Tag Archives: Energy

The Week In Commodities

Global Economy, On the cover, Sin categoría

Despite all the intra-week volatility, which saw Brent reach the highs of $115/bbl and then retreat back the following day, both oil benchmark ended the week up (Brent +2.2%, WTI +0.9%). After more than two months of planned maintenance, the UK’s largest field and contributor to the Forties Blend, has restarted after repeated delays lasting over a month in total. This restart, however, has not been fully flawless and the field began producing between 140-170kb/d, significantly short of its optimal rate of 220kb/d. Elsewhere in the North Sea, Total’s Elgin field is unlikely to restart on schedule, and may be delayed into 2013 instead, the operator has said. This combination is likely to keep supporting Brent time spreads. In the US East Coast, a large number of refineries, terminals and pipelines have reopened after Hurricane Sandy related closures, although some not yet at full capacity. Phillips 66’s 238kb/d Bayway refinery in New Jersey is still out and is not expected to resume operations for at least another 2-3 weeks. Also in NJ, Hess’ Port Reading refinery restart date is not yet known as the operator will need all power infrastructure to be back on line before an estimated time-frame can be announced. Despite some ongoing terminal and refinery outages in the region, supply is normalising after the United States lifted the Jones Act, allowing products to be tankered by foreign-flag carrying vessels from the Gulf of Mexico into the East Coast market.Steam coal markets have staged a moderate recovery this week, as rock-bottom prices triggered some buying and short covering despite what is still a relatively poor physical demand situation globally. China’s Ministry of Railways has reported that railings on the key Daqin line to Qinghuangdao hit a new high of 1.31mt/day on November 6, up from 1.17mt/day in September and 1.01mt/day in August. Meanwhile, McCloskey China Coal Daily has reported that coal stocks at QHD have risen by 17% since 22nd October to a level of 6.06mt. At the same time, coal stocks held by six major power generators in Eastern and Southern China dropped 1.9% from the previous seven day period to 13.886mt. This is equivalent to 23.7 days of consumption, down 0.9 days w/w, however still high by historical norms.UK natural gas prices were largely flat this week. The market was up on Monday due to concerns about LNG availability given nuclear outages in Korea, but it softened through the week on better actual LNG supply into the market. However, expectations of a continuation of a cold remainder to Q4 have provided support for the curve around current levels.

US natural gas prices gained slightly after the market received a much lower than expected storage injection (+21bcf vs. +26bcf expected). Hurricane Sandy remains a net positive factor for natural gas demand as colder-than-normal-weather-induced heating demand has more than offset the power outages in the north-east so far. Furthermore, although power demand edged slightly higher during the hurricane due to the large amount of nuclear shutdowns, about 3.6 GW of nuclear capacity came back on Wednesday, while the rest should also come back to service by the end of the month. Although the boost for demand from nuclear outages is now smaller, the amount of power outages has also been reduced to 750,000 households from 8.5mn at the peak. This represents a very small amount of demand destruction that is by far outweighed by heating demand growth expected for this week.

CO2 was up 2.5% this week. The European People’s Party, the biggest group in the European Parliament, has asked the Commission to delay the set-aside proposal scheduled on 14th Nov until after the Parliament vote in April which would give the Commission the right to intervene in the ETS market. They said that the Commission said in a phone interview that it will not delay the proposal. The news highlights continued tension between the Commission and member states over set-aside. The EPP includes centre-right parties from almost all member states such as France’s UMP, the CDU/CSU from Germany and PP from Spain. The UK Conservative Party is not a member. If correct, this means that set aside proposals including how many credits should be removed will be released as planned on 14th of November. It is unclear when the Climate Change Committee may vote on the proposals, but the CCC could give its opinion on its 13th December meeting. This will be one of the key votes, and will be held on a Qualified Majority Basis. The main question is whether Eastern European countries, led by Poland, will form a blocking minority. should the set aside proposals be passed, it should pave the way to higher CO2 prices which will be especially important for generators in countries where coal sets the electricity prices, such as Germany, the Nordic region and the Czech Republic.

German power prices were up 0.4% this week. Dark spreads continued to ease and are now at the lowest level since August. Nord pool was flat this week, as gains in CO2 were offset by continuing gains in hydro reservoir levels in the Nordic region.

Baltic Dry Index lost 7.1% this week, as the weakness persisted across all the segments. While the situation in coal markets described above explains the continued weakness in Panamax, activity in the Capesize segment has also been weak as the recovery in iron ore prices has reduced the China-international price arbitrage from its peak in early September.

Massive Subsidies Endanger Spanish Energy Reform

Global Economy, On the cover, Sin categoría, Spain,
This article was published in El Confidencial on August 27th 2012 

“If technologies have economic merit, no subsidy is necessary. If they don’t, no subsidy will provide it”. Jerry Taylor.
“Governmental subsidy systems promote inefficiency in production and efficiency in coercion”. M. Rothbard

This week the press has highlighted the discrepancies between two of Spain’s top ministers regarding the much delayed electricity sector reform. The shares of many of the companies involved have moved between +7% and -6% depending on the words of one minister or another.
Let me begin by saying that I do not find anything wrong when a company hires a consultant to defend its interests and that, when they do, they do it with the best. And I believe this controversy creates a great opportunity for the government to demonstrate that their decisions are not influenced by one lobby or another, but focused on the only thing that matters: that Spain cannot continue destroying its competitiveness with a massively subsidized and inefficient energy sector, where the electricity bill has soared by 40% while demand fell and where excessive renewable subsidies count for 39% of the costs (excluding energy component) of the system.
renewables II
To eliminate the tariff deficit accumulated until 2012; electricity bills will have to go up by an estimated 35%.
The Spanish tariff deficit is the difference between the real system costs and those recognized in the tariff, where the result is an IOU from the government that is financed in the balance sheet of the companies until it is settled. This tariff deficit is part of the infamous “Spanish private debt,” which is in no small part made of outstanding commitments from the government and funded by the balance sheet of private companies. It is also the consequence of a highly optimistic central planning of the system that incentivised overcapacity and massive new build that has made companies more indebted, with or without acquisitions, and less and less profitable.
renewables I
The tariff deficit myths are:
– “Companies make billions out of it” We must differentiate between accounted and real profits. We sometimes forget that companies account for the tariff deficit as a “receivable” so their profit and loss is not made of real cash. As such they generate no free cash flow and borrow more and more. Investments in Spain, from generation to distribution, generate less than 7% return on capital employed. However, companies are told by governments to undertake massive investments, but without legal certainty or acceptable returns. And there is always someone willing to build more for less.
–  “It is a temporary problem that goes away with the latest measures.” The latest government measures to reduce the costs of the system seem to look to collect from the efficient and cash generating businesses to cover inefficiency errors, but these measures do not solve a problem of subsidies and overcapacity, as they have been mainly applied on one-off costs, with a maximum impact of 2 billion euros, yet they do not take into account that in 2013 renewables subsidies will rise by another 2 billion to almost 9 billion a year in 2014 due to the plants that are coming on stream, bringing the tariff deficit up again.
–  “Renewables are unfairly demonized.” This is true, in part. The tariff deficit is not an issue created by renewable energy, but by the excessive cost of certain subsidies-particularly solar photovoltaic- where massive premiums were given to build 400 megawatts, ending with 3000 megawatts built – the consequences of an extremely generous aid system and a poorly controlled approval system, where all regional governments gave permits to plants regardless of the 400MW limit. But who pays that “tiny” 5 billion per annum mistake?. No one has anything against renewable energy. I love to read that Spain will build nearly 600 megawatts in solar PV without subsidies. The problem in Spain is the accumulated upfront cost of those subsidies, the fact that the excess cost is not paid but deferred in the tariff, and the claim from some operators to continue with the same scheme of subsidies and installations when all 2020 targets have been fully met. Many renewable companies in Spain have followed a model of builder-developer entering a country, and maximizing capacity to move on and grow in others. But there is no eternal growth in each market.
– “Coal generates no deficit because it is a social cost.” Other subsidies maintain inefficient capacity alive, like coal, which gets 600 million a year. If the rationale to keep coal is “social” it should not accumulate costs to the power bill, but be paid by the regional governments like healthcare or social services. The problem is the habit of subsidizing outdated technologies while building up the deficit that is generated by other new technologies.
–   “The renewable subsidies are offset by the fall in wholesale prices.” The cumulative net reduction in wholesale power prices between 2005 and 2011 was less than 9.2 billion euros, according APPA- while accumulated subsidies to renewable energies shot to 25 billion in the same period. In any case, talking about the benefits of renewable energy on price is almost comical when the power tariff to consumers has risen almost 40% in four years.
–   “The tariff deficit is created by the manipulation of wholesale price by large utilities”. It would be the most disastrous manipulation ever, when wholesale prices have remained exactly in line with the energy mix, below Italy’s, France’s and Britain’s, and in line with Germany.
renewables III
–  “Nuclear and hydro should pay the deficit.” They do, but it makes no sense to use cheap sources of energy to subsidize more expensive ones. And let’s not forget the string of regional and national taxes that traditional utilities suffer.
–   “If nuclear capacity is shut down, there would be no overcapacity.” Sure, and if EDF and France dismantle their 58 nuclear reactors, there would not be any overcapacity there either. And if Saudi Arabia closes Ghwar and Khursaniyah there is no oversupply of oil. We have to take advantage of technologies that are cheap while they work, and work well, because we need cheap, non-interruptible power. We forget that solar and wind are interruptible and cannot be installed exponentially because the land occupied by megawatt is finite. And the cost of adding a network connection is not properly taken into account.
renewables IV
What has led to this problem? 
An optimistic central planning based on demand expectations -2% pa growth- which were completely unjustified, an increase of generation capacity and infrastructure -25 000 megawatts of additional capacity in gas and 35,000 megawatts of renewable- and the joy of subsidies to every technology without control –renewables, coal subsidies, capacity payments, island grants…
As subsidies mounted over each other, capacity rose and demand collapsed, we find a power system in which the annual costs -guaranteed by the state- exceed revenues by c4 billion euros … and regulation has always been modified to tax the efficient to subsidize not only “nascent” technologies, but also “dying” ones.
The solution
The solution to this issue will have to be a compromise between the industry, the entire sector-traditional and renewable-, the State and the consumer, and cancel future subsidies in all technologies. From the existing deficit, part will have to be absorbed by the energy sector, the state-responsible for the optimistic planning- and consumers, who wildly applauded the green economy and coal-mining subsidies without knowing its costs.
The German model is simple: subsidies are paid 100% by retail consumers, so people know the true costs of green energy – and 70% strongly agree- while industries, many highly energy intensive as BASF or BMW, do not pay the cost of those subsidies. Therefore, competitiveness does not sink and the country doesn’t suffer from industries closing down due to excessive power costs. Additionally, unnecessary capacity is removed, while inefficient companies go bankrupt, as they should.
The American model is interesting. Investors are given tax incentives, not direct subsidies, for renewable projects. Thus, if there is no investor interest or projects are not economically viable, the system will be reducing unnecessary capacity by the law of supply and demand and, of course, if a company has to file for bankruptcy, it does.
Spain needs to be absolutely clear in its power sector regulation, guarantee legal certainty and avoid changing rules retroactively to solve past mistakes. But the consumer cannot support all costs if everything is subsidized and if there are no market mechanisms that enable cheaper and more efficient technologies to displace the expensive inefficient ones. Our excellent renewable companies are competing exceptionally well in the previously mentioned international models. So let’s not ask at home what we don’t need abroad.
Seizing revenues from the efficient to give it to the inefficient does not help. More importantly, a couple of years later the need for revenues will make the inefficient of today suffer as well.
I commented a few months ago in my article “the problem of fixing the price of power in government offices and not in markets” that Governments and some companies do not like to liberalize. They live very well asking and giving favours while the bill is either not paid or sent to the consumer. Amazingly, while governments see power costs soar, they are surprised to see that the country’s industries close down and that demand falls.
Mistakes in planning –always from excess, of course- have led to a power sector overcapacity that has many similarities to the housing bubble. The generation fleet overcapacity in Spain is enough to cover demand for years. Let us use this opportunity to end the current tariff deficit through market mechanisms.

More on Africa… Things Just Keep Getting Better

Global Economy, On the cover, Sin categoría
africa 4
This is a continuation and detail of my previous post “Africa, the most promising frontier area” http://energyandmoney.blogspot.co.uk/2010/12/africa-most-promising-frontier-area-for.html)
 
Sub-Saharan Africa has grown to represent a material reserves base, contributing 5% of total world proved oil reserves in 2010. Most of those reserves are located in Nigeria and Angola. Africaas a whole represented 10% of world total.
Reserves growth in sub-Saharan Africahas been faster than in the rest of the world in the past 30 years and has accelerated in the past 10 years while the rest of the world slowed down.
Africa 1
Sub-Saharan Africa outside of Angola and Nigeria was the world’s fastest growing reserves base in the past 10 and 30 years.
While representing 5% of total world proved oil reserves is material in itself, in contrast with some other regions of the world, most of the reserves in sub-Saharan Africa, as well as the opportunities for reserves additions in the future, are accessible to international investors.
  1. Apart from Oman, Yemenand Syria, most of the Middle East is closed to outside investment. Iraq is only slowly opening up to international explorers in the Kurdistan region and also to a limited extent in the south of the country;
  2. The FSU is open to international investment but in practice the best opportunities end up in the hands of powerful local oil industry players;
  3. In Latin America, Venezuela and Mexico have long been closed to international investors.

Only about a quarter of world proved oil reserves can be classified as accessible to international investors and that sub-Saharan Africa represents 20% of that accessible base.The picture is similar for gas with Africaas a whole representing 25% of accessible world proved gas reserves, which are about a third of total world proved gas reserves.

Reserves evolutionafrica 2

In 2010, proved reserves in sub-Saharan Africa were 69Bbbl of oil and 228TCF (38Bboe) of gas and represented 52% and 44% of African oil and gas proved reserves respectively, up from 37% and 25% in 1980.
Africa as a whole with proved reserves of 132Bbbl of oil and 520TCF (86Bboe) of gas represented respectively 10% and 8% of world oil and gas proved reserves. Reserves life in Africa was 37 years for oil and 74 years for gas versus world reserves life of 47 and 63 years, respectively.
While oil reserves are diversified across the continent, proved gas reserves are still largely dominated by Nigeria, although potential future gas producing provinces are being discovered elsewhere, e.g. East Africa. The emergence of export and local markets for gas in Africashould provide incentives for gas exploration and increase further proved African gas reserves in coming years.

Shale gasThe US Energy Information Administration estimates that the technically recoverable shale gas resources contained in the Karoo formation in South Africais 485TCF. However, given evacuation issues, demand being poor and low interest given the high reserves of conventional gas, shale is not an issue for now in Africa.

The South African Department of Mineral Resources announced in May 2011 a moratorium on applications for rights to explore for shale gas in the Karoo until it has formulated adequate policy, a process expected to take several months. No new applications will be accepted and existing applications will not be finalised until the Department has conducted the feasibility study.
Companies involved in exploring for natural gas in South Africainclude, Shell, Sasol, Falcon Oil & Gas and Bundu Oil and Gas
 
Production
 
The growth of proved oil and gas reserves in sub-Saharan Africa in the past 30 years resulted in the growing importance of Africa as a major world hydrocarbon producer. Africa has consistently gained market share of world hydrocarbon supply to reach 12% of world oil production and 7% of world gas production in 2010, with annual production of 10.1MMbbl/d of oil and 1.2MMboe/d of gas.
Oil production in sub-Saharan Africa reached 5.8MMbbl/d and gas production 0.3MMboe/d in 2010 with oil production dominated by Angola and Nigeria.

M&AHaving realised the importance of Africa as a long-term hydrocarbon producer and in order to diversify their energy supply mix, the US and Chinaare importing an increasing proportion of oil from Africa.

Currently 25% of USoil imports and 30% of Chinese oil imports are sourced from Africa, and those proportions are expected to increase in the future.
Petronas, from Malaysia, was the first Asian company into Africa with its purchase of 30% of Engen Ltd, a South African firm, in 1996. The reason for this acquisition was to assist Engen in expanding marketing in South Africa, sub-Saharan Africa and along the Indian Ocean rim. Engen became a fully owned subsidiary of Petronas in 1998. Also Energy Africa was owned 56.5% by Petronas through Engen when it was sold to Tullow in 2004.
In more recent years, China has been the most aggressive in proactively becoming operators of African oil and gas production by acquiring existing operators and/or participating in exploration/production activities, using a number of different vehicles.
In 2009 Addax Petroleum was acquired by Sinopec, a Chinese petrochemical major, for US$7.2bn while CNOOC bought in the Ugandaoil development project together with Tullow and Total.
CNOOC was also interested in acquiring Kosmos‟ interest in the Jubilee field offshore Ghana in 2010.
Petrobras also acquired in Namibia and Gabon while Indian companies, led by public sector majors, have been also actively looking for upstream oil and gas assets in Africa, so far mainly as minority interest holders in upstream licences, e.g. in Mozambique with Anadarko.
In 2010 the Korean National Oil Company (KNOC) bought Dana Petroleum which had assets in Egyptand offshore Guinea, together with Hyperdynamics, a small US independent.

So far in 2009-2011 M&A activity has surpassed $58bn.WhyAfrica

  • No OPEC exposure, so no risk to volume cuts.
  • Supportive regulatory and managed legal framework.
  • Strong business-driven mentality.
  • From a costs perspective, finding and development costs across Africa are inline with world average of some US$15 per barrel of oil equivalent (boe), but lifting costs at US$4-9 per boe are lower than world average of some US$11 per boe
africa 3
East Africa
 
East Africa could prove to be one of the most prospective regions globally.
By applying old ideas to new basins, Tullow/Heritage and Anadarko/BG, respectively, opened the multi billion barrel Lake Albert Rift system, Uganda and the Rovuma Basin, Mozambique/Tanzania.
Tullow and Anadarko’s successes have coincided with a push by many of the NOCs/IOCs to capture frontier acreage around the world as they seek to fill their exploration portfolio. In addition to the several pure-play East African E&Ps, current IOC/NOC acreage holders include Anadarko, BG, CNOOC, Eni, Exxon, Shell, Petrobras, Petronas and Statoil.
According to Wood Mackenzie in 2010, 3.5bn barrels of oil equivalent (+33%y/y) were discovered in Sub-Saharan Africa alone.
The largest contributions were Anadarko’s gas discoveries in Mozambique: Windjammer, Barquentine, Lagosta and Turbaro with the Rovumabasin accounting for half of all discoveries.
Anadarko’s find is large. Following the recent results APC is now saying that the Windjammer, Barquentine, Lagosta and Camarão complex now holds at least 10tcf, while Cove has been saying 12tcf (base) for a long time now. The companies are looking for an FID by end of 2013. If reserves are 12tcf a 2 train LNG development would be feasible and commercial.

Ophir provided higher-than-expected gas resources in Jodari in Tanzania (3.4tcf vs pre-drill estimate of 2.2tcf) de-risking concerns about the pace of gas discoveries needed for an LNG development.According to Afren “East Africa holds more than 31 billion barrels of oil, , three times as much as Brazil’s Tupi field”.

In addition to the 1bnboe already discovered within Uganda Tullow recently announced that it estimates that an additional 2.5bnboe of resource exists within the Lake AlbertBasin alone.
Moreover, a recently conducted independent report estimated that c.2.2bnboe of prospective resource existed in Block 10BA, Kenya, alone with an upside case of 4.4bnboe.
Furthermore, according to BP, between 1989 and 2009, Sub-Saharan Africa’s oil reserves more than doubled to 130 billion barrels.
 
East Africa deepwater
Big expectations in oil and gas from deepwater Mozambique and Tanzania after Anadarko’s Windjammer gas discovery confirmed the Rovuma basin as an emerging gas province.
With gas in nearby markets selling for $2-3/mcf, the lack of nearby infrastructure means that threshold commercial volumes will likely be high.
Much will be dependent on recovery rates per well (which can range from 50 bcf/d to 450 bcf/d offshore) but two subsequent gas finds (Barquentine and Lagosta) have already led to talk of there being enough gas to underpin an LNG development.
An even bigger prize is finding commercial oil after the Ironclad well penetrated a 38 metre column of oil and gas-saturated sands in one of two fan lobes of cretaceous sediments.
The ultimate prize would be the opening up of not only the Rovuma basin but also the other eight basins contained in the Mozambique channel which runs from Southern Tanzania to Madagascar.
Companies: (Mozambique) Anadarko, Tullow, Mitsui, BPRL, Videocon, Cove Energy, Artumas,
Eni, Statoil (Tanzania) Exxon, Statoil, BG, Tullow, Dominion, Aminex, Beach Energy, Orca
Exploration, Artumas, Maurel and Prom.
Guyana basin 
The Equatorial Atlantic Margin play has its origins when Africa and South America drifted apart. Following success in Ghana and subsequently Sierra Leone (with the Venus well), the industry is now turning its attention across the Atlantic to the stratigraphic potential of the Guyana basin, which stretches across Guyana, Suriname and French Guiana. The main challenge is to define prospective traps along the migration path from mature source rocks. Much of the multi billion barrel potential is thought to exist in stratigraphic traps in tertiary turbidite sandstones and deeper cretaceous fan systems similar to the Jubilee play.
In French Guyana, Tullow found one of their biggest successes (Tullow operator, Total and Shell also partners) with resources (P10) of 700mb.
Companies: Exxon, Shell, Total, Repsol, Tullow, Noble Energy, Murphy Oil, Inpex, Petro-
Hunt, CGX Energy, Staatsolie (state energy company of Suriname)
West Africa
Many companies think that West Africa’s pre-salt geology mirrors that of Brazil.
The theory here is that the pre-rift geology below the sealing thick salt layer remained the same even after Gondwana separated to form Africa and South America. 3D basin modelling and geochemistry suggests a close match between West African and South Amercian margin basins in terms of pre-salt depositional sequences. This holds out the possibility of large pre-salt oil deposits in Angola, Namibia, Gabon and Congo.
Possibly the biggest proponent of this is Marcio Mello, CEO of HRT, who thinks that giant deposits in the pre-salt in Angola is “a certainty, not a possibility” with objectives in the Upper Cretaceous turbidite sandstones and syn-rift carbonates and sandstones identified that are analogous to the Tupi and Jupiter fields in Brazil. Sonangol and Petrobras recently started a joint preliminary study into the Angolan pre-salt and Sonangol has stated that it intends to drill one or two pre-salt wells by 2012. Petrobras and Cobalt hold African pre-salt acreage in Angola and Gabon whilst Repsol and Chevron are showing a strong interest through public statements they have made. It is early days yet but it does look like the risk capital will come.
In Namibia the biggest success so far has been the Kudu gas field (1.3tcf of proven reserves – Tullow, Gazprom main partners). However, the development is still undecided.

Companies: Petrobras, Sonangol, Cobalt, ChevronGhana

Tullow was responsible for the first major oil discovery in Ghana back in July 2007 with the Mahogany-1 well. The field was subsequently re-named Jubilee in honour of the 50th anniversary of the country’s independence from Great Britain.
Jubilee is now one of the most succesful and largest discoveries in the oil industry, holding 700 million barrels of recoverable resources with upside, according to Goldman Sachs, of 1.1 billion barrels.
First oil was produced from Jubilee just 40 months after first discovery – a world record – in late November 2010. A number of further discoveries have been made since then (including Tweneboa, Enyenra, Teak, Akasa and Mahogany East).
Jubilee is now producing at 85kbpd with ramp up to 120kbpd targeted for year end.
 

Field operations:Tullow’s field operations are based in Takoradi, about half an hour’s flight west of Accra. The site was formerly an airforce base, which Tullow now leases. Several oilfield service companies now have bases in Takoradi. I met with employees of FMC who are supplying the Christmas trees.Tullow managers and suppliers were both in agreement about the ease of doing business in Ghana. It has a strong rule of law, a straightforward customs process and Takoradi has modern and efficient ports (Tullow has dedicated berths).Given this accommodating background, Ghana could in time become a primary hub in West Africa for the oilfield service companies. Right now there are no supply chain bottlenecks.

Local content:

Ghana currently has a local content law in front of parliament, but nothing has been agreed to date. There was some discussion of this being as high as 90% but it is anticipated that the end result will be somewhat less onerous and, like Brazil, will vary depending on the specific product/service. However it is Tullow’s aim to stay ahead of the game in this situation.

Tullow has around 250 employees in Ghana, around 85% of whom are Ghanaian. Tullow has a very active education programme for local employees, many of whom are sent to the UK and elsewhere for training.

JubileeJubilee was designed to consist of three separate phases: phase 1, 1a and 1b. Phase 1 scope was an FPSO/subsea scheme planned to cost $3.15bn (the eventual cost was $3.35bn, or 6% over budget) with 17 wells including 9 production wells, 6 water and 2 gas injection wells. Plateau of 120kbpd was expected to last for around 2.5 years. Phase 1a adds a further 8 wells and is planned to extend production plateau to 2014/2015, while phase 1b will incorporate 10-20 wells and will either extend plateau or increase production.

The development plan for phase 1b depends to a large extent on the design for Mahogany East Area (Kosmos operated) as this could involve a  second FPSO rather than producing through the current Jubilee FPSO.
 

Jubilee production ramp up – aiming for 120kbpdCurrent production at Jubilee is c85-90kbpd from 7 wells. The path to 120kbpd sees the following:

  • One water injection and one gas injection well yet to be drilled, to be brought on by year end (adding c15kbpd);
  • Production contribution from well J06, which has been completed and is waiting to be tied-back (adding c10kbpd+)
  • Drilling, completion and tie-back of well J07 sidetrack (adding c10kbpd+). Tullow is pushing hard to achieve 120kpd.
Upside potential yet to be tested
 
Jubilee reserves and resources range is 500-700-1100Mbbls. While it is too early to tell whether the company could begin producing into the P10 case (phases 1a and 1b yet to be sanctioned and only 10 months of production history), Tullow is confident around the P50 number of 700Mbbls, saying that if things were going to go badly with respect to the ramp up and production levels, thus impact resource estimates they would know very early on and so far haven’t seen anything to give cause for concern. Aspects relating to recovery factor, such as effectiveness of water and gas injection will be the determining factors in achieving the upside case.

Key Drilling Campaigns 2012Tullow Africa Oil and Tullow’s Ngamia well discovered oil in Kenya. The well encountered 20m of net oil pay in Tertiary sandstones and is a significant play opener in Block 10BB. Pre-drill estimate was 45mmboe P50 and 180mmboe P10. 2012 drilling campain includes some strong high-impact wells like Paon-1 (Cote d’Ivoire) and Jaguar-1 (Guyana) plus multi-well campaigns in French Guiana, Uganda and Ghana

Afren has one of the busiest drilling campaigns this year, with the company looking to drill 13 wells across Ghana, Kenya, Kurdistan and Nigeria in FY 2012. Afren is currently drilling three wells Nunya (Ghana), Ain Sifni (Kurdistan) and an appraisal well in JDZ. Nunya is the most exciting well in the company’s drilling campaign for 2012, with pre-drill P10 estimate of 325mmboe. Afren will also drill the Pai Pai well in Block 10A, Kenya in H2 2012.
Ophir: 3.4TCF recoverable at Jodari is the strongest possible start to the five well 2012 Tanzania drilling campaign. Beyond Jodari-1, Ophir expects to spud 8 other wells before end 2012. These include 3 wells in Block R, Equatorial Guinea where are rig (Eirik Raude) has been contracted – the first well is to spud in May 2012. As a reminder, these wells are to prove up gas to feed a second LNG train in Equatorial Guinea. Preparations are underway for a more ambitious 12 well campaign in 2013, contingent upon additional financing.

Chariot: Expect Chariot (25%) to participate in the Petrobras-operated Kabeljou-1 well, on the giant Nimrod structure. Management hopes to continue drilling in 2013, from Delta-1 on the Central Licences, to the Zamba-1 well on the Northern Licences, which would test a separate play fairway to the Tapir Trend.

Other names like Africa Oil (Kenya/Ethiopia), African Petroleum (Liberia/Sierra Leone/Ivory Coast/Senegal), Chariot (Namibia), CGX (Guyana), Camac (Kenya/Nigeria/Gambia), Rialto (Ivory Coast), Pan Continental (Kenya), FAR (Kenya/Jamaica/AGC/Senegal) have intensive drilling campaigns throughout 2012.

Summary

Strong oil prices and a desire to escape out of OPEC and Russia onerous contract types have led the oil Industry to explore further into Africa. The quality and volume of the discoveries has led African plays to become a hot topic in the market. I believe this will continues as a low cost, high quality resource is the most sought-after in the current oil world.
Afren, Tullow, Ophir, Soco, Cobalt, Chariot, Cove, Africa Oil, Hyperdynamics, Kosmos among others remain at the top of the list of the independents driving the Africa theme.
Sources:
. Tullow Oil
. Morgan Stanley
. Chariot Oil Gas
. SBG Securities
. Oriel
. Nomura