Gas use at issue in Iran as oil production sags

May 2, 2005
Future use of natural gas has become a political issue in Iran, whose status as a major oil exporter may be at stake.

Judy Clark
Senior Associate Editor

HOUSTON, May 2 -- Future use of natural gas has become a political issue in Iran, whose status as a major oil exporter may be at stake.

In the past decade, the country has encouraged domestic consumption of gas to keep oil available for export.

Now, however, plans to export gas as LNG are under attack by opponents who say the gas should stay in Iran for domestic uses that include injection to sustain flagging oil production.

And domestic demand, stimulated by prices capped by the government at 1¢/cu m, is skyrocketing, notes Fereidun Fesharaki, president of FACTS Inc., Honolulu, who says raising the price would "create a major social and political upheaval."

Fesharaki outlined Iran's gas dilemma in April reports showing that the Islamic republic's oil fields need not only gas injection but also stronger appeal to foreign capital than exists under the current fiscal regime.

Conflicting needs
Opponents to Iranian gas exports say that by 2010 domestic demand will be 42 bcfd. They say 20 bcfd will be needed for oil field injection; 10 bcfd for commercial, residential, and compressed natural gas—including a CNG program to replace 63,000 b/d of gasoline by 2008-09—7 bcfd for electric power production; and 5 bcfd for industrial and petrochemical use.

The export opponents note that current production is 25 bcfd, including three phases of giant South Pars gas field. When South Pars is fully producing, they say, there is barely enough gas to supply domestic needs.

Iran is losing 350,000 b/d/year of oil production capacity, Fesharaki said, and the decline rate could increase to 500,000 b/d/year by the end of the decade. Onshore decline rates have risen to 8%/year from 7%/year and offshore decline rates to 13%/year.

"These numbers are alarming, particularly as they come at the same time as runaway demand," Fesharaki said. "It is now possible to see a future with little or no oil export revenues within 2 decades."

Production of Ahwaz Bangestan oil field, for example, has fallen to 160,000 b/d from 250,000 b/d and will fall to 60,000 b/d within 1-2 years. A gas injection program could increase production to 220,000 b/d and maintain it at that level.

Opponents to gas exports, led by Kamal Daneshyar, head of the Energy Committee of the Majlis (parliament), say Iran has 30 fields in need of gas injection totaling 12-14 bcfd. Only 3 bcfd currently is being injected. All of the 20 bcfd the opponents say will be needed for injection by 2010 to avert a massive decline in oil production would come from South Pars.

Iran's fourth 5-year plan, covering the period ending Mar. 20, 2009, calls for an increase in production capacity to 5.4 million b/d through measures that include injection of 5 bcfd of South Pars gas by the end of the period. To reach that level of oil production, Iran must add 1.5-1.6 million b/d of capacity to compensate for declines plus 1.4 million b/d more.

"Adding 3 million b/d is virtually impossible given the revised buy-back system [of contracts with international oil companies] and the way the system is set up," Fesharaki said.

Each year, Iran reports large oil discoveries, but at yearend, its capacity remains at 4 million b/d.

"We believe this is the realistic limit to Iran's capacity under the present system," Fesharaki said.

South Pars gas
He said a detailed technical study is needed to determine how much gas would be needed for future oil field injection.

Yet, of the 18 planned South Pars development phases that the government expects eventually to produce 21.4 bcfd of gas, only 3.7 bcfd is dedicated to oil field injection. About 9 bcfd of gas is dedicated to the domestic grid, 6 bcfd to LNG exports, 2 bcfd to the Iran-Pakistan-India pipeline, and 700 MMcfd to a gas-to-liquids program.

"The allocations so far are in favor of the domestic grid, followed by LNG, and the lowest priority is given to reinjection—Iran's most urgent problem," commented Fesharaki.

"Today, based on Iran's crude exports prices, exporting oil will provide Iran with five to six times higher revenue than gas on the basis of heat value at the wellhead," Fesharaki said. "The logic of increasing productivity of oil overwhelms the revenue expectations from gas exports."

Fesharaki said members of the aggressive movement opposing gas exports are sure to try to persuade the winner of imminent presidential elections to resist exports. He added that no one is considering interfering with existing agreements.

LNG export projects
No one knows how big South Pars field is or how much it can produce for export above what will be needed for domestic use. Iran and Qatar share the reservoir, and "both sides seem determined to produce as much as possible to stop the other side from taking 'their' gas," Fesharaki said.

Qatar's North field comprises 62% of the reservoir and Iran's South Pars 38%. Initially, both countries claimed the field held 100 tcf of gas. Qatar raised the reserves estimate to 200 tcf, and Iran followed suite.

"It was further increased to 400 tcf by both sides and then to 500 tcf," Fesharaki said. "When Qatar went up to 900 tcf, the Iranian side just stayed at 500 tcf."

Proposed LNG export projects from Iran have generated more confusion. In addition to changing the size of upstream fields, officials frequently change the size of the LNG liquefaction trains and the destination of exports.

"Moreover, Iran has not adopted the more normal process of train-by-train exports. It sees the projects in phases," Fesharaki said (OGJ, June 23, 2003, p. 78). Each project has a phase. Reserves have changed several times. Downstream and upstream segments are run by different companies—National Iranian Gas Export Co. (NIGEC) for downstream and Pars Oil & Gas Co. (POGC) for upstream. Sometimes LNG projects have been marketed with no upstream player identified, and some projects are linked to upstream acreage onshore.

New refining capacity
Demand is rising rapidly for gasoline as well as for natural gas in Iran. The price of gasoline also is held well below world market levels.

Iran in 2004 imported 150,000 b/d of gasoline and is expected to import 9% more than that this year. It exports about 250,000 b/d of fuel oil.

To decrease gasoline imports, Iran plans to add extensive refining capacity. The 100-year-old Abadan refinery will be closed or semiretired. A 180,000 b/d plant is to be built nearby to make use of existing facilities. The government also plans to make Bandar Abbas Iran's primary refining center, expanding total capacity there to 1 million b/d by 2015.

Approved are additions of 88,000 b/d of capacity by 2007 and 160,000 b/d by 2010, primarily to process heavy, difficult-to-market Soroush and Nowruz crudes. In the next phase Iran will add condensate splitters to increase processing capability by a further 360,000 b/d by 2010. An additional 150,000-200,000 b/d of refining capacity additions are planned by 2015.

Foreign investment cools
Iran's success in attracting foreign investment to its oil and gas developments remains tepid, Fesharaki said.

Hindrances to participation include internal and external political opposition to international involvement, an unfavorable return on investment under buy-back contracts, a fractured tender process, and growing unease over accuracy of the country's production estimates.

BP PLC withdrew from bidding on Ahwaz Bangestan field development in the wake of concerns over "US government displeasure," leaving France's Total SA the lone bidder. National Iranian Oil Co. (NIOC) quickly awarded the development permit to its own subsidiary, Petroiran Development Co. (Pedco), before the end of Iran's fiscal year Mar. 21 to avoid expiration of the permit, which might not have been reauthorized by the new conservative Majlis, Fesharaki said.

He said NIOC nonetheless expects Pedco to make arrangements with Total in getting the project completed.

Faulty bidding process
Awaiting a final decision is disposition of Yadavaran oil field, formerly Kushk and Hosseinieh, which could be developed in conjunction with several LNG deals being negotiated with companies from China and India for 71-73% of the field's natural gas.

At the same time, however, bids have been received from a number of companies, including Royal Dutch/Shell, Petronas, Total, Repsol YPF SA, and ENI SPA, for the entire Yadavaran field (OGJ Online, Sept. 28, 2004).

"This points to another fundamental weakness of the Iranian system of attracting foreign investments," Fesharaki said. "There is no integrated approach, and each group is negotiating on its own." The oil minister decides who wins.

In addition, production forecasts remain in question. Iran claims Yadavaran will produce 300,000 b/d and Juffeyr 30,000 b/d—"numbers to entice the Chinese and Indian investors," the analyst said.

"Privately, field engineers believe these numbers are exaggerated. They expect 140,000-150,000 b/d from Yadavaran and 10,000-15,000 b/d from Juffeyr. Actually, Iran is not providing a guaranteed output, but production shortfalls will likely lead to disagreements later."

Fesharaki said the lukewarm reception to exploration blocks "is an indication of the perception of international firms to Iranian terms offered" (OGJ Online, Sept. 20, 2004). Interest remains very low, although several firms bid on the Khoramadad Block, which Shell won.

In addition, Petrobras signed a contract in July 2004 for eight Persian Gulf blocks with the minimum financial commitment of $31.5 million for 42 months, extendable by 18 months. It is adding $10 million for the 6,300 sq km Tousan Block southeast of Qeshm Island. Another agreement was signed in October with Repsol for the Forouz and Iranmehr Blocks under similar terms.