Middle East energy briefing

Iraq's oil-contract awarding schedule seen to slip again

Iraq will not be able to award technical service contracts to oil majors for some of its largest producing fields by March as Oil Minister Hussein al-Shahristani had hoped, oil executives familiar with the ongoing negotiations have told Reuters.

With oil majors ExxonMobil, BP, Chevron, Shell, and Total embarking on a new round of negotiations with the Iraqi Oil Ministry in Jordan's capital, Amman, vital details such as the scope of work, payment, and the link to the long-term development work on the field (which the majors are hoping for and the government has promised), still remain unresolved.

Awarding and signing is unlikely before mid-year, according to one oil executive Reuters spoke to, especially since the companies are seeking some kind of legal guarantees that a new Iraqi government will respect their long-term involvement and provide them with legal security of operations and investment.

The technical-service contracts have been portrayed by the oil minister as a stop-gap arrangement, in the absence of an oil law allowing IOCs to sign production-sharing agreements (PSA) and invest in long-term production capacity.

Significance: As Global Insight has previously said, awards by mid-year have looked increasingly likely for the past couple of months and if so, not much actual work by the IOCs will get under way before October-November.

This does not mean that Iraq's expansion of it oil production capacity will stop; rather, the full hoped-for 500,000 b/d incremental output rise might not be achieved during the year.

Majors are already assisting local state-owned production companies by advising them on work and providing training, in programmes that have proven to be very successful. Unfortunately the long-term link guarantee against political changes to their involvement that the companies are asking for will remain a stumbling block, as the government will not be able to rush any laws to that extent through parliament in the current political stalemate, especially regarding the increasing sensitivity of the issue.

However, if it bypasses the parliament—by the issuing of a decree of some sort—the chances of it being seen as illegitimate by a successor government will be very substantial, raising the risk of its overturn.

DNO cuts stakes in Iraqi Kurdistan fields to bring contracts into line with Iraqi law

Norway's DNO has taken a cut in its licence shares for two Iraqi Kurdistan tracts, the company said in a statement.

Its Dohuk licence has been divided into two licence areas, where DNO will retain a 55% stake in the tract that includes its Tawke field discovery, while cutting its share to 40% in the licence comprising the remainder of the Dohuk area.

The company has also cut its Erbil licence stake to 40%, from the 55% stake it previously held in both its original Iraqi Kurdistan exploration and production (E&P) licences.

DNO also revealed that it has agreed to altered cost recovery and profit oil rates, in which the revenue-sharing mechanism will be set to DNO receiving 60% of revenues up to a gross revenue of $484m, after which standard cost recovery rates will apply.

The Norwegian company also announced initial successful results from its Hawler-1 discovery well, which it hopes will lead to development of its second field in the region. The well flowed 9,000 b/d in initial tests, but will be drilled to deeper levels.

Significance: DNO has updated and brought its production-sharing contracts (PSCs) in line with the oil law enacted by the Kurdistan Regional Government (KRG) last year. While the cuts sound substantial, the actual change was not particularly unexpected and DNO's success to date has by far exceeded initial expectations.

With DNO's legal framework finalised, the focus would now be placed on securing DNO access to export routes.

The KRG's dispute with Iraq's central government over the control of the region's resources, together with geopolitical realities, has hitherto denied the region the ability to export its production, forcing DNO to limit its production to only satisfy domestic demand and sell its output at a discount.

A continued campaign for export rights will require the Iraqi government's consent and a political push by the Kurdish factions for the replacement of the centralisation-leaning current oil minster, Hussein al-Shahristani, can be expected.

Shell's Pearl GTL Project in Qatar eyes good profitability despite huge construction costs

Shell's Pearl GTL plant in Qatar is likely to have a pay-back time of as little as four years, given the current high oil prices and despite the fact that the project, which originally was budgeted at around $5bn, will come in somewhere between $12-18bn, or more.

In a report by Upstream, the integrated Pearl GTL project is said by observers to be able to bring in $4.5bn per year at oil prices of around $50 per barrel. The 140,000 b/d facility will come onstream at the end of the decade, converting 1.6 billion cf/d of gas produced by Shell at Qatar's offshore North Field into high-quality fuels, as well as treating an additional 120,000 boe/d of condensates, ethane and LPG.

The project is thought to have a development cost of between $4-6 per boe, according to Upstream, and international consultants Wood Mackenzie have put the project's net present value at $27bn, based on a $65 oil price per barrel and assuming a capital expenditure of $15bn.

Significance: Spiralling construction costs have led to the scrapping of several GTL projects around the world and in Qatar, where ExxonMobil withdrew from a proposed large-scale GTL venture some years ago, doubting its plant's profitability.

The news from Shell, Wood Mackenzie and industry insiders in Upstream, however, indicate that news of the GTL technology's low-profitability in a high-construction-cost environment has been severely exaggerated, especially considering the growing demand for the cleaner fuels produced by GTL plants in the United States, Europe and parts of Australasia remains undented.

While there might therefore be some reason to revisit suggested GTL projects, the Middle East and North Africa (MENA) offers some reasons for caution. The generally high domestic fuel subsidies and reliance on refined products imports in many MENA states makes GTL ventures highly uneconomical as soon as parts of the production have to be sold domestically.

Gas exports from Egypt to Israel commence through EMG Pipeline

Egypt has commenced commercial gas exports to Israel through the East Mediterranean Gas (EMG) pipeline, terminating in the Israeli port city of Ashkelon.

As Global Insight reported, initial flows commenced late last month between the countries, with flows now being reported to have reached full volumes.

Egypt has committed to supply 1.7 bcm/year to Israel, transported through a 100-km pipeline from Egypt's El-Arish port, which has been constructed by France's Technip since the agreement was reached in 2005.

The deal has, however, become increasingly controversial, not only because of the increased violence and political stand-off between the Hamas-ruled Gaza strip and Israel, but also because the $2.75/million British thermal unit price agreed in 2005 is seen as very low today and aggravated by Egypt's need to import fuel oil at higher costs in order to meet its own domestic electricity demand, Upstream reported.

Significance: As Egypt has moved to renegotiate many of the prices from its other gas export deals, the EMG deal is likely to come under significant pressure in the future, although Egyptian-Israeli relations remain fraught and the move will be interpreted by some on the Israeli side as a way of demonstrating intransigence against the Israeli government.

The price is, however, very low and since Egypt will suffer from a tight gas market for some time yet, before new production comes onstream, a revision of the price to more international levels would be appropriate.

Clients pressed to pay higher price for Egyptian LNG

Egypt is pressing its LNG clients to raise the price they are paying for their long-term contracts, Upstream reports.

The Egyptian government is seeking to receive a sale price of around $7/million British thermal units (mmBtu) for the LNG from Gaz de France and Spain's Union Fenosa, which are the largest offtakers of LNG from the country's two LNG plants.

Significance: There are two main reasons for Egypt's push for reasonably large upwards price revisions. Firstly, its domestic gas demand has outstripped production development recently, creating gas shortages and forcing the country to import fuel oil to feed some of its power plants.

This has raised the domestic power supply costs significantly, while most of Egypt's LNG export agreements were reached before the liquefaction plants came onstream in 2004/2005, when world market prices were significantly lower.

The second reason is Egypt's capped domestic gas prices, which it pays IOCs for the gas they produce and have to sell domestically. As it is chronically unable to offer a market price for the between two thirds and three quarters of gas production it forces the companies to sell at government-set prices, exploration and development in more expensive offshore areas—where the highest potential exists—have been suffering as a result.

While the government has addressed that by somewhat lowering the share they need to supply to the domestic market, it cannot lower it enough—given the tight supply situation—and so trying to raise the IOCs profit margin on the amounts they export instead is another way of making their Egyptian operations more profitable and encouraging further deepwater exploration and development.