Many Problems Remain Unresolved In Iran’s Oil And Gas Projects

This article comprises edited extracts from the confidential report Energy Insights No 5: Overview and Update of Iran’s Oil and Gas Industry, prepared for clients in early May by Fereidun Fesharaki, President of FACTS Inc, Honolulu, and exclusively made available to MEES.

Despite US sanctions, the Iranian oil industry has made great progress. Indeed, US sanctions have only delayed Iran’s plans for one or two years. However, politicians have forced the National Iranian Oil Company (NIOC) to squeeze foreign investors so hard as to make investment in Iran marginal, and the trend points to even lower incentives and tougher conditions. Iran is fully capable of orchestrating a take-off of its oil industry both in upstream and downstream, and in the gas business. But, at this point in time, the political will is not there and things are likely to just muddle along.

Oilfield Buybacks

The three Bangestans – Ahwaz, Mansouri, and Ab-Teymour – have been awaiting award for some time. Proposals were submitted last fall and revisions were made but there was no action. The government has now decided to move forward and award these contracts in the next few months.

NIOC is now facing difficulties in comparing bids by BP, Shell, TotalFinaElf, and Eni. Except for Eni, the companies have bid for all three Bangestans, and apparently all bids are non-conforming in that they are multi-phased with 15-20 years of project work. NIOC had asked for its standard five-year buyback contract. The foreign bidders do not believe the work can be done and managed in such a short time, nor is it economically worthwhile to spend billions of dollars and then walk away. That every bid is non-conforming is an indication that NIOC requirements may not have been appropriate. The non-conforming bids make it next to impossible for NIOC to compare who has the best bid. Numerous internal meetings at NIOC have not resulted in any conclusions. The next step would be negotiations between the Petroleum Engineering and Development Company (PEDEC – the NIOC subsidiary responsible for negotiating oilfield buyback contracts) and individual bidders. More likely than not, a consortium will emerge, being led by the company least objectionable to the labor unions and politicians. So far, the only benchmark is the proposed additions to production. Each bidder is proposing 100,000-150,000 b/d of incremental output per project for Bangestan, and it appears that TotalFinaElf is slightly ahead on that score. All in all, some 350,000 b/d of incremental production is expected from the three fields (for original NIOC requirements see MEES, 6 July 1998).

The Cheshmeh Khosh project allocated to Cepsa will likely be re-assigned to Cepsa and OMV. While Cepsa is primarily a downstream company, OMV is a major downstream player but has upstream interests too. Interestingly, both Cepsa and OMV have an important Middle East shareholder – Abu Dhabi’s IPIC (International Petroleum Investment Company), jointly created by ADNOC and Abu Dhabi Investment Fund. IPIC owns 6% of Cepsa and 20% of OMV, and has important influence on their boards.

The new risk and reward buyback contract introduced in the Darquain project remain unpopular with the foreign companies. NIOC, however, is adamant that there is no going back on the new structure. All new Bangestan awards as well as Cheshmeh Khosh will be under the new regime. Some oil companies do not find the risk and reward concept so onerous. The key remains in the joint committee, supervising operations of the field. If this is properly structured, perhaps, risk and reward buybacks can be made to work.

The Azadegan field feasibility study is still being undertaken by Japex and INPEX under METI stewardship. The Japanese side has proposed to bring in Shell as a partner and is making great efforts to develop a Master Development Plan by June 2002 as specified in the contract. However, due to landmines in the area from the days of the Iran-Iraq war, seismic work has not been completed, as the Iranian side has not cleared the mines. The Japanese companies feel quite frustrated by the slow pace and the inability to proceed for reasons beyond their control. They have also not received approval from NIOC regarding bringing in Shell as a partner, and are not comfortable with rate-of-return (ROR) discussions. NIOC has the option to extend the deadline by six months but the Japanese feel that the deadline should be suspended while the mines are being cleared. Meanwhile, NIOC continues to talk about dividing the field into two or three sections, while the Japanese side has planned on a buyback for the whole field.

Offshore buybacks are doing reasonably well and most projects are on schedule. One of the last issues to be finalized is the PetroIran Development Company (Pedco)/BHP Billiton proposed buyback for Foroozan-Esfandiar. BHP Billiton has managed to offer a Master Development Plan, raising the recoverable reserves substantially, but also raising the cost. The per barrel cost has come down but the high total cost created hesitancy on the part of NIOC. As time was running out and discussions dragged on, there was a chance that NIOC would put the field to open bid. PetroIran therefore felt it had to grab the opportunity before it was lost (MEES, 27 May). It is still hoping to negotiate a deal with BHP, but unless the deal is made economically attractive, no foreign investor will dive in, no matter how attracted they are to Iran.

South Pars Gasfield

The South Pars projects are in full swing. Phases 2 and 3 came on-stream in March and will be in full production by end of summer 2002. Phase 1 is expected on-stream in the first or second quarter of 2003, and Phases 4 and 5 by late 2004 or early 2005. These projects will yield 200,000 b/d of South Pars condensates. Phases 6, 7, and 8, awarded to PetroPars, are facing some difficulties. Initially, Enterprise Oil was interested and had offered to take a 20% share. Statoil also was interested and had considered a share of up to 60%, leaving PetroPars with 20%. Both Enterprise and Statoil insisted on a minimum ROR of 15%. Given PetroPars’ ROR of only 12% for the entire three-phase project, this would have reduced PetroPars’ ROR share to less than 5%, making it impossible to finance. In any event, Enterprise was taken over by Shell and may be forced to withdraw. Enterprise has been paid some $50mn for the contract work carried out for PetroPars prior to the finalization of a possible buyback arrangement. Statoil remains a strong contender but will need to bid for the project.

There are now three schools of thought as to what the next step should be:

· Leave the situation as is and allow PetroPars to bring in new players through bids or negotiations;

· Award a bid for a contractor to do the entire job for PetroPars with Naftiran Intertrade Company (NICO) doing all the financing in return for entitlement to the entire 120,000 b/d condensate; and

· Re-bid for the whole three phases again and reserve 40% for PetroPars as is the case for Phases 4 and 5. A new operator would be appointed and given an ROR of 15%, with PetroPars still given only 12%

The jury is still out as to what will happen, but the first option may not be viable as the job will be too big for a non-oil company operator to execute. Financing may also not be so easy, given NICO’s various commitments. The last option, however, is to admit that the original idea was wrong and this may not be so easy to swallow. The last option, however, may be the only viable and practical option.

The South Pars Phases 9 and 10 development is about to be signed as a straight contract, not a buyback. Winners are expected to be a consortium of South Korea’s LG, the Iranian Offshore Engineering and Construction Company (IOEC), and Iran’s Oil Industries Engineering and Construction Company (OIEC). Apparently, NIOC may be guaranteeing bank loans by contractors through some kind of pre-sale of condensate. Phases 11 to 14 are now totally restructured. Phases 11, 12, and 13 have been redesigned for each to provide 1.4bn cu ft/day (cfd) of gas and 56,000 b/d of condensate. This would put the available gas and condensate on the same footing as Qatargas, which was used as a model. The normal South Pars gas supply of 1bn cfd per phase would not provide for enough gas for a two-train 8mn tons/year LNG plant. Phases 11 and 12 are being bid on by BP, TotalFinaElf, Statoil, and Eni. There is a strong possibility that BP and TotalFinaElf will get a block each. Phase 13 is not up for bid, but will be negotiated with Shell and Repsol. All three are for LNG and combined have a capacity of 24mn t/y of potential supply. The three LNG projects are: Iran LNG (BP, Reliance and NIOC); Pars LNG (TotalFinaElf, Petronas and NIOC); and Persian LNG (Shell, Repsol and NIOC). NIOC has set certain milestones for finalizing negotiations on the three projects. All three are expected to enter into negotiations by end of the summer 2002, with the milestone for Iran LNG to come first, followed by Pars LNG and then Persian LNG. Phase 14 is cut out of the Phase 1 area and is reserved specifically for gas-to-liquids (GTL), with Shell being the leading contender at this stage.

LNG And GTL Plans

The idea of marketing 24mn t/y of LNG supplies in one go is unrealistic. NIOC, with long and deep expertise in the oil market does not have the same experience with LNG. NIOC intends that Iran LNG should be directed towards India, Pars LNG to Asia, and Persian LNG to Europe, but this would simply not work. Each project must be free to sell in all markets. NIOC must decide who the primary project sponsors will be and help that project move forward, then permit the second and third projects go forward after a decent interval so that the first project gets off the ground.

NIOC should also be ready to take the price risk for at least the first greenfield train. Iran is at the back of the LNG sales queue. To make an entrance, it must make the initial sacrifice by accepting a price risk. Primary markets will be in Asia, primarily Korea, and then India. The key issue with India is the ability to pay: Indian customers cannot and will not pay the Eastern price of $4/mn BTU for LNG. It is very likely that a final decision will be reached by end-summer 2002 on which will go first and under what conditions. Though no final decisions have yet been reached, the prospects for Iran LNG may be somewhat brighter, if all other key details can be worked out.

Finally, there are two important remaining issues affecting LNG developments in Iran. First, a traditional five-year buyback cannot be applied to LNG projects and NIOC has yet to indicate a separate plan. Second, NIOC has indicated that the buyback compensation will be in the form of gas and some liquids, but if there is no immediate LNG sale, how would the remuneration be paid? The traditional compensation package has been based fully on condensates but it has been reported that even a full condensate volume may not be sufficient for the remuneration. In the case of TotalFinaElf, it may be possible to supplement the liquids from Sirri but it is not clear how the others may be compensated. Further thinking and negotiations will be needed to avoid future problems in this area.

Many in Iran remain excited about the GTL prospects, just as the Qataris and many others see GTL as a major new revenue source. The assumption that Iran can convert abundant gas to high quality oil makes perfect sense to the supporters of the scheme, but this fails to recognize that GTL is not about gas but about diesel fuel. To the best of our knowledge, at no time has the refining industry in Iran been included in the debate. Few understand that the key factor is economics of hydrotreating/cracking versus GTL. So far, the only official project is the proposed Shell GTL plant for Phase 14, but there are discussions about several other GTL plants too.

South Pars Condensate

South Pars condensate is a mirror image of Qatari condensate or NFC II. It has high sulfur, high mercaptan, and is difficult to use. Qatari production of NFC II is 55,000 b/d together with 38,000 b/d of RasGas condensate and there is a 27,000 b/d splitter in Messaieed using NFC II. Another unit of 140,000 b/d is planned for construction at Ras Laffan by 2005. Qatar has long experience in marketing the condensate, with great difficulty, mainly in Korea and Japan. Currently, the total volume marketed by Qatar is 28,000 b/d of NFC II and some 30,000 b/d of RasGas condensate.

Iran’s entry into the condensate world changes the dynamics substantially. Phases 2 and 3 bring in 80,000 b/d to be supplemented by another 40,000 b/d of Phase 1 and then another 80,000 b/d of Phases 4 and 5. In two years, Iran will be marketing 200,000 b/d of condensate from South Pars.

Marketing of condensate is a means of remuneration for the buyback contracts. NIOC can preempt the producers and market all the condensates. For Phases 2 and 3, NIOC intends to market the condensate in the early stages, but may assign exports to the operator TotalFinaElf and other partners in the venture (Gazprom/Gazexport and Petronas).

The first cargo of South Pars condensate is heading for ENOC’s sour condensate splitter, which has been shut since November 2001. Besides ENOC’s 60,000 b/d splitter, Fujairah also has a 15,000 b/d splitter shut down which can be reactivated. Another 25,000 b/d splitter belonging to TPI in Thailand, which is mothballed, can also handle the condensate. Selling to refiners is a different and difficult proposition. This may create problems as Phase 1 and Phases 4 and 5 come on-stream. If not handled properly, serious discounts may be needed to sell the material.

Qatar is selling NFC II off Dubai and has worked hard to establish a price regime. Iran is selling South Pars condensate off naphtha, because its only experience is with Kangan and Pazanan condensate selling off naphtha base. Selling off naphtha reduces the buyer’s risk, but can send the prices down faster if naphtha prices head down. NIOC pricing is sure to create major difficulties for NFC II pricing on Dubai basis. Indeed the early marketing of South Pars condensate has already impacted the market significantly. The May 2002 pricing indicates that Qatari condensate is selling at a $1.50/B premium to Dubai while the sister condensate in South Pars is around $1/B below Dubai!

NIOC intends to sell some 40,000 b/d of South Pars condensate to the National Petrochemical Company (NPC) at naphtha-related prices within a year. Eventually, the volume may be larger, but there are doubts as to whether NPC will pay the international price and whether it might insist on a ‘friendly price’. A friendly price might well delay the period of cost recovery by the foreign investors.