russia, the most likely candidate for reduction is the Venezuelan-Azeri stream, given its high cost differential vis-á-vis Urals Blend. In 2010 Belarus paid an average US$647 per ton (US$89 per barrel) for Venezuelan oil versus US$434 per ton (US$59 per barrel) for Russian crude, and the former figure probably does not include all the transportation costs involved, whereas the Russian import cost is probably delivered at the border (DAF). Indeed, Belarus “temporarily” suspended its swap arrangement, reportedly for purposes of maintenance at its Mozyr plant, after only two months, and total Belarusian imports of crude during the first half of 2011 amounted to only about 9.4 mt (376,000 bd), or around 36% of the planned annual total. Of this amount, 8.5 mt (340,000 bd) came from CIS countries (i.e., from Russia), representing 91% of imports, while only 0.9 mt (36,000 bd) came from non-CIS (i.e., via the swap). Russia reports that it sent nearly 8 mt (320,000 bd) of crude to Belarus by pipe in the first half of 2011.

5.4 AMBO

The proposed 890-km AMBO pipeline would originate at Burgas on the Bulgarian coast of the Black Sea and terminate at Vlore on the Albanian Adriatic coast. It would have a capacity of 35 mt per year (700,000 bd). The cost of construction was estimated several years ago at US$1.5–$1.8 billion. The pipeline would be built and operated by the US-registered AMBO Pipeline Corporation.


Advantages

It would have synergies with existing infrastructure; in particular, much of the right of •way in Bulgaria (where it is estimated that about 50% of the project would be built) would parallel an existing gas pipeline.



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The Vlore port is more accessible and can handle larger tankers than some of the other •competing bypass export terminals.

Disadvantages

No oil supplies have been secured so far, nor has there been even an expression of •interest in using the pipeline by any major oil producers.

One of the key drivers for the original pipeline scheme was to provide crude oil to •Macedonia’s land-locked Skopje refinery, but this impetus essentially disappeared with the privatization of the refinery into the hands of Hellenic Petroleum and the completion of a pipeline from Thessaloniki to supply crude to the plant.

There are three transit states involved (instead of only two in the case of BAP or one •for TAP), and the history of interstate pipelines in this region suggests the potential for conflict among the parties to AMBO: for example, in 2005 a dispute arose between Macedonia and Greece over oil transportation revenues from the Thessaloniki-Skopje pipeline.


Supporters.• The US government has been a strong backer and financed a feasibility study for AMBO, completed in September 2002. According to a May 2000 report on the project funded by the US Trade and Development Agency, the AMBO project fits in with the larger US policy objective of using commercially viable pipelines “as tools for establishing a political and economic framework that will strengthen regional cooperation and stability and encourage reform for the next several decades.” The governments of Macedonia and Albania have also expressed their support for the project. The government of Bulgaria has expressed support for the project, but at the same time it also backed BAP.

Opponents.• Various environmental organizations in the countries along the AMBO route have come out strongly against the proposed oil pipeline.

latest developments

A January 2007 intergovernmental convention signed by Bulgaria, Macedonia, and Albania reiterated support in principle for AMBO and governs construction, operation, and pipeline maintenance procedures. This agreement was subsequently ratified by the parliaments of the three countries, but there has been little progress since. Most importantly, Bulgaria also remains a member of the BAP consortium (at least pending a final decision by Sofia on BAP), which would effectively compete with AMBO for crude supplies and markets.

5.5 CONSTANTA-TRIESTE

The most ambitious of the Bosphorus bypass pipeline options in length (reported in various sources as either 1,319 or 1,400 km) and announced cost (US$2.0–$3.5 billion), the Constanta-Trieste or Pan-European Oil Pipeline (PEOP) would originate in Constanta in Romania on




the Black Sea; pass through Serbia, Croatia, and Slovenia; and extend to Trieste (Italy), a distance of about 1,400 km. Some variants include the incorporation of segments of existing pipelines into the project, such as the existing line that now carries crude eastward to the Serbian refineries from Croatia, to reduce the amount of new construction. In Trieste, the pipeline would be connected to the Trans-Alpine (TAL) pipeline which carries crude to Austria and southern Germany. The Constanta-Trieste pipeline would transport up to 90 mt per year (1.8 mbd) by 2012 according to the April 2007 Zagreb declaration in support of the project by the EU energy commissioner and the energy ministers of Romania, Serbia, Croatia, Slovenia, and Italy.


Advantages

It has been endorsed by the European Union and several of the regional governments (see •above). The US government provided a grant for a preliminary feasibility study.

It would be connected to existing pipelines that serve inland refineries in Romania •and Serbia, as well as the TAL that connects to the Ingolstadt plant in Bavaria and (via IKL) to the Kralupy plant in the Czech Republic.

Disadvantages

It is the longest and most expensive of the proposed bypass pipelines.•

It would cross the territory of five countries (more than any of the other proposed •bypass pipelines), magnifying the “transit state” risks and problems of multinational coordination.


Supporters.• The government of Romania is perhaps the strongest supporter, followed by Serbia. Romania expects that the project will create benefits for the country of up to US$4.4 billion over 20 years of the pipeline’s operation.

Opponents.• Notwithstanding their participation in the April 2007 Zagreb declaration, Croatia has in effect opted out and Slovenia’s commitment is questionable, in part because 29 km of the proposed route would cross an ecologically sensitive area (karst) of Slovenia.

latest developments

On April 22, 2008, the PEOP Project Development Company (PEOP PDC) was established by existing oil transportation companies in Romania (Conpet and Oil Terminal Constanta), Serbia (Transnafta), and Croatia (Janaf). This was followed on July 10, 2008, by adoption of a statute and appointment of a managing board. However, in February 2009 the chief executive of Janaf noted that Italy had not yet confirmed its participation and that “without Italy and the markets it serves, it doesn’t make sense to build the pipeline.” In 2010 Janaf did not pay its share of project capital and was then excluded from the pipeline consortium.



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In early 2011 press reports suggested a possible revival of project momentum amid Romanian efforts to interest Russia in joining PEOP as an alternative to the stalled BAP initiative. But given the absence to date of any official Russian declaration of support for PEOP or other signs of forward motion, it seems fair to conclude that the project remains essentially in limbo.

5.6 ISTANBUl CANAl

While on the campaign trail prior to Turkey’s June 12, 2011, parliamentary elections, Turkish Prime Minister Erdogan announced his government’s plan to build a new waterway, dubbed “Canal Istanbul.” that would connect the Black Sea to the Sea of Marmara via a canal to the west of Silivri in Turkey’s Thrace region, just outside Istanbul. The canal would be around 45 to 50 km in length, with a depth of approximately 25 m and a width of 150 m. These dimensions should permit passage of VLCCs in the range of 200–315,000 dwt and also allow for two-way traffic. According to the Turkish plan, the canal would be able to accommodate 150 to 160 ships per day, thus facilitating a near-complete diversion of oil tanker traffic from the Bosphorus. Turkish officials say that the canal would take eight years to construct, and Erdogan envisages its completion by 2023, in conjunction with the hundredth anniversary of the founding of the Turkish Republic. Estimates of the construction cost range from US$10 billion (the official estimate) to more than US$20 billion.


Advantages

The canal project offers shippers the prospect of an uninterrupted tanker channel to •world markets, in contrast to the bypass pipeline projects, which would involve extra expenses for tanker offloading and subsequent loading on each side of the pipeline.

Oil tankers would likely be subject to reduced insurance rates compared with tankers •transiting the Bosphorus, given the relatively remote location of the planned canal, far from highly developed urban areas such as on either side of the Bosphorus.

Disadvantages

Mandatory diversion of tankers or other large ships from the Bosphorus to the planned •canal and requiring them to pay canal transit fees would appear to violate the Montreux Convention (specifically Article 2 guaranteeing merchant ships complete freedom of passage in the straits).

The canal bypasses the Bosphorus and would allow VLCC passage, but this does •not solve the problem of the Cannakale (Dardanelles), which has become the more significant bottleneck in recent years (see above). VLCCs could not be used in the proposed canal unless they can also navigate the Cannakale.

Great uncertainties about the final project cost, which would nevertheless eclipse the •cost of all bypass pipelines under consideration even according to the official estimate, may open the door for budget overruns and delays.





Supporters.• Aside from the Turkish government, Turkish construction and other business interests that would benefit from the canal project are logical supporters of Erdogan’s plan.

Opponents.• The consortia supporting alternative bypass pipelines are among the primary natural opponents of the project. More generally, all oil producers and shippers that depend on relatively free passage through the straits are likely to oppose any project for rerouting oil flows through a new (and potentially expensive) Turkish water tollway.

latest developments

Since Turkey’s June parliamentary elections, there has been little news of the canal project, suggesting that the announcement may have been primarily an electoral ploy designed to drum up support for Erdogan’s faction in the lead-up to the vote by appealing to Turkish patriotic sentiment. However, in light of the government’s formal commitment, it is too soon to write off the Istanbul Canal. The next key signpost of this initiative’s viability may be whether the government meets its project design target schedule of about two years.



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6. OIl DEMAND DEvElOPMENTS IN GlOBAl MARKETS

This section discusses the identification and dynamics of target markets for the crude oil coming to the Black Sea. In addition to the traditional European market that has been the destination of the bulk of Eurasia’s Black Sea exports so far, the North American crude oil market of the Atlantic Basin is also a likely prospect. Although Eurasian volumes going to North America still remain relatively small (see above), North America was a significant destination for Iraqi crude loaded at Ceyhan back in the 1980s. It is also possible that China, India, and other Asia Pacific destinations may represent commercially viable outlets for oil exiting Black Sea outlets, and so this region is also discussed. Asia Pacific markets must be considered as viable targets for Eurasian flows in light of both the great potential for oil demand growth in this region (see below) and the opportunity to displace crude imports from points more distant than the Mediterranean (not only from other regions of the world, such as West Africa, but also including Russian volumes shipped by tanker from Baltic or Barents ports) at real transportation costs that are likely to be competitive with those of Russia’s ESPO pipeline.

6.1 OvERvIEw OF METHODOlOGy

IHS CERA’s historical global oil balance data are based on the following concepts of aggregate demand and production:

Demand.• This includes end-consumer product demand for all the liquid fuels (measured in volumetric terms), which essentially includes anything consumed as a “petroleum product” (including LPGs) in any sector, as well as blendstocks (such as ethanol and biodiesel). To avoid double counting, this definition does not include crude oil or any feedstocks that are used in a transformation process (such as refining) to produce the finished products in the form in which they are consumed. However, we do include the consumption of oil involved in these processes (i.e., refinery fuel and losses) as part of total consumption. Therefore, this concept serves as a general proxy for total crude oil demand.

Production.• This includes liquids supply that would go into one or another transformation process, such as an oil refinery or a condensate splitter, as well as supplies of unconventional liquids. Thus the definition covers conventional crude oil (including heavy oil from Venezuela and Canada); condensate; natural gas liquids ([NGLs] including LPG) produced in plants; coal-to-liquids, mostly middle distillate or methanol production; gas-to-liquids ([GTL], mostly middle distillates); ethanol or other biodiesel; and minor amounts of various other, more exotic fuels.

These two categories (demand and production) do not exactly balance in volumetric terms globally because of volumetric gain during refining. The supply side is always augmented with “refinery gain,” which at the global level has been on the order of 2.1 mbd per year. Of course, on a weight basis, the demand and production numbers basically balance.




IHS CERA develops aggregate demand projections for each major region of the world and refined product type from national-level statistics.* These projections depend on a variety of factors, called “demand drivers,” that vary depending on the availability of data for each region. Generally, the analysis of demand in each region is developed for each of the main products (i.e., LPG, gasoline, naphtha, jet fuel, gasoil/diesel, heavy fuel oil, and other) at the end-use sector level (e.g., residential, commercial, industrial, transportation, and electric power). Although the availability of data for each region is an important determinant of the methodology used and in the complexity of the analysis, a number of factors are always explicitly considered in preparing projections of refined product demand in all regions and countries.

Using the available historical data for sectoral product demand as a reference, IHS CERA evaluates the relationship between demand trends and the main drivers of the specific products. For example, in the United States commercial diesel fuel consumption is mainly related to commercial trucking tonnage hauled. Thus, overall economic activity, manifested in the projection of real economic growth (GDP), will be the key driver of demand for diesel fuel through the intermediate variable of commercial trucking tonnage hauled. In Europe, in contrast, high taxes and preferential taxes favoring diesel over gasoline (and the higher efficiency of diesel-fueled cars) leads to a major (and growing) concentration of highway diesel demand in personal vehicles. Similarly, jet fuel is consumed in air passenger and air cargo movements, but both are related in most regions to the pace of economic growth—the faster an economy grows, the faster the growth in passenger travel and air cargo shipments. But in projecting jet fuel demand one must be mindful that changes in airline operations, such as schedule changes to minimize empty flights and routing flights through company “hubs,” can increase the effective load factor of commercial aircraft. Thus, observed load factor trends and improvements in efficiency become an additional driver of the behavior of demand in regions where such data are available.

Generally the projected demand for each major refined product in a region and sector is related structurally to a logical driver of demand. Many of the drivers for commercial fuels are related to the economy, so real GDP trends are important drivers of demand. In some countries, such as China and India—which both have very low vehicle ownership per adult—the growth in demand for personal vehicle fuels (whether gasoline, diesel, or alternative fuels) is related directly to the growth in ownership of personal vehicles. In addition to projections for the pace of vehicle ownership, it is important to know the characteristics of the “driving cycle”—how many miles the driver will accumulate over the course of a year—as well as the fuel efficiency of the average vehicle of each type.

IHS CERA also takes into account the current and anticipated regulations affecting oil product demand and quality. The mandating of specific quality improvements and the efficiency standards with which oil-consuming equipment must comply—as well as shifts in demand among products—are often very important determinants of trends in demand for certain oil products.

*To provide consistency among the regions and to ensure a global balance between supply and demand, historical consumption data for most countries of the world are derived from information reported by the International Energy Agency (IEA) and the US Energy Information Administration.



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6.2 OIl DEMAND IN IHS CERA’S THREE GlOBAl ENERGy SCENARIOS TO 2030

IHS CERA’s global energy outlook is covered in three general scenarios, referred to as Global Redesign, Metamorphosis (Meta), and Vortex, based upon their most striking features within the general story developed for the future. Of the three global oil demand scenarios, the one in which we currently find ourselves, Global Redesign, assumes that reinvigorated market forces and shared interest among major powers to expand trade and investment foster robust economic growth over the longer term (see Figure A-1).

IHS CERA projects that global aggregate oil demand will rise in all three scenarios, although at different rates and with different compositions by region and by product (see Table A-1). In Global Redesign global oil demand increases by about 25.9% by 2030, or by 1.13 billion metric tons per year (22.64 mbd), reaching 5.51 billion metric tons per year (110.12 mbd). In the Meta scenario global oil demand increases by only about 14.4%, or 629.7 mt per year (12.59 mbd), to reach 5.0 billion metric tons per year (100.07 mbd) by 2030. In the Vortex scenario aggregate global demand increases by about 20.3%, or 887.6 mt per year (17.75 mbd), to reach 5.26 billion metric tons per year (105.23 mbd).

The most important driver of demand is global economic growth. Apart from economic growth, the key elements of future global oil demand are mandates and incentives to push the fuel efficiency of personal vehicles higher, a shift in the mix of refined product demand toward the middle of the barrel, and the dominance of Asia as the main source by far of future demand increases (see Figures A-2–A-6 and Tables A-2–A-7).

The key highlights of the base case Global Redesign scenario are

Global economic growth is fairly robust, averaging 3.6% per year in 2010–30.• Asia Pacific is the leading growth region. The United States, Europe, and Japan struggle with difficult tax and spending decisions because of deep fiscal deficits. These painful decisions, along with reinforcement of market-oriented reforms in China, India, and Brazil, strengthen the foundation for the so-called Long Reset—the rebalancing of global trade and capital flows.

Greenhouse gas (GHG) reductions fall short of aspirations, but the long-term trend •of declining carbon intensity of the global economy continues. In the early 2010s an international agreement is established to limit GHG emissions: the “Good Hope Accords.” But the lack of confidence in the veracity of GHG emissions data leads to questions about commitments and trade distortions. Many fear that “green protectionism” will reverse globalization. Tensions diminish following a 2021 agreement establishing the International Emissions Monitoring Committee (MC). The MC sets standards and collects and vets data on national and global GHG emissions.

Oil demand growth is concentrated in the middle of the barrel.• Nearly half of the total rise in world liquids demand over the outlook period comes from middle distillates—diesel/gasoil and jet fuel, with diesel/gasoil accounting for most of the rise. This partly reflects the sharp increase in transportation of goods during the scenario period, particularly in emerging markets where growth is achieved on the back of




commercial trucking of goods—fueled by diesel. The growth in transportation use of diesel and jet fuel is also a prime driver in raising the transport sector’s share of world oil demand from about 54% in 2010 to 59% by 2030.

Asia, Latin America, the Middle East, Africa, and North America dominate •aggregate growth in oil demand. Along with Asia, the fastest growing demand regions in percentage terms are Latin America, Africa, and the Middle East. Over the longer term (to 2030), IHS CERA expects Asia Pacific oil demand to grow the most in absolute terms in all scenarios (by as much as 718 mt per year [14.36 mbd] above the 2010 level in the high case scenario, Global Redesign), followed by Latin America (maximum growth of 178 mt per year [3.56 mbd]) (see Table A-1).

In contrast, aggregate oil demand in Europe is projected to decline in all three scenarios. In Global Redesign the average annual decline in Europe’s aggregate oil demand between 2010 and 2030 is 0.4% per year, while in Meta it is 1.1% per year, and in Vortex it is 0.9% per year. This general perspective is important, because currently, Eurasian oil exports flow principally into European markets (including both Northwest Europe and the Mediterranean) even though these are among the most saturated of the major world crude markets and are likely to remain so in the outlook period. The combination of relatively flat regional demand and escalating supply from a variety of sources indicates that oil prices in these markets will remain relatively soft (compared with other regional oil markets), increasing incentives for Eurasian producers to access more distant markets.

6.2.1 EUROPE

Imports of Eurasian crude oil. Europe remains the biggest export market for crude oil from Russia, as well as from Kazakhstan and Azerbaijan. Turkmenistan is the exception among the major Eurasian oil producers: its major export market for crude oil has been Iran, but in 2010 most of Turkmenistan’s crude exports went out via the BTC pipeline following an interruption of the swap trade with Iran (see above).

Although Europe is the dominant market for Russian and Eurasian exports of crude, these supplies represent only part of a diverse supply mix for the region as a whole. Imports of Russian crude oil by European refiners (including Poland, Hungary, and the Czech and Slovak Republics) increased steadily during the 2000s. Over 2000–10 the average annual increment for Russia’s crude oil (and gas condensate) exports to Europe was about 7.1 mt (142,000 bd), notwithstanding significant declines in three of these years (2003, 2009, and 2010).

In 2009, the last year for which a total European oil balance can be compiled from IEA data, Europe’s total crude oil demand was 668.3 mt (about 13.37 mbd), met largely with 595.5 mt (11.91 mbd) of imports. With Russian crude and condensate exports to Europe amounting to 177.9 mt (around 3.56 mbd) that year, Russian imports accounted for around 27% of European total demand and 30% of its total crude imports. Almost all European countries with a refining presence have increased their imports of Urals Blend over the past 10 years. However, only Finland and the Central European countries on the Druzhba Pipeline (Poland, Hungary, the Czech Republic, and Slovakia) depend on Russia for a majority of



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their crude requirements. In other European countries, Russian imports currently constitute a more modest share, typically between 15% and 30% of total imports.

Of these imported volumes, approximately 4.8 mt (98,000 bd) was Siberian Light (35.6o API gravity, 0.5% sulfur content) in 2010, and the rest was predominantly medium-sour Urals Blend (32o API gravity, 1.3% sulfur content); Russia also exports some other light crudes and some condensate (about 10.9 mt, or 222,500 bd) that reach European markets. Urals Blend’s increasing market share has been a function of two dynamics: displacement of medium-sour Middle Eastern crudes and an increasing appetite for more sour crude grades generally in Europe as the region’s desulfurization capacity has increased. Given the wide access of different crude grades to both Northwest Europe and the Mediterranean, Urals Blend is not expected to become a dominant feedstock for the area’s refiners in aggregate over the next decade. Rather, it is expected to remain an important, but not dominant feedstock.

Kazakh crude exports to Europe, which are sold primarily in the Mediterranean (although exports via Gdansk and Primorsk are sold in Northwest Europe), comprise a mixture of crude grades, depending upon the particular export route that is used: Urals Blend (for crude transported via Russia’s Transneft pipeline system), CPC Blend (for CPC pipeline exports), and some “neat” crudes exported by rail via Batumi, Kulevi, Odessa, Feodosiya, etc. CPC Blend is a very light, sweet crude (47o API, 0.5% sulfur content) that has been placed in a number of European refineries despite its relatively high yield of gasoline fractions. Azerbaijan’s crude exports comprise Azeri Light, a medium-sweet crude (35–36o API, 0.1% sulfur) that has a relatively high yield of middle distillates. As a result, Azeri Light has been highly desirable for European refiners, and it is typically priced at a slight premium to Brent.

Overall oil demand outlook in base case (Global Redesign). In this scenario, overall European liquids demand falls by 58.2 mt per year (1.16 mbd) during 2010–30. As noted above, the average annual decline rate during the entire scenario period is 0.4%, but demand is relatively flat over 2010–20, falling by only 0.1% on average, while the decline accelerates to 0.3% on average in the second decade of the outlook period, in 2020–30.

The decline in oil demand is particularly pronounced in the case of motor gasoline and fuel oil, the consumption of which declines 1.8% and 1.9% per year, respectively, on average during 2010–30, while the fall in gasoil consumption averages 0.4% per year. There are nevertheless a few significant sources of oil demand growth among the major products within the overall trend of declining oil demand, including LPG (growing at an average annual rate of 0.9%) and jet/kerosene (1.5% average growth per year).

One bright spot for external oil providers in this overall picture is that Europe’s indigenous oil production—principally from the North Sea—is projected to decline steadily, from about 212 mt (4.25 mbd) in 2010 to just 111.5 mt (2.23 mbd) in 2030.

The general European oil demand trends under IHS CERA’s three global energy scenarios include the following key features:




Global Redesign

In the transport sector, the decline trend in energy consumption that began in 2007 turns •out to have been the inflection point, as by 2030 on-road energy use in the European Union falls to the 2004 level.

Growth in energy use by an expanding vehicle fleet is offset by mandated improvements •in vehicle tailpipe carbon dioxide (CO2) standards, resulting in higher vehicle fuel efficiency: An extra 43 million light-duty vehicles (LDVs) are on Europe’s roads by 2030 compared with 2010, but LDV energy consumption is 24% lower.

There is a slowing of the dieselization trend in the LDV fleet, which had developed in •the 1990s, as diesel sales start to trend downward in response to rising diesel prices relative to gasoline prices.

Meta

European energy demand was structurally changed by the severe contraction of the •Great Recession of 2008–09. It never returns to prerecession levels. In the years that follow, EU energy consumption patterns are shaped by a desire to trim Europe’s import dependency and emissions intensity. Fossil fuel demand for transport is a main target of new policies, which show the more hands-on approach European regulators had first adopted in their response to the economic downturn in 2008.

The Low Carbon Transport Directive of 2014 is a sign of the times. Rather than opting •to bring road transport into a market-based cap-and-trade program, the European Union seeks to improve transport energy efficiency by establishing a standard of 60 grams of CO2 per km by 2030.

At the same time, this directive provides further incentives for grid-based electric •vehicles (EVs) throughout the next decade. EU-level funding for individual countries is matched by member states in what proves a successful bid to entice private sector sponsors for these targets. The market acceptance of EVs does not happen overnight, but it progresses far faster than anticipated. By 2020, 12.5% of new vehicle sales in Europe are EVs. One key factor in this progress is the significant reduction in both the cost and size of batteries. As the cost of EVs continues to fall, so too does the competitive edge of petroleum-based fuels. Total oil consumption falls 5.1% between 2020 and 2025 and a further 4.6% in the five-year period that follows.

Vortex

By 2030 total oil demand falls by about 130 mt per year (2.59 mbd). •

Much of this decline is due to a fall in demand for gasoline, which is offset to some •extent by continued growth in demand for diesel and jet fuel as well as continued (albeit gradual) growth in biofuels consumption.



177


6.2.2 NORTH AMERICA

Imports of Eurasian crude oil. Eurasian crude is occasionally shipped to the North American market at the present time, where it competes with many varieties of medium-sour crudes, both domestic and foreign grades. Small amounts of condensate also are shipped to the US Gulf Coast from Vitino, a port that evacuates into the Atlantic Basin via the Barents Sea. Imports of Russian crude by the United States and Canada were in the range of about 2–8 mt per year (40–160,000 bd) during the past five years, with a volume of 8.2 mt (164,000 bd) in 2010, boosted somewhat by ESPO volumes going to Hawaii and the West Coast. Larger volumes of Eurasian crude oil exports into the United States will depend on availability and increased use of deepwater ports which can accommodate large crude tankers (and therefore reduce per-barrel transatlantic freight rates).

There are nevertheless logistical challenges in addition to the transatlantic passage. Several refineries in eastern Canada are able to accommodate VLCCs, but draft restrictions in US East Coast crude oil ports prevent direct offloading of conventional VLCCs, although “wide beam” VLCCs currently operate in this service. Overall, the US East Coast and eastern Canada appear to be promising markets for light, sweet crude streams, and these regions are already a common destination for West African and North Sea supplies. In contrast, the US Gulf Coast and Mid-Continent refiners will continue to increase integration with heavier supplies from Mexico, Venezuela, and western Canada. These refineries may be a market for medium-sour crude exports from Eurasia, such as Urals Blend, or for light crudes/condensates to use as blendstocks.

Overall oil demand outlook in base case (Global Redesign). Although the rate of annual demand growth is relatively low in North America (defined as the United States, Canada, and Mexico), at only 0.2% (compared with the world average of 1.2%), North America is nevertheless a significant growth market in volume terms because of its sizable consumption base in 2010. Total North American liquids demand growth over 2010–30 amounts to 58.5 mt per year (1.17 mbd).

Throughout the scenario period the single largest component of North American oil demand remains motor gasoline (accounting for about 39% of total North American liquids consumption in 2030), but demand for this product nevertheless declines at an average annual rate of 0.5%. In contrast, the chief driver of the moderate overall increase in oil consumption over 2010–30 is LPG (for which demand rises at an average annual rate of 1.9%), followed by gasoil (with an average per-year rise of 1.1%).

North America’s general oil demand trends and issues under IHS CERA’s three different global energy scenarios are as follows:

Global Redesign

North American petroleum demand recovers modestly from the Great Recession lows •of 2008–09 but never returns to the peak levels reached in 2005. US and Canadian oil demand (including for biofuels) increases from 2010 to 2015 but then flattens out through 2030. The key driver of this “peaking” in US and Canadian oil demand is the




decline in US gasoline demand. In contrast, in Mexico, where per-capita consumption began from a much lower base, oil demand growth is continuous.

Several key forces lead to the continued decline in gasoline demand for North America •overall. After the US and Canadian fuel economy targets for 2016 are met, new, more stringent standards are gradually phased in from 2020 to 2030. By 2030 the average new passenger vehicle is able to meet a standard of about 21 km per liter (or 50 miles per gallon [mpg]). Substantial improvements in internal combustion engine (ICE) vehicle efficiency and a shift to smaller, lighter vehicles account for much of the gain, although EVs, including plug-in hybrid electric vehicles (PHEVs), are also a key tool for automakers to meet the standard.

Demographics also play a role in reducing demand for gasoline. The aging of the •baby boomer population in the United States has a dampening effect on transportation fuel demand as the number of commuting miles rises more slowly than in the past. Biofuel consumption rises steadily, although at a slower pace than in the boom years of 2005–10. The growth is lower because the government enforces its cap on production of corn-based ethanol; commercial volumes of ethanol and other biofuels produced from cellulosic plant material do not materialize until 2020, and then only in very modest volumes.

Most of the increase in North American oil demand is the result of higher diesel •consumption, as the heavy trucking fleet expands to deliver freight in a modestly growing economy. Demand for jet fuel also grows in tandem with the economy, albeit at a slower pace, as increases in airline efficiency are offset by rising demand for both passenger and freight airline system miles.

Meta

Personal mobility technology in North America undergoes a revolutionary transformation •following the rapid escalation of world oil prices in the aftermath of the Great Recession. In 2010 there were virtually no EVs (including PHEVs) on the roads. By 2030 sales of EVs make up 40% of all new passenger vehicle sales and reach 20% of the US LDV passenger fleet. The rise of grid-based vehicles, improvements in ICE efficiency, and greater biofuels consumption are the key reasons that North American gasoline demand falls from 2010 to 2030.

The US and Canadian governments continued to see biofuels as a key tool in their efforts •to shift the transport sector away from petroleum. In particular, the US government significantly raises the allowable volume of corn-based ethanol in the US Renewable Fuels Standard mandate. At the same time, the US and Canadian governments progressively increase the allowable volume of imported Brazilian sugarcane-based ethanol. During the first decade of the scenario, high oil prices support the economics of developing next-generation biofuels produced from cellulosic plant material, but production volumes fall substantially between 2025 and 2030 following a decline in world oil prices at this time.



179


Vortex

The strong rise in oil prices from 2010 through 2012 contributes to the tepid recovery •of North American oil demand in the wake of the Great Recession of 2008–09. US motorists are spooked by the rapid rise in pump prices and the reappearance of $4 per gallon gasoline in 2012. Many drivers feel resigned to the probability that pump prices will only head higher in the years to come, driven by rising oil demand in China and the rest of the developing world. In similar fashion to the previous price spike in 2008, many motorists across the region cut back on discretionary driving. Ridership in mass transit rises. Smaller cars increase in popularity at the expense of sport-utility vehicles and other light trucks, whose sales suffer. North American gasoline demand falls sharply in 2012–13, as it had in 2008.

With the onset of the “Second Great Recession,” North American oil demand again •stagnates; by 2015 demand is about 5% lower than its peak in 2005. Reinforcing the weak demand trend are the higher fuel economy standards being phased in during this period.

6.2.3 ASIA PACIFIC

Imports of Eurasian crude oil. The Middle East will undoubtedly take the lion’s share of the Asia Pacific region’s rising oil import requirements going forward, but growth opportunities are certainly available for other crude producers, including those in Eurasia. This is particularly relevant given that the quality issue will remain problematic for many Asian refiners because of limited secondary processing capacity, so their main demand will be for light, sweet crudes, whereas Middle Eastern crudes are predominantly heavy and sour.

The Asia Pacific region’s consumption of Russian crude oil has grown sharply in recent years, but starting from a very small base. From a trickle of just 0.6 mt (12,000 bd) in 1995, Russia’s exports of crude oil to Asia Pacific destinations reached 35.4 mt (708,000 bd) in 2010, of which China accounted for 12.8 mt (256,000 bd), or about 36% of that total. With the start-up of the ESPO Skovorodino-Daqing spur in January 2011, most of China’s imports of Russian crude will be delivered via this pipeline. In the first eight months of 2011, about 10 mt (300,000 bd) out of 10.4 mt (312,000 bd) of Russian exports to China (i.e., 96.2%) were delivered via the ESPO spur; practically all of the remaining Russian volumes were delivered from Sakhalin or Kozmino. Pipelines have also accounted for the vast majority of crude exports from the other major Eurasian source of Chinese imported oil, Kazakhstan, since the start-up of the Atasu-Alashankou pipeline in 2006, displacing almost entirely the flow of rail-based exports of previous years. In 2010 this pipeline carried all of Kazakhstan’s crude exports to China, which amounted to 7.5 mt (150,000 bd).

Large-scale utilization of the long sea route from the Baltic or Black Sea for Eurasian crude to Asia Pacific markets is problematic because of the restrictions on tanker size imposed by the Danish Straits, the Turkish Straits, and the Suez Canal. Some Russian Urals Blend crude was traditionally shipped to Asian markets, including China’s Dalian port, via tankers from Russian Baltic and Black Sea ports (Primorsk or Novorossiysk) and also from Poland’s Gdansk port by various traders: this was as much as 5 mt (100,000 bd) in 2005 before




the start-up of the ESPO pipeline.* Eurasian shipments via the Black Sea may compete effectively with ESPO flows, depending on the longer-term Transneft tariff structure.** Although the current ESPO tariff arrangement amounts to a major cross-subsidization of ESPO deliveries through relatively high tariffs on Transneft’s western pipeline routes, if ESPO tariffs eventually approach the ESPO cost-recovery level, Russian crude exports from western ports to Asian markets would become more competitive.***

Overall oil demand outlook in base case (Global Redesign). The rise in Asia Pacific oil demand, by 718 mt per year (14.36 mbd) overall by 2030, or an average annual increase of 2.2%, is concentrated primarily in the first decade of this scenario. Annual oil demand grows by 2.8% on average during 2010–20 but by just 1.5% on average over 2020–30.

The primary sources of demand growth among the major products are gasoil (average per-year growth during 2010–30 of 2.8%) and motor gasoline, which accounts for smaller incremental volume growth than gasoil but nonetheless eclipses all other major products in rate of growth (3.2% per year on average).

Global Redesign

In 2030 Asia Pacific accounts for 37% of global oil consumption.•

China and India stand out as the key growth markets for oil and refined petroleum •products. Although public transportation expands significantly in these countries between 2010 and 2030, as incomes rise the desire to own a car becomes a powerful force in transportation energy demand.

Though gasoline and diesel vehicles still dominate the market, PHEVs start to make •inroads into vehicle sales, especially in China and Japan. By 2030 EVs, PHEVs, and battery electric vehicles represent close to 20% of Asia’s new LDV sales. However, the strong hold that gasoline vehicles have on the transport market leads to continued growth in gasoline consumption, despite tighter fuel economy regulations.

*The Gdansk shipments typically involve only partial loading of a VLCC in the Polish port, so the tanker can get through the Danish Straits, and then topping up with oil or products in Rotterdam or ship-to-ship transfers off the Danish coast outside the straits. Some of these long-distance shipments, including some that go across the Atlantic to North America, involve ship-to-ship transfers from smaller tankers to VLCCs, such as at Scapa Flow (Orkneys) or Kirkenes (Norway). The amount going to China dropped significantly in 2008 as the key operator at Gdansk, Mercuria, lost its contract to supply Sinopec with up to 120,000 bd. This seaborne flow dropped to only about 1.6–1.7 mt (33,000 bd) in 2008.**For the time being, Transneft charges a single “network” tariff for all ESPO shipments (either Taishet-Skovorodino or Taishet-Kozmino), now set at around $65 (1,870 rubles) per ton. In contrast, the minimum cost-recovery tariff for ESPO-1 is estimated at $119 per ton (with $15 billion capex), without rail costs to Kozmino (Transneft has estimated real costs for those shipments at about $130 per ton). In 2000–11 Transneft was allowed to sharply hike tariffs on westward export routes to help finance the ESPO project and keep tariffs on ESPO shipments low enough to attract oil needed to fill pipeline.***Industry observers have estimated that tanker shipments of Russian crude from western ports to Asian markets cost about US$52.60 per ton (US$7.20 per barrel) in 2007 (when tanker freight rates still remained fairly high), to which must be added the costs of transport from Russia’s producing fields to the ports; i.e., about US$27 per ton (US$3.70 per barrel) from West Siberia in 2007. This is slightly more than the 2009 cost of rail deliveries to China of about US$15 per ton (US$2.05 per barrel] from West Siberia to Angarsk via Transneft, plus US$51.90 per ton (US$7.11 per barrel] for the rail segment to Zabaikalsk (i.e., a total of US$66.9 per ton) or the 2011 cost via ESPO to Skovorodino of US$90.2 per ton ($24.5 per ton from West Siberia to Taishet+$65.7 per ton on ESPO).



181


An expansion of the heavy trucking sector means continued strong growth in diesel •demand. Across Asia tighter restrictions on fuel product specifications drive up demand for low-sulfur diesel and also provide the commercial incentive for investments in GTL plants.

Meta

The big story in Asian energy demand under the Meta scenario is the change in •transportation patterns driven by the swift and sizable deployment of grid-based vehicles, which in turn is made possible by improvements in battery life, weight, power, and cost. The degree of penetration of grid-based vehicles in the domestic transportation markets varies across the region. By 2030 nearly half of the LDV sales in China are of electricity-powered vehicles. On average across the region, grid-based vehicles account for 40% of new vehicle sales in 2030. However, taking into account the full spectrum of light- and heavy-duty vehicles, petroleum-based fuels still meet the largest share of transport energy requirements.

By 2030 total fuel demand in Asia Pacific ends up lower than many expected in •2010 because of significant strides made in efficiency. New vehicles become smaller, and conventional ICE efficiency improves to over 23 km per liter (55 mpg) by 2030. Additionally, growing urbanization and better access to public transport helps trim the growth in car ownership. In some markets, such as Japan, car ownership levels do not increase at all.

Vortex

Total oil consumption for the region grows by about 39% between 2010 and 2030. •However, oil’s share of total primary energy falls from around 26% to 23% in the region, driven primarily by comparatively slower demand growth for oil in the OECD countries of Asia.

Asia’s transport sectors remain very dependent on the conventional ICE and traditional •petroleum fuels such as gasoline and diesel. Asian natural gas prices remains linked to oil prices; therefore, the volatility in oil and gas prices during the period hampers the expanded use of compressed natural gas in transport. However, strong refined product prices in the early 2020s and through the end of the scenario period feed policy and market incentives toward greater demand for the use of battery-powered cars than had been projected in 2010, particularly for China and Japan.

6.2.4 MEDITERRANEAN REGION

The Mediterranean region is not one of the geographic regions employed in IHS CERA’s global analysis of oil supply and demand. The region includes portions of other regions employed by IHS CERA (Europe, Africa, the Middle East, and even Eurasia if the Black Sea littoral is also included). As a result, IHS CERA does not have a specific quantitative outlook that covers the entire region. Still, we can assess the general situation for the Mediterranean from available information aggregated from selected country statistics.




An important issue is assessing the future absorption capability for Eurasian crude in the Mediterranean market, including potential for further displacement of other crudes. If there is ample room for further absorption of Eurasian crudes within the Mediterranean (either from organic growth or via displacement), then the attractiveness of exports into the Mediterranean is higher vis-à-vis other markets for Eurasian crude. This also affects an important tanker issue: how valuable long-haul shipments (via VLCC or Suezmax tankers) from the Mediterranean might become. The value of such long-haul shipping possibilities is less than if substantial volumes of incremental crude must go beyond the Mediterranean to find markets. The additional issue of protecting netbacks to existing (Mediterranean) markets by adding in some long-haul shipments (even if sufficient market space is available to place it, albeit at a discounted price) must also be taken into account.

The Mediterranean constitutes the largest market destination for Eurasian crude oil, and traditionally nearly all Eurasian crude arriving in the region stayed there, but this is evidently becoming less true for Caspian oil (see the box “Ex-Med Long-haul Eurasian Crude Flows”). In 2010, according to customs statistics, Russia exported 41.3 mt (826,000 bd) of crude to Mediterranean countries (including Austria, but not Germany), representing about 19% of Russia’s total non-FSU exports. This volume is up substantially from only 26.8 mt (536,000 bd) to these same countries in 2000. For Kazakhstan, however, the share of Mediterranean exports has dropped over the past decade, main reflecting the rise of China as an export destination. The share of Mediterranean countries as destinations for Kazakhstan’s non-FSU crude exports has dropped steadily over the past decade, from 85% in 2000 to 71% in 2006 to only 49.5% in 2010.

But Eurasian crudes still represent only a minor share of the Mediterranean region’s overall diversified crude supply and therefore are competing against many other crude streams for what limited incremental demand may emerge in coming years. The Mediterranean crude market is particularly strongly contested and is anticipated to have access to increased supply from a variety of sources in the future in addition to Eurasia: local producers (chiefly Libya and Algeria), Iraq, and via both the Suez Canal and Sumed (Suez-Mediterranean) pipeline, Saudi Arabia, Iran, and other Gulf producers.

Oil demand in the Mediterranean region was essentially stagnant overall during the past decade: aggregate crude oil demand (or available domestic supply) in the region was 398.5 mt (7.97 mbd) in 2000 and reached 410.6 mt (8.21 mbd) in 2005 but subsequently declined to 370.1 mt (7.4 mbd) in 2009 (see Table VI-1).* During the decade of the 1990s oil demand increased by only about 12% overall (an average of 1.2% per year), so growth has been relatively slow or nonexistent for the Mediterranean region as a whole for some time.

This largely reflects relatively low growth for the region as a whole in aggregate (final) product demand, similar to the broader European region discussed above. Because most of the region’s incremental demand is concentrated in middle distillates, the region suffers from the typical European distillates deficit combined with a gasoline surplus. Furthermore,

*This is not quite the Mediterranean region proper, but rather an aggregate of 17 countries along the Mediterranean littoral: Albania, Algeria, Austria, Croatia, Egypt, France, Greece, Israel, Italy, Lebanon, Libya, Morocco, Serbia, Spain, Syria, Tunisia, and Turkey. It does not include (southern) Germany, even though that region’s crude oil supply is procured via the Mediterranean.



183


Ex-Med long-Haul Eurasian Crude Flows

evidently because of the other export routes available to Russian producers to reach other markets, most of the Russian crude physically exported into the Black Sea and Mediterranean still tends to remain in the region. that is, if Russian exporters sell to non-Mediterranean markets, they do not use the Black Sea routes to access them. this is apparently not the case for Kazakhstan and azerbaijan, probably because they have fewer physical options other than the Black Sea/Mediterranean to start with. in 2010, for example, over 90% of Russian crude physically exported via the Black Sea was delivered to countries in the Mediterranean region. this high proportion has been fairly consistent over the past decade, with the exception of 2002–04 when the share dropped to only about 70%. this probably reflected Yukos’s activities during that period to dispose of its rapidly growing oil exports and also its ambitions to emerge as a true global oil player.

in contrast, in the case of Kazakhstan the trend has been for an increasing amount of crude to go “ex-Med” over the past decade. the share of Kazakh crude physically exported via the Black Sea that is delivered to Mediterranean countries has declined from 90%–100% in 2000–03 to 84% in 2005, 81% in 2009, and only 66% in 2010. Much of this has been to non-Mediterranean european countries (i.e., to Northwest europe).

a similar trend has emerged for azeri exports out of ceyhan. the situation at ceyhan sheds light on how changing market dynamics can alter transportation logistics (specifically, the tanker configuration) and also indicates the sort of long-haul markets for eurasian oil that would available to shippers from Mediterranean ports. as noted above, Mediterranean markets have traditionally been the destination for the vast majority of azeri crude exports (including the largest component, the Btc crude stream exported from ceyhan). over time, however, as regional markets have become more saturated (and as long-haul tanker rates have dropped), a growing share of total exports from ceyhan has been sent to markets outside the Mediterranean, particularly in the asia pacific region and North america.

this shift is reflected in the changing tanker configuration, with Vlccs utilized every year from 2007 through 2010 (whereas none were employed in the first year of the terminal’s operation in 2006 and none so far in 2011). although ceyhan is equipped to load two Vlccs simultaneously (and was evidently designed to include up to 20% of its annual loadings in Vlccs), for more than half a year after ceyhan began operations in June 2006 crude was shipped exclusively on Suezmax or smaller tankers. it was not until February 2007 that the first Vlcc was loaded at ceyhan (carrying 2 million barrels [272,000 tons] of azeri light from Statoil, apparently destined for South Korea). Most, if not all, of the other Vlccs loaded at ceyhan have also presumably shipped oil to long-haul markets (even though all Mediterranean ports except Venice can handle Vlccs, the maximum transportation savings possible with Vlccs are realized via ex-Med shipments). the share of Vlccs in total tanker shipments from ceyhan has nevertheless remained very small, averaging only 2.8% in 2007–11, for which data are available, though the share of all oil carried by Vlccs during this same period was significantly higher, at 6.4% (see table Vi-2).

even more striking is the trend toward increased utilization of Suezmaxes at the expense of the share in total shipments of the smaller aframaxes. in 2009 the Suezmax share of total vessel shipments jumped to 68.3%, compared with 47.5% in 2008 (while the share of oil carried by Suezmaxes increased to 71.7%, from 53.9% in 2008) and the Suezmax share has been similar during 2010–11. although details on all of the Suezmax destinations are lacking, there is compelling circumstantial evidence that much of the incremental Suezmax deliveries are predominantly long haul. For instance, during January 2009, the record month so far for transatlantic exports from ceyhan (during the period for which data are available), shipments




local crudes are poorly adapted to changing product demand requirements. The region needs to make more middle distillates, but local crude supply is evolving to yield naturally less distillates.

At the same time, it is important to bear in mind that the Mediterranean comprises three distinct subregions with quite different supply and demand profiles, and new Eurasian crude streams may well find additional niche markets in the areas that remain most dependent on imports; i.e., OECD Europe (accounting for 61% of regional refining capacity) and the Balkans (13% of refining capacity). In contrast, refineries of the southern (North African) Mediterranean region (26% of regional refining capacity) rely primarily on local crude production and therefore are relatively unlikely destinations of significant Eurasian crude flows.

The outlook for the fundamentals of the Mediterranean market reflects the traditional north-south division of the region. The lack of unity between the different parts of the Mediterranean is due in large part to different levels of economic development and to demographic trends. Several trends are discernible, and each of them will have a strong impact on the demand for crude oil, and on the refining industry:

The northern Mediterranean oil picture (European portion), not surprisingly, is similar •to the one described above for Europe overall. The southern countries of the European Union (e.g., Spain, Portugal, and Greece) have traditionally had a more dynamic oil sector, with a demand outlook somewhat more bullish than elsewhere within Europe, but the southern-tier EU countries were particularly hard hit by the Great Recession, and the speed of their recovery remains uncertain.

The picture for the northern countries in the region (especially France, Italy, –and Austria) includes high taxes, growing fuel efficiency, and substitution

Ex-Med long-Haul Eurasian Crude Flows (continued)_

amounted to 805,000 tons, but only one Vlcc loaded at ceyhan during the month. the implication is that most of these long-haul cargoes were carried by Suezmax tankers, perhaps reflecting the restrictions on tanker size through the Suez canal for oil shipments heading for asian markets. the drop in overall freight rates since 2009, which has narrowed the differential between tanker classes, has provided a further impetus to long-haul traffic and has reduced the cost savings from Vlccs on such voyages as well.

Data available for the period November 2008 through February 2009 show both a sharp jump in the volume of long-haul shipments overall and a growing share of such shipments to asia pacific markets. Whereas asia pacific destinations took less than half the long-haul ceyhan cargos in November 2008 (roughly 200,000 tons out of a total of around 500,000 tons, with the remainder going transatlantic), in February 2009 the asia pacific share of the total greatly exceeded that of other destinations (around 900,000 tons, compared with transatlantic shipments of about 500,000 tons).



185


Tab

le v

I-1

Med

iter

rane

an R

egio

n O

il B

alan

ce(th

ousa

nd m

etric

ton

s)

cR

UD

e o

il

ave

rage

a

nnua

l pct

. c

hang

e19

9019

9119

9219

9319

9419

9519

9619

9719

9819

9920

0020

0120

0220

0320

0420

0520

0620

0720

0820

0920

00-2

009

pro

duc

tion

188,

118

200,

287

197,

627

195,

050

196,

287

198,

889

197,

040

194,

687

196,

778

186,

893

183,

046

180,

074

182,

537

201,

059

202,

966

208,

317

208,

757

206,

101

206,

932

188,

193

0 im

por

ts26

0,26

0 25

3,71

0 26

5,60

7 26

7,46

1 26

8,99

6 27

6,50

5 28

2,26

2 29

6,02

7 31

0,99

9 28

9,86

0 29

7,83

6 30

0,03

0 29

2,25

3 30

1,91

9 30

7,28

0 31

1,03

7 30

7,62

8 30

6,98

1 30

0,06

9 26

5,87

8 (1

)e

xpor

ts(1

03,7

50)

(108

,743

)(1

08,6

94)

(105

,986

)(1

06,7

96)

(105

,913

)(1

04,0

59)

(99,

867)

(103

,992

)(9

4,52

6)(9

7,60

3)(9

3,36

3)(9

6,85

5)(1

09,8

43)

(118

,170

)(1

28,6

51)

(128

,730

)(1

24,6

68)

(123

,933

)(1

02,9

83)

1 S

tock

cha

nges

1,11

8 3,

636

(1,1

20)

1,50

1 3,

210

(596

)1,

607

(134

)(5

49)

2,76

7 24

5 3,

201

5,50

1 (1

,961

)1,

654

3,77

1 62

7 1,

937

1,05

0 89

0 D

omes

tic s

upp

ly34

5,74

6 34

8,89

0 35

3,42

0 35

8,02

6 36

1,69

7 36

8,88

5 37

6,85

0 39

0,71

3 40

3,23

6 38

4,99

4 38

3,52

4 38

9,94

2 38

3,43

6 39

1,17

4 39

3,73

0 39

4,47

4 38

8,28

2 39

0,35

1 38

4,11

8 35

1,97

8 (1

)tr

ansf

ers

0 0

0 0

0 0

0 0

0 (1

)0

0 0

0 0

0 0

0 0

0 S

tatis

tical

diff

eren

ces

(378

)76

7 (2

56)

(74)

(186

)(1

,488

)(2

,216

)(7

58)

(292

)86

1 (1

,751

)11

8 (9

08)

936

712

955

(143

)(4

05)

152

1,26

9 tr

ansf

orm

atio

n se

ctor

344,

285

348,

463

351,

564

356,

825

360,

194

366,

138

373,

445

388,

944

401,

881

384,

732

380,

684

389,

050

381,

242

391,

249

393,

514

394,

536

387,

508

389,

400

383,

598

352,

576

(1)

Nat

UR

al

Ga

S l

iQU

iDS

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

pro

duc

tion

26,5

66

26,3

69

26,1

37

26,4

32

25,6

12

25,5

87

26,3

01

27,3

75

27,7

91

29,0

44

30,8

64

31,0

80

30,4

54

29,9

73

28,7

98

29,9

32

29,6

40

30,0

43

30,1

34

28,4

71

(1)

imp

orts

0 0

0 0

0 0

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135

21

6 86

18

6 53

25

0

298

50

1 35

19

e

xpor

ts(1

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3)(1

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6)(1

6,89

2)(1

6,80

9)(1

5,70

4)(1

5,61

7)(1

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7)(1

6,03

8)(1

5,53

6)(1

5,32

5)(1

5,92

0)(1

5,60

3)(1

4,79

1)(1

3,85

2)(1

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3)(1

3,81

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3,36

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0 0

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Dom

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16

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)(8

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)(8

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)(9

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)(1

0,14

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5)(1

1,94

8)(1

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9)(1

2,67

7)(1

2,43

2)(1

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8)(1

1,96

2)(1

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4)(1

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0)(1

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3)(1

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3)(1

)S

tatis

tical

diff

eren

ces

(1)

0 0

0 0

0 0

0 0

(34)

(7)

(40)

102

(33)

(29)

(18)

(31)

(22)

(20)

(322

)47

tr

ansf

orm

atio

n se

ctor

1,10

5 1,

130

1,14

4 1,

366

1,40

6 1,

381

1,50

5 1,

731

1,94

9 2,

742

2,64

1 2,

899

3,25

8 3,

677

3,24

3 4,

124

5,27

2 5,

429

5,24

5 6,

559

10

cR

UD

e o

il a

ND

Nat

UR

al

Ga

S l

iQU

iDS

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

pro

duc

tion

214,

684

226,

656

223,

764

221,

482

221,

899

224,

476

223,

341

222,

062

224,

569

215,

937

213,

910

211,

154

212,

991

231,

032

231,

764

238,

249

238,

397

236,

144

237,

066

216,

664

0 im

por

ts26

0,26

0 25

3,71

0 26

5,60

7 26

7,46

1 26

8,99

6 27

6,50

5 28

2,26

2 29

6,02

7 31

1,13

4 28

9,88

1 29

7,84

2 30

0,11

6 29

2,43

9 30

1,97

2 30

7,30

5 31

1,03

7 30

7,92

6 30

7,03

1 30

0,07

0 26

5,91

3 (1

)e

xpor

ts(1

20,8

73)

(125

,879

)(1

25,5

86)

(122

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22,5

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(121

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)(1

20,3

76)

(115

,905

)(1

19,5

28)

(109

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)(1

13,5

23)

(108

,966

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46)

(123

,695

)(1

31,7

53)

(142

,462

)(1

42,0

94)

(137

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36,9

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tock

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1,11

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636

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20)

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210

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)1,

606

(144

)(5

47)

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7 24

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187

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3,77

3 63

1 1,

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010

Dom

estic

sup

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355,

189

358,

123

362,

665

367,

649

371,

605

378,

854

386,

833

402,

040

415,

628

398,

744

398,

469

405,

491

399,

299

407,

346

408,

971

410,

597

404,

860

407,

542

401,

266

370,

072

(1)

tran

sfer

s(7

,872

)(8

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)(8

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)(1

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tatis

tical

diff

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ces

(379

)76

7 (2

56)

(74)

(186

)(1

,488

)(2

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)(7

58)

(292

)82

7 (1

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)78

(8

06)

903

683

937

(174

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27)

132

947

tran

sfor

mat

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sect

or34

5,39

0 34

9,59

3 35

2,70

8 35

8,19

1 36

1,60

0 36

7,51

9 37

4,95

0 39

0,67

5 40

3,83

0 38

7,47

4 38

3,32

5 39

1,94

9 38

4,50

0 39

4,92

6 39

6,75

7 39

8,66

0 39

2,78

0 39

4,82

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8,84

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Reg

iona

l Net

imp

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(im

por

ts -

exp

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7 12

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1 14

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1 14

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6 14

6,49

6 15

4,97

5 16

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6 18

0,12

2 19

1,60

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0 18

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0 18

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3 17

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5 16

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)R

egio

nal N

et im

por

ts

(Dom

estic

Sup

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pro

duc

tion)

140,

505

131,

467

138,

901

146,

167

149,

706

154,

378

163,

492

179,

978

191,

059

182,

807

184,

559

194,

337

186,

308

176,

314

177,

207

172,

348

166,

463

171,

398

164,

200

153,

408

(2)

Sou

rce:

iHS

ce

Ra

, ie

a.

Not

e: N

Gls

are

the

liq

uid

or

lique

fied

hyd

roca

rbon

s p

rod

uced

in t

he m

anuf

actu

re, p

urifi

catio

n, a

nd s

tab

iliza

tion

of n

atur

al g

as. t

hese

are

tho

se p

ortio

ns o

f nat

ural

gas

whi

ch a

re r

ecov

ered

as

liqui

ds

in s

epar

ator

s, fi

eld

fa

cilit

ies,

or

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pro

cess

ing

pla

nts.

NG

ls in

clud

e, b

ut a

re n

ot li

mite

d t

o, e

than

e, p

rop

ane,

but

ane,

pen

tane

, nat

ural

gas

olin

e an

d c

ond

ensa

te.




Tab

le v

I-2

Dis

trib

utio

n o

f S

ched

uled

Cey

han

Cru

de

Oil

Tank

er S

hip

men

ts a

nd E

xpo

rt v

olu

mes

by

vess

el S

ize:

200

7–20

11(in

per

cent

of a

nnua

l tot

als)

i. D

istr

ibut

ion

of c

rud

e ta

nker

s le

avin

g c

eyha

n b

y Ve

ssel

Siz

e

tank

er S

ize,

DW

t20

071

2008

2009

2010

2011

2

tota

l Ves

sels

(num

ber

)23

833

536

036

018

1

>20

0,00

08.

41.

82.

80.

80.

010

0-14

0,00

040

.347

.568

.371

.465

.265

-80,

000

50.4

49.6

28.6

27.8

33.1

50-6

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00.

81.

20.

30.

01.

7

ii. D

istr

ibut

ion

of c

rud

e e

xpor

t Vo

lum

es fr

om c

eyha

n b

y Ve

ssel

Siz

e

tank

er S

ize,

DW

t20

071

2008

2009

2010

2011

2

tota

l loa

din

gs (m

illio

n to

ns)

27.9

936

.90

39.8

938

.64

18.7

6

>20

0,00

018

.54.

46.

82.

10.

010

0-14

0,00

046

.353

.971

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.572

.365

-80,

000

34.8

41.1

21.3

21.4

26.8

50-6

5,00

00.

40.

60.

20.

00.

9

ave

rage

Siz

e lo

adin

g (th

ousa

nd t

ons)

117.

611

0.1

110.

810

7.3

103.

6

Sou

rce:

com

pile

d b

y iH

S c

eR

a fr

om p

ublis

hed

mon

thly

load

ing

sche

dul

es (N

efte

com

pas

s; N

efte

tran

spor

t).

1. B

ased

on

dat

a fo

r Fe

bru

ary

thro

ugh

Dec

emb

er; c

omp

lete

dat

a fo

r th

e p

revi

ous

mon

ths

of t

he t

erm

inal

’s o

per

atio

n, s

tart

ing

in J

une

2006

, is

unav

aila

ble

. 2.

Jan

uary

thr

ough

Jun

e.



187


(by biofuels or electricity), which are likely to keep aggregate oil demand in check over the outlook period.

The other EU countries within the Mediterranean region (e.g., Spain, Portugal, –Greece, Bulgaria, Romania, and Croatia) are likely to follow generally similar policies as their northern neighbors. But due to structural factors related to the underlying growth potential of their economies, at least some of them will likely register some growth in oil demand, notably in transportation fuels. We believe that moderate demand growth will be achieved (perhaps as much as 1% per year in the high scenario for some of the countries) and will be concentrated largely in diesel and some in gasoline. But there will also be some displacement of fuel oil by natural gas that will depress aggregate oil demand growth.

The prospects for the southern and eastern shore of the Mediterranean are quite •different, especially given the rising demand for products, which is a consequence of economic and demographic changes. The demographic transition in these countries is under way, but population growth will remain relatively high in the next two decades. Thus, even if oil consumption per capita does not increase dramatically, the overall increase in population will keep oil demand growth rates higher than elsewhere in the Mediterranean. To meet rising product demand, the refining industry also is expanding, which is generating a need for more crude.

These trends in demand will have a strong impact on the refinery industry, and each of them will have a different set of consequences:

In the European portion of the region, refining operations are expected to decline •because of several factors:

Low growth or decline in aggregate product demand –

Displacement by natural gas of much of fuel oil demand, so upgrading units –are likely to be installed to enable the production of more light products from smaller crude throughputs

The growing presence of biofuels and other substitutes for refined –products

The refining outlook on the eastern and southern shores of the Mediterranean is quite •different, given the region’s more buoyant need for products. New refining capacity and higher utilization rates will push crude run levels up. Importantly, these higher runs will decrease the traditional product deficit present in this part of the region (traditionally met with supplies from the European refineries within the Mediterranean).

In terms of supply, overall production of crude and NGLs was stable during 2000–09. Notwithstanding a significant decline in 2009 (a sign of the negative impact of the Great Recession on demand for regional oil), production in that year was still 1.3% higher than in 2000 and totaled 216.7 mt (4.33 mbd) (see Table VI-1). The oil output of Libya, the




largest producer in the region prior to the 2011 internal uprising and conflict, depends on political stabilization and the extent of damage to oil industry facilities (both of which remain uncertain). In a best case scenario, IHS CERA concludes that a ramp-up to pre-rebellion levels of about 80 mt per year (1.6 mbd) is possible by sometime in the second half of 2013. Longer term, significant additional growth is likely, and in the Global Redesign scenario Libya produces around 110 mt (2.2 mbd) by 2030, for an average annual increase during 2010–30 of about 1.3%. Production in Algeria, the second largest producer in the region after Libya historically, will probably continue to rise, albeit slowly, in the next two decades, and our base case is for average annual Algerian production growth of 0.1% over 2010–30. Egypt, the third largest oil producer in the region historically, managed to reverse a long-standing production decline in 2008–09, apparently thanks to a number of new oil discoveries brought onstream, but output slipped again in 2010 and our base case scenario for 2010–30 is for an average per-year decline of about 3%. In Syria the picture is also one of moderate decline, averaging 4.2% per year, continuing a downward trend that has been present for over a decade now, albeit occasionally interrupted by temporary increases in annual production, as during 2009–10.

The combination of stagnant demand and sizable production growth resulted in a contraction in net import requirements for the Mediterranean region overall during the past decade. The net crude import requirement (the difference between production and primary demand) has shrunk from a peak (during the 2000s) of around 194.3 mt (3.89 mbd) in 2002 to 153.4 mt (3.07 mbd) by 2009 (see Table VI-1). With relatively stable or increasing overall crude oil output (following the recovery of Libyan production) and fairly flat demand going forward for the region as a whole, net import requirements will continue to contract or flatten out for the foreseeable future.

The Mediterranean crude oil market is already strongly contested, but over the next decade the competition in the Mediterranean may be ratcheted up several notches. Currently Iranian and Saudi Arabian barrels compete with Russian oil (and Egyptian and Syrian crudes to a lesser degree) in the Mediterranean and with North Sea barrels in Northwest Europe. Besides local production, more Iraqi crude oil will likely enter the Mediterranean via the Iraqi-Turkish pipeline system and more crude oil exports out of Eurasia (especially Kazakhstan) are likely (see above). The combined effect of higher volumes of Iraqi crude and more oil from the Former Soviet Union would add to the already existing fierce competition for the available crude oil demand of the Mediterranean.

An important question is whether Saudi Arabia, Iran, and others will continue to use the Sumed pipeline system and the Suez Canal to move crude oil into the Mediterranean market as well. Traditionally over the past two decades, much of Saudi Arabia’s northbound oil shipments were transported through the Sumed pipeline.* The Sumed system has a throughput capacity of 117 mt per year (2.53 mbd) as a result of a capacity increase completed in 1994. The pipeline transported 105 mt (2.1 mbd) in 2008, about 52 mt (1.1 mbd) in 2009, and 54

*The 200-mile (320-km) long pipeline system (comprising two parallel 42 in [1,070 millimeter] strings), which like the Suez Canal lies entirely within Egyptian territory, provides an alternative to the Suez Canal for crude oil shipments. The pipelines flow north from Ain Sukhna, located on the Red Sea coast, to Sidi Kerir on the Mediterranean. The Sumed pipeline is owned by Arab Petroleum Pipeline Company, a joint venture between the Egyptian General Petroleum Corporation (EGPC), with 50%, Saudi Aramco (15%), IPIC (United Arab Emirates) (15%), three Kuwaiti companies (with 5% each), and QGPC (Qatar) (5%).



189


mt (1.15 mbd) in 2010. The much reduced flows of 2009–10 compared with 2008 reflect the contraction in world oil demand associated with the Great Recession. This triggered OPEC production cuts (primarily from the Gulf producers), causing a sharp fall in regional oil trade that is only slowly recovering.

A major proposal for the extension and expansion of the Sumed pipeline system is also under consideration. The project would construct an extension of the Sumed across the Gulf of Suez from Ain Sukhna past the southern tip of the Sinai peninsula to the closest point on the Saudi Arabian coast and then by land down the coast to Yanbu (the terminus of Saudi Arabia’s east-west pipeline from the Gulf).

There is also the underutilized Trans-Israeli pipeline (Tipline) which runs to and from the Gulf of Aqaba and functions similarly to the Sumed, in that it moves crude oil between the Mediterranean and Red Sea. This pipeline route could become a commercial factor in Mediterranean oil logistics if a comprehensive Arab-Israeli peace deal should ever emerge.

Moreover, Persian Gulf crude transported around the Cape will not necessarily be backed out of the Mediterranean in the next 15–20 years. There are a number of reasons to assume that existing patterns will continue:

Existing long-term supply contracts between the Saudi and Kuwaiti companies on the •one hand and a number of Mediterranean refiners on the other will ensure a continuing flow from the Persian Gulf to the Mediterranean. More importantly, it is a long-standing policy by the Saudis (and to a lesser extent the Kuwaitis) to have their crude present in material volumes in all major consuming markets around the world. This includes the Mediterranean countries of the OECD.

Some of this crude will move through the Suez/Sumed system, and some will take •the Cape route. The flow through these two routes will be influenced by transportation economics and the competitiveness of the Egyptian Suez/Sumed system. In fact three elements have to be taken into account: VLCC economics for the Cape route; the Sumed pipeline tariff; and the Suez tariff imposed solely by Egyptian authorities.

The last two elements are set by Egypt and the Sumed company, with the goal to remain competitive with the Cape route. However, the two authorities in charge of the pricing of the Suez/Sumed system have to adapt their tariffs to the market rate, i.e., the Cape route. This administrative pricing usually lags behind the market rate, and adjustments are slower than the fluctuation of VLCC tariffs around the Cape.

The competition between a “free highway” (the Cape route) and a “tolled expressway” (Suez/Sumed) is unlikely to disappear within our time frame, considering the revenue needs of the Egyptian transit system. A situation in which Suez/Sumed takes even more of the market may emerge, but the Cape route will not disappear for Mediterranean-bound crudes (or, vice versa, outbound crudes from the Mediterranean). Moreover, VLCC economics for the Cape route (whether the crude is going to Northwest Europe or the Mediterranean) will remain a good option for shipping companies because they can load West African crude on their way back to deliver in Asia. This triangular trade maximizes VLCC values and will keep




the Cape route pricing competitive. This is why it is unlikely that the Suez/Sumed system will being able to back out completely the flow of Persian Gulf oil (with the Mediterranean as destination) around the Cape.

The general price-setting mechanism will probably remain twofold in the Mediterranean, one part linked to a crude benchmark and one linked to the marginal barrel of crude in the region:

The Suez Canal

the Suez canal is an artificial sea-level waterway running across the isthmus of Suez in egypt, connecting the Mediterranean Sea and the Red Sea (see Figure Vi-1). the canal separates the african continent from asia, and it provides the shortest maritime route between europe and asia, including the indian subcontinent and the pacific Rim countries. as a result, it is one of the world’s most heavily used shipping lanes.

Ship traffic in the Suez canal has rebounded from 2009 levels. the total number of ships passing through the canal in 2010 (in both directions) was 17,933 (up 4.1% from the previous year, but still well below the 21,415 passages recorded in 2008). the total number of tankers passing through the canal in 2010 was 3,550 (or 19.7% of the overall total), with 1,615 passing north-to-south and 1,935 passing south-to-north. these tankers carried 95.0 mt of oil (crude and products) in 2010, with 40.9 mt going south and 54.1 mt going north.

the majority of crude oil flows transiting the canal travel northbound, toward markets in the Mediterranean or North america. Northbound canal-based flows of crude oil amounted to 21.0 mt (420,000 bd) in 2010, while southbound shipments were 15.6 mt (312,000 bd). combined, the Sumed pipeline and Suez canal handled over 75 mt (1.5 mbd) of crude oil flows into the Mediterranean in 2010. two years before, in 2008, the volume was about double this, at 152 mt (3.04 mbd), with 105 mt (2.1 mbd) through the Sumed and 47 mt (940,000 bd) of northbound shipments through the canal.

the Suez canal is only a single lane for most of its length; i.e., ships can move in only one direction at a time. Ships pass through the canal under a tightly controlled timetable, stopping to moor at the two places where vessels traveling in opposite directions can safely pass, in the Great Bitter lake and Ballah Bypass. as a sea-level waterway, the canal has no locks, and water flows freely through it. But the water north of the Bitter lake flows north in winter and south in summer. the current south of the Bitter lake changes with the tide in the Gulf of Suez.

pilotage by Suez canal pilots is compulsory for all transiting vessels. the Suez canal authority assigns four pilots for each transiting vessel; each one specializes in a particular segment, and embarks and disembarks the vessel at certain locations.

after a series of enhancements, in 2010 the Suez canal was 193.3 km long and 205 m wide. the Suez canal authority is continuing to enhance and enlarge the canal; it just increased the permissible draft for ships to pass through the canal to 20.1 m (66 ft) in January 2010, which allows over 60% of all tankers in the global fleet as well as 97% of bulk carriers and 100% of container and other types of ships to use the canal. Vessels allowed to pass through the canal now can have a maximum draft of 20.1 m and a height of 68 m (because of the Suez canal Bridge). this allows laden tankers with a size of up to 200,000 dwt to transit the waterway under certain circumstances. previously, the laden capacity for tankers was about 170–180,000 dwt. Further enhancements to the canal and expansion are under way or being actively considered.



191


Formula-based price mechanisms in the Mediterranean will continue to be dominated •by the Brent pricing system: dated Brent and IPE for futures. There is little reason to doubt that Brent will maintain in the next decade its present key role. It will continue to fit the requirements of a benchmark crude: price set in an open, and transparent market, with sufficient volumes and a sufficient number of players. But there is a volume threshold below which Brent cannot meet these requirements, of course.

Spot-based pricing in the Mediterranean market will continue to be dominated by •marginal crude supplies pushed into this market: we see Russian and Iranian barrels continuing to be mainstays of the Mediterranean spot market, since little of that crude is sold through long-term arrangements and the volumes fluctuate according to seasonal patterns and domestic availability. These marginal supplies will probably be supplemented by Iraqi oil as well.

Considering all the upstream projects versus the region’s stagnant demand for crude, there is little chance that the Mediterranean market will tighten in the next 10 years. We believe that the Mediterranean will remain one of the weakest of the world’s major regional crude oil markets.

��

��

��




APPENDIx: IHS CERA’S GlOBAl ENERGy SCENARIOS



193


Figure A-1

Storylines of IHS CERA’s Global Energy Scenarios

Global Redesign (planning scenario)

Strong expansion of global trade and investment•

Global institutions adapt to new balance of power•

tension related to GHG policy and nuclear proliferation•

evolutionary changes in energy demand and supply•

average annual real GDp growth, 2010-30: 3.6%•

Meta Growth in global GHG emissions slows dramatically•

Main drivers are pain (very high oil prices) and gain •(innovation)

Big increase in electrification of vehicle fleet•

average annual real GDp growth, 2010-30: 3.4%•

vortex Severe economic volatility; Second Great Recession in •2013–14

protectionism leads to a “long Slowdown” (worldwide)•

little change in energy demand, supply, and technology•

average annual real GDp growth, 2010-30: 2.7%•Source: iHS ceRa.




Tab

le A

-1

wo

rld

Oil

(liq

uid

s) D

eman

d in

Pri

mar

y Ta

rget

Mar

kets

und

er IH

S C

ER

A's

Glo

bal

Ene

rgy

Sce

nari

os

Volu

me

cha

nge

2010

-203

0

per

cent

cha

nge

2010

-20

30

ave

rage

a

nnua

lp

ct.

cha

nge

2011

-20

3020

1020

1120

1220

1320

1420

1520

1620

1720

1820

1920

2020

2120

2220

2320

2420

2520

2620

2720

2820

2920

30i.

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195


Table A-2

Global Energy Scenarios:

Oil Signposts

Global Redesign Meta Vortex

Scenario of least average annual spare crude oil production

capacity, but supply is generally able to keep pace with growth

in demand, concentrated in middle distillates.

Market tightness and price spike in early period of scenario accelerate search for alternative

sources of energy supply, though oil demand still grows

overall.

High level of fluctuation of demand and prices, resulting

from macroeconomic volatility.

Average Spare Crude Oil Production Capacity, 2010–30

4.7 mbd 3.9 mbd 4.9 mbd

Average Annual Price per Barrel (2010 US dollars), 2010–30

average: $93 average: $99 average: $90

($111 nominal) ($119 nominal) ($92 nominal)

Source: iHS ceRa. prices are for Brent crude oil which is a benchmark price for oil traded on the international petroleum exchange (ipe) in london.




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199


Table A-3

Regional Oil Market Scenarios

Europe


in the transport sector •the decline trend in energy consumption that began in 2007 turns out to be the inflection point, as by 2030 on-road energy use in the european Union falls to the 2004 level .

Growth in energy •use by an expanding vehicle fleet is offset by mandated improvements in vehicle tailpipe carbon dioxide (co2) standards resulting in higher vehicle fuel efficiency.

Dieselization of the •light-duty vehicle fleet slows as diesel sales start to trend downward in response to rising diesel prices relative to gasoline prices.

european energy •demand is structurally changed by the severe contraction wrought by the Great Recession, and never returns to pre-recession levels.

Fossil fuel demand for •transport is one of the main targets of new policies designed to trim europe’s import dependency and emissions intensity.

the market acceptance •of electric vehicles (eVs) does not happen overnight but progresses far faster than anticipated, and by 2020, 12.5 % of new vehicle sales in europe are eVs.

oil demand is flat to •declining throughout the scenario period, reflecting a decline in gasoline consumption, which is offset to some extent by continued growth in demand for diesel and jet fuel as well as continued (albeit gradual) growth in biofuels consumption.

Weak environmental •initiatives in the power sector reduce pressure on oil- and coal-fired power generators in europe; oil plants initially scheduled for retirements benefit from derogations, allowing them to remain online until 2020 to maintain supply in the face of declining investment in new capacity additions.

Source: iHS ceRa.




Table A-4


North America


North american •petroleum demand recovers modestly from the Great Recession lows of 2008–09, but never returns to the peak levels reached in 2005.

after the US and •canadian fuel economy targets for 2016 are met, new, more stringent standards are gradually phased in from 2020 to 2030.

By 2030 the average •new passenger vehicle is able to meet a standard of nearly 50 miles per gallon (mpg).

Substantial •improvements in internal combustion engine (ice) vehicle efficiency and a shift to smaller, lighter vehicles account for much of the gain, while eVs make up nearly 15% of new vehicle sales by 2030.

By 2030 sales of eVs •account for 40% of all new passenger vehicle sales and reach 20% of the US light-duty passenger vehicle fleet.

a key trigger for such •a transformation is angst and frustration among North american consumers that grows in tandem with yet another round of record oil and gasoline prices.

the US and canadian •governments respond by throwing their weight behind an accelerated rollout of plug-in hybrid electric vehicles (pHeVs) and a step change in R&D funding for the next generation of biofuels, together with new incentive programs for consumers to purchase alternative fuel vehicles (tax rebates).

the strong rise in oil •prices from 2010 to 2012 contributes to the tepid recovery of North american oil demand in the wake of the Great Recession of 2008–09.

in similar fashion to the •last price spike in 2008, many motorists across the region cut back on discretionary driving; ridership in mass transit rises, and smaller cars become more popular at the expense of SUVs and other light trucks.

With the onset of •the Second Great Recession, North american oil demand again stagnates, and by 2015 demand is 1.5 mbd (about 6%) lower than its peak in 2005.

Reinforcing the weak •demand trend are higher fuel economy standards being phased in during this period.

Source: iHS ceRa.



201


Table A-5


Asia Pacific


china and india stand •out as the growth markets for oil and refined petroleum products.

although public •transportation expands significantly in these countries between 2010 and 2030, as incomes rise, the desire to own a car becomes a powerful force in transportation energy demand.

the strong hold that •gasoline vehicles have on the transport market leads to continued growth in gasoline consumption, despite tighter fuel economy regulations.

an expansion of the •heavy trucking sector means continued strong growth in demand for diesel, particularly low-sulfur diesel given tighter restrictions across asia on fuel product specifications.

the big story in asian •energy demand under Meta is the changes in transport driven by the swift and sizable deployment of grid-based vehicles made possible by improvements to battery life, weight, power, and cost.

By 2030 nearly half of •the light-duty vehicle sales in china are of electricity-powered vehicles, while on average across the region grid-based vehicles account for 40% of new vehicle sales in 2030.

taking into account •the full spectrum of light- and heavy-duty vehicles, petroleum-based fuels still meet the largest share of transport energy requirements, but fuel demand in 2030 is lower than many expected in 2010, particularly given improvements in conventional ice efficiency.

total oil consumption •grows by around 40% between 2010 and 2030, but oil’s share of total primary energy falls from about 26% to 24% driven primarily by comparatively slower demand growth for oil in the oecD countries of asia.

asia’s transport sectors •remain very dependent on the conventional internal combustion engine and traditional petroleum fuels such as gasoline and diesel.

Strong refined product •prices in the early 2020s and through the end of the scenario period nevertheless feed policy and market incentives toward greater demand for the use of battery-powered cars than had been projected in 2010, particularly for china and Japan.

Source: iHS ceRa.




Table A-6


latin America


Brazil is the most •important source for oil demand growth in the region owing to its market size and dynamic economy.

the transport sector •is responsible for most of this demand (especially diesel use by heavy trucks), whereas industrial and power generation oil consumption decline owing to greater natural gas use.

oil demand growth in •latin america continues at a fairly steady pace, but consumption of non–oil-based fuels also grows, with ethanol use increasing close to 7% per year on average from 2010 to 2030.

plug-in electric car •sales start to make inroads to varying degrees across regional transportation markets.

aside from the direct •impact of slower economic growth, the extended period of lower oil demand is driven by the declining ability of governments to provide price subsidies later in the scenario, as well as by the impact of subsequent cycles of high oil prices.

oil demand falls steadily •in Brazil for 10 years or more in several sectors, while transportation demand, the largest end-use sector for oil products, slows but does not decline.

Middle East


Various countries •introduce mechanisms to cut oil demand growth, particularly in the transport and electricity sectors.

But results are mixed •because of structural reasons, and neither Saudi arabia nor iran meets its ambitious target.

When prices/revenues •begin to decline in 2014–15, sustaining strong domestic demand is considered to be a favorable way to offset declining global demand, but by the early 2020s it becomes clear that such policies are unsustainable.

this coincides with more •intense promotion of alternative transportation technologies and the expansion of mass public transportation in urban areas.

During the long •Slowdown, as oil revenues decline and government coffers are depleted, some governments try to rationalize their subsidy programs.

Despite the comparatively •minor changes made to energy prices in most countries, these efforts meet public opposition and even contribute to social unrest.

Source: iHS ceRa.



203


Table A-7


Africa


Despite rapidly rising •oil demand growth (africa is the third fastest-growing region in the world during the scenario period), african oil demand in 2030 remains comparatively small, at 4.9 mbd—which is nearly half of its production.

at the beginning of •the century, 90% of african energy demand is concentrated in about eight countries, including nations of North africa, South africa, Nigeria, and Sudan, but by 2030 their combined share of total regional oil demand falls to around 60% as demand in the rest of the continent increases more sharply.

after briefly recovering •in the wake of the Second Great Recession, demand for oil (africa’s second largest source of energy, after traditional biomass) declines again as oil prices begin to recover and further constrain already weak african economies; oil consumption growth resumes in the wake of global economic recovery.

Eurasia


overall ciS liquids •demand grows by 0.7% per year on average during 2010–30, and consumption of motor gasoline, gasoil, and jet/kerosene increases somewhat more robustly.

Russian oil demand •remains low throughout the period: the primary driver of oil demand is diesel use, which fuels a modest agricultural renaissance and growth in Russian industry, but improvements in unit efficiencies limit the overall growth of industrial oil consumption.

the damage done •to the economies of the ciS during Vortex perpetuates the already weak energy demand growth trend that had existed in the region since the early 2000s, and the share of oil use in the energy mix remains the same.

Source: iHS ceRa.




ABOUT THE AUTHORS

MATTHEw J. SAGERS, iHS ceRa Senior Director, energy economics for eurasia, is a well-known expert on energy, energy transportation systems, and regional economic development in the Former Soviet Union, including pipeline constraints and solutions in eurasia, and is an authority on energy policy in that region. Dr. Sagers heads the iHS ceRa eurasian transportation Forum, a platform for improving the transportation environment for oil and gas in the region. He is a key contributor to iHS ceRa’s Russian and caspian advisory Services, including the eurasian oil export outlook, eurasian Gas export outlook, and analysis of the Russian domestic oil market. Dr. Sagers’ recent research reports provide analysis of the Russian oil production and export outlook to 2030, Russian upstream and oil export taxation, Russian and turkmen gas development prospects, the outlook for Russian gas consumption, flexibility in Russian gas supply, Russian liquefied petroleum gas issues, the Russian oil refining sector’s future prospects, oil markets in Kazakhstan, and new pipeline projects in Russia and eurasia (including the east Siberia–pacific ocean pipeline), among other issues. in the past Dr. Sagers has also served on several World Bank missions, study teams, and advisory panels focused on oil pipelines in Russia and Kazakhstan. He has worked on the international energy agency’s Survey of the Russian energy Sector and Survey of the Ukrainian energy Sector. prior to joining iHS ceRa Dr. Sagers was Director of the energy Service at planecon, inc., where he led that company’s analysis of the energy sector in the Former Soviet Union and eastern europe, and prior to that was chief of the Soviet Branch in the US census Bureau’s center for international Research. previously he was an economic advisor to the newly formed Federated States of Micronesia and a professor of geography at Weber State University and the University of Virginia. He is a coauthor of the chemical industry in the uSSr: an economic Geography and of the transportation of Soviet energy resources, as well as author of extensive articles, government reports, and other publications. Dr. Sagers holds a BS degree (magna cum laude) from Weber State University and Ma and phD degrees from the ohio State University.

JOHN C. wEBB, iHS ceRa Director for Russian and caspian energy, specializes in the Russian Federation, with a focus on the oil industry, the primary hydrocarbon-producing provinces, and the government’s energy policy at the federal and regional levels. He also monitors the more general evolution of Russian politics and of the economy and their impact on the investment climate and energy projects. Dr. Webb’s recent iHS ceRa research includes analyses of upstream Russian oil sector investment and production trends, changing regional refined product consumption patterns, and new crude transportation and export dynamics. He has contributed to Journal of contemporary History, the russian review, the cold War: 1945-1991, and the politics of local Government in russia. Dr. Webb holds a Ba from the University of california, Berkeley, and a phD from Georgetown University.

laurent Ruseckas, iHS ceRa Senior associate, and Paulina N. Mirenkova, iHS ceRa associate, Russia and caspian energy, also contributed to this report.

Documents

New Realities in Oil Transit Through the Turkish Straits · the Dardanelles [Canakkale Strait]), separated by the Sea of Marmara, constitute the only passage for ships either entering