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Algerian Bid Round Is A Tssst

American companies stay out of the race

Algeria’s 7th bid round didn’t turn out to be the big bang that the energy press had expected. As it happened, only four bids were received and four awards made. They all went to European companies: OAO Gazprom, Eni SpA, BG Group Plc, and E.ON AG.

At the first announcement in July 2008, more than 50 international companies expressed interest in bidding and numerous firms were pre-approved as operators. Somewhat surprisingly.

However, with the recent economic downturn the actual bidders were few. According to Chakib Khelil, Algeria’s Petroleum Minister, only four of the 16 blocks on offer received bids.

The four licenses went to Russian, European, and UK firms including Russian gas giant Gazprom, who was awarded the El Assel license. BG Group plc won the Guern El Guessa license. Italy’s Eni was awarded an exploration license in Kerza, while E.ON AG’s Ruhrgaz won the Rhourde Yacoub permit.

The 7th international bid round was the first to be held under a 2006 law that gives state parastatal Sonatrach at least a 51% share in every oil and gas exploration contract with foreign partners. This, in addition to the current economic crisis which has E&P company shares trading at a huge disadvantage, and the difficulty in accessing capital, could all have contributed to the low level of participation.

Khelil said the government planned to launch another round in 2010 to award those zones included in the 7th exploration and production licensing round. “We will launch another tender next year after evaluation,” he said after the bids opening ceremony.

Canamens Ventures into Eassaouira

Canamens has signed a suite of agreements — including an Association Contract, a Petroleum Agreement and a Reconnaissance Contract, along with associated permits and a license — to explore for oil in Morocco.

These agreements were signed in Rabat on December 15, 2008 between Canamens and Morocco’s Office National Hydrocarbures et des Mines (ONHYM).

The first agreement is a Reconnaissance Contract in respect of the “Essaouira Shallow Offshore” area, located in shallow water (<500 metres). Canamens will reprocess and acquire new 2D seismic and following evaluation prospectivity, decide whether to convert the license to an exploration permit, or elect not to proceed.

The second and third agreements are an Association Contract and Petroleum Agreement which govern four Exploration Permits for a similar location but in deeper water (generally over 500 metres), the “Essaouira Deep Offshore” area. Under these agreements Canamens will reprocess and acquire new 2D seismic and, following evaluation, have the option to extend into a second period with an accompanying 3D seismic and drilling commitment, or drop without further obligation.

Under these agreements, which cover an area of over 11,000 square kilometres, Canamens will be the operator with a 75% equity stake in both the Reconnaissance Licence and the Exploration Permits, with the remaining equity held by ONHYM. Canamens will bear 100% of the costs up until the development stage. The agreements represent Canamens’ first investment in Morocco.

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.




Afam Power Plant Is Far From Ready

Shell Nigeria has completed one of the three, Open Cycle gas turbines in the Afam Power Plant, but the facility cannot run, in part because of the vandalisation of the Alakiri gas pipeline. This is contrary to the widespread rumour that the recent, slight improvement in Nigerian power supply was due to the commissioning of the Afam power plant.

The company plans three 147MW Open Cycle gas turbines, (totaling 441MW) and one 200MW steam turbine which, when coupled with the three gas turbines, makes the Afam plant the biggest combined cycle power plant on the African continent.

But there are several obstacles on the way to delivery.  The entire plant may be ready for commissioning a year from today, but the transmission grid, as it is, is not stable enough to transport the power.

Afren to Develop Gas Assets with EDF, Gasol..

Afren, the AIM listed, Africa focused operator, has signed a Memorandum of Understanding (MoU)  with Electricite de France (“EDF”) and Gasol plc to examine  a gas aggregation joint venture to identify and develop stranded gas assets in certain identified West African countries.

The proposed joint venture will develop gas to proven status, construct requisite collection networks to aggregate, and deliver the gas to a central gas processing hub for domestic use and/or export to global markets as Liquefied Natural Gas (‘LNG”). It is envisaged that Afren and EDF will share participation in developing the exploration and production gas assets to proven status, and that EDF and Gasol will share participation in the collection of the gas, and its processing, liquefaction and monetization.

Afren already has a co-operation agreement with E.ON Ruhrgas AG and Gasol, to investigate the availability and accessibility of gas in Nigeria, with a focus on the Anambra Basin and south east Niger Delta, announced in January 2008.

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