(This article was published in Cotizalia on Thursday, 16th June 2011)

The Oil & Gas sector, the world’s most profitable and less indebted one, will invest in 2011 for the first time in its history more than $500 billion in exploration and production alone. The level of value creation and development that these investments generate can not be compared to any other industry or sector in the world, and if we include gas and refining they will reach a total of $790 billion.

Saudi Arabia announced this week an increase in production, showing the frustration they have after being one of the few OPEC countries to comply with the quotas. Imagine, if they presented themselves later this year at the next meeting and see that OPEC produces 26.2 million barrels/day (when the quota is 24.9) and found that the output gap between them and others had widened. Iran, for example, has increased production by 45,000 barrels/day (to 4.24 million barrels a day) despite a 35% drop in oil investments since the beginning of the embargo.

Saudi Arabia will not appear at the next OPEC meeting as the only good boy in the class with homework done. Because if quotas are revised up, then everyone has to start from the same base, and there is no evidence that the other OPEC countries will decide to reduce their current output.

Anyway, it’s a good decision which, together with increases in other countries over the quota, partially mitigates the effect of the lost Libyan barrels. Partially because Libyan barrels are of exceptional quality and the oil that is to replace them is heavier, making it difficult to replace, for example, in the Italian refineries.

In the last three weeks I have seen over twenty-five executives from oil companies, including all the big oil companies and if there’s a comment that is repeated each time over and over it’s this: Almost no one believes the sustainability of demand in China. And watch out for the estimates of the IEA, EIA etc., which use “diplomatic” data, especially in their demand models, where the estimates depend on GDP projections which are generated by the governments, which have a nasty habit of being wrong (as a fun exercise, look at the growth estimates published in 2006 for 2009).

As John Watson, CEO of Chevron, says, if the industry had listened to these agencies in the past twenty years, or whomever recommended them to “improve” their cost of capital by re-gearing, the sector would all be in bankruptcy.

According to BP’s latest report, the Statistical Review of World Energy, Iran’s daily oil production climbed 45,000 barrels compared to the 2009 figure. This increase comes despite the embargo having impacted oil and gas investments by 35%. if investments had remained at the level of 2005-2006, Iran could have posted the highest production growth of all OPEC countries (ex-quota changes).According to a friend at NIOC, lack of investment stands at the heart of the challenging environment for Iran oil output, not the quality of the reserves. In fact, according to Shell and ENI, Iran is a “dream” in terms of recoverable reserves, with low costs and high productivity. The only problem, as Total’s CEO pointed out as well, is the embargo, which could turn rapidly if the current regime changes.

Despite the positive 2010 figures, Iran could face a sharp drop in crude oil production due to sanctions and the lack of foreign investment. The Oil Ministry has determined that Iran would see a 30 percent decline in oil output given the 35% (average) drop in investments, unless the government attracts major foreign investment to the energy sector. The Teheran regime has set a requirement for $150 billion in investment for the period 2010-2015 (which would be in line with normal estimates and bringing the average capex back to historical pre-embargo levels).

“If the investments are not realized, the country’s oil output will drop to 2.7 million barrels per day,” Iranian Deputy Oil Minister Mohsen Khojasteh-Mehr said.

Under the ministry plan, Iran’s output capacity would increase from the current four million to 4.7 million barrels per day by 2015. Natural gas capacity, the focus of $75 billion in investments, would rise from 600 million to 1.47 billion cubic meters per day.

Average Iran’s crude production in 2010 stood at 4.245 million barrels per day, and the country’s natural gas production posted a 5.6 percent increase to settle at 138.5 billion cubic meters in 2010, the report said.

According to the BP report, Iran produced 5.2 percent of the global oil output, and 4.3 percent of the total natural gas production of the world.

Iran ranked fourth in the world in terms of crude production after Russia, Saudi Arabia and the United States. The Islamic Republic is also fourth in gas production after the US, Russia, and Canada, has the world’s second-largest crude reserves after Saudi Arabia and the second largest gas reserves after Russia.

Moreover, BP also stated that Iran has proven oil reserves that would last for the next 88 years, the second longest-lasting oil source in the world.

On a different note, and based on the reserves-to-production ratio index, UAE will be the prominent source of oil for the world with oil reserves that would last for the next 94 years.

(This article was published in Spanish in Cotizalia on June 23rd 2011)

Solar stocks are the worst performers again, despite the Fukushima hype and extremely generous tariff support. The solar sector (January to June) is down 10% versus the renewables sector down 5.8%, and some of the most abrupt moves in solar are in Q-Cells -33%, REC -41.5%, Phoenix Solar -26%,  Renesola -49%, E-ton Solar -50%, China Sunergy -56%.

The reason why the sector continues to collapse like a falling knife is that it has not proven how they can make any money unless there is dreamtime-like expansion.

We tend to believe that tariffs that support volume growth but cut prices more rapidly will benefit the industry (and equities) as a whole more, but hurt higher cost participants sooner. It is wrong. Because the sector starts from overcapacity and excessive cost and even with costs falling 39%, and subsidies that guarantee on average €180/MWh they still lose money.

Developers in regional markets in some cases would prefer capacity caps with higher tariffs, thus enjoying the spoils of overcapacity-driven solar ASP (average selling price) pressures from their suppliers. The Asian manufacturers have zero discipline in capex or growth, they need only a 3-month price signal and they further expand, which virtuously keeps driving down the cost. Something like 10GW of new manufacturing capacity (40%) is coming online during 2011, while demand (global) is expected to rise about 15% at best.

The big ‘if’ is if Italy imposes an annual 2-GW/yr cap on installations; if they do, most of the marginal players in Asia will have nowhere to put their last 20% of production and we have a rapid fall in prices, margins and profits which then will lead to the proverbial ‘boom/bust’. But before then, we would expect margins to compress by 50% or more in some cases in the food chain, as we saw in wind–could see stocks fall 20-40% over the summer.

If the industry were logical and wanted to lower the cost of solar – what should it do? If you assume 1600 kWh/kW capacity factor, €35c/kWh FiT (Italy), and assume that the installations are made from 2012-2016, the €6bb/year economic burden by 2016 translates to ~2.1GW/year from 2012-16.

If the industry instead accepted a €25c/kWh FiT (~30% cut), the industry could support a 3GW/year cap at the same economic burden. If the industry accepted a €20c/kWh FiT (~40-45% cut), the industry could support 3.75GW/year. If the industry accepted €15c/kW FiT (55-60% FiT cut), the industry could support 5GW/year. If the industry accepted a 55-60% FIT cut and used that as a basis to support a higher economic burden of €6.9bb/year, it could support a 5.8GW/year limit for PV.

Will they?. I doubt it. The Chinese companies have 50GW of capacity for a 20GW market. Companies are unable to achieve IRRs of 10% with subsidies of $140/MWh (US), €230/MWh (Germany) or, brace yourselves, €400/MWh (Spain), all PV solar. This is, on average between 4 to 10x the average price of power in any of those contries… and companies still are unable to make more than 10-12% IRR despite a fall in costs of 38-40%!!

In the first quarter of 2011, the average selling price (ASP) of solar modules fell again like a rock. ASPs fell c45% globally while costs fell a slower ~37% pace. So in essence, prices fall more than costs and, as overcapacity grows, the downward trend is exacerbated by working capital requirements. A race to zero? probably, unless capacity retirements really start and companies streamline their debt. But capacity cannot be slashed when the main competitors in all parts of the chain, Chinese in particular, but Germans too, have a capital allocation policy based on growth at any cost.

At the heart of this we have an over-leveraged industry: 80-85% at project level is already unsustainable, but the companies are leveraged also at the holding level, making total gearing to the tune of 5-6x Net Debt to EBITDA. Overcapacity in all parts of the value chain, from wafers to poly-sylicon and development stands at more than 50-60% on average, and competitors (not just Chinese, Germans too) show low capital discipline and imperialistic market share aspirations. So at the minimum price signal (a tariff announcement, a government renewable plan confirmation), capacity grows way above demand. And despite the fall in costs, it is astonishing to see the companies unable to get their head above water. Working capital requirements eat any equity IRRs and debt obliterates the profitability. Add to this overcapacity and no wonder you ave seen 40-50% falls in stock prices in solar.

The Asian build more and more capacity, however some part of the production chain are much easier (from a technology and timing stand point) and cheaper to add than others. To simplify, the lower in the value, the easier/cheaper it is to add capacity. As a result, the value chain today would look like an inverse pyramid with more capacity downstream than upstream:

From upstream to downstream the value chain is:
– Polysilicon
– Wafer
– Cell
– Module

As cell capacity grew larger than wafer, demand for wafer was tight and wafer ASP shot up, squeezing cell margins. Then with this positive price signal at the wafer level, Asians have added wafer capacity. As a results, there were more wafer capacity than polysilicon available. Wafer guys margin got squeezed and polysilicon guys reaped all the profit. In Q1 11, the CAPEX for polysilicon for Asian companies could be recouped within one year as spot price for polysilicon was so high (gross margin >50%). Now overcapacity looms, gross margin collapsed and we are at the tipping point where polysilicon companies still need to lower their margins otherwise the whole industry will come to a halt. Presently, wafer and cells producers are barely earning a gross profit.

If you wanted to be cynical, you could say that the Germans and Spaniards actually tricked the Chinese by sending positive price signals for a few years, enticing the Asian the build, build and build, and now that there is massive overcapacity, cost of PV is likely to be close to grid parity. But companies are in dire straits and making poor returns, so any cut in tariffs obliterates them.

As the ability of governments to keep those supernormal subsidies dies (85% of subsidies for solar are in Europe, mostly Germany), the industry is condemned to a massive re-structuring.

Solar returns are collapsing DUE to the big subsidies. Subsidies created this industry and are now part of its demise. They created artificial signals for demand and then ultimately supply. Now, supply is in trouble due to overbuilding/expansions. Is it temporary? Maybe, and if “temporary” means 5 years it will be death for many, but margin compression is not.

Solar energy is not a problem as a concept. Greed fuelled by government-led price signals, that fade as quickly as they come, added to unsustainable debt and undisciplined capital allocation is the problem.

Related posts:

http://energyandmoney.blogspot.com/2011/03/anti-nuclear-state-of-fear-japan-and.html

http://energyandmoney.blogspot.com/2011/01/some-energy-thoughts-for-2011.html

Notes on Africa (this is a follow up to my previous post from Dec 2010)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, Eni, Statoil (Tanzania) Exxon, Statoil, BG, Tullow, Dominion, Aminex, Beach Energy, Orca Exploration, Artumas, Maurel and Prom.

Guyana basin – joined up stratigraphic? …

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.

This is real frontier exploration with promise.

Companies: Exxon, Shell, Total, Repsol, Tullow, Noble Energy, Murphy Oil, Inpex, Petro-Hunt, CGX Energy, Staatsolie (state energy company of Suriname)

West African pre-salt – Gondwana again

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.

Companies: Petrobras, Sonangol, Cobalt, Chevron

Finally, I have screened the entire sector of quoted E&Ps to look for companies with the largest acreage and drilling, still with no production, or development. These are the largest ones, which go from $98m market cap to $665m, a median of $100m equity.

A) None of them has any debt

B) All of them have cash to undertake 18 months of drilling commitments

C) None of them has pipeline projects.

D) Most own 100% of licenses and are operators, with rigs already committed.
E) All of them hold very large acreage with enormous prospectivity (and risk).

. Chariot Oil (Namibia). $640m equity value. Acreage 30,000 sq km. 100% operator. Cash for 20 months of drilling.

. Dominion (East Africa). $150m equity. Acreage more than 20,000 sq kms. Tanzania, Uganda, Congo (with Soco). Cash for 16 months of drilling.

. Tower (Namibia and Namibia). $98m equity value. 18,000 sq kms. Cash in balance sheet.

See: http://energyandmoney.blogspot.com/2010/12/africa-most-promising-frontier-area-for.html