According to the Oil and Gas Journal (1/1/05), Iran holds 125.8 billion barrels of proven oil reserves, roughly 10 percent of the world's total, up from 90 billion barrels in 2003 (note: in July 2004, Iran's oil minister had noted that the country's proven oil reserves had increased to 132 billion barrels following discoveries in the Kushk and Hosseineih fields of Khuzestan province). The vast majority of Iran's crude oil reserves are located in giant onshore fields in the southwestern Khuzestan region near the Iraqi border and the Persian Gulf. Iran has 32 producing oil fields, of which 25 are onshore and 7 offshore (see table below). Iran's crude oil is generally medium in sulfur, with gravities mainly in the 28°-35° API range.
Major Iranian Oil Fields (est. production, bbl/d)
During 2004, Iran produced about 4.1 million bbl/d of oil (of which 3.9 million bbl/d was crude oil), up about 200,000 bbl/d from 2003. Iran's current sustainable crude oil production capacity is estimated at around 3.9 million bbl/d, which is around 100,000 bbl/d below Iran's latest (March 16, 2005) OPEC production quota of 4.037 million bbl/d. Some analysts believe that Iran's capacity is lower, and that it could fall even further until new oilfield developments (Azadegan, Bangestan - see below) come online in a few years. Iran's existing oilfields have a natural decline rate estimated at 8-13 percent per year (300,000-500,000 bbl/d) and are in need of upgrading, modernization, and enhanced oil recovery efforts (i.e., gas reinjection).
With sufficient investment, it is widely believed that Iran could increase its crude oil production capacity significantly. Iran produced 6 million bbl/d of crude oil in 1974, but has not surpassed 3.9 million bbl/d on an annual basis since the 1978/79 Iranian revolution. During the 1980s, it is believed that Iran may have maintained production levels at some older fields only by using methods that have permanently damaged the fields. Despite these problems, Iran has ambitious plans to increase national oil production - to 4.5 million bbl/d by the end of 2005, more than 5 million bbl/d by 2009, and 7 million bbl/d by 2024. The country is counting on billions of dollars in foreign investment to accomplish this, but this is unlikely to be achieved without a significant change in policy to attract such investment (and possibly a change in relations with the West).
Iran exports around 2.5 million bbl/d, with major customers including Japan, China, South Korea, Taiwan, and Europe. Iran's main export blends include Iranian Light (34.6° API, 1.4 percent sulphur); Iranian Heavy (31° API, 1.7 percent sulphur); Lavan Blend (34°-35° API, 1.8-2 percent sulphur); and Foroozan Blend/Sirri (29-31° API). Iran's domestic oil consumption, 1.5 million bbl/d in 2004, is increasing rapidly as the economy and population grow. As mentioned above, Iran subsidizes the price of oil products heavily, resulting in a large amount of waste and inefficiency in oil consumption.
State-owned National Iranian Oil Company (NIOC)'s onshore field development work is concentrated mainly on sustaining output levels from large, aging fields. Consequently, enhanced oil recovery (EOR) programs, including natural gas injection, are underway at a number of fields, including Marun and Karanj. Overall, Iran's oil sector is considered old and inefficient, needing thorough revamping, advanced technology, and foreign investment.
In February 2004, a Japanese consortium led by Inpex signed a final agreement on the $2 billion Azadegan oilfield development project. Azadegan was discovered in 1999, representing Iran's largest oil discovery in 30 years, and is located onshore in the southwestern province of Khuzestan, a few miles east of the border with Iraq. Reportedly, Azadegan contains proven crude oil reserves of 26 billion barrels, but the field is also considered to be geologically complex, making the oil more challenging and more expensive to extract. In January 2001, the Majlis approved development of Azadegan by foreign investors using the so-called "buyback" model (see below). Inpex, which has no upstream experience of its own, hopes to bring in an international partner - possibly Total, Statoil, Sinopec, or Lukoil (Shell has indicated that it is not interested) - as the field's operator. Initial production of medium-sour crude oil from Azadegan could come in 2007, ramping up to 250,000 bbl/d by 2009. At its peak, Azadegan production could account for as much as 6 percent of Japan's oil imports.
Since 1995, NIOC has made several other sizable oil discoveries, including the 3-5-billion-barrel Darkhovin onshore oilfield, located near Abadan and containing low sulfur, 39° API crude oil. In late June 2001, Eni signed a nearly $1 billion, 5 1/2-year buyback deal to develop Darkhovin, with the added incentive of a limited risk/reward element (payment is to be linked to production capacity). Ultimately, production at Darkhovin is expected to reach 160,000 bbl/d.
NIOC also would like to develop five oil and natural gas fields in the Hormuz region: Henjam A (known as West Bukha by Oman; the two countries are discussing possible joint development); the A field near Lavan Island; the Esfandir field near Kharg Island; and two structures near the South Pars natural gas field. According to NIOC, the five Henjam fields hold an estimated 400 million barrels of oil and have a production potential of 80,000 bbl/d. Other Iranian oil fields slated for increases include Doroud, Nosrat, Farzam, and Salman.
In February 2001, NIOC announced the discovery of a very large offshore oil field, named Dasht-e Abadan, in shallow waters near the port city of Abadan. According to a top NIOC official, Dasht-e Abadan could contain reserves "comparable" in size to Azadegan.
Foreign Investment/Buybacks The Iranian constitution prohibits the granting of petroleum rights on a concessionary basis or direct equity stake. However, the 1987 Petroleum Law permits the establishment of contracts between the Ministry of Petroleum, state companies and "local and foreign national persons and legal entities." Buyback contracts, for instance, are arrangements in which the contractor funds all investments, receives remuneration from NIOC in the form of an allocated production share, then transfers operation of the field to NIOC after the contract is completed. This system has drawbacks for both sides: by offering a fixed rate of return (usually around 15-18 percent), NIOC bears all the risk of low oil prices. If prices drop, NIOC has to sell more oil or natural gas to meet the compensation figure. At the same time, companies have no guarantee that they will be permitted to develop their discoveries, let alone operate them. Finally, companies do not like the short terms of buyback contracts.
The first major project under the buyback investment approach became operational in October 1998, when the offshore Sirri A oil field (operated by Total and Malaysia's Petronas) began production at 7,000 bbl/d. The neighboring Sirri E field began production in February 1999, with production at the two fields expected to reach 120,000 bbl/d.
In March 1999, France's Elf Aquitaine and Italy's Eni/Agip were awarded a $1 billion contract for a secondary recovery program at the offshore, 1.5-billion-barrel Doroud oil and natural gas field located near Kharg Island. The program is intended to boost production from around 136,000 bbl/d to as high as 205,000 bbl/d. Total is operator of the project, with a 55 percent share, while Eni holds the other 45 percent.
In April 1999, Iran awarded Elf (46.75 percent share), along with Canada's Bow Valley Energy (15 percent share), a buyback contract to develop the offshore Balal field. Eni is also involved, with a 38.25 percent stake. The field, which contains some 80 million barrels of reserves, started producing at a 20,000-bbl/d rate in early 2003, and reportedly reached 40,000 bbl/d in February 2004.
On March 18, 2005, a much-sought-after contract to develop the giant Bangestan field was awarded to Petro Iran Development Co., after having been delayed several times since 2001. Bangestan contains an estimated 6 billion barrels of oil reserves and produces about 250,000 bbl/d of oil, but the field is one of the oldest in the country, requiring investment and technological applications to compensate for natural decline. In April 2003, Shell stated that it was frustrated with the slow pace of negotiations on Bangestan, including numerous changes to terms of the project. Total and BP then bid on the project, which is now reported likely to be awarded to a local firm (PetroIran) instead. Development of Bangestan could cost $3 billion over 10 years, and aims to raise output to 600,000 bbl/d.
In May 2002, Iran's Oil Ministry signed a $585 million buyback contract with NIOC subsidiary PetroIran to develop the Foroozan and Esfandiar offshore oilfields. PetroIran is expected to increase production at the fields from around 40,000 bbl/d at present to 105,000 bbl/d by late 2005. The two oilfields straddle the border with Saudi Arabia's offshore Lulu and Marjan fields.
In other news related to buyback deals, the Cheshmeh-Khosh field, which previously had been awarded to Spain's Cepsa for $300 million, was re-awarded in January 2004 to state-owned Central Iranian Oil Fields Company (CIOFC). In December 2003, Cepsa and OMV withdrew from lengthy negotiations after a reported failure to agree on development costs and buyback terms. It remains possible, however, that Cepsa and OMV could still be involved at Cheshmeh-Khosh in some way. The objective is to raise crude production at the field from 40,000 bbl/d currently to 80,000 bbl/d within four years.
Recently, Iran appears to have had some second thoughts about buybacks (including charges of corruption, insufficient benefits to Iran, and also worries that buybacks are attracting too little investment), and reportedly is considering substantial changes in the system. In late May 2002, Canada's Sheer Energy became the first foreign company since Eni's Darkhovin deal to reach agreement -- $80 million to develop the Masjed-I-Suleyman, or MIS, field. Sheer's goal was to boost MIS production from 4,500 bbl/d to 20,000 bbl/d (the historic field, discovered in 1908, peaked at 130,000 bbl/d in the 1930s), but the company was replaced by China's CNPC, which bought the subsidiary of Sheer working on MIS. In general, the addition of a limited risk/reward element has not attracted the flood of foreign energy investment Iran both needs and wants. In January 2004, Iran announced modifications to the buyback model, extending the length of such contracts from 5-7 years to as many as 25 years, while allowing for continued involvement of oil companies after the field is handed over to NIOC.
Offshore Developments The Doroud 1&2, Salman, Abuzar, Foroozan, and Sirri fields comprise the bulk of Iran's offshore oil output. Iran plans extensive development of existing offshore fields and hopes to raise its offshore production capacity significantly. In early October 2003, Iran re-launched a tender for eight exploration blocks in the Persian Gulf after receiving little interest from a January 2003 announcement. One area considered to have potential is located near the Strait of Hormuz. Another interesting area is offshore near Bushehr, where Iran claimed in July 2003 to have discovered three fields with potentially huge - 38 billion barrels oil reserves. In May 2004, Brazil's Petrobras signed a 3-year, $32-$34 million deal to develop the Tousan fields of the Persian Gulf.
In late 2001 and early 2002, Shell brought part of the $800 million Soroush-Nowruz development online, with production of around 60,000 bbl/d. The two fields are located offshore, about 50 miles west of Kharg Island, and contain estimated recoverable reserves of around 1 billion barrels of mainly heavy oil. Output from Soroush is expected to reach 190,000 bbl/d in the next few months (the original target had been May 2004). In early 2003, a consortium of three Japanese companies bought a 20 percent share Soroush-Nowruz. In March 2004, the Iranian Offshore Oil Company (IOOC) awarded a $1.26 billion contract for recovery of NGLs and natural gas from Soroush, Nowruz, Foroozan, and Abuzar to Japan's JGC Corporation. Ethane from the gas will feed an ethylene complex at the Kharg petrochemical complex. Caspian Sea RegionAside from acting as a transit center for other countries' oil and natural gas exports from the Caspian Sea, Iran has potentially significant Caspian reserves of its own, although only a small amount (0.1 billion barrels) has been proven as "recoverable." Currently, Iran has no oil or natural gas production in the Caspian region. In early 2004, a 3-D seismic survey of the southern Caspian was being conducted by Iran's Oil Survey Co. In September 2004, it issued an initial tender to begin drilling in deepwater portions of the Caspian Sea sometime in 2005. Reports indicate that Brazilian company Petrobras has been in talks with the National Iranian Oil Company (NIOC) to finalize production sharing agreements.
At the present time, Iran continues to maintain that regional treaties signed in 1921 and 1940 between Iran and the former Soviet Union, which call for joint sharing of the Caspian's resources between the two countries, remain valid. Iran has rejected as invalid all unilateral and bilateral agreements on the utilization of the Sea. As such, Iran is insisting that either the Sea should be used in common, or its floor and water basin should be divided into equal (20 percent) shares. Under the so-called "condominium" approach, the development of the Caspian Sea would be undertaken jointly by all of the littoral states. However, using the equidistant method of dividing the seabed on which Kazakhstan, Azerbaijan, and Russia have agreed, Iran would only receive about 12-13 percent of the Sea. As of March 2005 , no agreement has been reached among Caspian Sea region states on this matter. In March 2003, Iran and Turkmenistan had noted "the need to achieve a consensus between the five [littoral] countries," while the two countries reportedly moved ahead in charting their common border in the Sea.
Crude Swaps Iran's desire to become a player on the Caspian oil front has led it to push forward in the area of oil "swaps." This arrangement involves the delivery of Caspian oil to refineries, via the Caspian port town of Neka in northern Iran, for local consumption. An equivalent amount of Iranian oil is then exported through Persian Gulf terminals such as Kharg Island. Shippers normally pay a "swap fee" of $1.50-$2.00 per barrel, with swaps handled by Naftiran Intertrade Co. (Nico), the Swiss-based trading arm of NIOC. As of late 2004, about 35,000 bbl/d of Turkmen and Kazakh oil were being shipped to Neka, down 75 percent compared to levels during the summer of 2004 as price differentials between sweet and sour crude rendered the swaps less competitive with Meditteranean routes. From Neka, oil is then sent to Tehran by the existing 170,000-bbl/d capacity Neka-Tehran pipeline. Eventually, Iran hopes to upgrade its facilities in order to greatly expand oil swaps, partly in order to compete with the 1-million-bbl/d Baku-Tbilisi-Ceyhan (BTC) pipeline, scheduled to open in late 2005.
Iran plans to boost capacity at its northern refineries at Arak, Tabriz, and Tehran in order to process additional Caspian oil, to boost Neka-Tehran pipeline capacity to 500,000 bbl/d, and also to increase port capacity at Neka to 500,000 bbl/d. In August 2003, a $500 million tender was issued to upgrade the Tehran and Tabriz refineries in order to handle 370,000 bbl/d of high sulfur Caspian crude. This follows a $330 million project, completed by a Sinopec-led consortium in late 2003, to expand storage at Neka and to upgrade the Tehran and Tabriz refineries.
Aside from Caspian "swaps," there were reports in February 2005 that Iran and Iraq were discussing a framework swap agreement involving possible construction of a 24-mile, 350,000-bbl/d oil pipeline from Basra to the Abadan refinery in southwestern Iran. In exchange, Iran would export a similar volume of oil from Kharg Island, crediting Iraq minus a swap fee.
Refining and Transportation As of January 2005, Iran had nine aging (most built before the 1979 Iranian revolution) but operational refineries with a combined capacity of 1.47 million bbl/d. Major refineries include: Abadan (400,000-bbl/d capacity); Isfahan (265,000 bbl/d); Bandar Abbas (232,000 bbl/d); Tehran (225,000 bbl/d); Arak (150,000 bbl/d); and Tabriz (112,000 bbl/d). In order to meet burgeoning domestic demand for middle and light distillates (gasoline demand is growing at around 9 percent per year), Iran plans to increase its refining capacity, possibly to 2.2 million bbl/d by 2008. One goal of this expansion is to allow Iran's refineries to process a heavier crude slate while decreasing the fuel oil cut. Currently, Iran's refineries produce around 30 percent heavy fuel oil and just 16 percent gasoline.
Iran has imported refined products since 1982, and these imports have been increasing rapidly. In 2004 alone, Iran imported an estimated 160,000 bbl/d of gasoline at an estimated annual cost of around $2-$3 billion. In June 2004, Japan's JGC reached an agreement with Iran to expand Arak to 250,000 bbl/d by 2009. In addition, Abadan is being expanded by 50,000 bbl/d, with completion expected by spring 2006. Bandar Abbas is being expanded in several phases, adding around 250,000 bbl/d of capacity by 2010 (and significantly more after that). Two planned grassroots refineries include a 225,000-bbl/d plant at Shah Bahar and a 120,000-bbl/d unit on Qeshm Island. Under Iranian law, foreign companies are permitted to own no more than 49 percent of Iranian oil refining assets.
Iran exports crude oil via four main terminals - Kharg Island (by far the largest), Lavan Island, Sirri Island (reopened on April 13, 2003 for the first time since 1988, when it was damaged by an Iraqi air raid), and Ras Bahregan. Refined products are exported via the Abadan and Bandar Mahshahr terminals. Many Iranian oil export terminals were damaged during the Iran-Iraq War, but all have been rebuilt.