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Algeria’s Oil and Gas Income likely $76bn in 2008

Algerian oil and gas revenue could reach a record high of $76billion in 2008,Energy and Mines Minister Chakib Khelil has been was quoted as saying. This compares favourably with $59billion in 2007. ‘The expected revenues of between $75billion and $76-billion are a record,” the official APS news agency quoted him as saying.

Algeria’s state energy conglomerate Sonatrach earned $57billion in 2007 from producing and selling oil and gas, while the state earned a further $2billion from a windfall tax on the earnings of foreign energy firms operating in Algeria.

Khelil said in May 2008 that Sonatrach expected to earn about $81billion in 2008 if oil prices stayed high. Prices at the time were about $111 a barrel and have since collapsed to around $45.

British Petroleum, Amerada Hess, Statoil, Anadarko Petroleum Corp., Repsol and TOTALare the main foreign companies involved in exploration and production of hydrocarbons in Algeria.


Mozambique Gets Funding For Power Project

The World Bank has released $88Million to fund the construction of transmission lines to carry power from Mozambique’s Cahora Bassa Hydroelectric (HCB) dam to Malawi.

The power transmission line, to be erected as part of a Southern Africa Development Community (SADC) energy co-operation agreement, will have an average capacity rating of 300 megawatts (MW). The project is expected to get underway in 2009, following a public tender for the venture.

$43 million of the World Bank funding is to be used for projects in Mozambique and the remaining $45 million in Malawi. Mozambique will enlarge the Matambo substation (in Tete province) and build transmission lines to the Malawian frontier, from where Malawi’s utility will construct a line to the Phombeya region, site of a planned new substation being built as part of the same project.

The new infrastructure is expected to boost Mozambique’s position as one of the primary electricity exporters in the region at a time when the energy crisis demands increased cross-border cooperation to respond to potential negative impacts on development projects. Mozambique is aggressively investing in its power infrastructure to solve the regional power crunch, which had caused many mega-projects to grind to a halt.

The government has approved the construction of an $800 million power station in the northern province of Tete starting from 2009, to boost regional power supplies. Building another power station would increase Mozambique’s capacity to export electricity to other southern African countries, which have been affected by a power crisis.

HCB has exhausted the maximum capacity of 2,075 MW of power it could produce from its generators on the southern bank of the Cahora Bassa river.

HCB, which suffered decades of neglect and lack of investment, now provides 60% of its power to South Africa’s state utility Eskom and 35 percent to the Zimbabwe Electricity Supply Authority (ZESA).

Mozambique consumes the rest of the power.  Only 15 percent of the country’s 20 million people have access to electricity.


First Oil from Uge Not Anytime Soon

Partner issues have forced the postponement of first oil from ExxonMobil operated deepwater Uge field from 2013. “We cannot say for certain whether the field would even get on stream by 2015,” say officials of the state hydrocarbon company NNPC, whose decisions are central to the delay. NNPC has ruled against the operator’s plan to refurbish and deploy the Falcon, first used on the company’s shallow offshore Yoho field, to the smaller Uge field. NNPC, with the support of other partners in the project, has instead called for a new build FPSO, which ExxonMobil complains has pushed up costs. Uge was discovered in 2005 in 1,350 metres of water in the Oil Prospecting lease (OPL 214) in the Western Niger Delta, offshore Nigeria. An appraisal well confirmed the discovery and provided the major input for a field development plan that called for at least two more wells to drain the reservoirs. ExxonMobil operates the OPL 214 with 20%. Partners include Phillips 20%, Chevron 20%, Occidental 20%, NPDC 15°o and Sasol 5%.


PGS In Best Quarter Ever

With strong Multiclient sale in West Africa and Brazil, and an overall robust performance by the group, PGS has announced its best quarter ever with an increase in revenues and earnings before interest and tax (“EBIT”) of 15% and 12% respectively from previous records.

The order book increased in the third quarter of 2008 to $ 1,193 million.

MultiClient late sales were $48.2 million in the third quarter of 2008 compared to $47.7 million in the third quarter of 2007, an increase of $0.5 million, or 1%, primarily reflecting increased sales in Brazil and West Africa, offset by lower sales in Gulf of Mexico and Europe. Record order book: Order book at the end of the third quarter of 2008 was $933 million for Marine and $260 million for Onshore, up a total of 1000 from Q2 2008.

Overall the Norweigian geophysical acquisition and processing company had revenues of $534.3 million, up $95.2 million (22%) from Q3 2007 and $69.2 million from previous record set in Q2 2008. EBIT of $187.8 million, up $20.4 million (12%) compared to the record set in third quarter of 2007.

“We delivered the strongest quarterly operating profit ever. Our order book of approximately $1.2 billion, combined with our sound profitability and competitive operations, provide a strong platform going forward. In addition, we have robust financing in place with very attractive terms and mainly fixed interest rates”, commented Jon Erik Reinhardsen, President and Chief Executive Officer of PGS.

 


World Bank Spends $2.7 Billion On Green Energy

World Bank funding for efficient and renewable energy rose 87% in 2008 to nearly $2.7billion, reflecting the importance of moving to a low-carbon economy. Funding in fiscal 2008, ending June 30, was nearly double the previous year’s $1,4billion, which in turn was 67% higher than in fiscal 2006. Investment in “green” energy projects is essential for poor countries hit hard by soaring oil prices, says Jamal Saghir, World Bank Director for Energy, Transport and Water. “What’s affecting the poor countries is not only the oil price increase, it’s the volatility as well which is creating vulnerability at the same time,” Saghir says. “That’s why you look at alternative sources of energy.”

Rising traditional energy prices has made alternative energy, such as wind power, more attractive and affordable in the developing world. Commitments for 2008, including carbon finance operations and support from the Global Environment Facility, consisted of the following:

  • “$1,1-billion for energy efficiency;
  • “$476-million for new renewable energy projects including wind, solar, biomass, geothermal and hydropower projects that will generate up to 10 MW per facility;
  • “$1-billion for hydropower projects with capacities of more than 10 MW per facility.

Fear of the effects of climate change also encourages developing countries to find ways of emitting less climate-warming carbon, Saghir argues. The high cost of traditional energy and acute power shortages have spurred demand for energy efficiency projects, according to a statement by the bank. Such projects are being put in place in China, Pakistan, Argentina, Ukraine, Burundi and Zambia, among other countries.


OPEC Reduced Growth Forecast, Cuts Production

OPEC, the Organisation of Petroleum Exporting Countries, has slashed its oil consumption growth forecasts for the rest of 2008  and 2009. The cartel has also agreed to cut production by 1.5 million barrels a day (BOPD).

The reduction in forecast growth is principally because of an “excessive” easing of demand in the United States, where many analysts foresee a recession looming. The

Production cut, however, responds to a more urgent situation: an ‘unprecedented’ fall in prices and fears over short-term demand.

OPEC lowered its estimate for growth in demand for the rest of 2008 by 330,000 barrels per day to 550,000 BOPD, giving average total demand of about 86.5 million BOPD. For 2009, it cut its forecast by 100,000 BOPD to 800,000 BOPD, to put average total demand at 87.2 million barrels per day.

The group says that the drop in oil prices could lead to the cancellation of existing oil projects, resulting in a medium-term supply shortage. “Oil prices have witnessed a dramatic collapse, unprecedented in speed and magnitude.. .which may put at jeopardy many existing oil projects and lead to the cancellation or delay of others.”

The 1.5 million BOPD cut will bring the current production ceiling of 28.8 million BOPD to 27.3 million BOPD, from November 1, 2008. It is the first production cut made by OPEC in two years. The decision will be reviewed at its next scheduled meeting in Algeria on December 17, 2008.

OPEC has called on non-OPEC producers and exporters to restore prices to “reasonable levels”, saying it cannot be expected to bear the burden of restoring equilibrium to the market on its own. Weak US oil demand would bear down on the oil market “at least in the first half of 2009.”

It cited US figures to the effect that American motorists cut their driven mileage by 62.6 billion miles (100 billion km) in the first nine months of 2008. This reduction, in large part a response to higher oil prices, reduced cut total gasoline (petrol) consumption by 250 000 barrels per day.

Total US oil consumption had continued to decline “in the last month of the summer” by 7.6 percent or 1.6 million barrels per day on a 12-month basis.


Chinguetti Struggles To Grab Headlines

The Chinguetti field off Mauritania, West Africa’s biggest deepwater disappointment, has been struggling, of  late, to grab the headlines it once dominated.

The field production increased to 17,000BOPD in October 2008, following the successful completion of the C-20 well. That’s good news for a field that averaged 10,000 BOPD in the first half of the year. But the fact that this makes a big splash shows how low the reputation of Mauritania’s flagship field has sunk.

This was the field on whose fortunes, Woodside, the Australian operator, had hung its West African adventure. It was also the reason why a long list of Australian operators had headed to Mauritania at the turn of the 21st century.

Back in February 2006, when Chinguetti delivered its first oil, there was hope that it would herald a fresh start for Mauritania. Output swiftly peaked at 75,000BOPD and the first million barrel cargo was shipped to China within three weeks. The field, however, quickly ran into technical difficulties and by December 2006, it was doing barely 24,000BOPD on average. Citing complexity of field subsurface geology, Woodside drilled more drain holes. In stead of raising production, output fell to an average of 15,000BOPD in 2007. That was when Woodside decided to leave.

In November 2007, Woodside sold its Mauritanian assets for $4lSmillion to Malaysian state hydrocarbon company Petronas.

Woodside, which is one-third owned by Shell, took a hefty loss in the Chinguetti sale, which forced the Australian operator to slash its 2008 production growth estimates.

Petronas almost immediately started trying to improve results.

The experience of Chingetti has cooled the industry’s outlook in Mauritania, but there are still adventurers taking a look in.


Addax Goes to the Belly of the Beast

By Fred Akanni, Editor-in-Chief

With $1.6 billion in the bag, Addax is transiting from a production company to an Exploration and Production company. The Swiss operator is expanding its focus from the Gulf of Guinea to the Caspian Sea. Now it describes itself in literatures and documentations as an international oil and gas exploration and production (E&P) company focused on Africa and the Middle East.”

The mantra has been; first develop what assets you have, get a handle on the portfolio, build a war chest and then take more risk.

When Jim Pearce, the company’s Chief Operating Officer, addressed an audience of Nigerian petroleum geologists in Abuja, in November 2005, he came across as the spokesman of an operator which had built its portfolio by squeezing production from assets it acquired in 1998, from 8,000BOPD to 86,000BOPD, with every drop of oil produced in Nigeria.

When he returned to the country, to address a similar gathering three years later, production in Nigeria alone had reached 110,000BOPD.

The company had also added producing properties in Gabon, outputting 30,000BOPD by the end of 2007. Addax had become a deepwater exploration company by acquiring the Oil Prospecting Lease(OPL 291), considered a very prospective property in Nigeria, in 2006. By getting out of Nigeria into Gabon, Cameroon and SaoTome et Principe, Addax could by now claim it was not limited to one country, but was focused on Africa as a whole.

Mr. Pearce’s talk, delivered at a lunch hour session at the Nigerian Centre For Petroleum Information(CPI), indicated as follows: With fortune made on the continent via record oil prices and cash generated by massive sale of shares, (through which it amassed some $400Million), the Calgary listed operator has found the confidence to consider itself a global player. And it is not afraid to go to the belly of the beast: to the troubled, secessionist prone Kurdistan, in the north of war torn Iraq.

Addax formed a 45:55 joint venture with Genel Energie of Turkey to implement a 25-year production sharing agreement (PSA) it signed with the Kurdistan Regional Government in early 2004. The JV, called Taq Taq Operating Company (TTOPCO), expects to be the first international firm to produce crude oil in Kurdistan.

In the first quarter of 2008, Addax signed an agreement with the Kurdistan Regional Government (“KRG”) amending the production sharing contract to sychronize the government back-in rights at up to 20 per cent and reduce the maximum Cost Oil recoverable in a given year, which is partially offset by an effective increase through an interim period that accelerates the recovery of the initial capital investment by the Contractor. It’s worth noting that while there’s so much reference to Kurdistan as a region in Iraq, there’s no talk about any dealing with the state of Iraq itself.

In the same week that Mr. Pearce gave his talk in Lagos, Addax announced the broadening of its imprint in Kurdistan; it had acquired a 33.33 per cent interest in the  Sangaw North Production Sharing Contract (“PSC”), operated by Sterling Energy.  The licence area is located approximately 80 kilometers southeast of the Corporation’s Taq Taq field.

This clearly is empire building of sorts, and it reminds commodity market watchers of a

certain period in the life of Jean Claude Gandur, Addax’s enterprising founder, President

and CEO. In the late 1990s, just as he was taking his company to Nigeria, Gandur was

fighting a bruising battle to gain control of Ashanti Goldfields, the gold mining company that was Ghana’s prime asset.  He lost to that company’s equally charismatic CEO, Sam Jonah.  Ashanti Goldfields has since been swallowed South Africa’s Anglogold, and Mr. Gandur has moved on to equally robust “mining” company.

Addax’s decision to go further in Kurdistan can be clearly seen from the perspective of the encouraging producibility of the wells it has tested in the Taq Taq field. In March 2007, the TT-05 in flow tested at an aggregate rate of 26,550 BOPD. Three months later, the TT-06 flow tested at an aggregate rate of 18,900 BOPD. But 2007 was not just about Taq Taq. The year may be recorded as the year of high risk, high reward. That was when Addax went on exploratory campaign in those assets in Nigeria that didn’t feature highly in its initial development campaign. It drilled a successful exploration well in each of the Udele West and Ofrima North fields in 0ML137 offshore Nigeria and booked its first reserves on the license area, which itself accounts for the largest surface area of any of Addax Petroleum’s Nigerian assets. As at December 31, 2007, estimated gross working interest proved plus probable reserves were 17.1 MMBBO.

With this string of discoveries in its portfolio, Addax, agreed to take over ExxonMobil’s 40% working interest in the Nigeria/STP Joint Development Zone (JDZ) Block 1. In that same third quarter of 2007, the company increased its Gabonese production more than three-fold to an excess of 30,000 BOPD, one year after acquisition of the operations of Pan-Ocean Energy Corporation Limited. By September 2007, the company exceeded 140,000 BOPD for the first time in its history.

 

 

 


Egypt Tackles The Subsidy In Natural Gas Pricing

 By ToyinAkinosho

IN THE WEEK OF THE WORLD ECONOMIC Forum (Middle East) in May 2008, the Egyptian government was in the throes of a major overhaul of its energy pricing policy. Gasoline prices had been raised, by 50%, in part to reduce subsidies to the minimum, and further hikes were on the horizon. But the most fundamental move, as far as international investors were concerned, was the pricing of natural gas.

“We are trying to embrace liberalisation up to the reasonable limits”, said a statement from the Egyptian government at the forum.

Egypt compels international companies to commit more gas to the domestic market, in spite of the pull of the export market, where prices have reached $11.6 per million British thermal units(btu), or $11.6 per thousand cubic feet (Mscf).

Then it sells its natural gas in the domestic market to Egypt based companies at a rate far cheaper than the international market determines. Thus, companies that utilise gas to produce cement, steel, aluminium, petrochemicals and other such products in the country, pay far less for natural gas than their competitors in Europe and the United States.

Now, such energy-intensive industries are to pay more for natural gas from July 2008. The prices would jump again in January, 2009, all as part of a plan to reduce subsidies.

Egypt will hike the price of natural gas to $2.22 per million British thermal units (or thousand cubic feet) in July from $1.85 and would increase the price of electricity by 20 per cent. Natural gas prices would eventually rise to $2.65 per million British thermal units. The price increases apply to Egypt’s steel, cement, and fertilizer industries.

The Egyptian government has been reviewing the prices under natural gas agreements in reaction to the rise of natural gas prices in international markets. A significant part of this price hike extends to the preferential price that the Egyptian government has offered to Jordan, its north eastern neighbour. Egypt will increase the price of gas it delivers to Jordan via pipeline under the Gulf of Aqaba by 200%, to $4.5 per million btu. The Jordanian government has agreed to the increase, which will be applicable only to additional supplies this year(2008) and not to the supplies, agreed upon in 2001 at a price of $1.5 per million btu. The new agreement is expected to take effect by the end of 2008. It gives Egypt the right to review the price every three years to reflect changes in international prices.

Egypt has also announced an end to the tax holidays granted to companies in the free zones. About 20-25 companies operating in the fields of oil and gas, petrochemicals and fertilizers which have long term contracts will be subject to the regular 20 percent tax. “Free zones will remain,” explained Rachid Mohammed Rachid,” the country’s minister of Trade and Industry. “We are only changing the tax status of those which use oil and gas as raw material. The remaining 2,000 companies in the free zone will continue operating as usual.”

Meanwhile, the country has agreed to increase natural gas prices to international oil companies operating in five separate concessions in the Mediterranean Sea. The new price of $ 3.95 per btu (from $ 2.65 per btu, the current price) is expected to boost the field development projects planned by BG, Eni, RWE Dea and Hess.

Egypt had brought forward the date of the subsidy cuts to July from September 2008, to help ease pressure on the budget. The Egypt’s Finance Ministry is worried that, without such a move, energy subsidies would rise to $11.13 billion (or 60 billion Egyptian pounds) in the 2008/9 fiscal year from $10.57 billion(or 57 billion Egyptian pounds). “Energy subsidies are a major contributor to the government’s budget deficit”, says Youssef Boutros-Ghali, the country’s Minister of Finance. “They help to push up interest rates”.

 

 


Drilling Rates, Performance, Upset Nigerian Regulators

NIGERIA’s STATE HYDROCARBON company and its petroleum regulatory department are worried about the increasing cost of drilling in the country. They are also concerned about aspects of compliance with performance regarding budget, as well as local content in areas of reservoir studies. These issues, in addition to the usual sloppiness from government quarters have ensured that the round of budget discussion for the year 2008 have dragged into the second month of the budget year. “ExxonMobil used to be a major example of low cost and high efficiency in drilling, but now their costs have gone through the roof’, officials of the Department of Petroleum Resources complain.

Industry sources argue that drilling rates for shallow offshore wells drilled by jack up rigs have increased by 45% on average. Drilling rates for Jack Up rig have shot up from between $130- 150,000 a day to $180,000 to 200,000 per day within the last one year.

Deepwater rates for a 9,000 feet well have shot from $400,000 a day to $600,000 a day.

But government officials counter that these sort of figures don’t cut it, especially because drilling contracts are usually long term. “We’d prefer they give us item by item”, they say. “But operators flinch when you say: let us have your details”, argues a DPR  official.

Nigeria is one of the few countries in the world running Joint Venture operations, where government partners actually put money into operations.

The Nigerian regulatory authorities are also concerned that TOTAL, the French major, has not domesticated its reservoir management studies as stipulated by the local content regulations. Chevron is seen to fulfill local content regulations in reservoir management studies, but the DPR and NNPC are worried that the company is running all its key projects out of sight of the authorities. “They are not communicating adequately on South Offshore Water Injection project, North Offshore Water Injection Project, nor are we getting much details on Tubu field project.” Of all the companies, Shell has had the best rapport with the upper levels of the Nigerian government, especially the President, in the last six years, but working level government officials are wary of this relationship. And the dissonance has led to spats between these officers and the company. “They (Shell), spent money on shelf (onshore and shallow water) projects way above agreed budget last year”, grumble petroleum engineers in government, “because they had the sympathies of the last civilian administration, who approved a supplementary budget”. The officials say that the incumbent government has insisted that any detailed budget discussion has to be directly with the regulatory units, below the Minister’s level.

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