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.

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 evolution

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

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.

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

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”.

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.

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.

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)

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

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.

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.

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.

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

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

As usual, lowly utilities are ignored, all we read about is the oil price issue. The real news is the savings coming to US consumers on power and gas bills. Assuming the average household pays about $100-$150/month for power and $85/month for natural gas. In the future, those bills should fall to $70-$120/month for power, saving perhaps $30-$40/month, or $375-$450/yr; and $45/month for gas, saving another $400/yr, for a total of about $700-$900/year.This is before the weak weather effect too, which will have lead to much lower usage levels than expected during 2012.

Compared to a $0.50/gallon rise in gasoline, on 500 gallons/yr (15,000 miles at 30mpg), that equates to $250/yr. In other words, gasoline could move from $3.00/gallon to $5.00/gallon with no net impact at home. RBOB gasoline contracts are at about $3.32 today, up $0.80 since early 2010. Maybe not a big deal in comparison; and for further comparison, the Bush income tax rebate checks (remember those?) were about the same ‘net’ amount, $400/household/yr.

Importantly, the bills for gas/power are delayed–hedges roll off, rate plans adjust slowly, etc, but it all comes through eventually.

The impact to businesses and industrials in the US, you can imagine, will be large and accretive to earnings.

US-PJM Monthly Peak electricity price futures.

Also of importance: in a power or gas utility bill, roughly 50-60% of the total bill will be fixed cost charges–largely invested capital and its cost–and thus not be impacted by a decline in power/gas prices, that is embedded in our calculation on total savings.

While it is true that some states won’t see as dramatic a decline as others and the timing will be constrained by rate mechanisms, as well as the timing of puchased power contracts/hedges rolling off, it would be incorrect to assume that these declines won’t flow through customers bills, eventually they will. In some states, power charges are disaggregated and run on a trailing moving average that simply run through bills.

While its true that the % of gas used to generate electricity is around 25%, the price of natural gas sets the price of electricity in many if not most of the major US power markets during peak hours, and during most of the year (exceptions being soft shoulders in April and October), due to marginal cost dispatch economics. This is particularly true for California, Texas and Florida, three enormous markets.

Now, a fully regulated utility is likely to use ‘average cost ratemaking’, in which case the moderations of natural gas price will be less impactful than in those markets with competitive structure (like PJM). Nevertheless, you would still expect to see 5-10% declines in a total bill in those regions. Where gas is on the pricing margin–some of the larger markets–you expect larger and faster declines in customer bills, as soon as this year in fact.

We are getting some odd reads on the US economy at the moment, which have obviously made their way into the bond, equity and gold markets now. In the past few days, there appears to be a rapidly accelerating acceptance of a better economic tightener, confirmed by the Fed yesterday, albeit begrudngingly.Goldman went so far as to outright recommend shorting/selling 10-yr Treasuries this morning (which the market did!). That is relevant inasmuch as they have been the leading cheerleaders for QE and much lower growth and rates, throughout the post 2008 period, well below consensus. Ironically, Morgan Stanley has been the leading proponent of inflation and faster recovery since QE1, and obviously got that very wrong…and yet this morning, they are out pounding the table that from their perch, most of the blast is inventory re-stocking and they see Q1 coming in at a very-low 1.3-1.5% GDP growth, below consensus

I’d love to say MS is getting it wrong both times (post 2008), but there are two factors out there that are puzzling….

According to analysis on power demand data in the US over the past 4-5 months, adjusting for the unusually low weather, power demand is growing at .6% per annum, and using historic correlations between power demand and GDP, GDP is growing at 1.3% now Y/Y. Prior period was 3.0%, though JP Morgan is out saying today that there will be a .5% revision upward to that number due to medical care spending up 15% vs 2.6% expected. (source: Macquarie, and others). The argument here is that efficiency, while slowly building in, can’t explain all the decline in demand and something else is happening.

Using DOE Crude Oil output implied demand statistics, the US just seems to stay virtually flat now for several years now–despite rising population and decent GDP growth. Certainly some of this is low moving rates for homes and efficiency in auto mileage, but that also alone seemingly might not explain it all.

Maybe things are different this cycle–internet efficiencies, power demand efficiencies in devices and appliances, etc. But it bears watching, because these are big data sets that never used to ‘lie’. Its possible the gas/coal switching is reducing oil demand enough to show up a smidge? As an aside, Macquarie calculates that based on real-time power generation data they are seeing in the US, as much as 100GW of coal is currently idled–that is 1/.3 of the entire fleet. Some is coming back online through forced burn due to dangerous stockpile levels (high) and maxing out their low point on annual allocations from the producers. Yikes.
Further read:

http://energyandmoney.blogspot.com/2010/10/has-cheap-gas-killed-renewable-star.html#

http://energyandmoney.blogspot.com/2010/12/can-oil-and-nat-gas-go-back-to.html#

http://energyandmoney.blogspot.com/2010/10/us-natural-gas-picture-gets-bleaker.html#

Here is the response from a reader, Rich Lyon, to my analysis of peak oil (http://energyandmoney.blogspot.com/2009/11/peak-oil-realities-myth-and-risk.html):Ref: “Also, 60% of world oil production declines from 1.5 to 2.5% annually”

Rich says “May I draw your attention to IEA’s World Energy Outlook 2008 p.244 “It is necessary to estimate the underlying, or natural decline rate — the rate at which production at a field would decline in the absence of any investment — in order to ascertain how much capital needs to be deployed to sustain production or limit observed decline to a particular rate…The production-weighted average annual natural decline rate for the world as a whole is estimated at 9.0% — some 2.3 percentage points higher than the observed decline rate…At the world level, the increase in the production-weighted average decline rate over the projection period is about 1.5 percentage points, taking the rate to around 10.5% per year in 2030. That’s a halving rate of 7 years. Against any criticism you might make of the IEA, even CERA concedes 4.5% – a 15 year halving time. Schlumberger CEO used 8% in an internal newsletter.”

My answer: If I take the top producing projects globally the decline rate dropped from 4.5% to 3% between 2003 and 2010. Added to the improvement in recovery rate seen in Russia we achieve a 2% annual decline. It’s documented in our analysis of the main fields and in Goldman Sachs Top 330 projects as well. Schlumberger, like any oil service company, benefits from decline by taking more projects and increasing engineering. Their analysis might be interesting but not conclusive.

Goldman’s analysis of the industry’s new legacy assets has grown from 91 bnboe in Top 50 Projects (June 2003) to 565 bnboe in Top 330 Projects. They estimate that these projects will deliver around 62 mnboe/d of production by 2020E (46% of current global oil and gas production)

In the Top 360 Project report (2012) decline rates are analyzed:

Decline rates have changed dramatically in the non-OPEC supply base over the past ten years and our forecasts. These declines are calculated by subtracting major new start-ups (Top 360 projects) from historical production, to estimate the base decline including enhanced oil recovery, satellites and small field developments. It is interesting to see that since 2008 the decline rates have improved and stabilized around 2.0%. This is the result, in our view, of increased spending on the production base and of debottlenecking of the service capacity.

Source of graphs above and below: Exxon

Exxon, who are well known for being prudent and conservative, sees 2010-2040 global oil & gas supply: +5.3% pa (unconventional), +4.8% pa (heavy/oil sands), +3.5% pa (LNG), +2.8% pa (deepwater) and +0.3% pa (conventional)

Ref: “but global investments between $720 and $750 billion a year in oil and gas have also seen an unprecedented discovery and addition rate” 

Rich says “In fact a perfectly good precedent exists – the discovery rate that was achieved in the period between 1940 and 1970, when global discovery rate rose from 5 billion barrels per year to 55 billion barrels per year. The rate of discovery peaked in 1968 and has followed a consistent 5% per annum decline rate ever since, punctuated by the isolated basin discoveries of Prudoe Bay and the North Sea, the recapitalisation of the FSU, and the modest (and now declining) contribution from deep water technology. It is perfectly straightforward to work out what discovery rate would be necessary to sustain 1.5% demand growth – about three North Seas every five years, commencing ten years ago. As it happens, that is the same discovery rate as they achieved 1940-1970. And, as it happens, the “unprecedented discovery rate” to which you allude is a pale fraction of that”.

 

My answer:  The chart shows two distinct flaws. First, a 5% decline, and a 1.65% pa growth of demand.

Let’s start with discoveries. An average of 3 bnbls of oil were discovered each year in 2003-05, vs.8 bnbls in the 2006-09 period (IEA, Goldman, CERA) .Most of the discoveries over the last five years have been made in the deep offshore, with Brazil dominating on size, followed by the Gulf of Mexico and Ghana. Onshore discoveries of large size have been rare and in general limited to Iraq (Kurdistan) and Uganda, although oil shales and field redevelopments in Iraq have provided very material additions to the pipeline of onshore oil projects .

Additionally, the old trend of delivery with only c.75% of the promised volumes delivered after five years has massively changed and a new trend of c.95% was identified 2005-2010 (Goldman). This proves that the “below to above ground” analysis of many peak oil defenders is not linear and that industry technology and delivery has massively improved.

The analysis you mention focuses only on conventional oil as we knew it in the late 90s… why? Not clear. Why don’t we disregard any oil that is not onshore Saudi Arabia? why not disregard any oil that is not API perfect?. Very much in line with most peak oil theories, the analysis you ention completely forgets non-conventional and liquids as “inexistent”. Just the addition of shale oil resources and heavy oil in Venezuela and Iran have brought reserve replacement well above 120%. In addition to that, the giant discoveries in West Africa have added to the base of low sulphur crude.

To ignore non-conventional, pre-salt and heavy oil would be the same as ignoring deep water in 1970, or ignoring oil sands in the 80s. Drivers and motorists do not make that distinction as it’s as valid (if not better, given the excess capacity at high complexity refineries of 8mmbpd there is plenty of processing available at cheap cost) as a fuel as anything else. And EROEI analysis is available in this blog as well here http://energyandmoney.blogspot.com/2011/06/peak-oil-defenders-most-overlooked-myth.html.

Further read from Robin Mills: http://www.thenational.ae/thenationalconversation/industry-insights/energy/flawed-views-on-peak-oil-rear-their-ugly-heads-again

Ref: Inability of the oil industry to catch up with “growing demand”

Rich points to this chart:

My answer: The first thing I will question, as I have since 2003, is that “perennial growth of demand” of 1.6%pa. Demand moves in cycles and is not uniform. The lack of understanding of demand cycles and ignoring fuel efficiency as it happens is a key driver of the perception of scarce supply.

I am a firm believer of peak oil…demand. The assumption that demand growth will be linear and exponential and that the millions of new inhabitants of the world will consume as many barrels of oil per day as the Americans is simply impossible. First, efficiency continues to drive the transport industry, second, new technologies and alternative energies create a completely different scenario. We have not even talked of natural gas vehicles, but the reality is that when emerging markets reach the level of maturity in their economies that the OECD has, average oil consumption per capita in those countries will also be well below the current US-EU level. In our calculations average oil consumption per capita declines by 6%pa due to efficiency and alternatives:

a) IEA long-term demand estimates have only been going down since 2005.

b) Growth of demand in Asia and EM is mostly offset by OECD decline, and the added growth is slowing down, as evidenced in China. More importantly, the “China angle” assumes that every city in China will consume 23bpd per capita. This is overstated by the fact that all major cities in China consume already that figure, and it’s slowing down, and like in Europe you cannot assume that the inhabitants of South Spain will consume as much as the Madrid citizens. It’s not an averaging up to the maximum, it’s an averaging down, as evidenced by efficiency impact in the US, where GDP grew 3% pa for a decade without a meaningful increase in power demand. Oil demand in the US went from 15mbpd to 18mbpd (a mere 3mmpd increase) in the period of highest GDP growth and monetary expansion (1970-2011).

Also, on Saudi Arabia’s exportable capacity, the assumption of exponential demand growth in my view is also questionable. Saudi Arabia already consumes oil above the per-capita demand of many OECD countries. Efficiency will also erode that exponential growth and you will likely see solar, gas and nuclear be added to the energy mix not due to “lack of capacity” but driven by a logical generation mix planning, just like the mix we have in most countries. Saudi Arabia is expected to increase electricity generation capacity to 80 gigawatts, driving primary energy intensity from 257 (EU=100) to 150 by 2020. The efficiency of the power sector (thermal power plants) has regularly increased over the period 1990-2009, rising from 27
percent to 31 percent. I personally have Saudi Arabia peaking its oil consumption in 2015. More in detail, I see demand in The Kingdom going from 83.73 bbl/day per 1,000 people to 68 by 2020, still a high EU-type of consumption per capita.

Here is my interview on CNBC:

http://video.cnbc.com/gallery/?video=3000076989

Further read:

http://oilprice.com/Energy/Crude-Oil/Why-is-Obama-Lying-About-US-Oil-Reserves.html

http://www.businessweek.com/magazine/everything-you-know-about-peak-oil-is-wrong-01262012.html

From Zerohedge: