According to the Oil and Gas Journal (01/2006), Iran contained an estimated 970 trillion cubic feet (Tcf) in proven natural gas reserves, making it the world's second largest reserves and surpassed only by Russia. Around 62 percent of Iranian natural gas reserves are located in non-associated fields and have not been developed. According to Global Insight, major non-associated gas fields include: South Pars (280-500 Tcf of gas reserves), North Pars (50 Tcf) and Kangan-Nar (23.7 Tcf). In 2005, according to provisional Cedigas data, Iran had marketed production of 3.5 Tcf of natural gas and consumed 3.6 Tcf of gas.
Despite the fact that domestic natural gas demand is growing rapidly, Iran has the potential to become a significant natural gas exporter due to its large reserves. Natural gas treatment and processing plants include Kangan-Nar, Aghar-Dalan, Ahwaz, Marun-4, Bid Boland, and Asaluyeh. In March 2004, Iran signed a $1.2 billion contract with a consortium of two foreign and two domestic companies to gather associated gas from the Nowruz, Soroush, Hendijan and Behregansar fields that was previously flared or re-injected.
Currently, natural gas accounts for nearly half of Iran's total energy consumption, and the government is planning to invest billions in coming years to increase this share. The price of natural gas to residential and industrial consumers is state-controlled at extremely low prices, encouraging rapid consumption growth and replacement of fuel oil, kerosene and LPG demand.
Iran has been involved in a border dispute with Kuwait and Saudi Arabia over demarcation of the border through the northern Persian Gulf continental shelf. This region contains the 7-13-Tcf Dorra natural gas field, which Iran had begun drilling in early 2000, but stopped after complaints by Kuwait. Saudi Arabia and Kuwait, which do not recognize Iran's claims to Dorra, signed a bilateral agreement in July 2000 on dividing up the field equally between the two countries.
South Pars
Iran's largest natural gas field is South Pars, a geologic extension of Qatar's 900-Tcf North Field . South Pars was first identified in 1988, and current estimates are that South Pars contains 280 Tcf or more of natural gas reserves, and over 17 billion barrels of liquids reserves. Sales from South Pars could earn Iran as much as $11 billion per year over 30 years, according to Iran's Oil Ministry. .
Development of South Pars is Iran's largest energy project, already having attracted over $15 billion in investment, but development has been delayed by various problems - technical (i.e., high levels of mercaptans - foul-smelling sulfur compounds - in the South Pars natural gas), contractual issues (i.e., controversy over buyback arrangements), politics, etc.
Iran’s condensate production from South Pars is currently 200,000 bbl/d, and by 2010, South Pars could be producing condensates of more than 500,000 bbl/d. According to FACTS, Inc., total condensate production from South Pars phases 1-14 is expected to reach 1 million bbl/d by 2015.
According to Global Insight, each of the 28 phases is set to produce almost 1 billion cubic feet per day. By 2006, five phases (1-5) were onstream, producing 3.2 billion cubic feet per day (Bcf/d) of natural gas. A further five phases are due onstream by 2007 with combined output of at least 10 Bcf/d. The government has called for 16 phases to be onstream by 2010 in order to keep pace with Qatari exploitation of the linked North Field, which could run down the reserve base. Development of the various phases will likely allow the government to reach marketed natural gas production targets by 2010 of up to 28.2 Bcf/d.
One important use for South Pars production will be reinjection for enhanced oil recovery. Total natural gas reinjection needs from South Pars are forcast by FACTS at 8-10 Bcf/d by 2010-2012. South Pars natural gas also is intended for domestic consumption and for export, by pipeline and also possibly by liquefied natural gas (LNG) tanker. .
South Pars Development Plan Phase 1, developed by Petropars, came onstream in November 2004. Phase 1 involves production of 900 million cubic feet per day (Mmcf/d) of natural gas for the domestic grid, plus 40,000-45,000 bbl/d of condensate.
In February 2003, Oil Minister Zanganeh officially inaugurated Phases 2 and 3 of South Pars development, which began to come onstream in March 2002. A consortium led by Total developed the project at a cost of approximately $2 billion. Currently, phases 2 and 3 are producing around 2.8 Bcf/d of natural gas, plus 80,000 bbl/d of condensates. Twin undersea pipelines carry gas from South Pars to onshore facilities at Asaluyeh.
Phases 4 and 5, estimated to cost $1.9 billion each, are being handled by Eni and Petropars, and involve construction of onshore treatment facilities at the port of Bandar Asaluyeh. These two phases began coming online in October 2004 and are ultimately expected to produce around 2 Bcf/d ,of natural gas, 80,000-90,000 bbl/d of condensates, plus ethane, sulfur, liquefied petroleum gas (LPG), and petrochemicals.
Phases 6-8 , are being handled by Petropars and Norway's Statoil, which signed an agreement in October 2002. The phases were due on stream by the summer of 2006 at a cost of $2.7 billion. Assessments now suggest the productivity of the 3 phases could potentially be 30% more than expected with each phase yielding 1.3 Bcf/d (instead of 1 Bcf/d) and condensate output per phase could reach 50,000-52,000 bbl/d. However, this expansion in productivity has not yet been approved and the whole project is facing delays because of platform and pipeline construction issues. This is due to delays in both offshore work and the lack of progress in building a pipeline from Assaluyeh to Agha Jari. Meanwhile, a pipeline is likely to bring some volumes of natural gas from South Pars Phase 1 to Phases 6-8 to provide enough natural gas for a sweet natural gas pipeline to Assaluyeh to go forward. Because of the above issues, it is now expected that one phase will be operational by early 2007, with the full three phases operational by end 2007 or early 2008.
The original plan was for the project’s natural gas to be transported via the planned $235 million IGAT-5 pipeline to the Agha Jari oilfield for injection as part of enhanced oil recovery efforts. NIOC is to take over as operator when development is finished.
Phases 9 and 10, being developed by South Korea's LG Engineering and Construction Corp., are expected to supply 2 Bcf/d to the domestic market, originally by 2007, plus around 80,000 bbl/d of condensate production. However, it appears at least one and half years behind schedule. In January 2005, a foreign subsidiary of Halliburton Co. reportedly reached agreement on helping develop Phases 9 and 10, along with local partner Oriental Kish.
Iran’s Minister of Petroleum Kazem Vaziri signed a contract in June 2006 under which the Islamic Revolutionary Guard Corps (IRGC) will build the IGAT-7 natural gas trunkline, to take natural gas from Assaluyeh to Iranshahr and also to the Pakistani border. The IGAT-7 line is planned to deliver natural gas from Phases 9 and 10 of the South Pars gas field.
Bids on Phase 11, which is slated for LNG export, were opened in March 2003. In April 2004, Total was selected to enter into final negotiations on the $1.2 billion project, while Petronas reportedly withdrew in May 2005. In addition, China National Petroleum Corp (CNPC) is negotiating for a 10 percent stake, and India’s ONGC is reportedly interested as well. Phase 11 is slated to produce 2 Bcf/of natural gas and 80,000 bbl/d of condensate under a buyback contract, possibly beginning in 2010.
Phase 12 was awarded to Petropars in 2006. The allotted structure comprises 3 Bcf/d of total production, with 1 Bcf/d for domestic use and 2 Bcf/d for a potential LNG project, with 120k bbl/d of condensate. Thus far, the LNG upstream project has made little progress and Phase 12 would at best come onstream in 2012 or 2013.
Meanwhile, in December 2005, Iran signed a contract with the Royal Dutch Shell Company and Spanish company Repsolon developing the downstream section of Phase 13, which is slated for LNG export (2 Bcf/d) and LPG production (80,000 bbl/d) starting in 2010. According to Shell, a final investment decision on the project has been delayed until late 2007. Phase 14 of South Pars is slated for gas-to-liquids (GTL) development, with Statoil and Shell reportedly interested.
In January 2005, Phases 15-16 of the South Pars project were initially awarded to a consortium of international and domestic companies led by Norway's Aker Kvaener. Subsequently, they were re-tendered and awarded to a consortium led by Ghorb, a domestic engineering company. The two phases are expected to cost $2 billion to develop. They are expected to produce 2 Bcf/d of natural gas for domestic use, plus 80,000 bbl/d of condensate and 133 million cubic feet per day of LNG for export. Phases 17 and 18 of South Pars are expected to produce 2 Bcf/d of natural gas. A service contract has been awarded to three Iranian companies: IDRO (43 percent), OIEC (25percent), and IOEC (32 percent). All natural gas will go to the domestic grid. Tenders for Phases 19-22 have been released but there are some questions on natural gas availability. Estimated output is 3.5 Bcf/d of natural gas for domestic use. Prequalification tender closed April 2006. The project is expected to be developed through a joint venture including IDRO and a foreign company, with costs are estimated at $3 billion.
Other Natural Gas Development
Iran likely will face stiff competition for LNG customers, particularly given the fact that many other LNG suppliers (Oman, Qatar, the UAE) are already players, having locked up much of the Far East market. U.S. sanctions also mean that Iran is limited to non-U.S. liquefaction technology, which is significant as most LNG plants use processes developed by U.S. companies. Currently, Iran has no LNG facilities.
In addition to South Pars, Iran's long-term natural gas development plans may involve the 48-Tcf North Pars field (a separate structure from South Pars); the 6.4-Tcf, non-associated Khuff (Dalan) reservoir of the Salman oil field (which straddles Iran's maritime border with Abu Dhabi, where it is known as the Abu Koosh field); the 800-Bcf Zireh field in Bushehr province; the 4-Tcf Homa field in southern Fars province; the 14-Tcf Tabnak natural gas field located in southern Iran; the onshore Nar-Kangan fields, the 13-Tcf Aghar and Dalan fields in Fars province, and the Sarkhoun and Mand fields. In September 2003, President Khatami inaugurated the first phase of Tabnak development, along with a related gas processing plant and a combined cycle power facility.
The dual Aghar-Dalan field development has been one of National Iranian Gas Company's recent successful natural gas utilization projects. Natural gas from both fields is processed at a $300 million facility at the Dalan field, which is also the location of a 40 megawatt (MW), natural-gas-fired power plant. Most of the treated natural gas from the Dalan processing plant is carried through a 210-mile pipeline for re-injection in Marun and other oil fields in Khuzestan province.
Natural Gas Trade
With its enormous natural gas reserves, Iran is looking to export large volumes of natural gas. Besides Turkey (see below), potential customers for Iranian natural gas exports include: Ukraine, Europe, India, Pakistan, Armenia, Azerbaijan, Georgia, Taiwan, South Korea, and China. Exports could be via pipeline and/or LNG tanker, with possible LNG export terminals at Asaluyeh or Kish Island. In late January 2002, Iran and Turkey officially inaugurated a much-delayed natural gas pipeline link between the two countries, following several years of delays. Exports of Iranian natural gas to Turkey could reach 960 million cubic feet per day by 2007. There are questions, however, whether Turkish demand will grow rapidly enough to absorb this volume of natural gas from Iran, in addition to natural gas slated to be supplied by Russia, Algeria, and Nigeria.
Iran is aiming for large-scale natural gas exports to Europe via Turkey. In March 2002, Greece and Iran signed a $300 million agreement which calls for extending the natural gas pipeline from Iran to Turkey into northern Greece. After that, gas could be transported to Europe via Bulgaria and possibly Romania. A memorandum of understanding (MOU) was signed on this possibility in January 2003, and a joint working group set up in October 2003. Alternatively, gas could be transported via an undersea pipeline to Italy, where gas demand is expected to grow rapidly in coming years. A deep water option could be extremely expensive, however, making an overland route more likely. In July 2005, Iran and Ukraine signed a MOU on the supply of up to 2.74 Bcf/d per year of Iranian natural gas to Ukraine.
In May 2004, Armenia and Iran agreed on a long-term deal, under which Iran will supply a total of 1.3 Tcf of natural gas to Armenia over 20 years starting in 2007, in exchange for electricity supplies from Armenia. As part of the deal, the two countries are building an 85-mile gas pipeline at a cost of more than $200 million. Construction finally began in early 2005 on the long-awaited Iranian portion of the Iranian-Armenian pipeline financed by Iranian Bank of Export and Development. According to the agreement, the construction must be completed by January 1, 2007. Initially, Armenia will receive 38 Bcf per year (1.08 million cubic meters per year) with plans to double the volume of imports by 2019. In exchange, Armenia will provide Iran with 3 kilowatts of electricity per cubic meter of gas. China has expressed interest in LNG imports from Iran. In October 2004, Iran signed a $100 billion, 25-year contract with China's Sinopec for the production and export of LNG to that country of possibly 1.3 Bcf/d, plus construction of a refinery for natural gas and development of the Yadavaran oilfield. Under terms of the deal, Sinopec would have rights to purchase half of Yadavaran's 300,000-bbl/d peak oil output over the 25-year contract period. However, Iran also received bids on Yadavaran from other foreign companies, so the field’s status is not completely clear.
Iran is also looking to export natural gas to Kuwait, most likely via pipeline from South Pars. In March 2005, Iran and Kuwait signed a preliminary MOU for natural gas sales, possibly 300 Mmcf/d for 25 years starting in 2007. The gas would be used for power generation and water desalination. Qatar's decision in mid-2006 to release to other projects natural gas earlier promised to Kuwait has required Kuwait and Bahrain to seek Iranian natural gas. At that time, Kuwait and Iran had edged close to firming up an initial agreement signed in 2000. This deal would supply roughly 35-40 percent of Kuwait's natural gas needs. Roughly three-quarters of the contract was worked out during those negotiations, and the parties were generally ready to continue, as the two countries had already agreed on the price and on the seasonal flow of supply.
Aside from natural gas exports, Iran also has discussed importing natural gas from Azerbaijan, and already imports some natural gas from Turkmenistan. This natural gas is for use in Iran's northern areas, far from the country's main natural gas reserves in the south. In December 1997, Turkmenistan launched the $190 million Korpezhe-Kurt Kui pipeline to Iran, the first natural gas export pipeline in Central Asia to bypass Russia. According to terms of the 25-year contract between the two countries, Iran will take between 177 Bcf and 212 Bcf of natural gas from Turkmenistan annually, with 35 percent of Turkmen supplies allocated as payment for Iran's contribution to building the pipeline.
Nabucco
In January 2004, Austria's OMV signed an MOU with the National Iranian Gas Export Co. (NIGEC) on possible cooperation regarding the proposed $5 billion Nabucco natural gas pipeline from Iran through Turkey to Austria. The Nabucco project, launched in 2002, entails the construction of a pipeline from the Caspian Sea region to Western Europe, bypassing Russia. Negotiations concerning the Nabucco project between the natural gas companies of five countries-- Bulgaria's Bulgargas, Romania's Transgas, Turkey's Botas, Hungary's MOL, and Austria's OMV-- concluded in June 2006, when Nabucco Company Pipeline Study Group was formed to undertake construction of the natural gas pipeline network. Though source natural gas for this project has not been decided upon, construction of the 1,760-mile, $5.8 billion pipeline is set to begin in 2008 and end in 2011. It will have an annual capacity of 170-480 Bcf.
Iran-Pakistan-India Natural Gas Export
Although India and Iran in 1993 signed an MOU on an overland natural gas pipeline, a variety of economic and political issues to date have blocked completion of a feasibility study. Meanwhile, in February 2002, Iran and Pakistan signed an MOU on a pre-feasibility study for a possible 1,600-mile, $3-$4 billion natural gas pipeline from southern Iran to southeastern Pakistan and on to India. Australia's BHP Billiton is the main foreign backer of the idea. Iran is offering to cover 60 percent of the construction costs of the pipeline. Pakistan could earn about $200-$500 million annually in transit fees from the pipeline and also would be able to purchase natural gas from the pipeline.
Given a thaw in India-Pakistan relations over the past couple of years, the pipeline idea has recently gained interest. Indian officials have stated that the plan could be considered if Pakistan can provide security guarantees for the $3 billion project. Two other options would be a pipeline serving only Pakistan, or separate pipelines for Pakistan and India. There also has been discussion of extending the pipeline to China. In September 2005, India and Pakistan agreed to seek third-party verification of Iran’s natural gas reserves before proceeding with the pipeline project.
However, pricing is an issue for the proposed pipeline as India is reportedly willing to pay at most $4.25/ million British Thermal Units (mnBtu), while Iran wants $7.20/mnBtu. India and Pakistan have together proposed to import roughly one-third of the total natural gas considered for export by Iran. Iran has put forward a natural gas pricing formula wherein the natural gas price is linked to Brent crude oil with an escalating cost component of around 3 percent annually. Both India and Pakistan oppose this formula and instead have insisted on having a floor and a ceiling.
Another possibility would involve LNG exports to India. In January 2005, Gas Authority of India Ltd. (GAIL) and the National Iranian Gas Export Corp. signed a 25-year deal with Iran for delivery of 5 million tons per year of LNG starting in 2009-10. In addition, NIOC offered Indian companies service contracts towards developing the Yadavaran and Jufeyr oilfields. Combined, India's shares in the two oil fields will produce 90,000 bbl/d. Iran reportedly will build three LNG plants at Assaluyeh, using South Pars natural gas as a feedstock. If successful, LNG exports most likely would flow to Dahej, in the western Indian state of Gujarat and/or Cochin in the southwest. India’s state-owned Oil and Natural Gas Corp. (ONGC) has an option for 20 percent of Yadavaran, plus 100 percent of Jufeyr. However, in July 2006, the proposed Iran-India LNG agreement stalled due to pricing issues. The 2005 agreement reportedly included a maximum price of $3.25/mnBtu, whereas Iran has since changed its price to $5.10/mnBtu. The stalemate in the LNG negotiations has implications in Iran’s upstream oil sector, given that the deal is tied to Indian participation in Iran’s Yadavaran and Jufeyr oilfields.