Prospects of export routes for Kashagan oil

Prospects of export routes for Kashagan oil

1. Introduction

 Kazakhstan has  emerged as the main focus of upstream oil and gas    investment  in   the  Caspian   region,  especially  since  the discovery of  a  world-class super giant at the offshore Kashagan field. The field known as Kashagan lies  in the north–west Caspian off  the coast of  Kazakhstan and  is  reported to  cover an  area 47 miles (75 km)  long by 22  miles (35 km)  wide. The discovery well, Kashagan East, was a single vertical well, drilled to a total depth of 4500 m.2     The  contracting companies continued to  explore other structures in the North Caspian Sea contract area and they found considerable reserves in 2002 at the Kalamkas field (Oil and Gas Journal—OGJ, 2002a, b).  The Aktote, Kashagan South West and Kairan areas explored by the end of 2004.  These offshore fields are large by  international standards, but  still  considerably smaller than the giant Kashagan field. Appraisal programs for these fields are still underway.

Kashagan oil field, believed to be the fifth largest ever found in the world,  has   estimated total  reserves  of  as  high as  50  billion barrels of  oil  (up   to  15–20  billion of  which are   thought to  be recoverable)3  and 25 tcf of natural gas  (EIA, 2008a–c; OGJ, 2001). Kashagan alone represents almost 50% of the proved oil reserves of  Kazakhstan4   and it is  by  far  the  largest offshore field in  the Caspian basin. The  480-square mile deposit is reportedly so large that it is believed to even surpass the size of the North Sea oil reserves (Krastev, 2002).

 Drilling began in 2000 under the auspices of its concessionaire, the  Offshore Kazakhstan   International   Operating  Company (OKIOC). The OKIOC later changed its name to Agip  Kazakhstan North Caspian Operating Company (Agip KCO). The contracting companies involved in the North Caspian Sea Production sharing agreement operated by Agip KCO originally were: ENI–Agip (Italy)

16.67%; BG (formerly subsidiary of  BP, UK) 16.67%; ExxonMobil (US) 16.67%; TotalFinaElf (France/Belgium) 16.67%; Royal Dutch/ Shell (UK/Netherlands) 16.67%; Inpex 8.33%; ConocoPhillips (US)

8.33.⁵    This   composition and company shares  have  changed

overtime which is explained below. The North Caspian production sharing agreement (PSA) covers 5600 sq km.

2.   Significance of Kashagan reserves and impact of the discovery 

 Although the field is  still being appraised, in 2007 Agip KCO estimated the field’s recoverable reserves at 13 billion barrels of oil equivalent, with further potential totaling 38 billion barrels using secondary recovery techniques (gas injection, for example). Further exploratory drilling activities are still in progress (in 2003 five wells have been drilled at Kashagan and three more wells drilled in 2006 for exploratory purposes) (EIA, 2008a–c).⁶

In late 2007, an Eni spokesman estimated that the field would initially produce around 3,00,000 bbl/d  from the field as  of late   2011.   According to  KazMunaiGaz, full-scale  commercial production is not expected to commence until 2013–2014. The consortium originally estimated  peak production at around 1.3 million bbl/d by  2016. The Kashagan project is  at the heart of Kazakhstan’s bid to  triple its output to 150 million tons by 2015 and become one of the world’s biggest exporters. This  figure may be adjusted under a new ownership structure agreed to in early

2008.

 The Kashagan field has presented particular challenges for its developers. ENI, the operator of the consortium, has pushed back the projected startup date from 2005, then to 2008, and then to the end of 2011. AGIP-KCO members have set a July 2013 deadline for the start of commercial output at the field and increased its projected expenditures from $57 billion to $136  billion (Socor,

2008a, b; Leonard, 2008). This huge discrepancy over the final cost of the project alone indicates the complexities faced in develop- ment phase. According to the Economist Intelligence Unit,  govern- ment receipts from the field’s production are expected to total $20 billion through 2041. Large scale production will require comple- tion of the Kazakh pipeline as well as an oil and gas treatment plant with an initial capacity of 3,00,000 bbl/d (EIA, 2008a–c).

 Kashagan also contains a high proportion of natural gas under very high pressure, the oil contains large quantities of sulfur, and the offshore platforms require construction that can withstand the extreme weather fluctuations in the northern Caspian Sea area. A new tax structure was introduced by the government in 2005, so the ownership rights of the field remained unclear for almost

2 years after British Gas (BG) decided to sell its 16.7% share of the field. Only  recently after drawn-out  negotiations, consortium members decided to  redistribute BG’s share, giving   half   to themselves and half to  KazMunaiGaz.⁷

 In September 2007, Kazakhstan requested over $10 billion in compensation from the  multinational consortium that was developing the Kashagan field in Kazakhstan, and the government prohibited further  work on   the field (in    part,  because of environmental violations) until the parties come to an agreement. After months of negotiations during 2007 and 2008, the share- holders finally agreed to allow Kazakhstan’s KazMunaiGaz to raise its stake from 8.33% to 16.81%, paying $1.78 billion or roughly half their book value. The other shareholders (Eni, Shell, ExxonMobil, and Total) will  reduce their respective 18.52% stakes and will compensate the Kazakh government for delays. The companies will pay an additional $2.5–$4.5 billion to the country, depending on the price of oil. Upon completion of the negotiations Eni, Shell, ExxonMobil and Total  each own 16.66%.  ConocoPhillips and Japan’s Inpex,  now both have  8.28%  and KazMunaiGaz has managed to increase its share 16.81%. Revised deal  was finally signed on October 31, 2008.

 According to the details of the deal, the proportion of Kazakh managers in   the Consortium is  being increased substantially, including a first deputy head of the operating company. Kazakh- stan’s income from the project (which had been fixed at 5% until now) will be tied to world oil price fluctuations of between $45 and $180   per  barrel. ENI  remains the operator during an ‘‘experimental’’ phase,  following which the other  four  major shareholders would each take charge of an area of responsibility. It is also expected that Total and Shell, along with KazMunaiGaz, will form a new operating company after the field comes online. There are some unconfirmed reports that at that stage Kazakh government might choose ExxonMobil as  the new chief operator of the project.

 The  start of commercial production is rescheduled to 2013, instead of 2010, for this 40-year project. First-phase production is now anticipated to rise from 75,000 barrels per day (bpd) in the first year to 4,50,000 bpd or some 22 million tons annually by the third year. Within 9 years production is expected to peak at 1.5 million bpd or 70 million tons.

 The discovery of Kashagan and subsequent discoveries in and around the  same Agip KCO  operating area (such as Kalamkas) have had a significant impact on the regional reserve estimates. The  four Caspian states—Azerbaijan, Kazakhstan, Russia (Caspian reserves only) and Turkmenistan—are projected to have remain- ing proven liquid reserves of 49.7 billion bbl (Fig. 1).

 The Caspian is dominated by six key projects (Kazakh–Kasha- gan, Tengiz, Karachaganak, Azeri–Chirag–Guneshli [ACG], Shah- Daniz, and  the   Severnyi block in  Russia), which contain a combined 26.9  billion bbl, or 68% of the region’s total liquids reserves.⁸   For the purposes of this analysis, even if we estimate immediate producible oil reserves of Kashagan at a conservative

10 billion bbl, it still  represents more than 20% of the regional total. The giant discovery has strengthened Kazakhstan’s regional reserve position, and it now controls about 80% of the Caspian’s oil (OGJ, 2001; EIA, 2007; BP, 2008).

 Further appraisal work at Kashagan and the surrounding Agip KCO acreage will  certainly lead to an  upward  revision of the reserves in the near future, strengthening Kazakhstan’s position in the region still further.

 Despite the addition of 750   million bbl of reserves from the Korchagin and Khvalynskoye oil fields in the Russian sector of the Caspian, Azerbaijan remains firmly in the second spot with 15% (7.5  billion b/d) of the Caspian total (Fig. 1). Exploration drillings in Azerbaijan during 2000–2003 has largely been disappointing, casting serious doubt over the ultimate potential of the southern Caspian. Turkmenistan’s  liquid reserves  have   more or  less remained unchanged at 4% (2.2 billion b/d), while Iran has  yet to contribute to the regional total  with substantial exploration drilling did not started as of 2006.

 With estimated associated gas  reserves of about 25 tcf, the Kashagan oil discovery has enhanced Kazakhstan’s position as a regional gas player too, bringing it closer with the vast remaining gas reserves held by Turkmenistan. Kazakhstan and Turkmenistan contribute 51% and 33%, respectively, of the Caspian’s 459 tcf total remaining gas reserves (Fig. 2).

 Although oil currently remains more important to Azerbaijan, it contributes about 17% of the region’s remaining gas reserves, primarily due to the giant Shah Daniz gas field. Despite its smaller gas volumes, Azerbaijan has   a geographical advantage that has enabled it to secure a significant gas sales contract with Turkey at an international market price. Unlike some of the other Caspian states, Azerbaijan  remains relatively well positioned to  gain additional gas market share and capitalize on its gas assets in the longer term.

 Iran, which has yet to commence exploration in its sector of the Caspian, is not expected to contribute to the region’s liquids production considerably before 2010. 
 
 
 
 
 
 
 
 
 
 
 
 

Turkmenistan 2.2, 4%           Russian (Caspian),0.3, 1%

                                            Iran (Caspian),0.1, 1%                  Azerbaijan,7.5, 15% 
 
 
 

                                       Kazakhstan, 39.6, 80% 

Azerbaijan  Kazakhstan  Turkmenistan  Iran (Caspian) Russian (Caspian)

Fig. 1. Caspian region remaining liquids reserves estimates (billion b/d;%) Total: 49.7 billion b/d). 

                 Iran (Caspian), 11, 2%

                     Russian(Caspian),0, 0%  Azerbaijan 65, 14%                                                                                                                            
 
 
 
 

                       Turkmenistan, 230, 51%                                Kazakhstan, 153, 33% 

                      Azerbaijan   Kazakhstan    Turkmenistan     Iran (Caspian)      Russian (Caspian) 
 

3.   Possible routes to export Kashagan oil and gas

   Successful exploitation of the Kashagan will depend on the construction of  new  transport  pipelines, capable of  handling large volumes of oil produced in a landlocked sea. The direction of  such a  pipeline remains in  question,  and thus  holds the potential for fierce competition among regional and global powers (OGJ, 2002a, b).

 Alternative routes that are being considered (Fig. 3) and some concerns associated with each project are as follows: 

Fig.  3. Map of the alternative routes for Kashagan hydrocarbon resources.

This 691 km route is part of  the interconnected Kazakh–Rus- sian pipeline system. Expansion work that started in 1999 is completed in 2001 at a cost of $37.5 million. Kazakhstan increased oil exports via the Russian route to 3,10,000 b/d in 2002, from a capacity of 2,10,000 b/d in 2000. Before  the completion of the CPC pipeline at the end of 2001, Kazakhstan exported almost all of its  oil through this system. But,  since Kazakhstan desired more independence from the Russian transit systems, it favored the development of transport alternatives. Still, in June  2002, Kazakhstan and Russia  signed  a  15-year oil  transit  agree ment under which Kazakhstan will export 3,40,000 b/d of oil annually via the Russian pipeline system. Russia’s trade ministry also   pledged to  increase the capacity of  the line  to  around

 5,00,000 b/d.⁹  As the CPC project grows with Kazakh production, absolute volumes though Atyrau–Samara are expected to grow, but this pipeline will become relatively less significant.

3.2.   Caspian pipeline consortium (CPC) (route 2 on map) 

 The CPC was formed to build a 980-mile-long pipeline system to transport oil from Tengiz, western Kazakhstan, to the Black Sea at Novorossiysk, Russia, and began to bring oil to world markets in the fall of 2001. The governments of Russia (Through Transneft

24% and Rosneft-Shell 7.5%),  Kazakhstan (19%), and Oman (7%) developed the CPC project in conjunction with a consortium of international oil companies.¹⁰ However, On November 6, 2008, Russian company Transneft announced that it has bought Oman’s share in the CPC for around $350 million—half the starting price offer from Hungary’s MOL and Kazakhstan (RIA Novosti). Another buyer for Oman’s share was Kazakhstan, which holds 19% in the CPC. Russia’s share is now 31%.

 The  CPC Project upgraded the existing line   from Tengiz via Atyrau and runs along the Caspian coast to join in the north with the Russian end of the line. The system also  consists of port facilities and a newly built line from the northwest Caspian coast in Russia to Novorossiysk. The total cost of the  project is $2.6 billion. The completion of both the expansion of CPC pipeline and ongoing Tengiz operations should add more than $150 billion in combined GDP to the Russian and Kazakh economies. The CPC pipeline will also be used for transporting natural gas liquids from a production plant to be constructed at Karachaganak by the KIO consortium.

 Initial capacity of the CPC pipeline was 5,60,000 b/d. The CPC pipeline exported around 6,90,000 bbl/d of crude oil in 2007, and the consortium has plans for a $1.5 billion expansion project to increase the pipeline’s peak capacity to 1.35 million bbl/d. With the completion of the two pipeline spurs from Kenkiyak and Karachaganak to the CPC at Atyrau and the usage of additives, CPC transport levels have increased from around 6,00,000 bbl/d in

2005 to  a monthly peak of 8,00,000 bbl/d in February 2007.

 The   pipeline is  an    extension  of  the existing  oil  transit infrastructure surrounding the Caspian Sea. Newly constructed components  of the line  run from the Russian town of Komso- molskaya  straight westward to  Novorossiysk. The  pipeline  is supplied with Kazakh oil through the Soviet-era links surrounding the Sea, which the consortium members have refurbished.

 In  September 2007 consortium members reached  a major milestone in agreeing to raise the transport tariff to $38/thousand tons (mt) from $30.24/mt, effective in October 2007. The share- holders also agreed to cut the interest rate on CPC loans to 6%/year from the previous rate of 12.66%. The decisions followed several meetings among the project partners this year as they attempted to resolve financing issues, which have held back expansion of the link. Consortium members are also awaiting the formulation of the Bourgas–Alexandropoulis pipeline route, which would keep incremental CPC volumes from  further  crowding the Turkish Straits.

Last   round of  talks   was held in  Moscow  where Russian Industry and Energy Minister  Viktor Khristenko and Kazakh Energy and Mineral  Resources Minister Sauat Mynbayev were negotiating a common position doubling the CPC’s throughput capacity in two stages by 2012 from 32 million to 67 million tons of oil annually. It is envisaged as part of the expansion of the CPC that an extra 17 million tons of Kazakh oil will be oriented to the Burgas–Alexandroupolis pipeline. However, despite the Russian Ministry’s press statement on the issue,¹¹ neither Kazakh side nor

the other CPC consortium members confirmed that deal was reached.

 The above-mentioned two projects represent the Russian route for  Kazakhstan.¹²    Russia  controls  nearly all  of  Kazakhstan’s current export routes. Recently, the industry newsletter ‘‘Petro- leum Argus’’ reported friction with Russian energy officials over Kazakhstan’s demands that it  should  be  able to  control the volume and destination of its oil shipments through the Russian pipeline system. In other words, the country’s influence has grown to the point where it wants to play the oil market, as Russia does. A Russian  official  reportedly  responded, ‘‘If they want equal treatment, they should start supplying oil to the Russian domestic market as our producers do.’’ (Russian companies must sell to the home market at a cheap subsidized price.) (Interfax, 2008).

 On the surface, relations with Russia have been free of such complaints. On December 7, 2002, Nazarbayev met in Astana with Aleksei Miller,  chief  executive of  the Russian gas  monopoly Gazprom,  about boosting sales of Kazakh gas abroad. The two countries were also worked on plans to raise Kazakh oil transit by

50%  with a  pipeline expansion project started  in  late  2003 (Lelyveld, 2002). However, problems beneath the surface, which endured for the last 4 years, seem to be driving Kazakhstan to look elsewhere for its future, including the projects like BTC.

 Many experts suspect that modifications of existing routes, like the established Druzhba system, may  satisfy investors and importers, not only in Russia, but also in Kazakhstan. The Russian pipeline  monopoly,  Transneft,  has  announced plans to  begin merging the Druzhba system, which runs from Russia to Slovakia, with a pipeline called Adria that terminates in Croatia. Connecting the Adria pipeline to Russia’s  Southern Druzhba system would require the cooperation of six countries (Russia, Belarus, Ukraine, Slovakia, Hungary,  and  Croatia). In  December 2002,   these countries signed a preliminary agreement on the project. Since then, however, progress has been slow moving, while the transit states wrangle over  the project’s details (including tariffs and environmental issues). Of the six partners, to-date, only three countries,  Slovakia, Hungary,  and Ukraine are  fully  ready  to implement the reversal (OGJ, 2002a, b).¹³ The most recent to ratify the necessary legislation, Ukraine, approved in February 2004. In the meantime, Kazakhstani oil may only access the Druzhba system to facilities on the Baltic  Sea, if those terminals do not handle Siberian oil.

Among potential north–south routes, it remains difficult to foresee where feasible routes might emerge. John  Roberts, an editor with Platt’s Global Energy Information Services, says that as long as the United States  opposes France’s TotalFinaElf north– south  pipeline  from Kazakhstan via  Turkmenistan  to   Iran, Kazakhstani oil can flow either North, to Russia, or West, to the Black Sea  and the Mediterranean. Washington is not averse to pipelines via  Russia. In  the past, the United  States  strongly supported a Tengiz–Novorossiysk major pipeline, and a smaller Baku–Novorossiysk one (about 1,00,000 b/d or less). Yet, although the Russian state-owned pipeline operator Transneft has invested in capacity upgrades, unrest in Chechnya and elsewhere in the

Northern Caucasus is detrimental to the viability of this option.

 The supergiant offshore oilfield Kashagan, where prospecting is  now  being completed,  may offer  a  last chance to  reduce Kazakhstan’s dependence on Russian transit, and the first chance to bring major volumes of Kazakhstan’s oil to the western Caspian shore and from there directly to international markets. Kashagan will be a make-or-break test of Russia’s policy to monopolize the transit  of  oil  from Kazakhstan. And  that  monopoly means controlling the lion’s share of Caspian oil flows (Socor, 2002). 

3.3.   Aktau-Baku–Tbilisi–Ceyhan: (route 3 on the map) 

 The  discovery at Kashagan immediately prompted plans to connect the proposed Baku–Tbilisi–Ceyhan (BTC) pipeline with a route from the port of Aktau on the Kazakh coast of the Caspian Sea. The entire route would have a total length of about 2300 km, although the proposed pipeline route would only run from Baku to Ceyhan. Kazakhstan ‘‘politically supports’’ the BTC route, and proponents of the BTC pipeline believe that the likely absence of robust routes through both Iran and China will probably make this the most  commercially and politically viable route for  vast reserves of Kashagan oil.

 At  a  September 2002  conference off  the coast  of  Greece sponsored by the Hellenic Foundation for European and Foreign Policy (ELIAMEP), the consensus among participants was that the Caspian Basin could probably support only one more main export pipeline beyond the existing CPC pipeline, and that a second pipeline could complement a major natural gas pipeline to create a stable transport system for the region’s fossil fuels. That descrip- tion  fits  quite well  with the BTC  and parallel  Baku–Tbilisi– Erzurum natural gas pipeline project (Lelyveld, 2002).

 Most crude shipped through the BTC pipeline is expected to come from Azeri  fields for about 10 years. Then around 2015, officials expect crude from Kazakhstan’s offshore Kashagan field to dominate shipments.¹⁴

 In order to facilitate exports  of oil from Kashagan during the next decade, Kazakhstan is developing an internal ‘‘Kazakhstan Caspian Transportation System’’ (KCTS), which will  include the construction of a 5,00,000 bbl/d pipeline from Eskene in western Kazakhstan to the port of Kuryk. From Kuryk  and the current nearby working port of Aktau, oil will be shipped via barge across the Caspian to the BTC pipeline. Current trans—Caspian ship- ments are expected to double at Aktau to around 4,00,000 bbl/d, and will augment a new 7,60,000-bbl/d oil terminal at Kuryk, just south of the Aktau port. KazMunaiGaz has not yet decided on the exact site for the port. Expansions of the oil terminals in Baku and Kuryk  and the pipeline’s construction could cost at  least $1.5 billion. Kazakhstan has also taken an interest in sending oil via rail (and the port of Batumi) to the Black Sea and then onwards to the reversed Odessa–Brody pipeline (EIA, 2008a–c). 

3.4.   Kazakhstan–Turkmenistan–Iran: (route 4 on the map) 

  A proposed pipeline from Kazakhstan to Iran via Turkmenistan has been discussed. The pipeline would have a crude capacity of 1 million b/d, have a length of 1600 km, and require  $1.2 billion in investments.  Although this route is  one of   the shortest and cheapest, US opposition and sanctions against Iran are likely to keep this project shelved for  some  time. The  destination of exported oil and gas is also another determining factor, depending on whether it is targeted towards Asia or Europe.

3.5.   Kazakhstan–Turkmenistan–Afghanistan–Pakistan (and India): (route 5 on the map) 

 Eastern and southern routes for both oil and gas, such as the oft-invoked route across Afghanistan, are  being considered by parties involved in the Caspian hydrocarbon development, but many experts doubt that Afghanistan or South Asia could offer investors assurances of political stability (OGJ, 2002a, b). 

3.6.    Kazakhstan–China: (route 6 on the map) 

 The   613-mile-long,  813 mm, and  2,00,000-bbl/d  capacity pipeline from Atasu, in northwestern Kazakhstan, to Alashankou in  China’s  northwestern Xinjiang region is  exporting  Caspian oil to serve China’s growing energy needs. PetroChina’s ChinaOil is the exclusive buyer of the crude oil on the Chinese side and the commercial operator of the pipeline is a joint venture of CNPC and Kaztransoil. In  addition to  around  85,000 bbl/d of Kazakh crude that flowed through  the pipeline during 2007, Gazpromneft and  TNK–BP have  received around 12,000 bbl/d each in allocations for their crude oil exports during the first quarter of 2008.

 The   source of  Kazakh oil  for  the pipeline  comes from CNPC’s  Aktobe field  and  from   CNPC  and   KazMunaiGaz’s Kumkol  fields.   Securing long-term crude oil  supply  for  the pipeline’s capacity is the current priority, so plans to expand the pipeline to 4,00,000 bbl/d are now of lower concern. The quantity of crude oil supplied to China through this route will still  represent only a   small percentage (i.e.  less  than  5%) of China’s expected oil demand by the time the project reaches completion.

 The  first stage  of the  project was completed in 2003 and runs westward across Western Kazakhstan from the oil fields of the Aktobe region to the oil hub of Atyrau near the Caspian Sea. This   line   will  be    reversed when all  stages are   complete. Construction began on the second section of  the Kazakhstan– China pipeline in late September 2004 and was completed during

2006. Crude oil reached the Chinese side on July 29, 2006, around two months behind schedule, and  was then pumped to  the Dushanzi refinery. Pricing issues were the main reason behind the delay, but China and Kazakhstan eventually came to a compro- mise. The final stage of the project,  scheduled to be complete around 2009,  will connect Kenkiyak and Kumkol at a cost of around  $1 billion, will  connect the first two sections, and will theoretically double the pipeline capacity to 4,00,000 bbl/d. The project will  complete a transport network linking the huge oil fields of the Kazakh sector of the Caspian Sea basin directly to western China.¹⁵  The speed of this final leg will in part also be dependent on the availability of Kashagan crude oil (EIA, 2008a–c; Stratfor, 2007).

 On the other hand, many experts do not rule out the possibility of construction of a pipeline connecting the Caspian Basin with China’s Pacific Coast. However, some of them like John Roberts, hold the view that a pipeline from Kazakhstan to China would be extremely costly and unfeasible, given the lack of enough volume commitments from the Kazakh Government. Such a pipeline, in order  to  reach China’s Pacific Coast, would need to  extend

5500 km  and would cost  upwards of almost $10 billion. (The

BTC route runs 1760 km)  According to Roberts, available oil in Kazakhstan could pump 4,00,000 barrels of oil a day through such a pipeline, but it would take a million barrels a day to make the project enticing for investors. He calculates that Russia would have to participate to deliver this volume, necessitating a three- way pact between Russia, Kazakhstan, and China. Such  multi- lateral projects, Roberts   says,   are   difficult to  negotiate and implement (OGJ, 2002a, b). 
 
 

3.7.   By-pass routes via Bulgaria and Ukraine (route 7 on the map) 

 In January 1997, Bulgaria, Greece, and Russia agreed on a plan to build an oil pipeline linking the Bulgarian Black Sea port of Burgas with Alexandropolis on the Mediterranean coast of Greece. The proposed 178-mile, underground pipeline would allow Russia to export oil through the Black Sea while bypassing the Bosporus. However, a wide range of technical and economic disputes has stalled the $700 million project. Primarily, there are no discernible sources of financing for such a pipeline, and there is not enough oil commitment from the producing countries of the Caspian Basin to make the pipeline feasible.¹⁶ Although Russia, Greece, and Bulgaria signed  a  memorandum  on  the commencement of pipeline construction in November 2004,   the countries did not complete a memorandum of understanding (MOU) by the end of

2004. Greece continued to lobby for construction of the pipeline, and the final MOU was signed in April 2005. In 2006, Russia was granted a 51% stake in the pipeline project. In response to Russian involvement, the Bulgarian state-controlled gas  monopoly Bulgar- az and the Universal Terminal Bourgas (UTB) proposed to co- create a Bulgarian corporation that will control a minimum 24.5% of the remaining 49% of the Burgas–Alexandroupolis oil pipeline. Greece and Bulgaria accepted the  new conditions, despite the project originally stated that the three partners would share equal

33% stakes in the pipeline. On March 15, 2008 in the presence of President Putin three countries finally  signed an  agreement (Intergovernmental Agreement) to construct the pipeline. How- ever  no  concrete action was taken since then.  According to Greece’s development ministry, Greece could profit between $30 and $50  million per  year  from the pipeline.¹⁷   According to environmental NGOs   active in  both Greece and  Bulgaria are arguing that this profit margin is far less than the environmental damages to  be inflicted by the pipeline.

 A second route to by-pass the Turkish Straits is the Albania– Macedonia–Bulgaria Oil  pipeline,  alternatively known  as  the AMBO pipeline. The AMBO project would take 4 years, linking the Bulgarian port of Burgas on the Black Sea to the Albanian port of Vlore on the Adriatic with an 890 km (550-mile) pipeline worth

1.2 billion dollars. The pipeline capacity would be 7,50,000 bpd. Even though the plans for this project were designed in 1996, large US petroleum companies, Exxon Mobil and Chevron Texaco, have dismissed AMBO claims that they have considered a role in the venture, saying that it was ‘‘far too early’’ for such a decision.¹⁸

In December 2004, AMBO announced that front-end engineering and design (FEED) on the pipeline would be completed in 2005 (which is done so) following the December 28, 2004 signing of an MOU by ministers from Bulgaria, Albania, and Macedonia. On January 31, 2007, the Republic of Macedonia, Bulgaria, and Albania signed a trilateral convention on the construction of the Balkan pipeline AMBO. This document has  been ratified by the Parlia- ments  of  all  three countries and  governs the construction, operation, and   maintenance   of   the  pipelines (Stojanovska, 2007).^19,20 Construction is expected to begin in 2008 for operation within 3 years.

 A third by-pass option would be the Odessa–Brody pipeline. The chief components of Ukraine’s strategy to bring oil bypassing the Bosporus across its  territory are the $750 million Pivdenny oil terminal and the 5,00,000-b/d Odessa–Brody pipeline. Ukraine already plays  a major role  as a transit country for Russian oil exports to Europe, and the  country is hoping that the Odesa– Brody  pipeline will  help Ukraine  reap  tariffs for  Caspian oil exports, as well.

 With  concern over the Turkish  Straits  ability  to  handle increased tanker traffic, Ukraine decided to build the Pivdenny terminal and Odesa–Brody pipeline to lure Caspian region oil exports  to  transit Ukrainian territory. The 400-mile pipeline, which Ukraine constructed with its  own  funds completed in August 2001, which became operational in December 2001, to the northwestern Ukrainian city of  Brody. The pipeline was initially intended to load Caspian Sea oil from the newly completed Black Sea  marine terminal, Pivdenny  (or  Yuzhniy),  and to  carry it northward through the Ukrainian system on to Europe with an initial capacity of roughly 3,00,000 b/d. However, for approxi- mately 3 years the pipeline has  been mostly dormant because Ukraine was unable to secure oil supplies from Caspian Sea area suppliers. Russia suggested that the pipeline be used in reverse, to move oil from Russia southwards to tankers in the Black Sea and onwards  to  world markets. Since  January 2003,  Russian oil companies have   used  the last 32-mile leg  of  the pipeline (in reverse) for these purposes.

 Faced with the possibility of losing direct access to Caspian Sea region oil, European governments have voiced their opposition to the reversal project in newspaper articles and public statements. Leading Caspian Sea  region producer, Kazakhstan, has also taken counter-measures. In July 2003, for instance, the country agreed to construct a 32-mile pipeline parallel to the segment currently being used in reverse  to transit Russian  oil. However, in late September 2003,   the Ukrainian government announced that in

2004, the pipeline will be used in its originally intended south– north direction to carry 1,80,000 b/d of Caspian Sea region crude to Europe. In 2004, the government pledged that its final intent for the pipeline would be for it to flow from Odessa north to Brody.  In the meantime, the Ukrainian state oil  company UkrTransNafta, effectively reversed that decision, declaring that it had accepted an  offer  from the Russian–British company TNK–BP to  ship

2,00,000 b/d from Brody  south to  Odessa  (in  reverse). On  a temporary basis, in September 2004, the first tankers shipped from Odessa with Russian crude oil, and the pipeline’s initial capacity level was roughly 97,000 b/d. Since  these  shipments remained very limited and new regime came into power after the so-called ‘‘orange revolution’’ in Ukraine, Viktor Yushchenko, the new President has finally decided in April 2005 to use the pipeline in the direction originally intended. European Union and World Bank announced that they will financially support the extension of the pipeline from Brody  to   Gdansk,  Poland. A preliminary agreement was signed between Azerbaijan, Georgia, Lithuania, Poland, and Ukraine, and a Kazakh deputy minister in May 2007 to  begin working on a multinational agreement.

However, there are multiple reasons why the extension may not be   currently   feasible.  The  primary hurdle is  securing, commercial guarantees of Caspian oil, especially in light of recent developments with Kazakhstan apparently agreeing in exchange of CPC expansion, to send oil via the Bourgas–Alexandropoulis pipeline and BTC routes. Azerbaijan will be sending most of its oil through the BTC pipeline. Also, the European Bank for Reconstruc- tion  and Development (EBRD) has  stated, it may make more economic sense to construct the extension further to Wilhelmsa- ven, Germany, where it would avoid the crowded straits off the Danish and Swedish coast. Additionally, industry players have publicly stated that Caspian crude oil will be unlikely to displace cheaper Urals  blend crude oil from Russia at central European refineries. Finally, the refinery at Plock would have to be upgraded to  accommodate the lighter quality Caspian crude.

 The  energy summit in Kyiv, attended by heads of state and government from Caspian, Black Sea and Baltic countries on May

22 and 23, 2008 revitalized the  Odessa–Brody–Plock–Gdansk pipeline project for Caspian oil. In the ‘‘Joint Statement Regarding the Euro-Asian Oil Transportation  Corridor’’ (EAOTC)  signed by Azerbaijan, Georgia, Lithuania, Poland,  and Ukraine, leaders acknowledged the importance of the decision of the Ukrainian side to use the Odesa–Brody oil pipeline in the originally projected direction. This has become possible thanks to rapidly developing oil  transport  routes from  Azerbaijan to  Georgian maritime terminals. There, the oil can be shipped to Odessa by  tankers for pumping to  Poland through the pipeline.

 Azerbaijan has become key to this European pipeline project. Although the European Union has long declared it a priority, and the United States has also supported it declaratively, Azerbaijan can make it a reality in its triple role as oil producer, transporter, and investor.

 On May 16, 2008, the State Oil Company of Azerbaijan Republic (SOCAR) inaugurated its export terminal in Kulevi, near Poti on the Georgian Black Sea coast. The terminal will handle 5 million tons of crude oil and oil products annually from 2008 to 2010, 10 million tons annually from 2010  onward,  and potentially 20 million tons in a follow-up stage. The expansion plans anticipate oil input from Kazakhstan, in addition to those from Azerbaijan. The Kulevi terminal marks Azerbaijan’s emergence as an investor in oil transport and infrastructure projects outside the country. According to Prime Minister Artur Rasizade and SOCAR head Rovnag Abdullayev at the inauguration, Azerbaijan is prepared to supply oil volumes from Kulevi  for the Odessa–Brody–Plock– Gdansk pipeline project.

 Azerbaijan also transports oil by railroad en  route to Georgian maritime terminals. Those volumes originate partly in Azerbaijan itself and partly in Kazakhstan, where some producer companies ship their oil across the Caspian Sea to Baku for transshipment by rail to Kulevi and Batumi on the Black Sea. High prices for oil allow profitable transportation by railroad, making this route far more attractive than it was during the era of low-priced oil. This new situation also markedly improves the prospects for Caspian oil to reach the Black Sea and Odessa directly.

 In  February 2008,  Kazakhstan’s state oil and gas company KazMunaiGaz purchased the Batumi oil terminal outright from the Danish-led Greenoak Group and its partners. Greenoak will continue to  manage both the oil  terminal  and the recently modernized port of Batumi for KazMunaiGaz. The terminal, with a capacity of at least 15 million tons/year of crude oil and oil products, can also become a point of origin for oil deliveries by tanker to  Odessa and the pipeline to  Poland (Socor, 2008a, b). 
 

4.   Predicting export route(s) for Kashagan article’s scope to fully explain the model of prediction, since it requires extensive statistical  work and separate assessment/ explanation (a full explanation of the model and basic assump- tions on  actors in  the Caspian Basin,  applicability of  it  are discussed and tested  at Babali, 2006), for   the sake of  the argument, however, the model used is explained briefly here.

 The    original Bueno De  Mesquita (de  Mesquita,  2002; de Mesquita and Newman, 1985) model of predicting international relations is modified in an attempt to develop another model based on certain factors to predict which possible export route will  be chosen for the Kashagan oil. Mesquita’s ‘‘game  theory analysis’’ is used as the basic method of analysis in the model. The  ‘‘game  theory analysis’’    provides the closest analogy to the situation  in  the Caspian basin, and  the  proper tools to predict some policy outcomes. The analogy used in Mesquita’s model is a game in which actors simultaneously make proposals to each other about how to   resolve a policy issue and exert whatever pressure they can  to get  their rivals  to accept their proposals. Proposals consist of suggested new positions on  a continuous policy of each actor’s preferred option (de Mesquita,