North Africa’s energy exporters are badly in need of foreign investment and technology to extract oil and gas from ever more difficult reservoirs, and to battle decline at the many mature fields in the region. The sharp rise in domestic gas consumption has added extra urgency to that imperative. But the political uncertainties and tough operating conditions facing companies in Libya and Algeria have obstructed progress on certain key projects and threaten to deter participation in Algeria’s forthcoming bid round, according to IOC representatives attending the North Africa Oil and Gas Summit in Tunis last week. Simon Martelli reports from Tunis.   

“What I think, and what we have seen in the last one or two years, particularly in Algeria, is that new investments will be much lower than they used to be,” RWE Dea’s General Manager for New Ventures in the Middle East and North Africa Manfred Bockmann said on the sidelines of the conference. “In my view this will also be reflected in the current bid round in Algeria.”   

Around 87 companies are believed to have pre-qualified for the licensing round that closes in December, with 20 having discussed with upstream regulatory agency Alnaft the blocks they are interested in. Algeria hopes it will compensate for the poor results of the previous tender a year ago, and finally see the awarding of the gas-rich Ahnet concession, with its recoverable reserves of up to 5tcf. Algeria’s Ministry of Energy and Mines pledged to improve the conditions for IOCs’ participating in the next tender, and in a recent interview the minister, Chakib Khelil, claimed that “all the changes desired by the companies” had been introduced.

Marginal Improvements In Algeria

But this is flatly denied by senior executives of companies planning to bid, one of whom described the contractual improvements as “very marginal.” And companies with operations elsewhere in North Africa, like OMV, are staying away because they do not see how exploration work in Algeria makes sense commercially with the existing terms. Renewed exploration activity is crucial to Algeria’s success in maintaining its 85 bcm/year export target over the long-term. But the development of Ahnet is of more immediate concern, being an essential part of the southwest gas development project that Sonatrach is in the process of sanctioning.

Development plans for GDF Suez’s Touat concession and Total’s Timimoun concession were agreed to in July and October respectively, after some delays (MEES, 12 October). This leaves only the plans for the Repsol-operated Reggane Nord concession to be authorized, for the initial 8 bcm/year phase of the project to get fully underway, and this is expected by January next year. But MEES learns that Timimoun was in fact sanctioned in January, nine months before Total received official authorization. Sonatrach is understood to have imposed tight margins on its partners in the southwest, and real concerns remain about the commerciality of the project.

“Reggane Nord will require around 70 development wells, each costing between $15-20mn,” says Felix Castaneda Ortega, Repsol Libya’s General Manager. “So it’s over $1bn just for the drilling, and that’s just half of the capital expenditure. It also has around 4% CO₂ . So we need to do sequestration. To make this fly, we would need the proper price environment, the proper tax terms and long-term stability.” The project, now expected on-stream in 2014, will feed into the planned pipeline connecting all the tight gas fields in the remote southwest to Algeria’s main gas hub at Hassi R’Mel.

Another important gas development that has suffered unforeseen delays is the installation of a low-pressure compression project at the Tin Fouye Tabankort field, Algeria’s second largest, which is designed to maintain its production plateau. Jointly operated by Sonatrach and Total, the field was brought on stream in 1999 and is currently flowing 6.8 bcm/y of gas, with production due to start declining in 2012. But the implementation of the compression project, which is finally due to start-up at the end of 2009, was delayed by two years, MEES understands, with negative consequences for the field’s output.  

Libyan Surprises

The uncertain investment outlook for IOCs operating in Libya has been more palpable than anywhere else in the region, as illustrated by the surprise resignation in August of the National Oil Corporation (NOC)’s Chairman Shukri Ghanem, and his even more surprising re-instatement last week. Given the potential reward on offer in Libya, the risk and uncertainty of doing business there has not deterred any of the major oil firms from returning since sanctions were lifted. But it is undoubtedly a factor in Libya having to revise down its medium-term oil production targets, from 3mn b/d to 2.3mn b/d.

“What we need in this industry is stability,” says a senior executive at a major oil firm operating in Libya. “We need good planning. We need to be able to make long-term investment forecasts. We already have geological uncertainty. But when we also have uncertainty about who is in charge, it makes [investment decisions] extremely difficult.”

One of the most pressing issues for IOCs currently operating in Libya is the re-negotiation of old EPSA contracts into the new EPSA-4 model. Virtually all of the foreign producers in Libya agreed to amend or “upgrade” their contracts in the past two years, taking a considerably smaller share of production in all cases, in return for license extensions (MEES, 12 July 2008). By contrast, numerous pre-EPSA-4 contracts still in the exploration phase have yet to be renegotiated. Repsol and RWE, for example, are now submitting development proposals for oil discoveries made on some of their pre-EPSA permits, and this seems likely to result in protracted contractual negotiations, which would in turn delay their development projects.

“So a project which may have looked very attractive five years ago is not now, because you are forced to move from EPSA-3 to EPSA-4,” says RWE’s Manfred Bockmann. “And that’s the main problem in Libya. The NOC or this governing framework is a bit unpredictable. And on top, you have these strange moves from NOC, as you see in the example of Verenex.”

Rising Egyptian Gas Demand Thwarts New LNG Plans 

In striking contrast to the uninviting investment climate in Libya and Algeria, Egypt has demonstrated remarkable flexibility towards its foreign partners and succeeded in attracting substantial foreign investment, especially in the challenging but gas-rich Mediterranean deep waters. This is illustrated by the meteoric rise in Egypt’s production of sales gas, from just 1.8 bcf/d ten years ago to around 6 bcf/d now, 76.6 % of which comes from the Mediterranean.

Speaking on the sidelines of the conference, EGAS Projects and Planning Manager Hasan Sabry insisted that Damietta LNG train 2 had not been cancelled, but simply postponed, and underlined the fact that the government’s priority was to supply the local market. Contrary to previous comments by senior officials from the Ministry of Petroleum, Mr Sabry said that neither of the two partners in the planned 5mn tons/year LNG project at Damietta, namely BP and Eni, had provided a certificate of proven gas reserves, as required by the ministry, and that one of them had in fact withdrawn from the project, while declining to say which. The EGAS official added that, due to the rise in local consumption, Damietta train 1 was still running at well below capacity, “maybe at 60-70%.” 

Eni’s Vice-President for Exploration and Production in the Maghreb, Abdurahman Benyezza, speaking earlier, had said that the company was still negotiating with the Egyptian government for the new LNG train, for which he said the firm had already identified reserves “to meet Egypt’s domestic requirements and to feed a second train.” Total Egyptian gas reserves discovered by Eni between 2004 and 2009 stood at 12tcf, according to Mr Benyezza.

But the sharp rise in local gas demand in Egypt remains a key obstacle to future gas exports, as clearly illustrated by the gas pipeline project connecting Bani Sueif to Aswan in Upper Egypt, the last leg of which is due to be completed this month. The pipeline, which has cost E£5bn ($910mn) to build and will have a capacity of around 9 bcm/y, will mainly supply industrial customers, including petrochemical plants and cement factories, in Upper Egypt. The Dahshour compression station, which should enable the pipeline to operate at full capacity, is due for completion in mid-2010.

© Copyright MEES 2009.