Integrated oil companies don’t create value for shareholders. This is the unanimous cry of investors.

But it’s even more impressive to see how terribly the integrated Europeans have performed (+3.8% annually in dollars) compared to the Americans (+7.6% pa) since the days of mega-mergers.The reason, sad to say, is that the Europeans have generated an average 12-16% ROCE due to the “diversification” into many low-return businesses, while Americans were generating a 18-23% ROCE. In Europe, poor refining investments (remember “the golden age of refining” bet?) and adventures out of the sector  from renewables to power and healthcare, telecoms and nuclear, have “eaten” the profits of exploration and production. Investing in refining in Europe is a donation, not a business.

It’s a shame, but many of the European oil majors are semi-state political vehicles where the alignment of interests between shareholders and managers is very low. As an example, using data from annual reports, we find that European managers have virtually no shares in their companies (less than 0.01% of capital), compared to 6% on average in the U.S., apart from the giants Chevron Exxon or Conoco (between 1% and 1.2% of capital). People tend to work harder if their own money is at stake, and if a CEO has more desire to become a minister than to see shares go up, his actions will lead to his principal goal.

No wonder, then, that ROCE driven companies outperform. Exxon just trades at a 4% discount compared to the sum of the parts of its businesses, while Chevron trades at a premium of 4%. On average, the listed American integrateds, according to UBS, trade at a discount of 5-8% while ENI (Italy, semi-state) trades at a 38% discount, OMV (Austria, semi-state) at 16%, Total (France, private but with strong public ties) at 22%, or BP (private but a “flagship company”) at 30%. Repsol, which emerged from the “Argentina trip to hell”, used part of the philosophy of Marathon (either by choice or necessity or shareholder pressure) has cut its discount from 40% to 20%. But it still has much to do to be remotely similar to Murphy or Marathon and it is important to remember that maintaining control positions in listed subsidiaries does not help because the conglomerate discount remains.(source: UBS)

We recently explained why the integrated sector does not work in the stock market , but what would happen  if they broke into parts?. Let us focus on the possibilities of a break-up to create value:

1) Not all have to. As we have seen, American integrated trade at a small discount or a premium to their sum-of-the-parts, thanks to the ongoing evaluation of their business portfolio, and having no mercy when it comes to divest in areas of low profitability .

2) Not all can do it . In order to do a successful break-up companies need to start with a powerful exploration business, with high growth that would trade at a strong premium and a very strong refining and marketing business with strong cash flow and good EV/complexity and margins so that investors value them.  Marathon and Murphy are companies that have exploration and production businesses that can trade at higher multiples, but also very successful in refining so it is easy to separate them.

In the European case it is more difficult because usually companies “limp” in one division or another. They are also companies with more “surprise invested capital” (a lot of hidden diversification with low returns) and thus this could lead to a separation at very low multiples. For example, despite having a world-class exploration and production business, Total’s refining + marketing + renewables, which has generated losses in France since 2001 as the CFO acknowledges, could not be separated. If Total, for example, could not close the refinery in Dunkirk, losing millions a month, could  Repsol sell its inefficient refineries given the same pressure from local governments?

BP, for example, also has a powerful exploratory heart, but very low growth (Thunderhorse, etc) and average exploration success, and is still trying to sort out its disastrous Russian adventure (TNK, 20% of its reserves), sell their underperforming European refining and reduce exposure to its renewable business at a time where renewables are falling in valuation every day. If it separated its activities in three, as some propose, these would very likely trade at sub-peer multiples as well.

There are also many pressures and core-shareholder policies that prevent companies from selling non-strategic assets. From ENI with its subsidiary Snam ReteGas and Galp, to Repsol and Gas Natural, which at some point traded at €40/share when it was a possible candidate to be sold, yet now trades at €14/share after a massive acquisition and a capital increase.

Furthermore, disposing of those assets would probably show to investors that the alleged “high growth” E&P division is probably not going to trade at the multiples of an independent explorer given the fact that, at the core, in most integrated oil companies, the exploration success ratio is well below that of independent companies, the reserve replacement is lower and they are not takeover candidates or sellers of assets, just aggregation vehicles.

Separation has only proven to create value for all stakeholders (shareholders, industry, country) when the parts are true growth and value, as the model of BG and Centrica showed, which delivered two strong national companies without massive conglomerate issues, lean operations, higher ROCE and clear market valuations. This made them also bigger and better companies.

3) Not all should. One should ask – sell and separated to do what? Sometimes you have to be careful what you wish for. When some of these companies are separated, the excess cash is often used to make acquisitions, and given the examples of the past, it is sometimes better to stay with the devil you know.

Example: If  ENI dispose of Snam it would lose €2.5 billion in operating profit.As an industrial and semi-state owned company, it would seek to acquire something that would replace that figure. And would probably be more expensive than the asset sold. Unless those gains are reinvested in buying back shares, pay dividends or make one acquisition of very obvious high value, the benefit may be non-existent. So the only way to create value is to forget trying to reinvent the wheel and focus their efforts on growth in exploration, an area where their returns and competitive advantage are obvious.

The illusion of value in Euromajors’ E&P businesses is another contention issue. If we look at European majors’ E&P business from the perspective of an independent upstream company, here is what we find: No real organic reserve replacement (most of it is acquired), sub-standard growth (1-2% pa at best), very exposed to OPEC, gas and non-conventional resources, exploration success below-E&P standards in past five years at less than 35% (versus E&Ps at 56%), low ROCE (15-17%), bureaucratic and slow management decisions. But most important, a major’s E&P business, even if restored to industry standards, is not for sale as they are asset aggregators, so it would never be valued on a NAV basis like other E&Ps. See the example of Statoil, which is now a pure play E&P, has no conglomerate problems and still trades at 16% discount to sector.

The only upside from integration is size and scale. By staying combined and being huge $100bn+ companies, the majors force the market to value them on P/E, and dividend yield rather than being subjected to the scrutiny of production growth, ROCE, reserve replacement etc  and EV/complexity adjusted barrel, margin, cash-flow etc  that smaller pure play peers are subjected to in upstream and refining.

14th July 2011

The figures add to concerns that the Chinese government will slow growth with a sharp tightening of monetary policy, in response to consumer price inflation running at 6.4 per cent last month despite five interest rate rises since October.

Meanwhile, Saudi Arabia has increased production to a record 9.6mbpd, an increase of 800kbpd from January, and Iraq reached record output of 2.75mbpd, almost back to pre-war levels.

As of June, IEA inventories remain above the 2006-2010 average.

However, I still receive doomsday messages about supply. And I say, don’t worry, supply is adequate.

Now the Shale Oil revolution is upon us.Remember what shale gas did to natural gas prices? Down 54% from the peak. Imagine what shale oil can do.Peak-Oil defenders, gas lobbies and environmental groups all said shale gas was not economical below $8/mmcfe, they said that it was a “bluff” and that the decline rates would make the “fad” disappear as soon as natural gas reached $6/mmcfe. It reached $2.5/mmcfe (now at $4.5) and the rig count is at all-time highs (890), companies continue to make good returns (18% IRR) despite pressure pumping and service costs rising, the environmental concerns are being addressed swiftly and adequately and decline rates have proven to be significantly less aggressive.

The NY Times battle against shale gas, driven by half-truths and questionable analysis, is lost. No one denies the massive resource base, even in Europe and China, and the opportunity to supply cheap, abundant energy.

Well, shale oil could generate a similar transformation impact for the oil market.

Last Thursday we met in London with twenty North American oil companies and a representative of the Energy Information Administration (EIA). We only talked about one issue: the revolution of Shale Oil, which could be a transformational force in the oil market.

The United States has over 24 billion barrels of recoverable oil in shale and Argentina over 200 million barrels of recoverable shale oil. Abundant oil supply delivered thanks to hydraulic fracking, a tried, tested and proven extraction technology. Companies like Anadarko, Oasis and Marathon are already developing shale oil fast. Repsol could benefit from this revolution in Argentina. First things first and let’s start with the U.S.

The oil sector is rubbing its hands at the prospect of a revolution which already generates 18-20% IRRs using a base price of $ 60/bbl.

Shale oil production in the United States has grown dramatically, from a modest 275,000 barrels/ day to an estimated 400,000 barrels/day in 2011 and up to 510,000 barrels/day in 2012. To give you an idea, this is the equivalent of Khursaniyah, one of the star oil fields of Saudi Arabia.

In a report published this week, the EIA estimates a level of productivity in the fields of North Dakota, Montana and Canada, together with Eagle Ford (Texas) that can make oil production reach very relevant levels in ten years, to the point where the US would halve its oil imports and its dependency on OPEC.

The figures are worth highlighting:

. With the improved hydraulic fracking techniques using recycled water and increased productivity, tight and shale oil is economically viable at $60/bbl. If we assume $100/bbl, each well repays its total investment cost in eight months. Three times faster than a conventional oil well.

. The oil industry alone will invest $25 billion in 2011 to drill 5,000 new wells. In 2012, the investment will reach $ 45 billion, giving employment to hundreds of thousands.

. Environmental concerns have already been addressed with the use of recycled water, isolation of aquifers and of drilling installations.

In Canada, there are several new plays popping onto investors’ radar screens, including the Mississippian Alberta Bakken/Exshaw shales in southern Alberta, Cretaceous Second White Specks in the Deep Basin, Jurassic Nordegg shales in the Peace River area of Alberta, and Devonian Muskwa/Duvernay shales in northwest Alberta/Deep Basin. On the more cautious side, Chesapeake quotes oil prices of between $30/bbl and $50/bbl being required to achieve 10% rates of return on different shale oil plays.

Who benefits from this revolution?

Anadarko , one of the best explorers in the world with the best track record of profitability in conventional and unconventional oil and gas, Oasis, small but very exposed to Shale Oil in Bakken, Marathon and Noble, two giants of exploration but more diversified, and the gas giants Chesapeake and EOG are all involved in very large acreage and moving fast in shale oil.

In Argentina, Repsol is prepared to follow the US-led revolution after announcing shale oil reserves of 150 million barrels recoverable. Of course, those reserves were already there and were known by the Repsol team at the time of the acquisition of YPF more than a decade ago, but what has changed is the development of hydraulic fracking techniques, horizontal drilling and the incredible expansion of the industry’s exploration and production of unconventional oil and gas, which has made ​​productivity soar and the average cost per well fall despite the fact that pressure pumping costs have risen by c30%.

Of course, in Argentina the problem is the price at which they can sell the oil and gas under schemes acceptable to the government, but if the country wants to revive the economy, attract capital and recover the disastrous situation of domestic production, it has no other option but to apply international prices. But let’s wait, as history reminds us that logic does not always prevail.

YPF, Argentina’s Repsol’s subsidiary, will drill 17 exploratory wells in 2011 with an investment of less than $ 200 million. Assuming a 12% royalty and 35% tax, the Argentine shale oil can generate returns of 35% (IRR) per well at $90/bbl assuming a 70% oil and 30% gas content, the latter sold at the “bargain-price” regulated by Argentina for domestic consumption (about $ 2.60/mmbtu compared with $4.50/mmbtu in the U.S. and up to $11 in Chile). Of course, if prices are adapted to the international average, returns would be much higher.

For now, the projections of production in Argentina are negligible and the political and regulatory environment is still uncertain. Repsol has sold 45% of YPF to institutional investors and the Argentine Petersen group, hoping that the participation of local investors can help improve the situation for their business in Argentina. Hopefully that will work.

For Repsol-YPF it will not be any problem to access enough water for extraction on a massive scale, as there is more than enough in the area of ​​Neuquen. The risk, of course, is the annoying habit of the Argentine government to seize profits when things work, so the presence of local investors can mitigate this interventionist “temptation”. We’ll see. But the other major unknown is how much will they have to invest to bring these reserves into production. A rough initial estimate of a development plan with 200 wells per year would mean an average of $2.8 billion annually (if the wells are multi-stage horizontal). And if Repsol invests aggressively in shale oil they might forget about questionable experiments in wind energy and marine algae, something that investors will appreciate.

Update:

Repsol announced on November 8th 2011 its “largest ever oil find”, with an estimated 927mb of recoverable resources (741mb of oil, the rest gas) in a 428 km2 exploration area in the Vaca Muerta shale formation on its Loma La Lata licences. In addition, it has started exploration on a further 502 km2 where it sees “similar potential” to the first area.
YPF has started exploring an additional 502km2 area, where its first well produced 400b/d of oil. Repsol believes that this new area has “similar potential” to the first area.

This oil would be sold at $60/bbl at the fixed price set by the government.

On February 8th 2012 Repsol’s subsidiary YPF announced 22.807bn boe of prospective resource, 1.525bn boe of contingent resource (1.213bn net to YPF) and 116Mboe of 3P reserves. The contingent resource lies in the 2 areas previously highlighted by YPF called Area 1 and Area 2. YPF highlight that Area 1 and 2 require 60 new drilling rigs and a $28bn investment (capex and opex) to develop. More would be needed for gas. The key remains whether there will be an adequate pricing/fiscal system to allow the investments. The update from YPF comes after government plans, as highlighted by Argentina’s Planning Minister Julio De Vido last Saturday, to force oil and gas companies to operate at full capacity even at a loss and follow new operating guidelines.

Shale oil could reduce dependence on changes in OPEC quotas and become the “cushion” to buffer the volatility of oil as the North Sea oil was a decade ago.

Shale oil is more than a promise. The pessimists will say, as they said with the shale gas in 2006 or Brazil’s pre-salt in 2005, that it’s all a lie, uneconomical, overstated and that the world is running out of oil. They are entitled to their opinion. Meanwhile Saudi Arabia has reached a record level of production of 9.6 million barrels/day, Iraq has surpassed 2.7 million barrels/day and Russia has surpassed 10.2 million barrels/day. And shale oil is upon us.

Further read:

http://www.eia.gov/oog/info/twip/twip.asp

http://energyandmoney.blogspot.com/2010/11/shale-oil-600-years-of-supply.html

http://energyandmoney.blogspot.com/2011/06/shale-gas-in-europe-poland-and-energy.html

http://energyandmoney.blogspot.com/2010/01/revolution-of-shale-gas.html

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

http://www.cotizalia.com/lleno-energia/2011/petroleo-abundante-barato-revolucion-shale-20110714-5806.html

The big concern, added to Europe, is China slowing down. Global GDP growth figures are being revised (although moderately) at large banks. But the sensitivity analysis on supply and demand is still not there.Here are a few figures worth considering that are obviously considering all other factors unchanged.

At the current estimates (+9.2% GDP growth), China is set to import 5.5mbpd of oil and 178m tons of coal.

If GDP growth falls to +7%, estimates call for a 5.1mbpd of oil and 168m tons of coal.

A fall of 500kbpd of oil demand brings oil demand down from 84.2mbpd to 83.5mbpd. This means that we would still be net consumers of inventory unless Iraqi volumes offset the Lybian barrels lost. This is quite unlikely.

On coal, imports are less sensitive because the decision to import is price driven (ie the arbitrage between domestic coal and international) and at the same timeimport decisions are also based on freight dayrates (and these have been falling quickly in the past two weeks).

I believe it is worth keeping in mind these figures. Obviously, if Chinese GDP growth corrects agressively it will also mean that German exports, and EU growth will slow down. But ven if we move to recession territory in EU, it is difficult to see coal and oil supply-demand balance move to oversupply.

(This article was published in Cotizalia on May 5th 2011)Today we will talk of Pakistan, a very rich country in natural resources, which contrast with its extremely poor current state. A report to which I had access estimated that with a maximum of $20 billion in investments the country would increase its oil production by nearly 2.5 times and natural gas could be exported for the first time, including a new pipeline and liquefaction plant near Karachi.

Today Pakistan is a disaster. Despite having a U.S. aid of $7.500 billion over a period of five years, and important natural resources, it still sees its potential unfulfilled due to its poor security and geopolitical contradictions.

Starting with geopolitics, part of the problem in Pakistan can be explained by the mixture between modernity, tradition and support for radicalism embodied in Dr. Abdul Qadeer Khan, almost a national hero, responsible for a nuclear proliferation program in the country, named by Time Magazine as the “Merchant of Menace”, creator of a black market accused of selling nuclear technology secrets to Iran, North Korea and Libya. If we add that several provinces, including the largest, Baluchistan, and the border with Afghanistan, rich in oil and gas, are controlled by radical armed groups completely independent and separate from Islamabad, the capital, we have the perfect recipe for geopolitical unrest.

As for its natural resources, Pakistan has 436 million barrels of oil and 840BCM of gas in proven reserves, yet more than a third of its 827,000 square kilometers of sedimentary areas are under-exploited. Thus, the country imports more oil than it produces, doesn’t export any gas and has been unable to attract sufficient investment to reduce the decline of oil production, which will likely fall 46% in 2020 according to internal estimates. Despite being the 49th country in proven reserves, it is well below number 60 in production. Less than 60,000 barrels per day, which could easily be doubled if the legislative and regulatory environment was safer, and as such currently the country only extends about 40 exploration licenses annually.

Taking a brief look at the oil companies present in Pakistan proves the caution of the large oil companies to invest in the country. The first thing that surprises is the minimal presence of the largest players of the sector. The country boasts that there are 17 international companies operating, but the most relevant, Petronas (Malaysia), OMV (Austria) or MOL (Hungary) are not exactly the top groups in operational efficiency, and the two Europeans mentioned can not even presume of having a robust financial position. On the other hand, in 2010 BP sold almost all its exploration and production assets in Pakistan to United Energy Group, a Chinese holding company, for $775 million.

China seems very well positioned to gain a strong foothold in the country, with good ties to the government, and a historical track-record of managing quietly the most difficult geopolitical environments (Sudan, Nigeria, Iraq).

For Pakistan to regain a strong position in the oil and gas market I believe we would need to see three fundamental conditions

a) The end of the conflict in Afghanistan , which would close the geopolitical axis Turkmenistan-Afghanistan-Pakistan, isolating the influence of Iran and make attractive a large-scale presence of big oil investments. This is especially important to implement the infrastructure (a pipeline of more than $2 billion investment) to carry gas from Afghanistan to Pakistan and connect to a liquefaction plant to allow liquefied gas exports from Afghanistan and Pakistan to either China or the U.S.

b) The establishment of a strong government that recovers the lost provinces, particularly Balochistan, and to adopt a sustainable and predictable legal framework.

c) The involvement of China and U.S. in Pakistan to develop the fields (onshore and offshore) is essential to bring oil export production to 120,000 barrels per day and gas production from 37BCM year, primarily for domestic consumption, to export up to 67 BCM.

Who would win? The main beneficiary if Pakistan would rise would be Schlumberger, the U.S. oil services company, with expertise and resources to develop the fields and local staff. But Pakistan, at least in the short term, is much more a risk than an opportunity.

Improving the economic situation of Pakistan with a current estimated GDP growth (+2% 2011) ridiculous for the area, is really complicated and depends on the future access to natural resources development, which is intrinsically linked to political normalization in a country with the nuclear bomb and that remains a hotbed of support for radicalism. An unequivocal commitment to eradicate the terrorist support may be the key that opens the door to growth. Being “Merchant of Menace” only brings poverty.