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Egypt Is Frantic For New Gas

Dreams of new LNGs may be deferred as Africa’s largest domestic gas market fails to make new discoveries

EGYPT’s GAS RESERVES NEARLY TRIPLED from 23Trillion cubic feet (Tcf) in 1995, to 67 Tcf by the end of 2005, allowing the country to commission two LNG trains of 3.6Tcf in the same year. The government hopes the reserves will almost double to 120 Tcf by 2011, so that Egypt could host three new LNG trains, exporting 3 billion cubic feet per day.

But that may be far fetched. None of the handful of discoveries in the past year has been huge enough to support the addition of another LNG train — let alone the government’s wild hopes for a doubling of exports.

Of the 15 discoveries in 2006 (by early November figures), only four tested up to 20Million cubic feet per day. 2005 was slightly better, with 38 discoveries.

These don’t match the sort of discoveries that helped boost Egypt’s reserves in the last 11 years.

It is not just the lack of new big finds that worries companies wishing to export LNG. Domestic gas demand has accelerated in the last few years, putting pressure on the scant reserves that have been found. The government places a high premium on domestic gas use, often saying that two-thirds of gas discoveries to be set aside for domestic use and as a strategic reserve, explorers must find three times as much gas to support their export plans.

That would not bother producers if it were not for the second problem: the low price of domestic gas in Egypt, which sells for just $2.65/MMBtu. At that price, more and more of the expensive offshore work is beginning to look uneconomic, in the view of international oil companies (IOCs), especially in the wake of rising rig and production costs in the sector.

Low domestic prices are a deliberate government policy in Egypt; it’s a policy that has made it Africa’s biggest consumer of own gas and it would be a politically difficult decision to adjust domestic prices to international prices. Still, some operators argue that such subsidies are a huge disincentive to exploration. There’s a middle of the road solution: While Egypt may not cut the subsidy on domestic prices, the authorities seem ready to allow operators to develop whatever new discoveries they find for export purposes.

That’s part of the reason why there was so much enthusiasm, for the 2006 bid round by state gas company, EGAS.

Still a key challenge is that companies are impatient about long term exploration in frontier basins when the price doesn’t look right. Apache sold its deepwater acreage in mid 2006, citing increasing costs of rigs. Late in the same year, Shell withdrew from the West Manzala and West Qantara exploration blocks, and an LNG cooperation agreement with Centurion was also terminated.

BG has maintained a relatively good record as an oil finder, it only recently encountered new gas in deepwater; the commerciality of Mina I and Silva 1 are currently being evaluated.

Shell, on the other hand has had far less than it forecast, to report on its North East

Mediterranean (NEMED) Concession. Appraisals of the discoveries have suffered delays, and the company’s initial claims of up to 15Tcf in the acreage is not holding up.

Sources have suggested that the NEMED may not prove up to 2tcf, which is less than enough to support an LNG train.

Apache is relatively on the roll. The small pockets exploration in Egypt in the last two years have of discoveries that have been the rewards of been mostly Apache’s. “They are like local champions”, says an earth scientist at EGPC. Apache is strong in the Western Desert, holding the turf away from the Nile Delta and the Mediterranean deepwater, which it sold to Amerada Hess earlier in 2006. Apache spent $700millionto drill l70wells in 2006. The company has drilled more than 700 wells in the last decade in the western desert, with 50% success rates and 90% in delivering to the market. Out of 38 discoveries in 2005, 16 were Apache’s.

EQUATORIAL GUINEA’s Bullish On Gas Investment

The small Island Nation is in A Race To Monestise All Its Methane

SIX YEARS AFTER ITS FIRST GAS utilisation project came on stream, Equatorial Guinea will be completing a far bigger facility. First shipments from the LNG plant under construction on Bioko Island could start as early as mid-2007. The new dates are at least four months earlier than the earlier announced November 2007; the Train 1 project was about 95% complete as of the time of this writing. The plant is located at Punta Europa, on the northwest side of Bioko Island. The first LNG train will operate at a rate of 3.4million tones per annum ( MMTPA). The second train, with a planned capacity of up to 3.8 MMTPA, is expected to be operational latest 2010.

Feedstock gas for the first train will be primarily sourced from the 4.4 Tcf (gross risked) Alba field operated by Marathon (63.25%), but additional gas could come from yet- undeveloped reserves in the area and from ExxonMobil’s Zafiro field, of which approximately 3 Tcf is expected to be produced through the LNG plant under the contract with BG.

Much of the gas for the second train will be supplied by Nigeria, whose state hydrocarbon company, NNPC, has signed an agreement with Equatorial Guinea’s authorities for the delivery of 600 to 800MMsf/d by 2009. There’s also promised supply from Cameroon. Additional reserves discovered by Marathon in the Alba Block (Deep Luba, Gardenia, Estrella) and in the neighboring Block D (Agate, Bococo) would not be produced before 2009/2010. The recent gas and condensate discoveries in blocks B and O could bring further resources.

From the onset, Equatorial Guinea had always wanted to utilize its gas resources. Compared with most of the hydrocarbon producers in Subsahara Africa, the country is a late bloomer. The small island nation of less than half a million people started producing hydrocarbons- condensate precisely-only in 1991, when the Alba field came on stream. Gas produced in association with the condensate was flared. But it would take only 10 years for a major project to put out the flares and monetize the gas would take off. In May 2001, Atlantic Methanol Production Company (AMPCO), a consortium consisting of Marathon, (45%), Noble Affiliates Samedan Oil Corp. (45%), and the Equatorial Guinea government (10%), completed a new $450 million methanol plant on Bioko. The tanker “Noble Spirit” left the methanol plant on the Bioko Island for the European market with 41,000 metric tons of methanol on board.

The LNG project continues Equatorial Guinea’s ambition of converting gas to money at the slightest opportunity. The interests in the Equatorial Guinea LNG project are shared between Marathon Oil Corp. (60%), the state-run Sonagas (25%), Mitsui (8.5%), and Marubeni (6.5%). Total costs are estimated at $ 1.4 billion. BG Gas Marketing Ltd signed a Letter of Understanding (LoU) for the purchase 3.4 MM TPA of LNG (approximately 460MMcf/d) over a period of 17 years.

Nigerian Gas: A Steady growth In Domestic Demand

 By Angus Djibouti

FO HEAR THE COUNTRY’ S MINISTER of energy tell it, Nigeria’s domestic gas utilization is low. “The power sector accounts for 90% of domestic consumption” says Edmund Dakouru. For the time being, that is no more than 800Million standard cubic feet per day, supplied to four thermal stations, collectively generating 2,500MW at peak. Other potential consumers of relatively large volumes of gas, such as cement manufacturers and the fertilizer industry, are only just scrambling to get up to their feet. Nigeria’s still struggling to increase the in-country demand for Liquefied Petroleum gas, targeting a measly per capita consumption of 3kg by 2008. All of which explain why the offshore market is the main destination of Nigerian gas.

But several initiatives, related to the ongoing power sector reform, the privatization of government owned companies and the emboldening of local enterprise, are giving rise to projects that will lead to projects that can only boost domestic gas use. A 150MW power plant, constructed by the River State government, was commissioned late November. Its turbines are being run with 45MMscf/d of gas from Agip’s Obrikom gas field.

The Nigerian government itself is constructing seven Thermo electric plants, under the Niger Delta Independent Power Project (NIPP), expected to consume as much as 650MMscf/d at peak capacity by 2010. Outside of the NIPP, four other government owned thermal plants are under construction in Geregu in the north of the country, Alaoji in the east, as well as Omotosho and Papalanto in the west. They will all guzzle 430MMscf/d. Pressured by the Nigerian government, major oil operators in the country-Shell, Chevron and TOTAL -are all currently engaged in various stages of construction of IPPs. Agip’s 480MW IPP has been put on stream, and its gas consumption is already accounted for in the figures stated above. ExxonMobil has been quiet on commitment to build IPP, which the Government encourages fervently, but Shell, Chevron and TOTAL have publicly stated their commitment to build power plants with total capacity of 1,828MW, expected to consume around 533MMscf/d at full throttle.

The liberalised power sector witnessed the commissioning, late 2006, of a 135MW plant to energise a new cement factory in Obajana, in Nigeria’s middlebelt. An eight inch, 90km buried gas pipeline was built from the main ObenAjaokuta gas pipeline to the site of the cement factory, supplying 60MMsf/d at take off, for firing the gas turbines as well as the kilns, with the capacity to grow to 90MMscf/d when the entire cement plant is completed.

The same gas entity, the Nigerian Gas Company, will be supplying an initial 48MMscf/d to Notore Chemicals, which recently bought over the state owned fertilizer company, the National Fertiliser Company. It would be the first time ever that a fertiliser company in Nigeria would be requiring natural gas. Under Notore’s 20 year

contract, the initial 48 MMscf per day is expected to rise to 143 MMscf per day to support Notore’s aggressive expansion programme. Notore hopes to produce 1,700 tonnes per day of urea on  commencement in March 2007, increasing to 3500 tonnes per of urea by 2010 under a second  project phase. The 20 year contract will cater for the first two phases of Notore’s urea production, but the company is looking ahead to a third project phase with the construction of a large scale plant which will take its urea production capacity up to 6,500 tonnes per day.

In Lagos, Shell is expected to supply gas to Shoreline Power, a Nigerian company planning to build a 40MW power plant in Agbara, in the west of the country. Shoreline Power acquired the ABB switchgear manufacturing facility in Lagos and is working on purchase of the ABB manufacturing facility and this is its first project outside of those it inherited. Shell is also supplying gas to a proposed power plant to be cited near the Aba industrial city in eastern Nigeria, but the project too is still at formative stage. Shell Nigeria gas says it would be supplying up to 25mscf to the IPP and other industrial customers around Ossisioma and gas supply would be extended to Owerrinta and other nearby industrial facilities in the near future.

What’s significant about these activities is that they may be small individually, but they are all coming together at the same time.

Initial oil production had associated gas which was flared, since the production areas in the Niger Delta were too remote from nascent industrial areas in the western region. Earliest use of gas in the sixties were solely for power generation while the first gas utilization for a petrochemical plant was at Eleme (now Indorama) Petrochemical in 1993. The first gas export was in the form of LPG from the Escravos Gas Project in 1997. An exponential increase in gas export was achieved in 1999 with the commissioning of the Nigerian LNG at Bonny which has been expanded from one to five trains with a sixth under construction. The success of the NLNG Bonny in response to global energy demand has resulted in the planned establishment of two other LNG projects to be sited at Brass and Olokola. These two LNG projects are expected to be operational in 2009. The 11 power plants currently under construction by the Nigerian government as well as those being built by the oil and gas operators are expected to add 7,250MW to the national grid. The resulting upsurge in the demand for gas for new projects has thrown up challenges that Dakouru, the energy minister, considers urgent, “in order to enable monetization of gas assets match the revenue accruing from oil by 2010, based on our projections”. The challenges include: Gas gathering infrastructure (backbone network in both onshore offshore with looping to enable switching of supplies in the pipeline network to where gas is mostly required)

  • Fair pricing mechanism
  • Determining actual gas reserves through collating dispersed gas data from all operators
  • Effective gas policy sustained by an effective regulatory agency to administer the sector
  • Securing investment from international investors to reduce dependence on projects from JV operators
  • Creating avenues for involvement in the gas chain
  • Investment in the development of new gas technology in order to be in the vanguard of cutting edge technology.

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