Stock Market Notes

2011 and 2012 -- Years that the central banks drove markets

2012-01-06T13:32:00.001-08:00

A very large factor in the overall market performance this last year has been the actions of the world central banks. Martin Feldstein, at NBER, stated that most of the stock market appreciation last year (2010) was due to the Fed's QE2. See: http://www.project-syndicate.org/commentary/feldstein33/English. According to Marty Feldstein, the income effect of the rising market made consumption go up temporarily increasing GDP.

In other words, the economy was extremely weak, which necessitated the worldwide QE programs, but the printing of money at the Fed made the market go up even as economic conditions deteriorated. So, one could say, the market would be a lot weaker if the central banks didn't step in, and, further if the weak economic conditions continue in 2012 (which, considering the weakness in southern Europe and potential weakness in China and unprecedented deficit spending in the US, is likely) central bank's actions will determine the fate of markets in 2012.

In 2011, the Fed finished up $600Bn of Quantitative Easing then went on a $400Bn Operation twist. Operation Twist lowered long term interest rates to even closer to nothing -- meaning bond prices appreciated. QE2 (coming after QE1 which totaled approx $2Tr) was meant to supply cash to financial institutions, with the intention that they lend this cash to the private sector.

It seems the money from the QE2 went directly from the financial institutions back to buying government bonds, as well as other high grade corporate bonds. Further, according to a paper by M Singh at the IMF, the largest component of the shadow banking system (money market funds, hedge funds, off balance sheet vehicles) is lending to hedge funds and other investment vehicles. So it seems some of this money was lent to these hedge funds and other investment vehicles, which put the money into investments such as stocks and commodities.

The Swiss Central Bank finished up an approximate $100Bn QE program in August buying Swiss Francs to lower the Swiss Franc, while the ECB had a Euro600Bn QE program in November.December to buy up southern EU debt.

Bank of Japan also did a large QE over approx $100Bn to lower the value of the yen this year.

What makes it stressful from an investor's standpoint, is that the central banks are very secretive and hush-hush -- Bernanke for example does not want the Fed audited publicly (and also secretly pushed for a new accounting rule at the Fed that subprime bonds at the Fed can never be marked down). The ECB didn't really announce it's buying program until a few days before -- in fact comments from the ECB made it sound as if the ECB was not going to buy southern EU debt.

So it total, this past year has been really stressful and unusual -- note the Federal Reserve and the ECB had never done any money printing (Quantitative Easing) in their respective institutions' histories. 2008-2011 for the Fed and 2011 for the ECB have been "groundbreaking" years, even as they have kept this information somewhat behind closed doors.

Wealth and GDP

2011-10-10T12:32:00.000-07:00

"Political Economy is defined as the science of wealth" wrote Francis Wayland in 1870 (Wayland was Yale University's first professor of Political Economy). Adam Smith wrote "An Inquiry into the Nature and Causes of Wealth of Nations" in 1776 inspired by a group of mainly French economists called the Physiocrats. The Physiocrats (who could probably be considered the first economists) proposed that all material wealth came from the development of land.

A question is: does the classical view of wealth production provide any insight into the modern conception of GDP and economic activity?

Wealth Defined by Classical Economists

Wealth from a Classical sense (classical economists are economists from the 1700's before the mid 20th century) was defined on a national level as, according to the classical economist Jean Baptiste Say (1821) in his Letters to Malthus on Political Economy. Say asked and answered a series of questions in these letters concerning wealth. Say defined Wealth as "Whatever has a value; gold, silver, land, merchandise..." and then defined Value as "[A product] having utility." Value was conceived of as mainly a product with "utility," and utility was viewed as having a both subjective and a non-subjective element in so far that, according to Say, utility drives value as "persons are then to be found who are in want of this thing (with utility); they desire to have it from those who produce it."

The subjective element of wealth -- wealth as defined that is deemed useful by potential customers in the classical economic tradition, to the extent that they will pay for that item -- is interesting in so far that wealth has to be something not already extremely abundant and/or provided by nature (classical economists asked "if I hold a glass of water, is this wealth? The accepted answer, after much debate was no, in so far that water is already in abundance).

Further wealth could hold significant value, but if this value was not recognized by consumers or if the necessary infrastructure was not in place to realize this value, then perhaps the item would not have value. One could think of, for example, petroleum oil in the 1800's, at first was considered a nuisance for agriculture and therefore did not represent wealth.

Alfred Marshall, John Maynard Keynes' mentor at Cambridge University, in the late 19th century proposed the concept of supply and demand curves for products summing up the idea of price (value) as the intersection between supply and demand for the product.

On a national scale, Jean Baptiste Say defined the "wealth of nations" as: "(A wealthy nation) in which many things of value, or more briefly, many values are to be found." But Jean Baptiste Say did not formalize a measurement system for quantifying a country's wealth -- this was not to be performed until the 1930's under the economist Simon Kuznets (to be examined below).

One last interesting point is that classical economists stated that wealth could only cocur with the legal right of private property: Jean Batiste Say asked in his Letters: "Can Riches Exist without property?" and answered "No, as richest represent property."

Classical Economists on How Wealth is Produced:

The next question is, according to classical economics, how is wealth produced? The production of items of value (note Say did not cover services in detail, or even conceive of services as a major portion of the economy) was split by Say into three separate activities in his Letters (1821):

1. "Cultivation," by which Say meant the production of resources and commodities, agriculture and mining and resource extraction -- Say began with this activity in so far Say was influenced by the Physiocrats, who stated that all value came from land.

2. Manufacturing -- the conversion of resources to a usable end product -- Say expanded and improved upon that all value came from land only by expanding value added to manufacturing.

3. Commerce -- the distribution of manufactured and processed products to the end customer. One can think of modern retail chains, grocery stores and online as falling under this designation of commerce.

Say noted that each of these three steps in the economy was necessary for the completion of the next step, in so far that manufacturing could not occur without cultivation or resource extraction and commerce could not occur without manufacturing or processing. Say did not discuss trade in detail -- whether one step could be outsourced to another country sustainably.

Two questions come to mind: first, would all new industries (from technological advances) since 1821 fit into these three steps in terms of producing value? And second, how would services fit into Say's 3 step framework?

Major advanced such as the cotton gin and steel industry, the Bessemer Steel Process, the steam engine would all fit in very well within Say's Framework. The textile industry, revolutionized by the cotton gin and the spinning jenny -- told resources in the form of raw cotton and manufactured these into clothes, then distributed these clothes to the end customer.

Industries invented in the 20th century such as the computer industry would also fit in, albeit with a more substantially available raw material (semiconductors are made from silicon -- sand, and also energy - from coal and natural gas) and an interesting "manufacturing" process, if one can view production of software or the "soul" of a computer as "manufacturing." (taking prewritten logic commands and constructing them to give instructions, on a silicon base). Technology consulting companies such as EDS could be viewed as providing both manufacturing (programming of local data processing for banks, for example) and commerce -- directly providing a service to the end customer.

One can see that much of our "service based" economy can be viewed as really either processing and/or commerce. Currently retail is classified as services and IT work is also classified as services in modern GDP accounting.

The modern finance industry, one could say is meant to assist the other segments of society. Warren Buffet has stated that the "raw material" of banks is "capital" by which they make loans (end product) in which the capital would not be dependent on physical raw materials (even software depends on silicon, but in modern banking money can be created by the central bank). I am not sure how to classify finance according to Say's three part system, but would lean towards finance supporting other industries, not as an industry in and of itself (one could also make this case with legal services).

The modern health care industry -- which accounts for upwards of 15% of US GDP -- does not exactly follow Say's threefold method -- more thought on this by the author is needed.

To sum up, classical economics was the study of wealth by which a country produced and distributed items of perceived utility, by a three step process of gathering resources by the land, processing these resources and then delivering these products to the end customer. We will next see how this view fits with modern GDP theory. Note that classical economics did not focus in any significant way on debt -- Say did mention national debts, but only in passing, and also did not focus on income distribution -- what would occur if a small percentage of the population owned most of the wealth? Say did not address this in detail, nor did Wayland or John Stuart Mill. ONe would have to wait for economists in the early 290th century such as John Maynard Keynes and Mickal Kaleci to discuss the distribution of wealth.

Modern Gross Domestic Product Defined

Classical economics did not provide a substaniative calculation procedure to determine the size of the overall economy -- before the invention of the gross domestic product methodology in the 1930's economic activity was roughly gauged by production of key outputs such as steel and/or by the unemployment rate. Modern conceptions of gross domestic product are generally based on theories of the early 20th century economist Simon Kuznets: consumption is calculated by utilizing the formula Consumption = income - savings (income both salaried and capital gains and profits can be obtained by tax records). GDP is then calculated by the formula GDP = net domestic consumption = C + I + G + (X-M), which theoretically equals net domestic income (aggregate salaries plus capital gains and profits) which also theoretically equals net domestic product (aggregate hours worked times productivity). The fact that the three equations for GDP must equal each other is the reason, according to Kuznets, that GDP account is refered to as the "National Accounts" (similar to the accounts, balance sheet, cash flow and income statement of a business).

Gross Domestic Product calculations do not focus on the conception of wealth as utility per say. One could conceive of an economy mainly driven by the production and sale of tulips at a very high price, which would result in high sale prices and therefore high salaries and therefore high GDP. However this economy would soon collapse -- once consumers realized tulips are plentiful and don't have much intrinsic utility (cannot be eaten, made clothes out of, etc).

GDP calculations do not give too much indication as to the utility of GDP -- not to say that classical economics provided significant insight into the economy as utility, but at least classical economics would indicate the citizen to consider the functionality of goods produced. Modern economics reports one number, GDP, without much discussion of its underlying "value." An economy producing very high amounts of "intrinsic utility" items, such as food in a period of food, energy, clothing and transport, in a period of surplus of these items (meaning the items sell at a low price) mean that the GDP calculation for this economy would be low, despite the high "real" living standards and relatively high sustainability.

There is a sense Modern GDP accounting has well known shortcomings -- it does not typically (except for certain countries like Norway) account for resource base depletion, GDP only accounts for economic activity in constant currency (so if the currency depreciates by a significant margin it is unclear if GDP is really declining), related to resources the sustainability of GDP is not indicated, nor is the overall debt level of the economy. GDP also does not measure the distribution of wealth in the overall economy -- it seems a country would be "richer" overall if more of its citizens enjoyed a wider range of its products.

It seems that the production of goods and services in Say's three economic productivity dimensions that have higher "utility" that satisfies "needs" -- clothing, shelter, nutrition,

What Will Happen When Greece Defaults?

2011-10-07T12:03:00.001-07:00

Greece will likely not be able to pay back the full value of its debt, due to the fact that Greek debt to GDP is 140%. Many market commentators are stating that a Greece default will not cause a significant move in the markets ("Greece is only 3% of EU GDP" or "A full meltdown is very unlikely but the market must price in this very unlikely event")

These commentaries do not perform a cause and effect analysis -- meaning, what would occur in the case of a Greek default, if one takes into account the impact on banking institutions, and national economic activity, in a step by step, sequential analysis? Such an analysis shows that significant problems occur with a Greek default for the EU and world economy and markets.

If Greece defaults, then the value of its bonds will drop by 50-80%. Note that the average sovereign default since 1980 according to Moody's has seen net losses of between 50-60%, but Greece is has significantly more debt than the average default, so losses would likely be higher.

Greek Banks would be insolvent:

This default in turn would cause the major banks of Greece (which in turn hold Greek sovereign debt) to go bankrupt. As the Greek government cannot guarantee the deposits of the Greek banks, the deposits of these institutions would be wiped out.

Significant Declines in Greek GDP:

What would happen to Greece's gdp? Many large banks go bankrupt in Russia in 1998 (although not in Argentina to the same extent in 2002-2003, as Argentina limited the amount of funds deposit holders could withdraw) as Russia defaulted on its debt in that year. Russia's GDP fell approximately 50% from 1992 to 1996, then recovered somewhat from 1996 to 1998 but then declined a further 15% fro 1998 to 2000. Argentina's gdp declined approximately 15% from 2002 to 2004. Both countries began to recover when their currency declined significantly and the export market (as both Russia and Argentina are major commodity exporters) picked up.

Greece's GDP would likely fall more than 15%. The world economy is more fragile currently, so a recovery in two years may not occur, through an export led recovery, so the slump would likely last for several years. The issue of leaving the Euro would have to be addressed -- instituting a new currency in a very difficult economic environment would be problematic.

Other Southern EU Banks at Risk:

Deposits in other southern European Union countries would be at risk, in so far that account holders in Italy, Portugal, Spain and Ireland would see Greek banks default, then attempt to transfer their deposits to safe havens, whether northern European banks. Italian, Portuguese, Irish and Spanish banks would be at risk from direct losses from holdings of Greek bonds (total outstanding Greek debt is over $400Bn, held mainly by European banks). As the southern EU governments are already highly levered, it is not likely that they would have the ability to raise funds to bank stop losses in their banking systems.

Southern EU Countries GDP at risk of significant decline:

Southern EU banking insolvency would be a significant risk, which could drive declines in Southern EU gdp.

French and German banks with exposure to Greek debt would be at risk:

Deutsche Bank and the major French banks have significant exposure to Greek debt, which would mean significant losses at these banks, and likely a need for government assistance. As both France and Germany have debt to GDP ratios in the 80% range, further payments to their banks would likely move their respective debt to GDP levels to close to 90%, which is the cut-off range (according to Harvard economics professors Kenneth Rogoff and Carmen Reinhart) for markets funding debt to GDP without significant issues (although this 90% cut off grade has received some criticism as being too arbitrary, however 90% likely does not leave too much room for further debt financed growth or assistance).

Certain Hedge funds will likely go insolvent and will likely have to liquidate, driving stock values down:

In the October 2008 crash, according to the book "The Quants" many large quantitative and macro hedge funds which were levered had to panic sell in order to meet investor redemptions. With the unprecedented volatility in the markets from a Greek debt, some larger hedge funds would have to liquidate, driving asset prices down.

Mutual Funds would see higher redemptions, causing selling to drive the market down:

Most mutual funds have been bullish through this crisis and have encouraged their investors to hold through the long term. Mutual funds had record low levels of cash in July and many have seen significant declines in equity values since that time. Further the average mutual fund investor is likely an aging baby boomer who is nearing retirement. All these factors point to higher redemptions.

Pension Fund Values would decline, leading to unrest:

Pension funds as a whole are more heavily invested in equities, due to the fact that they can assume a higher rate of return on equities (more in the range of 8-9%) verses bonds (in the range of 4-6%). The projected value of the pension plan is highly dependent on the projected return on plan assets. With panicked selling, pension plans would see the value of their assets decline significantly.

Safe Haven Assets would increase in value:

Safe haven assets are likely the US dollar, the Swiss Franc, potentially precious metals (however precious metals are held by hedge funds, which would likely liquidate in the short term).

Government Bailouts of Banking Institutions would be even more unpopular with the public, worsening the banking crisis.

The public of many countries is already upset with the banking bailouts of 2008 and 2009, and would not be in any mood for continued bailouts. This would complicate efforts to shore up bank balance sheets, making the banking crisis worse than otherwise would be. As banking crises have a "cumulative" character - the farther they are allowed to fester, the more the public panics and withdraws funds, potentially causing and worsening a bank run -- the unpopularity of bailouts can only worsen events for the banking system.

Recovery for Southern Europe would be more protracted, due to a weaker than normal world economy and therefore export market:

Both the United States and China are currently slowing -- China is attempting (successfully) to slow housing and infrastructure spending, however this means that commodity demand from China is slowing. This, in turn, impacts the major regions more dependent on commodity export: Latin America, the Middle East, Russia, Australia. This means that the EU will have a more difficult time utilizing exports to dig itself out of crisis.

What can be done to avoid a Greek Default?

As this analysis shows that a Greek default would be extremely problematic for the EU and world economy as well as stock markets, the question is, what can be done to avoid a Greek Default?

Either the EU, or another institution such as the IMF, should come in and guarantee Greek debt so that banks are assured of receiving 90%+ of their full value of their bonds. If the full value of Greek bonds are more or less assured, the chain of events described above will not occur.

However, likely the sovereign debt of the other Southern EU states, Italy, Spain, Portugal as well as Ireland needs to be backstopped as well in order to stop potential defaults of these countries, which in turn would cause banking crises moving to economic to market crises.

What would be the amount of funds needed to guarantee Greek and Southern EU debt?

Something in the range of 50-80% of Greek Debt would be needed to fully backstop this debt, meaning funding in the range of $200Bn to $360Bn. This is likely at the highest range for France and Germany combined to fund. Germany's debt to GDP is 80%, and German GDP is $3.33 Trillion, meaning that Germany can afford $333Bn before it moves to 90% debt to GDP (the danger zone, according to Rogoff and Reinhart). France's debt to GDP is also approximately 80%, and France's GDP is approximately $2.65 Trillion, meaning France could contribute $265Bn before reaching 90% debt to gdp.

Both France and Germany would therefore be seriously strained to provide a backstop to Greek debt, and the UK (also at 80% debt to GDP) is not in the Eurozone, and would likely significantly resist paying for Greek debt. Other countries with relatively low debt to gdp such as Finland (48% debt to GDP) only have smaller GDP levels (Finland's GDP is approximately $222Bn). Of course, Southern EU countries such as Spain and Italy cannot provide funding to Greece, in so far that their debt to GDP levels are already too high and the markets would likely not support these countries issuing more debt.

The problem is that not only Greek debt needs to be guaranteed, but also Italy, Spanish, Portuguese and Irish debt needs to be guaranteed. Italy currently has a debt to gdp of 119% with total debt outstanding in the $2.5Trillion range. In order to get this debt down to a manageable 80%, total funds would be needed of approximately $700Bn. All in all, the total backstop for Europe to guarantee all its "in danger" countries would likely be over $1Trillion.

Overall, it appears unlikely that France and Germany or a combination of other European countries can backstop $1trillion.

Can the IMF provide funding to Europe?

The current lending capacity of the IMF is approximately $400Bn -- so the lending capacity of the IMF would have to be increased. To get to $1Trillion, the United States (which contributes 17% to the overall IMF funding capacity) would have to increase $106Bn, which is possible, but politically unlikely. Other countries, such as Japan (which contributes 6% to the IMF budget) would have a difficult time raising funds to contribute to a vastly increased IMF lending capacity. Overall it appears the IMF will have a very difficult time guaranteeing EU debt alone.

Can a combination of IMF and the EU Guarantee Southern EU Soveriegn Debt?

This is possible, but would require the IMF taking the lead, as it is difficult to see how the northern EU states and France could guarantee more than $400Bn, while over $1 Trillion would likely be needed. An increased funding capacity to $500-$700Bn for the IMF is more possible -- meaning additional funding by $200 to $300Bn. This would require close cooperation between the IMF and the EU, which appears very difficult currently, politically. But financially, it is possible although difficult.

Conclusion: Greek Default and Southern EU Sovereign Defaults Very Possible -- if not likely -- without joint EU -IMF Bailouts

Currently as of the beginning of October, it does not look as if there is the political will to get the EU and IMF coordinating on a combined, increased bailout package, which would require significant additional funding (read: additional taxes) for the EU from France and Germany and increased funding for the IMF (read additional taxes for IMF member countries). The likelihood of this occurring is very difficult to say, but cannot be considered "the most likely outcome" meaning that the probability is higher for less than a needed guarantee for southern EU debt materializing in the future.

Valuing Corning in an Extended Period of Lower Revenue Growth

2011-10-06T14:01:00.000-07:00

Corning (NYSE: GLW), founded in 1851, has historically been at the forefront of glass production technology. Corning invented the glass process to produce light bulbs in the late 19th century, fiber optic cable in the 1970's, and liquid crystal displays (LCD's) in the 1990's to early 2000's.

Glass, which is produced from silicon (which in turn is made from sand) will likely be utilized in society far into the future, in so far that glass has certain suprior optic characteristics vis-a-vis plastics, a chief competitor material. Further, plastics are produced from more expensive hydrocarbons.

Corning, along with many downtrodden stocks in the current environment, is currently selling at a multi-year lows, at approximately $13, down from $22 in July and only moderately above the depths of the near $8 valuation at the bottom of the financial crisis. Corning's valuation represents 1x book value and approximately 6x historical earnings, with a net cash position of over $4.1Bn on Corning's balance sheet.

The question most relevant for investors is: at this current valuation is Corning significantly undervalued?

The answer to this question mainly lies with the direction of the High Definition television market. Corning's current profitability is highly dependent on its patented Fusion Process for liquid crystal display (LCD), which are used for high definition televisions and displays for computers and hand held devices. Corning, along with its 50% owned equity company Samsung Corning, has an estimated 83% market share in the manufacture of LCDs.

In the last quarter ended 6/30/11, Corning's LCD segment, along with equity earnings from Samsung Corning, comprised 90+% of operating income.

Corning's Profitability is Likely Significantly Higher in LCD's Produced for HD Televisions Verses for Computers and Hand Held Devices:

Corning in its 2010 Investor's Day estimated that approximately 60% of the volume (square feet) of this LCD glass was produced for HD televisions, and 40% by sq footage was produced for computers and hand held devices. Corning does not split out the relative profitability for computer and hand held display glass, however it is likely that Corning derives a higher percentage of its display earnings from HD Television glass, in so far that this glass is significantly thicker and represents a higher valued added product, in which screen resolution is significant competitive differentiator.

The Fusion Process Invention for LCD Marked an Incredible Turnaround for Corning in 2004:

Corning in the 1990's derived the majority of its income from the production of Fiber Optic fiber, where GLW had a market leading market share. In 1998, Corning derived 65% of its operating income from its telecommunications division, which mainly sold fiber optics. Interestingly, in 1998, Corning derived only 11.5% of its operating income from its information display segment, which at that time produced glass mainly for cathode ray tube televisions and computer monitors (this segment would by 2005 comprise the vast majority of Corning's profits through LCD technology).

Optic fiber sales collapsed in 2000 following the popping of the Internet bubble. Corning reported losses of $5.2Bn, $1.2Bn and a slight gain of approximately $200M in 2002, 2001 and 2000 respectively. In retrospect, it could be said that fiber optics worked TOO well, in so far that, according the publication The City of Light: The History of Fiber Optics by a medium sized, single fiber optic cable had enough capacity to carry ALL the phone calls in the United States simultaneously. One could say, Fiber Optics would be built once, then would not need to be rebuilt for 10 years or more -- a difficult market to build a sustainable business.

Are there Parallels Between Fiber Optics and LCD Technology in terms of the technology "working too well?" LCD's interestingly do not wear out at any sort of moderate pace -- most technological publications estimate that LCD screens will last decades -- 30,000 to 60,000 hours for the LCD screen to lose 50% of its display brightness, which, at a rate of 8 hours of use a day means a minimum of 10.6 years before the LCD needs to be replaced.

One could envision a scenario in which consumers buy one LCD television and do not replace this television for 15 or more years. Corning, in its 2010 annual investor meeting, estimated that 50% consumers would replaced their HD televisions every 6 years on average, but this data is speculative in so far that HD televisions have been introduced only since 2006 and therefore not many consumers have replaced their televisions for functional deterioration or any other reason.

HD televisions were introduced in 2006, and experienced rapid growth as consumers replaced their traditional cathode ray tube (CRT) sets with LCD and plasma televisions. In North America, Europe and Australia and New Zealand, initially the sales of HD televisions was likely buoyed by a strong housing market -- as one buys a new house, part of the improvements process likely involved buying a HD television for the living room (which could be viewed as an "investment" along with new floors, landscaping, furniture etc). All in all, HD televisions increased at an annual rate of over 30% from 2006 to 2008, driving HD televisions to a respectable 44% of all televisions in the United States (or slightly more than 1 HD television set per household in the US) by 2010. HD televisions represent 37% of all televisions in the EU-27 and 45% of all televisions in Japan. Even China reports HD television market share of total television units of 21% across all approximately 400 million households, even as according to the China's People Daily, the Chinese middle class (defined as households with income of at least 60,000 rmb or approximately $10,000 per annum) comprises 23% of the total population -- in other words nearly all of China's middle class as of the end of 2010 already owns an HD television set.

Will HD Televisions Units Sales Grow Significantly Going Forward?

At first glace, this question would be ridiculed by Corning and industry consultancies, which would reply of course! Corning has estimated that the total sq footage of HD televisions will increase at an annual rate of 21% in China and other emerging markets, with a total increase in HD television sales to 2014 across all areas of 12% (with only 4% growth in North America and Europe on an annual basis).

It is argued here that 1) HD television penetration in China likely will only grow at the rate of the overall Chinese middle class growth and 2) economic weakness in the US and Europe will mean flat to declining HD television unit sales in the near term.

The Chinese publication estimated at in July 2010 that the middle class would reach 48% of the total population from the current 23% by 2020, or a near doubling in 10 years. However, this implies that HD television sales will increase at only an approximate 7.2% per year -- and this under more optimistic economic growth forecasts for China of last year (in which growth rates of 8-10% were considered attainable for the next 10 years, currently China is more likely to achieve lower economic growth).

HD televisions do not appear to be any cheaper within China than in the US or Europe, with starting costs at around $US300 -- a newly minted middle class member of China with approximately $10,000 of annual income can afford this purchase but those with lower incomes likely will keep their old CRT televisions (currently China already has on average 1.1 televisions per household).

In the 4th quarter of 2008 and the first quarter of 2009, Corning's display segment reported significantly lower sales, total year on year sales declines of 50-58%, as North American and European consumers cut back on discretionary purchases. As Goldman Sachs has recently updated the forecast for a recession in the US to a 40% probability in 2012, and likely the odds of a recession in Europe are significantly higher (given the banking crises there) unit sales growth of HD televisions appears to be on a declining trend in the US and Europe for 2012 and the intermediate term.

Overall, Corning's 2010 investor day forecasts of 12% industry growth in HD television sales growth should be averaged to a rate that is significantly slower, and potentially (probably) slightly negative (mid single digit sales growth in China, declining sales growth in North America and Europe). The question is, can Corning remain profitable in these conditions?

Estimating Cornings' Display Segment Profitability with Mid-Single Digit HD Television Sales Declines:

In the 1st quarter of 2009, Corning's display segment actually reported a small profit (excluding Samsung Corning) of $38M despite 57% lower sales year on year -- however $37 of this profit was due to favorable exchange rates. Some of this moderate result was due to Corning idling LCD plants. Impressively, Samsung Corning only reported 13% lower year on year profit declines to $180M in the 1Q 09 -- mainly (appears, as Samsung Corning does not publish separate financial figures) due to continued growth in HD sales in China during 2008 and 2009 as the Chinese middle class bought new HD televisions.

With lower than expected growth over the near to intermediate term, it can be inferred (very roughly, based on Corning's historical ability to idle plant capacity) that Corning will eek out approximately low profits, in the $100M range per quarter. It does not appear that Samsung Corning will get the same boost from Chinese demand going forward into 2012 as it did in 2008 and 2009, but on the flip side, other region's declines of 50-58% in revenues is quite severe and not likely to be repeated. Total yearly profits therefore appear around $400M to $800M in the LCD division for intermediate term.

What Annual Earnings in a Slow Growth Environment would Corning's Other Division's Yield?

Corning's fiber optics group has reported relatively break even profits (with growth mainly dependent on infrastructure spending in China) and three interesting, but smaller groups -- specialty materials which includes Corning's Gorilla Glass and Biologic Glass, which includes high-tech glass for biotech laboratories (cells, test tubes, etc -- glass is non-reactive so has an advantage in these applications verses plastic). Corning's environmental technol0gies group produces glass for catalytic converters, and reported profits of $42 in 2010. Earnings were $60M for life sciences in 2010, and Gorilla Glass reported impressive sales growth but no profits in 2010. All in all, in appears Corning's other divisions can be counted on for around $100M in annual earnings in a slow economic growth environment in 2012.

Dow Corning Earnings:

Corning owns 50% of Dow Corning, which is a major producer of silicon and silicon based materials. Dow Corning is a large company in a period of world economic growth, with earnings approaching $800M for 2010. In a recessionary environment, Dow Corning broke even in 2008. With recessions more likely than not in 2012, Dow Corning appears to be set for low profits in 2012, barring significant governmental action.

Likely Earnings for Corning in a low Growth Environment:

Corning appears to be set for $600M in annual earnings without significant new product introductions ($400M approximately in their Display Segment and $100M per year in their other segments combined, and $100M for the 50% stake in Owens Corning). With a 14x multiple, $600M would command a market cap of $8400M (plus $4.1Bn of net cash) would be valued at $12.5Bn -- current entreprise value is $15.71Bn.

Corning would likely significantly disagree with this analysis, but such an analysis assumes significantly lower HD television sales growth and significantly lower replacement rates for HD televisions, based on a more challenged global economic enviornment. To the extent that Corning is accurate in forecasting close to double digit HD television sales growth going forward, Corning's long term value would be significantly higher.

Very Low Cost Electricity -- Impacts on Commodity Prices

2011-07-14T15:05:00.002-07:00

What impact would very low cost electricity have on commodity markets? First let's consider on commodity prices that are used for electricity generation -- mainly coal and natural gas. This is to say, if, the great scientist John Von Neumann was correct in the previous post, nuclear energy had become extremely abundant to the extent that natural gas and coal were mainly used for chemical feedstocks, then the expenditure that was used for natural gas and coal for electricity would be diverted to (costless) nuclear fuel -- or another costless source of electrical power.

However note, that the previous post calculated the savings from electricity, which should include the expenditures for coal and natural gas. This is to say, as almost all of the coal and natural gas in the United States is purchased by power utilities as inputs, and then sold to consumers through electricity as kilowatt hours, savings in electricity costs would include the savings in costs spent on natural gas and coal (interestingly, this calcualtion makes sense, the entire natural gas market in the United States in 2010 was 24.1 billion cubic feet, which at a price of $5 per cubic foot is approximately $120Bn. The price of all electricity sold in the US in 2009 was $383Bn (about 4.5 Billion megawatt/hours at 9.7 cents per megawatt -- the total expenditure on electricity includes the expenditure on natural gas and coal).

Further we will assume that electric power has become so abundant that natural gas is not even used for heating, but for chemical feedstock purposes only. This usage represents actual cost savings however (not included in electricity), so in 2010, the US according to the EIA supplied 8.2 Billion cubic feet to residential and office and commercial buildings, which at a price of $5 per cubic foot would be cost savings of $41Bn.

Natural gas in particular is used as a feedstock for chemical synthesis, as is oil -- approximately 20% of the oil consumed by the United States is used as a feedstock for petrochemicals. According to the EIA, the US supplied Industry with 6.6B cubic feet. Let's assume without the recent rise in natural gas prices over the last decade, with very low cost energy, natural gas would average long term prices from 1980-1999, of approximately $1.50 per cubic foot (much natural gas is produced along with oil, and producers of oil could supply natural gas as a side business to chemical producers). This would mean savings of ($5-$1.50)*6.6Bn = $23.1Bn

According to the EIA, only approximately 2% of coal was used for non-electricity generation purposes in 2010, so the vast majority of cost savings that are not already calculated by savings in electricity costs.

How would the price of Oil be affected by very low cost electricity?

Oil prices are determined by supply and demand. Demand: Oil on the demand side is mainly used for transportation (80% in the US) and petrochemicals (20%) in the US. As oil is a world market, the world demand for oil determines world prices, and world demand is a higher percentage for transportation (as the United States is the world's largest producer of petrochemicals).

It is not clear if a large number of cars would be converted to electrical (battery-operated if electricity was very low cost, and whether this would encourage more public transport dependent on electricity (trains, trams, etc). Currently the firm "A Better Place" is undertaking projects to convert a large percentage of cars in several countries (Israel, Denmark, Australia) to battery powered -- in light of high oil prices. With extremely low electricity costs, more battery powered vehicles is more feasible.

On the supply side, low cost electricity would assist exploration and production through lower cost drilling as well as refining and marketing, through lower electricity costs.

How much would oil prices be lowered in a world of very low electricity costs, stemming from these factors? It is very difficult to tell. Supply would be incentivitzed to increase by a small amount, while demand would likely decline, by what amount is very difficult to tell. One could say that China would be more likely to build a transportation infrastructure highly dependent on electricity, in light of its relatively low domestic reserves of petroleum, which would likely have reduced demand by a great deal throughout the decade of the 2000's. China has been cited as one of the main drivers of higher oil prices, by several commentators.

For the purposes of this analysis, oil prices with very low electricity costs are assumed to decline to levels averaging in the 1990's, of approximately $20 per barrel (this is a large assumption! But also shows how much oil prices have risen over the last decade). With prices of $20 per barrel, the US would save ($90 per barrel approximately currently - $20 per barrel)*19.5M barrels consumed per day*365 = approximately $498Bn per year.

Would the prices of non-energy related commodities such as food (grains) and metals decline with very low cost energy?

As the prices of all commodities are determined by supply and demand, one would go through the sources of supply and demand for each commodity to determine what direction the prices would move. It would be very difficult to argue that prices would actually go up with very low cost and abundant electricity. For the purposes of this analysis, I will leave out the cost savings as an impact on GDP (as this post is getting very lengthy:).

Environmental Impacts from Low Cost, Clean Energy:

An additional benefit to GDP would be from environmental impacts. Carbon production would be significantly lower, as most carbon in the atmosphere is due to coal production and oil production (coal consumption would be much lower, oil consumption would be debatable, how much it would decline, as argued above).

Oddly, GDP impacts from lower carbon would not be dramatic as of 2011, as very few companies engage in carbon trading/credits, however if some publications and scientists are to be believed -- such as the late Steven Schneider of Stanford University, a lower amount of carbon in the atmosphere is an extremely -- extraordinarily -- serious matter.

Some countries' GDP such as Norway includes environmental degradation, but the US' GDP to a large extent does not, so this would not be directly added to GDP. I will look for environmental estimates of the impact on GDP from other published sources.

Additional Technological Breakthroughs from Very Low Cost Electricity:

Very low cost electricity would likely lead to more scientific breakthroughs (besides the knowledge of low cost nuclear energy in itself) with more funds being available for scientific research grants, and lower costs to research labs (which depend on electricity as a cost and an input to experiments). This is likely a critical outcome of lower cost electricity, but I won't go into detail on this as this time as this post is getting quite lengthy.

Conclusion: Calculation of Additional Savings from Lower Oil and Natural Gas Prices:

In addition, to the GDP benefit calculated from lower electricity costs in the previous post, the additional lower oil and natural gas prices are assumed to add an additional (pre-multiplier) $498Bn + $41Bn + $23Bn = $592.1Bn. At different multiplier effects (see previous post for a discussion):

At a MPC of 0.94, additional $9368 Bn of GDP
At a MPC of 0.5, additional 1242Bn of GDP

Combined with the previous gain in GDP from lower electricity costs:

At a MPC of 0.94, total GDP gain of 122.7% (more than twice as large of a GDP with zero cost electricity)
At a MPC of 0.5, a total GDP gain of 58.53%

What Does of This Discussion of low cost electricity have to do with stocks?

Well, this discussion is somewhat removed from stocks but has been inspired by a thought experiment of why the economy is not performing as expected currently with lower consumer expenditures on the horizon, and a shaky recovery (the recent Federal Reserve minutes demonstrated significant concern on the economy, and employment is disappointing). If electricity was available at a very low cost, likely the economy would be doing significantly better now and the stock market (as an index, with perhaps different/additional firms in it) would be much higher. As many economists have stated, GDP over the long term is determined by productivity, and productivity would be enhanced by low cost electricity -- and a higher GDP means that we would all be wealthier.

What impact would very low cost electricity have on the economy?

2011-07-13T12:39:00.000-07:00

An interesting question to ask is what effect low cost electric power would have on the modern economy. In the United States, electricity rates are climbing upward, averaging 9.7 cents per kilowatt hour in the year ended February 2011, up from approximately 5.5 cents per kilowatt hour in 2000. (non-inflation adjusted, however) This is approximately a growth rate of 5.2% per year, a growth rate significantly higher than the average real GDP growth rate of the US of 1.5% per year over the same period.

Electric power is of course a prerequisite of almost every aspect of modern life, from the production and shipping of commodities (crushing reservoir rock, drilling into rock, pulverizing grains, etc) to manufacturing, to the operation of consumer products that rely on computing, lighting and/or moving parts or chemicals of any type.

The increasing cost of electric power in the United States is been driven to a large degree by higher coal and natural gas prices, which, combined, accounted for approximately 70% of electricity generation. One can certainly say that supply is failing to keep up with demand -- the reasons for the decline in supply relative to demand of coal in particular is not fully understood to my knowledge, as the supply of coal appears, on the surface, to be abundant. (I will address this topic of supply and demand in more detail below).

Alvin M. Weinberg's The First Nuclear Era: The Life and Times of a Technological Fixer captured the optimism of future low cost power -- nuclear power -- in the early 1950's until the early 1970's. Alvin Weinberg, along with the Nobel Laureate Eugene Wigner, were two scientists at the forefront of the development of nuclear power, and both theorized that fission and later fusion power would become exponentially more efficient (an electricity production version of Moore's Law) over the next few decades. As such, Weinberg describes (somewhat infamously) that nuclear power had the potential to be "too cheap to meter" which earned him and the nuclear community a significant dose of ridicule with the higher build costs experienced in the US in the 1970's.

Interestingly the potential of nuclear power was shared by other members of the scientific community in the 1950's and 1960's. One of the greatest scientists of the 20th century, John Von Neumann, wrote in 1955 that nuclear power was likely to be the source of vast amounts of energy by the late 20th century: "A few decades hence (nuclear) energy may well be free -- just like the unmetered air -- with coal and oil used mainly as raw materials for chemical synthesis, to which, experience has shown, their properties are best suited." Science Fiction movies such as "The Day the Earth Stood Still" (1951)implied that rapid technological progress in nuclear energy production was imminent (the movie showed Aliens coming to Earth due to the potential technological breakthrough from nuclear energy).

In 2011 however we are still stuck with a significant reliance on oil and coal for energy while nuclear is fading as an energy source, and energy is anything but free as the cost of energy is rising.

Estimating the Impact of Higher Energy Prices on GDP:

The most direct way to estimate higher energy prices is through treating higher energy costs as a "tax" on consumption on the residential electricity usage side and as a cost to business on the industrial and commercial usage side. Utilizing the GDP formula: GDP = Consumption + G + (X-M) + I, consumption should be reduced by the amount of the additional electricity costs on residential customers. Note that residential customers comprise approximately one third of US electricity demand, while industry comprises one-third of electrical demand and commercial (office buildings, retail, grocery, non-industrial) comprises one-third of demand.

Higher electricity costs on industrial and commercial sources will be treated as a direct tax to income in the income measure of GNI -- as GNI must approximately equal GDP then a simplifying assumption is that the higher rates pass through to consumption as well on the consumption measure of GDP. (actually I am not sure if this assumption holds, but will go with this anyway :)

The Keynesian Multiplier!

I've been informed that a higher amount of consumption would ripple through the economy through Keynes' multiplier. This is to say, that as a typical consumer has more income, they spent a percentage of this income, then the recipient of this income spends the income, etc, leading to a "ripple" effect through the economy. Keynes termed this effect "the multiplier" which actually (I believe) wasn't Keynes' original idea but one of his student's ideas (the Polish economist Michal Kalecki had a similar idea of revolving around additional stimulus impacting the economy, but did not come up with the idea of the multiplier).

With additional income that is present over all time periods -- and not during a recession (when consumers are more likely to save income to reduce debts and plan for an uncertain future) the marginal propensity to consume should be higher, towards the normal spending range for Americans, which is currently around 0.94. In times of recession, tax cuts tend to have a lower MPC, this paper argues that the MPC in the 2001 tax cuts was somewhere between 0.6 and 0.4.

The impact will be calculated according to the simplified MPC impact on GDP formula: Change in GDP = 1/(1-MPC)

So, a calculating the increase in GDP from electricity costs at a variety of rates per KWh verses the average rate of 9.7 cents in 2011:

Total Electricity Usage (thousand MegaWh) (2009): 3950331

Cost per KWh (cents) 9.7 8 7 6 5 4 3 2 1 0
Total Cost $383,182,107,000.00 $316,026,480,000.00 $276,523,170,000.00 $237,019,860,000.00 $197,516,550,000.00 $158,013,240,000.00 $118,509,930,000.00 $79,006,620,000.00 $39,503,310,000.00 $0.00
$ Savings (verses $0.097) $0.00 $67,155,627,000.00 $106,658,937,000.00 $146,162,247,000.00 $185,665,557,000.00 $225,168,867,000.00 $264,672,177,000.00 $304,175,487,000.00 $343,678,797,000.00 $383,182,107,000.00
GDP 2009 $12,832,600,000,000.00

Percentage Increase in GDP 0.52% 0.83% 1.14% 1.45% 1.75% 2.06% 2.37% 2.68% 2.99%

With a Marginal Propensity to Consumer of 0.94 for additional consumption from additional income, increase in GDP:8.72% 13.85% 18.98% 24.11% 29.24% 34.37% 39.51% 44.64% 49.77%

With a Marginal Propensity to Consumer of 0.5: 1.05% 1.66% 2.28% 2.89% 3.51% 4.12% 4.74% 5.36% 5.97%

Results: At first glance, with electricity at ZERO cost, the increase in GDP is appears to be only 2.99% from current levels, as a total, not in growth terms. (meaning that the savings from electricity are equivalent to about one year of additional GDP growth, as the US economy can easily grow about 3% in real terms during a good year).

However this result does not take into account the effects of the multiplier. With a normal multiplier of 0.94 -- meaning that consumers spend 94% and save 6% of their income -- the increase in GDP with free energy is nearly 50%. With a multiplier more in line with stimulus/tax break spending of 0.5, the increase in GDP from zero cost energy is only about 6%.

The 50% increase in GDP sounds more in line with what one should expect from zero cost energy, in a very unscientific way, mainly by being be more in line with the optimistic comments from the great scientists of the 1950's, referenced above:). Nevertheless, it is likely that the increase in GDP from very low cost energy would be even higher, for several reasons.

Reasons for likely higher GDP from Low electricity costs than implied by the multiplier:

First of all, low cost energy would likely translate to lower cost commodity prices across all sectors, in so far that cheap and abundant energy can be used to produce and extract commodities at a lower cost, leading to higher returns for oil, mining and agricultural firms. For oil refining, for example, electricity costs are approximately 10% of total costs. Lower costs would encourage higher supply, lowering prices relative to demand.

Low Cost Electrical Power as a Signal to the Market That an Energy Shortage is Not Foreseeable:

One aspect of very low electricity costs is that it would signal that a shortage in other energy commodities -- oil, natural gas and coal -- is not imminent over the medium term. There has been a lot of speculation on why the prices of commodities have risen over the past decade, for example this discussion forum at the Economist Magazine presents a wide variety of reasons for rising commodity prices, from Federal Reserve monetary policies, to demand from China. Financial speculation has also been blamed in some circles. One reason for higher prices is that an impending shortage may be anticipated relative to supply.

Adam Smith once asked, "Why is it that diamonds, although frivolous, are expensive, while water, while necessary for life, is free?" This question led decades later to the concept of supply and demand (invented by the economist Alfred Marshall, in (incredibly for such a core concept) the late 1800's. One can say, if water was in shortage, it certainly would be expensive -- the last remaining volume of water would be "bid" upon by millions of individuals (one can think of the movie "Mad Max" -- absolute chaos if water was in shortage relative to demand (although in that movie it was gasoline that was in shortage)(perhaps this mental picture is a bit silly but does illustrate the basic concept :). There is a lot of evidence that many key commodities, from oil to copper to even grains, have been getting close to shortage levels (the subject of this is lengthy, and for another post). For example, the additional supply of iron ore in late 2009 were bid upon by the European Union and China, with the only additional supply coming from three companies (BHP, Rio Tinto and Vale), causing the price to increase from around $80 per tonne to over $200 per ton. China, in particular, in late 2009 was desperate for iron ore as a key input into in construction-heavy stimulus program passed in 2008 -- the economic livelihood of China was at stake in obtaining iron ore as as such demand outstripped supply, causing prices to skyrocket.

Figure 1: The Historical Price of Iron Ore:

I would argue that a proper calculation of GDP savings would calculate additional price declines across energy as well as metal and food related commodities, stemming from low cost electricity. As this post is getting lengthy, I will calculate this GDP increase in the next post.

Ratings History and Credit Risk for Southern EU Sovereign Debt

2011-06-07T07:52:00.000-07:00

Contagion in 2008 was driven by credit losses, and so it follows that the main risk for a new round of contagion is also credit risk. This is to say that the EU banks potentially could lose a lot on the default/restructuring of Greek and/or Irish debt, and/or other Southern EU debt.

Credit losses depends in part on the previous ratings of, in particular, Greek and Irish debt -- anything above A would mean that the European banks could hold the government debt without much in the way of reserves. (I believe under Basel, a bank can buy with AAA rated debt with no reserves, AA with 10% or so and A with 20% or so -- need to check this)

This is what got the banking system into such a tangle with the subprime mortgages -- they were rated AAA, and so the banks bought them without almost any reserves. The losses flowed down straight into equity.

So rating history of Greece: (Moody's)
currently as of 6/11 Caa
A1 --> A2 12/09
A2 --> A1 11/02
Baa3 (oldest I can find) 1996

So Greece has never been above A2, which means the European banks likely have some reserves for this debt. (this is to say, the writedowns won't be the same as write downs on AAA debt)

Raing History of Ireland (Moody's):
Baa1 --> Baa3 4/11
Aa2 --> Baa3 12/10 (ouch!)
Aaa --> Aa2 7/10 (Ireland was rated triple A??)

Note that from 2000 to 2007 Irish debt/gdp was below 38%, reason for the AAA rating, now it's at 93.6%. However, the main problem in Ireland is the banking system not necessarily the governmental debt. If the governmental debt became an issue, this could be a problem (only slightly mitigated by the fact that overall Irish governmental debt is not overwhelmingly large at around $US165Bn approximately -- in so far that the EU banks tend to be highly levered and any losses will put capital ratios at risk).

Other countries:
Spain:
Aa1 --> Aa2 3/11
Aaa -> Aa1 10/10 (Spain was also triple A!)

Note however Spain has debt to GDP of 63% so isn't a huge default risk currently.

Italy:
Aa2 (current)
Aa2 (2007)
Aa2 (2004)
Aa3 --> Aa2 5/2002

Appears Italy has been rated Aa2 for a long time, before in 2002 it was Aa3 (thank goodness it hasn't been AAA).

Overall, the main risk again appears to be Italy -- due to its relatively high rating and above 100% debt, so far the market isn't worried about Italy, rather Greece, which was never rated higher than A2 -- EU banks likely have reserved (in part) for holdling Greek debt.

Still there is risk due to the fact that the European banks tend to be more levered than American banks. I´ll research to see if the major EU banks publicly disclose their EU sovereign debt holdings.

Some Thoughts on the Current Market Volatility

2011-06-05T18:57:00.000-07:00

I spent the weekend reviewing the economic situation and the most concerning situation to my mind is Greece and Ireland, in the EU. Northern Europe -- mainly Germany - is effectively transferring capital to Ireland (through Central Bank transfers) and Greece, direct monetary transfers to the government. Losses in the banking system in Ireland, and a lack of tax revenue in Greece to cover governmental debt interest costs are driving the need for capital transfers.

Greece is interesting because it is mainly a governmental problem, not a banking problem -- Greece has serious societal problems. Most other countries with problems in this last downturn saw banks sort of drive the economic problems, (one can think of the US, Ireland, Iceland, Britain) but Greece mainly has problems because of governmental corruption, lack of work ethic and lack of transparency with regards to taxes.

It seems these problems are fixable (if the problems are only isolated to Greece and Ireland), in so far that Ireland isn't that large -- Germany can cover Ireland's banking debts (Germany is the fourth largest economy in the world, Ireland has only 4.4M people, although Ireland's banking debts are quite large, as shown in Figure 1 below) while Greece,seems to be coming back every year for funds. Greece, it seems, eventually they have to start paying taxes and working a bit longer -- in any case Greece's sovereign debt is not that large as a total sum.

Contagion can happen if there are additional large writedowns of sovereign debt in other EU countries -- one can think of Portugal -- but especially Spain and Italy. So far Spain looks ok -- the debt to GDP is in the 60-65% of GDP range (the US is now getting up to over 90% of GDP). Greece is up at 142% of gdp --this is why there are problems. I don't think there will be problems with Spanish governmental debt too soon, due to the relatively moderate debt/GDP level.

However, Italy does not look strong with debt/GDP of 114% -- but they do not seem to be a major concern for the markets now. Italian debt is yielding around 4.5% -- not in danger territory. Actually also Belgium looks not so great, with debt/GDP at 100%. The other EU countries look ok (with the exception of Portugal but they are getting IMF assistance).

So the main problem is that problems in Greece and Ireland can trigger problems in Italy and Belgium. Here is a nice chart showing the interrelations --

Source: http://www.minyanville.com/businessmarkets/articles/italy-piigs-europe-sovereign-debt-crisis/1/7/2011/id/32053

So far it appears problems in Greece (and note, Greece is much smaller than Ireland, in terms of debt owed) are more impacting Germany and the UK. If there are problems in Italy, in particular, there will really be problems in Europe - in so far that Italy owes significant total amounts of debt to countries outside of its borders.

The other issues, slower growth in China-- so far my impression is that China is following growth at all costs so is still going to register 9% growth this year (even with the slowdown) according the the IMF. The US is shaky -- I am not sure what to make of the stimulus and the Quantitative easing coming to an end.

So overall things look shaky out there but so far not nearly as bad as the subprime problems going into late 2008, when major institutions were failing every month (but it would be this bad if Italy was having serious economic and debt problems).

In terms of holdings, I think oil should be ok -- interest rates will have to be kept low in the EU, leaving commodity inflation -- but copper may be a bit more unpredictable -- copper is being driven by China,(and mainly construction in China) -- I'll look to pare down a bit of exposure here).

World Copper Supply is Being Gobbled up by Residential and Office Construction in China

2011-05-15T14:31:00.000-07:00

China consumes approximately 40% of the world's copper, making it by far the most important end market for the yellow metal. Copper prices are at near record highs currently (in mid-2011) a large part due to the strong demand from China, as well as flattening mine production of copper.

What exactly, is driving the massive consumption of copper in China? Copper is by far the best electrical conductor of the base metals - copper is approximately twice as conductive as its closest base metal substitute, aluminum -- making copper essential in any structure or product that utilizes electricity. It follows that as China industrializes, it will be a massive consumer of copper. According to BGRIMM, a copper research agency in China, construction and infrastructure accounted for 56% of total copper usage in China in 2007, and the broad category "general consumer goods" accounted for an additional 27% of consumption, as shown by figure 1:

According to copper.org, Copper has its largest use in residential and office construction as building wire -- electrically conductive wire built in the structure in order to allow electricity to be used in the structure through electrical outlets, air conditioners, computers, and other devices. The relative percentage useage of copper in a multi-family unit according to the copper.org is as follows:

It is useful to calculate the actual consumption numbers to give more detail on these overall categories. What is the percentage of copper in China consumed by laptop computer production (a laptop is approximately 6.9% copper by weight)? Office building construction? Mobile phone manufacturing -- note that the average mobile phone is approximately 13% copper by weight.

The author has calculated the expected copper consumption in China by residential and office construction, mobile phone, television set, computer (both desktop and laptop), power and telephone line, and automotive production. These results are presented in figure 3 and 4 below. Interestingly, even as China is, in the World Bank's words, the "world's manufacturing center," accounting for the manufacture of approximately 90% of the world's laptops, 50% of the world's mobile phones, and 30% of the world's television sets (among many other products that use copper) it appears that the overwhelming majority of copper in China is used in residential and office construction. The author's calcuations puts office and residential consumption of copper at 82.4% of the total consumption, presented in figure 3.

Figure 3: Calculated Chinese Copper Consumption by End Use:

The numbers of residential and office construction are estimated by the Economist Intelligence Unit for 2010, then the copper usage of these structures are estimated by applying similar per unit copper useages from US residential and office consumption. The sources for the numbers of products and km of infrastructure are including in figure 4 below.

The author's estimate of copper consumption by end use is different than the BGRIMM figures in chart 1 above, this is due to two factors: first, the BGRIMM numbers are for 2007, in which total infrastructure spending was lower than in 2010 (the year for which the author has estimated copper usage in China). Total residential construction totalled an incredible 2.4 Billion square meters in China in 2010, and office construction totaled an incredible 1.8 Billion square meters (more than a square meter of office space for every man, woman and child in China in 2010) according to the Economist Intelligence Unit. Second, there is likely significant error in the author's estimates of total copper consumption, as estimates are based on average copper usage per application, times total estimated application numbers (both variables are likely to have high errors in estimation, depending on the source of the numbers). BGRIMM, to the author's knowledge, does not disclose their methodology for estimating copper consumption by end use, so thye author was not able to determine sources of difference between this estimate and BGRIMM's estimate further.

It appears that copper usage in technological devices including PC's, netbooks, and mobile phones do not comprise a major component of overall copper usage for China. The author's calculations have these computing categories at only 2.1% of copper usage in 2010. This is due to the fact that as computing power increases, the size and weight of computing devices declines which means despite very large production numbers, the overall usage of copper is relatively small.

Even power cable appears to not be a massive driver of copper consumption in China. Power cable is typically a smaller copper core surrounded by aluminum insulation -- perhaps this is part of the reason why so the overall copper usage is not massive.

Copper consumption for residential and office appears to be the main source of demand in China, which makes residential and office building forecasts for China -- such as ones done by the Economist Intelligence Unit -- to be paramount in the forecast for the price of copper going forward.

A couple of notes on the supply side for copper: Approximately 38% of the world's supply of copper comes from Chile. Geologically, 75% of world's copper reserves exist in the form of copper porphyrys -- porphyrys are igneous rock (this is to say, rock relatively recently formed by volcanic lavas) and most copper sulphides are in the "Ring of Fire" -- a geological term for newly formed rock around the Pacific Ocean. Chile has the highest geological deposits of copper but is having difficulty increasing production significantly. The state owned Codelco -- which produces, along with BHP and Rio Tinto, the majority of Chile's copper -- warned in 2010 that without high levels of investment, its production of copper would fall by 50% over the next decade, due to declining copper grades. This, in turn, has led to some analysts warning of "Peak Copper" -- the inability of particularly Chile to increase copper production. Currently, Chile has projected that will expects to increase copper production levels modestly to 2020 based on an intensive capex program. However, uncertainties exist as to whether Chile can achieve this forecast in the light of the geological limitations presented by continuing declines in copper grade at the major Chilean mines.

In addition, it is interesting to note that according to geological estimates, almost all porphyry copper despoits were formed 500 million to 200 million years ago. This is to say, if humans had evolved 200-500 million years sooner, we would not have access to copper in any meaningful quantity on the surface of the Earth, and widespread usage of electricity would have likely not developed in industrial society.

Figure 4: Geological Date of Origin of Porphyry Copper Deposits:

Source: Source: Ore Metals Through History. Science, Vol 227, March 22, 1985 p 1421-1428

Figure 5: Calculations of Copper Usage by End Production/Infrastructure in China 2010
(numbers in millions of KGs of copper consumed)(bold indicates totals for each catagory)

Office 280 2800M sq m of office space added http://seekingalpha.com/article/256768-where-is-the-chinese-real-estate-bubble
Total office 2800
Residential Apartments 36.00 million, per year average 50 sq m http://www.slideshare.net/economistintelligenceunit/eiu-building-romeinaday
per apartment 80 http://www.copper.org/education/c-facts/c-home.html
Total Apartments 2,880.00 1.8B Sq M residential space added
Power Cable per km 70
Power Cable Total 511 7.3M km of cable capacity http://www.flykeyquartz.com/news_view.asp?id=58
Telecom Cable per km 80
Telecom Cable Total 0.8 10,000 km of copper telecomm cable added per year itri2.org/telecom/report/Chap9.PDF
High speed train 0.01 per km
Total High Speed Rail 20 about 2000 km per year
per PC 1.725
Total PCs 93.15 377M PCs + laptops worldwide http://www.computerworlduk.com/news/it-business/20788/idc-predicts-growth-in-desktop-and-laptop-pc-sales/
per laptop 0.207 6.9% copper, 3 kg av weight http://ask.metafilter.com/38447/How-much-copper-in-an-average-PC
Total laptops 39.33 approx 90% of all laptops made in China - 190M units www.redherring.com/Home/17724
per mobile phone 0.01469 kg http://www.nokia.com/corporate-responsibility/environment/case-studies/where-is-your-used-mobile-phone
mobile phone total 5.22 355.5M mobile phones produced China 2009 http://news.softpedia.com/news/Half-The-World-039-s-Mobile-Phones-Made-In-China-52014.shtml
0.069 per netbook
Total Netbooks 1.10 32.8M total http://lowendmac.com/ed/fox/09ff/netbook-market-too-small.html
Per Automobile 17 http://resources.schoolscience.co.uk/CDA/16plus/sustainability/copper5.html
Total Automotive 238
per television 5
Televison 300 est 60 M tvs Produced China http://factsanddetails.com/china.php?itemid=357&catid=9&subcatid=61
Total: 6,887.50

Actual Consumption China 2011 Est 7300

Total World Production 16,400.00

Comparing Net Present Values to Market Values of Alberta Conventional and Oil Shale Plays

2011-04-26T16:18:00.000-07:00

Several Canadian Royalty trusts have converted to corporate status over the past two to three years, including Equal Energy (EQU), Penn West (PWE) and Pengrowth (PGH). Many newly converted Canadian Royalty Trust have significant unexplored and undeveloped land holdings, which they did not develop due to capital restraints -- in so far that the royalty trust legal structure required that most net income earned to be paid as dividends.

How can these firms be analyzed for potential value? Canadian firms are required to publish after tax, forecasted discounted net revenue from proven and probable oil and natural gas reserves with SEDAR (the Canadian equivalent of the SEC).

The oil and gas companies selling below future net discounted oil revenues will be undervalued, all other factors equal. The forecasted value is listed as the "PV-10" value below (Present Value of oil and gas reserves, discounted at 10% per year, minus income taxes, development and transport cots, not taking out corporate costs and interest expense).

Table 1: Disclosed Future Value of Proven and Probable Oil and Natural Gas Reserves, year end 2010 Reserves Data, Selected Canadian Oil Firms (and Exco, US based Oil Shale Development Company):
PV-10 Value (proved)($C1000's) PV-10 (Proved + Probable)($C1,000's) Enterprise Value EV/PV-10 (proved) EV/PV-10 (prov+prob)
Equal Energy (EQU.TO) 318.7 374.7 375 1.18 1.00
Pace Oil & Gas (PCE.TO) 515.9 681.9 574 1.11 0.84
Penn West (PWE) 7401 9205 14580 1.97 1.58
Pengrowth (PGH) 3218 4028 5670 1.76 1.41
Enerplus (ERF) 2914 3683 6340 2.18 1.72
Baytex (BTE.TO) 2478 3327 7410 2.99 2.23
Bonavista (BNP.TO) 3012 3780 5316 1.76 1.41
Can Natural Res (CNQ) 38892 54302 59140 1.52 1.09
Encana (ECA) 18083 23566 30940 1.71 1.31
Exco Resources (XCO) 1223 na 5940 4.86 na
Legacy Oil&Gas (LEG.TO) 815.2 1192 2230 2.74 1.87
Imperial Oil (IMO) 21295 na 44950 2.11 na

Note in Table 1, the ratio of the PV-10 values for both proven and probable reserves are placed in bold font, and the lower, the more potentially undervalued, all other factors equal.

From table 1, it appears that most of the Albertan oil and gas corporations are trading a bit above their PV-10 values. PV-10 to market capitalization plus debt is between 1 to 2x for most of the firms listed. Pace Oil and Gas is the sole exception, while Equal Energy and Canadian Natural Resources are trading very close to their PV-10 values, on a combined proven and probable basis.

Most US based Oil and Gas Firms trade well above their PV-10 values, as the market assumes (probably correctly) that these firms will discover significant new reserves going forward -- and also possibly on the assumption that energy prices will rise going forward. An example of this is Exco Resources, which is US-based (included in Table 1), which is typical of US firms in so far that it sells at 4.86x its PV-10 value.

Summing up, overall the Albertan energy industry appears to be selling at a discount compared to its US based counterpart for PV-10 values, and may have good expansion potential. This means that the newly converted Albertan Royalty trusts may be undervalued. Future questions include the relative land holdings of the firms compared to the current market valuation, and the ability of these firms to execute on expansion plans, now that they are organized as corporate entities.

Imperial Metals, Duluth Metals and Amerigo Resources

2011-04-21T18:31:00.001-07:00

In Canada mining companies are required to publish their best estimates of the net present value of their mines. In the US, only oil companies are required to do this. The value of a mining company should equal the future net discounted profits from mining operations, so this is really a great resource.

So I've been spending some serious time going through the filings. I found 3 very interesting firms. First:

Imperial Metals:

Imperial Metals is listed in Canada ticker: III.TO but also has a US OTC listing. III mines copper and gold -- have two main mines now that generate around $C40M at $3.40 copper and $1000 gold -- stock is at a market value of $781M -- the net present value of a new project, Red Chris, is $C2.5Bn, at $3 copper (current copper is at $4.10 per pound) and $1000 gold (currently gold is at $1500 ou). Revenues will be about 70-30% copper gold. Red Chris is starting up at Dec 2013.

Present value of the current projects are around the current market value, so once the market anticipates the Red Chris, the market value should appreciate to around $C2.5Bn. This is a gain of 210% by the end of 2013, so in 2 and a half years (we'll see if we get this, but do expect Imperial to sell close to net present value). I've checked many other mining firms and they sell close to the market value of the mines. This one is unusual since they don't highlight the Red Chris project very much in their investor presentations, I had to dig to find it.

The Red Chris project in British Columbia is really large -- has about 2 M tons of copper at a cutoff of 0.3% grade and 5.5M ou gold at a cut off rate of 0.55 g ton. To put this in perspective, the largest copper co in the world is Codelco (Chile) which has 77 M tons of copper (albeit at a cut-off grade of 1%), and Barrick is the world's largest gold producer, with 130 M ou gold -- Red Chris is smaller, but still isn't too small.

Environmental issues have been settled at the supreme court of British Columbia so the mine is moving forward with high probability.

Duluth Metals:

Duluth (DM.TO) has a 50% concession of the Nokomis reserve in Northern Minnesota, which is 48% Nickel, 36% copper and approx 8% palladium. The future value of this reserve is $800M (for Duluth's share) albeit starting in 2017, while Duluth's current market value is $269M, so a gain of 200% by 2017. The present value of the income is calculated based on $7 nickel (currently nickel is at $11) and $1.75 copper (Copper is currently $4.10) -- so really the net present value should be significantly higher.

Duluth has a major mining partner, Antofagasta, so the project is likely going through. The main issue is the 6 year wait to production, but note Duluth has a net cash position of $26M so won't go bankrupt and Antofagasta will pick up the majority of the development costs. In anticipation of the production, the share price should rise -- or the co can sell itself.

Last firm: Amerigo Resources:

Interesting company, Amerigo (ARG.TO) treats the tailings (the waste rock and sludge) from Codelco's largest mine, El Teniente -- which is the world's largest underground copper mine and also a major producer of Molybdenum. Interestingly, the tailings have an average grade of 0.125% copper -- probably due to the fact that the El Teniente mine has very high grade reserves, in excess of 2.0% copper. Many new mines are coming online with around 0.3% copper, since new high grade copper deposits are very, very rare -- Amerigo has all the infrastructure set up and electricity etc, so margins are ok.

Amerigo produces a lot of copper, in excess of 1M pounds per year -- also produces a lot of Molybdenum by treating the tailings (I don't know the split between copper and Moly revenues -- need to research). They have forecast production of over 1 M tons of copper to 2021, which is a lot.

The co was selling at around $C2-$C3 before the financial crisis, now it's at $C1.20 , market cap of $C200M -- back in 2007 they earned $30M, in 2007 they earned $40M (but with a $8M one time gain). They paid dividends of $7M in 2006 and $11.2M in 2007 so should have record earnings this year, as copper prices are at an all time high.

I found a research report here: http://www.baystreet.ca/articles/research_reports/fundamental_research/Amerigo041511.pdf Fair value is estimated at $2.00 per share, approximately, according to this report.

NPV is not given in the technical reports since the mine isn't fully owned by them but projections are given, production is expected to remain steady to at least 2025.

One issue, is that they have the contract with Codelco until 2021. They have renewed it twice in the past so shouldn't be a problem but there is still risk.

The El Teniente mine is set to produce for several more decades.

Which Country is the World's Largest Food Producer?

2011-04-17T09:07:00.000-07:00

In 1890, the United States' 'non-farm' GDP surpassed 'farm' GDP for the first time. Currently in most industrialized countries GDP from agriculture accounts for less than 5% of GDP (according to the CIA World Factbook the US derives less than 2% of its GDP from agriculture). Despite its low 'ranking' in GDP methodology, agriculture forms the base of an economy on which other economic activities stand, in so far that workers cannot work if they don't have food.

It is interesting to ask which country is the world's largest food producer. There are overall two main methods to show which country is the world's largest producer of food. First, by food production by total calorie content (one could say this is a way to judge if the country has sufficient resources to feed its population) and second, by monetary value of the food categories produced. Interestingly, the monetary value appears to get more attention from statisticians and economists -- actually the author is unaware of calculations showing total calorie production by country by food category.

Below in Figure 1 this information is presented -- utilizing USDA production numbers across grain, protein, dairy and selected fruit categories and then taking the average calorie content per ton per food item.

Source: author's calculations, USDA for production, NutritionData for calorie Content, total calories in 1000's Note a limitation of the above chart is that it does not account for all food categories, such as marine food, nuts, oats and other grains and vegetables.

According to calculations presented in Figure 1, China is clearly the world's largest producer of food by calories. The largest percentage of calories produced in China came from rice at 34% of the total (China accounts for approximately 26% of world production of rice), and wheat at 32% of the total. India, in second place, narrowly beating the total calorie production of the US, derives 37% of its total from rice. The United States is slightly behind India, but ahead of the EU-27 -- the US is unusual due to its relatively large production of corn -- 39% of total calories are produced from corn across the major grain, meat, dairy and fruit categories in the US.

One would expect countries which comparative advantages in land, sun and water to be the food's largest agricultural producers, according to economic theory from Ricardo and Heckscher-Ohlin's theories. However, necessity appears to play an equally important (if not more important role). China and India with the world's two largest populations of citizens, requires high food production for domestic food self-sufficiency. Further, labor also may play a high role in certain crops, such as rice and fruit, which are highly labor intensive.

Taking into account the value in monetary terms, China also appears to be the world's largest agricultural producer, although more narrowly beating out the US. India falls to the bottom of the 5 countries surveyed by monetary value of food produced. The US is a relatively larger producer of protein -- beef, pork and poultry account for 9% of all calories produced in the US (although note that China is a much larger producer of pork than the US, with more than 4x the production of pork in 2010). Meat tends to sell for a significantly higher price than grains. India produces a relatively low level of meat, with poultry, beef and pork only accounting for approximately 2% of the total calories consumed in India in 2010.

Source: author's calculations, USDA, Moneycnn for commodity price data

BRIC Banks, verses EU and US Banks, by Assets, Market Capitalization and Asset Growth Rates

2011-04-11T11:46:00.001-07:00

As economies grow, their banking assets by institution also grow in lock step. The following charts show banking assets at the largest of the banks in the BRIC countries (Brazil, Russia, India and China) compared to assets and growth rates in the largest banks in the US and the EU (plus Switzerland).

Note that all of the US and EU banking institutions have seen very low asset growth over the past three years -- due to a large degree to the Global Financial Crisis in Oct 2008 which forced these countries to cut bank on problem assets and shore up financial ratios.

It is interesting to note that asset growth all the selected BRIC banking institutions was relatively unaffected by the GFC -- BRIC banks on average saw annual average total asset growth in the mid to high teens.

From a total asset level, the largest US and EU based banks still hold the lead in overall assets. Interestingly, Industrial and Commerical Bank of China is the largest bank in China by total assets and market capitalization, and has been growing at an average annual rate of 13.9% per annum over the past three years. This means it will be as large as the largest EU and US bank by assets -- Deutsche Bank -- within the next three years (if growth rates continue).

From the perspective of market capitalization to net tangible assets, it appears the market has more than priced in growth at the BRIC banks, with market capitalization/tangible book value averaging 2.5x for the BRIC banks on average, compared to 1.3x for the EU & US banks, on average.

Is Chaoda Modern Dropping Because of an Unfounded Rumor that it Changed Auditors?

2011-03-14T21:49:00.000-07:00

Chaoda Modern, the 3rd largest agicultural firm in China has dropped from a price of near HK$10 in the past year to somewhere near $HK4 currently. I suspect the current drop is due to an inaccurate rumor that Choada changed auditors -- but the last auditor Grant Thornton was acquired by the current auditor, BDO Seidman, which is the 5th largest auditor in the worldwide.

An article stating that Chaoda changed auditors appeared on Dec 31, 2010 on a blog --http://www.certifiedchinesetranslation.com/10/1230-Chaoda-Modern-Change-Auditors.html. Since that time the stock has dropped from $HK6 to $HK4ish, with the only other news a moderately positive 6 months ended Dec 31, 2010 earnings release (more on this earnings release below).

Chaoda is audited by BDO Seidman,which is the largest US based accounting firm outside the Big 4. The previous auditor Grant Thornton merged with BDO (reference: http://goingconcern.com/2010/11/exodus-watch-600-in-grant-thorntons-hong-kong-office-move-to-bdo/ but no change in auditors. BDO actually is probably a stronger accounting firm than Grant Thornton, but Grant had a good reputation as well.

Grant Thornton gave an unqualified opinion in the last Annual Report:
source: http://www.chaoda.com.hk/pic/201010272026685000.pdf p. 41-42

It should also be noted that Chaoda is ranked by Forbes as the 3rd largest agricultural co in China. It is very difficult to fake being one of the largest agricultural firms in the world's largest country in terms of agricultural production.

The results announcement was moderately strong. Chaoda reported good top line for the six month period ended Dec 31, 2010 (+18%) but flat in net profit, the main item was an increase in general and admin expenses to 6% of revenues from 2% the previous period, plus they issued shares to pay for mainly an acquisition of more land.

Shares increased as they issued equity instead of dipping into cash to fund expansion (don't really know why they won't utilize their very large cash and investment position). Chaoda has RMB3.8Bn of cash and no debt -- all assets are in RMB and look solid, buildings (RMB8Bn), vegetables in inventory (RMB2Bn) and they have very low liabilities RMB218M total. They also have RMB1.3Bn of equity assets - mainly I believe their share of HK listed Asian Critus. One asset is "prepaid premium for land leases" at RMB5.8Bn -- I believe this is tangible (prepaid leases, so expenses won't appear in future periods, as long as the firm is a going concern). With prepaid land leases, net tangible book value is RMB 24.9Bn while market cap is HK15Bn (RMB12.5Bn) so market cap is around 50% of book. PE is below 4 (interim 6 mo net profit is RMB1.54Bn).

Operating cash flow looks strong, equal to EBITDA of RMB1.8Bn for the interim period, but the co raised RMB2.3BN of financing (mainly equity) to fund expansion. Almost RMB1Bn from new shares issued over the past half year (this seems to me, not a huge dilution).

Note, the major reason for the increase in SG&A was an increase in options exercised, from only RMB6M in 2010 to 160M in 2011 - also note salaries were up about RMB100M (this is likely due to wage inflation in China, surprisingly workers are somewhat in short supply for farming). So this hopefully won't be repeated. -- they are approx 192M share options outstanding but the majority have excercise prices between $HK6.75 and HK$8.10 per share. The exception is the ceo who has 66M options with an excercise price of HK1.50 (but at least he'll be motivated to get the stock price up).

They are paying a dividend this year of RMB84M -- didn't pay a dividend last year. So at least will get some income, also shows they care about the stock price a bit.

Overall to me the company looks strong I don't know why it's dropping for sure -- the first drop, issuance of equity at HK$7.50 when the stock was trading at HK$9 -this made sense to drop, but the second drop, if it has anything to do with the rumor that they've changed auditors, is just plain wrong (the news of the previous auditor, Grant Thornton, being acquired by BDO maybe is not well known, and it may be thought that Chaoda really did want to change auditors, but BDO is a well respected accounting firm). So this one really has me scratching my head. It looks very strong, with the exception of the issuance of equity to fund expansion, that has made net profit growth relatively flat.

Follow Up on Frontier Resources

2011-03-10T14:43:00.000-08:00

As posted in a previous note, the main question for Frontier Resources (ASX: FNT.AX) is whether the deposit on New Britain has a reasonable chance of proving to be a large scale, economically producing, high grade mine. This is significant because the initial exploratory data was reported to be very positive (could this be a major deposit of Gold in a new territory, relatively unexplored New Britain of Papua New Guinea? -- similar to Lihir of Newcrest Gold (the 7th largest gold deposit in the world, discovered in the past 5 years?)

We won't answer this out with 100% certainty, but it seems we can be able at least shed some light on this main question, by asking few sub-questions first: 1. Does the management team have the connections and experience to at least get the ball rolling on development, if reserves are economic?

Second, are there high grade deposits nearby (in Papua New Guinea?). Mineral deposits are formed by geological processes, and these processes can be similar in nearby locations.

Third, what are the (known) geological processes for forming gold? This might sound too esoteric, but really this helps a lot, at least in the case of oil, in looking for new reserves (really many analysts won't even speculate on this, but for example, I know a bit about oil formation theory, and so for example, took a look at Petrobras of Brazil, looked at their producing wells, and saw huge territories unexplored plus offshore areas next to rivers -- good signs of future oil discoveries and Petrobras subsequently has announced very large
discoveries).

First question -- actually this is probably the best question -- management experience. The Chairman and CEO Peter McNeil is also CEO of another PNG based gold mining firm in addition to Frontier -- New Guinea Gold Corporation. Frontier Resources has only 2 full time employees in management, it appears, the CEO and a co secretary. (this data is really hard to find, is not in the Annual Report -- have to infer since they don't state how many employees).

New Guinea Gold is also mainly on New Britain, same management structure, just McNeil and a secretary and non-exec directors (so essentially it is a twin of Frontier except drills different prospects) has drilled 12 projects, got good exploration results (grades of over 2 g/ton, but hasn't been able to develop these projects, one problem was that crushing the ore turned out to be a problem, so gold production has been disappointing. The stock has been down a lot -- stock price on the Venture Exchange of Canada of New Guinea Gold has gone from .6 in 2007 to 0.1 currently -- the market has lost confidence that management will bring any projects into production and/or sell deposits.

Frontier Resources is also a vehicle to explore New Britain, is up a lot with the recent report of grades but -- really reading the reports from New Guinea Gold Corporation they sound sort of similar in terms of grade (some reports of very high grade 30-60 g/ton then most of above 2 g/ton) -- but New Guinea Gold hasn't been able to bring these online.

I've seen a small management team be CEO's of more than one mining co before --example New Gold and Silver Bear Resources -- both headed by the same management team -- note New Gold is doing great while Silver Bear isn't. So this isn't a bad sign necessarily -- what you do want to see is proven experience getting mines to production and building value. New Guinea Gold isn't this, Frontier so far isn't proven (wondering actually why two co's in the same region for the same type of deposit -- Silver Bear is at least for silver while New Gold is for gold, makes sense -- wondering if Frontier is another vehicle to make investors forget about lack of success at New Guinea Gold).

Anyway -- on the first question overall summary is "iffy."

Second question, yes there are good, relatively recent discoveries is Papua New Guinea. The most publicized is the LIhir Gold discovery on tiny Lihir Island in PNG: http://www.mining-technology.com/projects/lihir/ Amazingly, this deposit has 28.8M ou of gold reserves at an average grading of 3.5 g/ton (which is extremely high, most grades are 1 g/ton or lower) and ranks #7 on the world's largest gold deposits. http://www.minefund.com/mineral-deposits/richest-deposits.php In other words, huge! Lihir was bought out by Australia's Newcrest Gold in 2009, and Newcrest states that it wants to produce about half of its production from Lihir going forward (Newcrest is an amazing stock, Australia's largest Gold producer, has rocketed up to a $A30Bn market cap (3rd largest gold mining co in the world). Note that Newcrest's other major producing mine, Cadia East in Western Australia, produces over 1M ou per year of gold but from an average
grade of about 0.5 g/ton (so Lihir is about 7x more concentrated). Cadia East
has reserves of gold of about 18.7M ou, so Lihir has about 50% more gold. (in
other words, Lihir is a world class deposit)

Two other PNG projects appear in the top 200 largest gold deposits. Allied Gold owns Simbiri which is located also on a tiny PNG island (called Simbiri) about 30 km north of Lihir -- average grade is between 1.0-1.5 g/ton with total reserves of 2M ou (so much lower and smaller than Lihir, but LIhir is unusually large and high grade). Harmony Gold and Newcrest co-own Hidden Valley on the main lsland of PNG, with an average grade of 1.7 g/ton and total proven resource of 1.2M ou.

For gold mines in Indonesia, there are three in the top 200 (Indonesia could have similar geology to PNG, both are island countries and actually the main island of PNG is split evenly between Indonesia and PNG). Interestingly, Indonesia's gold deposits are all relatively low grade, below 0.5 g/ton, including the massive Grassberg mine, owned by Freeport (FCX), which has approx 35M ou of gold at an average grade of 0.4 -- note this mine is ranked #3 in terms of reserves of gold, and has already been in production since 1975 so could be depleted in terms of its higher grade ore.

In summary to question 1, there are high grade deposits in PNG and it doesn't appear that PNG has been a major destination of mineral exploration budgets (only a few firms, Newcrest, Harmony, Allied and some minors including Frontier searching so it is possible. Actually the next question is, what did the exploratory mineral info look for Lihir and the other major deposits? Were these close to info coming about concerning Andewa? Will try to find this.

Third question, (this is getting lengthy) gold appears to be formed by three main geological processes. First process, the Witwatersrand deposit in South Africa (largest in the world, produced approx 40% of the world's gold, but now is largely depleted except for underground mining, was in production since the 1910's) was formed approx 3 bn years ago -- the earth is 4.5 bn years old so South Africa is one of the few areas with surface areas formed during this time. Almost all other areas (with the exception of parts of Australia) have been reformed by more recent geological processes. The best theory is that during this period of the earth's history (3 bn years ago) heavier metals were flowing from the magma to the surface (gold, platinum) and the earth was in a different phase of history -- the gold is left over from this period, but not covered in vast amounts of overbuden unlike almost all other areas. This process is probably unique to S. Africa, won't explain Papua New Guinea gold.

Second process Carlin type deposits, found in Nevada -- gold is completely dissolved in minerals -- unique (I thnk) to mainly North America -- won't go into detail.

The journal Science explains a process of gold formation unique to Pacific Islands
-- water flow accumilates gold over relatively short periods (couple 100,000 years). Will reference for this (getting tired) -- anyway, need a lot of flowing water and a trap, can be a good source for PNG, for New Britain -- was how Lihir gold was formed.

Anyway so the summary would be management -- medium to negative, close-by deposits -- moderately positive, gold formation -- positive. Overall however probably question 1 is the most indicative and so overall I would say "iffy."

Further Notes, Thompson Creek

2011-03-09T12:01:00.000-08:00

A couple more notes on Thompson Creek:

1. They have to build the infrastructure at Mt Milligan and another site, which will cost $350M in 2011, likely will run cash to a bit less than $0 in 2011-2012, (currently net positive cash balance after the acquisition of Mt Milligan is about $300M). As long as copper and gold prices stay where they are, this is ok -- I would say copper prices are more vulnerable than gold prices out to 2013.

The expected of revenue from Mt Milligan from copper is $243M per annum at $3,50 lb copper (81M lbs) and from gold is $230M at $1200 gold (relatively even split copper gold). So the expected revenue from Mt Milligan will be about the same as current total sales (2010 sales of $594.8M).

2. Along with note 1, TC just bought Mt Milligan in Oct 2010 for $700M. They financed this with a stock issuance and also a gold forward sales agreement with a company called Rand Gold (I looked at this, and it looks ok). But now as mentioned in point 1, they have to build the mine infrastructure.

3. Molybdenum production will decline at their main Moly mine, Thompson Creek in Idaho in 2012, overall Moly production is expected to be down to 26-28 M lbs in 2012 from 31-33M lbs in 2011. They have to also spend $181M to expand their other Moly mine, Endako, in 2011. Further, cash costs are going up to the $9 range per lb for the thompson creek mine from $7 range in 2011. Endako is not as high quality an asset (grade of 0.,04% Moly verses 0.08% at Thompson Creek). It appears Moly production at Thompson will stablize after 2012, but I am not sure -- mine life currently is 11-14 years at Thompson Creek. Mine life at Endako is also 15 years.

4. Moly prices may come under pressure in 2014, when the largest Moly project in the Western Hemisphere, owned by Moly Corp (ticker: GMO) comes online This project will approximately double US production of Moly, producing 50M lbs per annum of Moly current US production is 56M lbs according to the USGS: http://minerals.usgs.gov/minerals/pubs/commodity/molybdenum/mcs-2011-molyb.pdf World production of Moly is 234M lbs so General Moly will add about 12.8% to world supply. General Moly has Chinese financing for its project so it is most likely going through.

5. Lastly, TC has 22M warrants outstanding with an exercise price of $9, which is actually a lot. These expire on Oct 11, 2011, so the stock could be under pressure from these -- my understanding is that TC will have to pay out cash for the exercise of these warrants. At a stock price of $12.50, this is $3.50*22M or $77M, which is actually going to drain the cash balance of TC further.

So in summary, TC is interesting however will likely be under pressure through 2011 until visibility on the Mt Milligan project is more clear, which will be sometime in 2013. Further, currently copper and some other industrial metals are weakening in anticipation of perhaps less stimulus from the major economies and therefore lower economic growth. So TC (I think) won't see a breakout until 2012 (but can watch the co, see if it gets close to $10 where the warrant exercise won't be such an issue).

Thompson Creek

2011-03-08T18:43:00.001-08:00

I was going through the world's largest gold deposits, then seeing which firms own them, -- interestingly you can search the mines here: http://www.minefund.com/mineral-deposits/richest-deposits.php I'd like a large deposit, so that the co can set up operations and then have a long mine life, plus the resource firm's main source of value is its mining assets.

Anyway, what is interesting is that Thompson Creek, mainly a Molybdenum producer, owns the 47th largest gold deposit in the world, Mt Milligan in Canada, with 6 million ounces of gold proven, also contains about 1 M tons copper (comparison, Codelco, Chile's gov't owned copper miner world's largest has 77M tons copper)(which is to say, it won't set records in copper, but the copper is a source of value). 22 year mine life, will come online in 2013, so current forecasts don't include earnings from this forecast to 2012 (current forecast is selling at 13x 2012 earnings). Production will be 194,000 ou gold, which is around a small to mid tier producer -- you'd see this at around $1Bn in market cap by itself at least.

This doesn't include Molybdenum, which is the main asset, interestingly Moly prices haven't moved up too much, despite the fact that iron ore, copper, now nickel -- most base metals are up -- see http://www.infomine.com/chartsanddata/chartbuilder.aspx?z=f&g=127676&dr=5y Moly prices were at $30-35, now at $15, but at an uptrend.

Nice net cash position, market cap of only $2Bn, nice chart (stock looks flat, no breakout yet).

Corporate presentation here: http://www.thompsoncreekmetals.com/i/pdf/Presentation_February_24_2011.pdf

I really like the "hidden" asset of the Mt Milligan gold and copper mine. However note, the grades are on the low side for the mine, -- grades of around 0.4 g/ton for gold -- you want to see at least 1 g/ton, and copper grades of 0.14% copper -- you want to see grades of 1% copper. However, the reserves are very big, I noted one of the most successful gold miners, Newcrest in Australia, has one main mine, Cadia, which has a grade of 0.5 g/ton but 27 M ounces total., Now Newcrest is worth almost $30Bn, due to the fact that they have all the operations set up, even as the mine as a relatively low grade (can just process and process ore).

TC should be able to do the same, perhaps on a bit of a lower scale, but a 6 M ou mine is not small at all (again gold mines of over 1M ounces are very rare).

Anyway, once the market either anticipates the gold mining operation Mt Milligan coming online, or higher moly prices, TC should do better than a relatively low $2Bn market cap.

It's not showing up as a gold producer yet since it is classified as Moly, so that's why I think it hasn't moved too much. (most gold producers are up a ton over the past year and a half). It's sort of like KHGM, which is the world's 6th largest copper producer, but also has the 5th largest reserves of silver (always classified as copper, doesn't get a benefit yet too much from silver) (KGHM has already up a ton so probably isn't too much of a buy here).

Feasibility Study of Mt Milligan:

I found an NPV for a feasibility study of Mt Milligan (located about 500 miles north of Vancouver): http://www.terranemetals.com/i/pdf/2009-10-09_PreTaxMatrix_2.pdf

The chart gives different prices of copper and gold, and different discount rates. The maximum prices for copper are $3.50 per lb (now $4.33) and $1000 for gold (now $1400 ou). At $3.50 copper and $1400 gold, the NPV is $C3,134M at a 5% discount rate, $C2,156M at a 8% discount rate.

Of course you'd increase that value is the value of copper is $4 and gold $1400.

So I think the stock will do really well once revenues come in from Mt Milligan. (and as long as commodity prices stay strong).

Checked the message board for TC, and the explanation for the low stock price is possible bankruptcy, from a potential meteor strike (this is a joke). The messages are very frustrated with the stock, blaming it on management, for some reason (need to figure out why). So perhaps it will be a while before it moves. But it appears the value is there.

Petrobras -- Economics of Deep Sub-Salt Operations Hinges on Cash Costs per Barrel

2011-02-23T07:49:00.000-08:00

Petrobras´ market value is nearing $250Bn which is fairly high but if (the key) is ´the cash costs of the deep sea oil per barrel. PBR is spending at least $174Bn to develop this (one of the largest capital projects in history, ever).

I did a quick calcuation of the payback period of the deep sea oil costs. The estimate is that initially the deep sea will produce an additional 2 million barrels of oil -- quick calculation, assuming a profit per barrel of $40 after direct operating costs = $29.2Bn of profit per year, or a 5.96 year payoff period -- this is at the high end of aceptable levels of payoff, in which oil and gas firms want payoffs to be below 5 years.

If the profit after operating costs is $60, the payback period drops to 3.94 years. Need to find better data on direct operating costs. If it is only costing PBR $20 to hire workers, equipment, power, water, foodservice etc then this isn´t bad at all (since the deposit is likely very large and will last for decades)(the price of oil should be in the $70-90 range for a while).

One more note: I did find data that at least at Tupi the gas/oil ratio is 15-20% -- majority oil (perhaps the pressure maintains the longer hydrocarbon chains). In geological theory, the deeper the deposit, the hotter and the more the longer hydrocarbon chains will have been broken to form natural gas, but PBR seems quite confident the deposit is mainly oil (of course natural gas is cheaper currently and less profitable and also is much more difficult to transport from offshore locations).

Polyus -- High Reserves but Some Operating Problems

2011-02-23T07:11:00.000-08:00

I did some more research on Polyus and they had some mixed operating performance in 2010 -- their biggest mine, currently Olimpiada showed a decrease in production of almost 30%, from 839,000 ounces in 2008 to 584,000 ounces in 2009 -- apparently the problem is that two other mines are close by, and Polyus is allowing ore from the other two mines to be processed at the processing center at Olimpiada, which caused problems with the exaction of ore. The solution appears to build a separate processing center (which can crush the ore, and exact the gold by a bath of high-grade acids and chemical solutions) but it doesn´t appear that the firm has this in the works.

Another concern was that the production was up 10% y/y to 1.39M ou (approx) but the profit didn´t increase, mainly due to higher costs -- I´m not sure I did note that the mines are spread around the country in mainly three locations, which are extremely far away from each other (well over 1000 miles), so the co isn´t getting any syngeries from the operations.

Polyus is having serious problems with its acquisition of KazahkGold, and is going to divest this -- about 2 years after acquiring it -- the owners of Polyus and the ruling family (Nazerbyev) of Kazakhstan really got into an argument. On the negative side, KazahkGold was the one asset so far that is significantly increasing production

Current forecast is for 1.5M ou, which one analyst takes to mean that the problems at Olimpiada will continue. The capital expenditures appear to be (according to UBS) well under maintance levels -- strangley, the CEO (who is also the owner to the New York Nets) wants to sell the firm, not develop it.

The basic idea is to find Gold miners which are the most undervalued on reserves. Below is a useful chart by UBS that shows potential undervaluation by reserves, since Gold is not really concentrated in one geographical area, there are many firms and it does appear that Polyus is undervalued, although perhaps not by a whole lot (in the chart below, Anglo Gold, Harmony and Gold Fields appear to be the cheapest on an EV/Reserves and Resources). I´ll look into these -- (although I´m not sure how these miners stack up against individual gold mines, I did like the fact that Polyus had one very large mine in the works -- will research).

Polyus' Gold Reserves: Under-Appreciated

2011-02-20T14:11:00.000-08:00

Polyus Gold may have significantly larger reserves of gold than is credited to the stock by the market currently. Polyus Gold (ADR: OPYGY) is the gold mining spin off from Nolisk Nickel. Polyus has the world's second largest gold mine by reserves, Natalka, at 40.8M ou of gold in place -- this compares to all of Barrick's Gold's reserves of 138M ou.(Barrick is the world's largest gold miner).

Gold miners report proved (90%) and probable (50%) reserves all together, unlike oil which typically report only proven (90%). Barrick reports it has 138M ous of reserves of gold, when you look at the 40-F, it has 30.3M ou of proven gold, 109.4M ou of probable http://www.sec.gov/Archives/edgar/data/756894/000110465910017012/a10-4461_1ex99d1.htm

In comparison, Polyus reports reserves in the Russian classification system, which is A,B,C1 and C2. According to Nikolai Vlasov, chief geologist, Peter Hambro Mining plc, A,B,C1 are roughly equivalent to proved and probable. http://www.imcinvest.com/pdf/Russian_reserves_8.pdf

Polyus reports in its 2009 Annual Report 77M ou of A,B,and C1 gold reserves. Polyus also reports international standard reserves, mesaured of 14M ou and 66.3M ou of indicated. (total 80.4M)

Note that measured means that the reserves exist with high certainty (90%) but are not yet proven, in so far that they have not been proven to be economically mined through a feasibility study and http://www.polyusgold.com/eng/news/reports/audit/

According to Polyrus' investor's relations, Natalka's mine life to 2073 (very large mine), average cash costs per ounce of $51.3 (should be very profitable)(this is the mine info). The mine will double Polyus' current output of 1.38M ou per year of gold towards 2020, in 2014 it will increase by 48%.

In comparison Barrick (market cap: $50.9Bn) produces 7.4M ou. Newmont (market cap $28.8M) produced 5.3M ou in 2009, reserves of 92 M ou.

Polyrus I'm not sure the market cap, one source is saying $10Bn, another around $5Bn -- it is really attractive at $5Bn. I will double check this.

You can find a comparison of the world's richest gold mines here: http://www.minefund.com/mineral-deposits/richest-deposits.php There are only 6 mines with reserves of 30M ou or above,and only 8 with total reserves of 20 M ou or above. Barrick does not own any of these top 8 mines, but has interests in many smaller mines -- it appears Barrick has consolidated many individual mines, to form the world's largest gold miner.

Natalka will come on-stream in 2013 - actually late 2013. The shares haven't moved up too much -- except for after the financial crisis.

Overall I can tentatively say that Polyus is comparable in size to Barrick, in so far that it is a major miner of gold (the Russian reserve show that Barrick has 80% more gold than Polyus) -- but the market cap of Barrick is far higher, $50Bn verses $10Bn. Of course this reflects geopolitical risk (mining in Russia) -- next steps would be to compare average costs per ounce -- it seems most gold miners would have higher than Polyus' cash costs since the mines will be located in many different locations (a single, large deposit will lower cash costs per ounce since the set up costs of the electricity, water, housing, roads, equipment etc can be depreciated over a longer mine life). Further next steps are to analyze political risk.

Frontier Gold: Is the Andewa Deposit Legit?

2011-02-20T12:17:00.000-08:00

Frontier Resources (FNT.AX) has move from sub-..10 to mid .30's in a week -- the main reason is the announcement of exploratory drilling information at the Andewa prospect on the island of New Britain in Papua New Guinea.

Frontier has 7 deposits in Papua New Guinea - the main source of value is Andewa in the Island of New Britain- the firm is implying that there is gold deposits between 14 to 66 g/ton in this region which stretches for about 7 km, at a good seam -- in comparison Barrick Gold, the world's largest gold producer averages about 2 g/ton, so this would be 7-33x more concentrated.

Actually Frontier also has 2 projects in Tasmania, but again the best potential is the Andewa project in PNG. (actually the Bulago deposit is also promising, see below)

I sort of don't believe the numbers. I was searching through the world's richest gold mines and all have gold per ton numbers below 3 g/ton see:http://www.minefund.com/mineral-deposits/richest-deposits.php
This would be by far the most rich gold find in the database --well so far I've searched Barrick's deposits (in their annual report, and the Polyrus Gold (Russia) deposit which is #2 on the list and this averages 1.5 g./ton.

The newest release has some geological data but not nearly enough to establish reserve numbers - so far this is all in the beginning stages.

The firm is really small, having to raise capital even for exploratory drilling. (they had to raise $A1.1M to survey the region -- Frontier will certainly have to raise capital to develop the project. Actually the deposit looks like it is close to the coast, so could be served by water transport, see a map of the projects in the 2010 Annual Report, p. 3: http://www.frontierresources.com.au/

Previously in 3/10 Frontier announced another 67 g/ton deposit, this time on the main island of PNG, in the Bulago deposit, but this didn't generate much excitement -- I don't know why all of a sudden the latest report has really made the stock go off, but the previous ones did not. (more word of mouth, or a better geological survey, actually I don't know).

Anyway I'll be researching more and will try to find out if the find in legit.

If the economy doesn't grow, will it collapse?

2011-02-09T04:00:00.000-08:00

An interesting question has been posed, mainly by pundits concerned with peak energy but also by economist and fund managers -- whether the economy will shrink dramatically if the economy does not offer the promise of growth. This subject or question can be rephrased in several ways, such as "if the economy doesn't grow, will it collapse?" or, as Bill Gross of PIMCO theorized in his August 2010 Investment Outlook "...Not only growth but capitalism itself depends on a growing population," as, Bill Gross states, that a growing population implies steady growth in consumer demand.

However, most articles on this topic state capitalism will collapse without higher demand in the future, without going into detail as to why. Why, in more depth, will shrinking demand -- and also importantly lower expectations of demand -- lead to dramatically lower GDP numbers? This is to say, why can't capitalism exist in a steady state (no growth)?

John Maynard Keynes would answer this question based on the relation of investment to consumption demand as components of GDP, as explained in Chapters 5 and 6 of his General Theory of Employment, Interest and Money. The largest component of GDP is consumer demand. In the US consumer demand ranges from a high 60% of total GDP to low 70%s of GDP. Investment ranges around 15% of GDP (the other parts of GDP according to GDP = C+ I + G +(E-I) are net exports and governmental spending, which total in the US approximately 15% of GDP).

The investment component of GDP is related to the consumption measure, in so far that businesses will not invest in new capital and equipment unless they expect a steadily increasing market (demand) for their products and services.

So, if the businesses expect future demand to be lower, they will dramatically cut back on investment - why would a business invest in more capacity if it doesn't expect to have higher sales? This means that the 15% of GDP represented by investment will drop significantly faster than the 70% of GDP represented by consumption. John Maynard Keynes referred to the attitude of businesses to invest famously as "animal spirits" -- this phrase was recently picked up by George Acklof and Robert Shiller in their book with the same title, published in 2009. (Keynes exact discussion of animal spirits argued for a non-rational contemplation of future investment, verses other schools of economics that argued that investment was rational, but for this purposes of this post, we will not go into detail on this, the discussion however is important for implications on the future equilibrium of aggregate demand and aggregate supply in terms of GDP)(and actually is a bit beyond the understanding of the author :).

A Malthusian version, where peak energy or peak food results in high prices and therefore lower consumption, would also impact future investment, and also carry a re-enforcing cycle between consumer demand and investment (however the details of the exact transmission mechanism from higher prices to investment could be different than expectations of lower demand from for example higher saving rates, which is not analyzed here, in so far peak energy would be a production issue, not at first a demand issue).

The relation between investment and consumer demand can be explained as a self-reinforcing cycle. We can see many examples of re-enforcing cycles in nature, such as theoretically higher temperatures, which melt snow caps, which then do not reflect as much solar radiation, which then leads to higher temperatures, which further melts snow caps etc (this is theoretically proposed by scientists such as the late Steven Schneider of Stanford University). In a GDP measure, lower consumption could reinforce a lower investment, which in turn could reinforce lower consumption, leading to a downward cycle which means significantly lower GDP at the final equilibrium.

The idea here is relevant in so far that sustained declines to consumer demand, from a declining population (in Bill Gross's concerns, outlined above) to lower levels of consumer credit, to deleveraging of consumer debt, to average declines in expenditures from declining capital gains from property, can all lead to significantly lower GDP than at first calculated based on reduction in demand, through the relationship of demand with investment.

The analysis appears to be supportive of emerging economies such as China and Brazil (at first glance) in which businesses are more confident of future demand, in terms of a positive, self-reinforcing cycle between consumer demand and investment by business. (both Petrobras and Vale of Brazil have announced record breaking investment budgets for 2011 and beyond, for example at over $US70Bn and $US20Bn, respectively).

However, the analysis does not initially (in the author's opinion) support slower growth economies that are deleveraging, such as many EU countries, and the US. Businesses in the US and certain countries in the EU may not be as confident of future demand increases, due to deleveraging of consumers in these countries, and other factors.

As a final note, this relation of demand and investment explains some rational of John Maynard Keynes insistence on governmental, stimulus spending, which would find its way, through Keynes' multiplier (which is incidentally currently being debated in the economics profession, in terms of its size and impact on the overall economy), which, in turn, would support demand and then support investment, as businesses would be more likely to invest in an expanding economy.

What is Going On in the Oil Markets? OPEC Appears to be in Control

2008-07-29T20:38:00.000-07:00

Oil prices are generally very volatile, but this year has been an exceptional roller coaster. What is going on in the oil markets currently? Note that over the long term, oil prices tend to be determined to a greater degree by fundamental factors (supply and demand) verses technical factors (financial speculation). This article will focus on fundamental factors, making the assumption that supply and demand factors fundamentally determine oil prices.

In the author's view, the effective consensus view on oil prices from approximately 2002 onward prior to July, 2008, was that demand would increase significantly going forward, while supply would stagnate, leading to continued high, and even higher, oil prices. The new "market consensus" since the beginning of July 2008, appears to be, in the author's opinon: slightly higher supply (we are finally seeing a supply response) and only slightly higher demand (developed countries' oil consumption will go down, developing countries oil consumption will go up, but at a lower rate). The new consensus appears to imply a slightly higher supply than demand, going forward, resulting in significant downward pressure on the current and future price of oil.

The reassessment since July 2008, has mainly been driven by two new pieces of information, which are being digested -- world supply in the past few months increased, albeit slightly (by approximately 500,000 bpd from a world average production of 86M bpd, also note that exportable oil has so far not shown increases in supply), and total world consumption slowed significantly, driven mainly by consumption declines in the United States (offset by continued consumption in the developing world, mainly China).

It is argued in this article that this new, as of July 2008, "market consensis" is not exactly accurate -- the supply response in 2008 is not a fundamental change regarding future production, due to the fact that all the increased supply in 2008 has been from OPEC countries, who have an interest in relatively high oil prices. But the demand response in 2008 is likely a fundamental change, meaning that world oil demand will likely slow significantly going forward. The new market consensus is therefore close on demand, but off on supply. If supply is actually being effectively controled by OPEC, but demand is moving at a lower rate, the net result will likely be current pressure on the oil price, but a long term, supported reletively high oil price, in line with OPEC's interests (note OPEC has stated that they are comfortable with long oil prices around $100, if over the short term in the $80's).

The risk to the author's view of the current oil situation -- which is can be summed up by the title "OPEC controling prices" -- is a worldwide economic recession and/or a very large conservation movement in both developing and developed countries, that decreases demand to a higher degree than OPEC effectively can cut supply. In this case, the price of oil would decline significantly.

Oil Prices: Dominated by OPEC Currently

There have been notable developments on both the supply side and the demand side in 2008 in the oil markets -- namely, there is a small overall supply increase in total oil and condensate production in 2008, and on the consumption side, most notabily, oil consumption in the overall world has increased only very slightly (under 500,000 barrels per day) -- with a surprising 5% decline in 2008 in the United States, the world's largest oil consumer, for the past three months (May, June and July).

On the supply side, OPEC is engineering this supply increase, by removing all restrictions by members towards oil production by OPEC members in 2008. The removal of OPEC production quotas, (by a senior OPEC official, reference) has not been reported widely in the media. The king of Saudi Arabia stated in July 2008, that he is "very disappointed" by the increase in the price of oil. This move has been initiated by OPEC in order to support the flagging OECD economies by lowering oil prices, and alleviate pressures on the developing world's economies, according to comments by OPEC officials.

Near term supply increases are determined mainly by Saudi Arabia, currently, as the only country with stated high (over 1 million barrels) of unused oil capacity. Saudi Arabia has promised new oil production in 2008 and so far has delivered between 200-500k of new production (depending on the source, different info from governmental sources the EIA and IEA). The key new oil capacity as most of the new announced projects are very old oil fields, from the 1960's. However note, the political will to increase prices by SA down to below $60 is assessed as "very low" as the King of Saudi Arabia, despite the comment above about being "very disappointed" in another July 2008 interview signalled confidence that reletively high oil prices will continue:

"Prices will continue to soar as the economy flourishes because energy is a vital resource in development. Thanks to the Almighty, our region has a strong oil reserve that can meet future demands."

The apparent paradox of King Abdullah wanting to increase production while supporting a reletively higher price of oil can be solved by Abdullahs observation that (from the July 2008 interview) that: "Our enthusiasm to protect the interests of the international community, in terms of oil, is on par with our eagerness to protect national interests."

It should be noted that since about 2005 Saudi Arabia and OPEC have signaled a willingness to act to support signifcantly higher oil prices -- higher than the 1990's normalized levels of $10-$30 per barrel. In 2006, when the price of oil briefly dropped below $50, Saudi Arabia cut back production which was a major factor towards oil prices re-starting their trend upward. Quote from March 26, 2006:

"OPEC's unity may keep oil from dropping below $50 a barrel for years to come, energy experts say.``They've learned their lessons,'' said Daniel Yergin, author of the Pulitzer-winning history of the oil industry, ``The Prize: The Epic Quest for Oil, Money & Power.'' ``They like this band from $50 to $60 and they prefer the upper part of the band rather than the lower part,' `We are happy with the level of compliance,'' Mohamed al- Hamli, president of the Organization of Petroleum Exporting Countries, said in an interview in Bangkok on March 22. (2006)"

Further, OPEC has currently removed all restraints on oil production from all countries. OPEC has lifted all quotas as of early 2008 on OPEC production due to the run up in oil prices which threatens the world economy.

"A senior OPEC delegate said Monday that OPEC ceilings and quotas had become largely irrelevant and that OPEC had a "tacit" understanding that those members capable of boosting crude production should supply as much oil as world oil markets needed."

With OPEC producing all out, we get a very small move up in overall oil production. (which actually can be interpreted as a reason for long term concern in terms of oil productive capacity for the world as a whole over the long term -- does OPEC really have potential for significant future output increases if maximum current output increases total output by less than 1 million barrels?)

Which other countries besides SA can increase oil production and oil exports significantly with a moderate probability over the intermeidate term? Almost without exception, they are OPEC member countries. Of non SA production, the two main countries with the most potential are Iraq -- which is quietly increasing production -- and Iran. Lower probability of future significant increases exist from Brazil, Venezuela, Nigeria, Angola and Kazakhstan -- these total the only countries with moderate probability for potential of significantly higher (over 1 million) of future production increases over the intermediate term. But note, these countries, with the exception of Iraq, Kazakhstan and Brazil are in OPEC -- although both Kazakhstan and Brazil have signaled they are interested in joining OPEC.

Note that non-OPEC production is flat, without significant prospects for increases over the intermediate to long term, according to IEA (International Energy Agency) president Faith Birol. The most notable current development is the fact that Mexican oil production declined at over 30% last year without prospects for reversal of that decline this year (that is to say, is continuing to decline at near 30%) and North Sea production is declining at 20% per year. These moves are offsetting any new production -- from for example, Canada or deepwater Gulf of Mexico.

In summary, overall, on the supply side, the current supply increase is likely a deliberate response by OPEC, and it is likely future supply increases are controlled by OPEC. Going forward, without significant world "demand destruction," it is likely OPEC will continue to move to support a long term, relatively high price of oil.

What is Occurring With Demand? Real Demand Destruction in Developed Countries, Developing Countries Still See Demand Increases

The key question on the consumption side: is it possible that overall consumption of oil can decline going forward? This would require, in the developed world, continued declines year to year. Further, this would require, in the developing world, oil consumption to increase little or not at all. The most obvious solution to lower world oil demand is that recession will lower oil demand in both developed and developing countries. The probability of a collapse in China is beyond the scope of this analysis, as is a "Second Great Depression" in the United States. If the US continues to experience a slight recession while China continues to grow, OPEC would still appear to have the upper hand in determining long term oil prices.

One more "risk" to the above theory, that OPEC controls the intermediate price of oil. Can the world move away from oil use in the intermediate term, without economic impacts? It is noted that demand in the United States dropped by approximately 5% so far in 2008, Denmark's oil demand peaked back in 1998, and Japan's oil demand hasn't moved significantly since the 1980's, despite economic growth there (more specifically, in Japan, economic growth in the 80's, followed by stagnation in the 90's).

Proposed:

- lower oil consumption is related to either 1) lower rate transport of goods and persons and/or 2) more efficient transport of goods and persons. 1) is more correlated with lower economic activity (recession), while 2), efficiency, is more correlated by mass transport -- both Denmark and Japan have very good public transportation. Will both the developing and developed world move massively into public transport? The rate of this increase is also beyond the scope of this analysis, but will be addressed in a future analysis.

Gazprom Neft and KazMunaiGas Left Out of the Forbes Global 2000 and the PIW 50?

2008-07-22T16:10:00.000-07:00

Both the Forbes Global 2000 and Petroleum Intelligence Weekly 50 do not include either KazMunaiGas or Gazprom Neft in their rankings of the world's largest firms. In future years, as the financial and journalistic community gains knowlendge of these firms, based on the size of these firms reserves and expected production of oil and natural gas, both KazMunaiGas and Gazprom Neft should place in the Forbes and PIW rankings.

Energy firms are very well represented among the largest public firms in the world, according to the Forbes Global 2000, which can be found here: http://en.wikipedia.org/wiki/Forbes_Global_2000#2008_list The Forbes Global 2000 ranks firms in terms of size according to a formula that includes revenues, market capitalization, profitiability and assets, amoung other factors. The Forbes Global 2000 includes 3 private oil firms as of 2008, Exxon, BP and Shell in the top 10. (interestingly, has three banks in the top 3 spots -- with the current lower market capitalization of the financial sector due to the ongoing 2008 credit crisis, it is likely the Forbes 200 2009 version may drop financials from the top three spots). The Forbes Global 200 ranks publicly-held and privately-held firms only.

It should be noted that in the energy world, the largest energy firms are mainly national oil firms -- otherwise known as "NIOCs", 100% owned or partially owned by governments. Saudi Aramco, the national oil company of Saudi Arabia, is by far the largest oil firm in the world, according, to the Petroleum Intelligence Weekly top 50 (PIW 50), which can be found here: http://www.energyintel.com/documentdetail.asp?document_id=218175 Saudi Aramco's #1 ranking in terms of size in the PIW 50 is based on Saudi Arabia's massive size as an oil producer: Saudi Aramco expects to produce over 9M barrels per day of oil and natural gas liquids in 2008, and boasts oil reserves of approximately 250 billion barrels, a full quarter of known conventional oil reserves. In comparison, the privately owned Exxon Mobil produces approximately 3M barrels per day of oil (including natual gas in terms of oil equivalent barrels) and boasts reserves of approximantely 21 Billion barrels, including affliates. From these measures, it is clear that Saudi Aramco is the largest oil firm in the world in terms of energy production.

If the Forbes Global 2000 included both government-owned firms in addition to publicly held firms, it is likely that Saudi Aramco would be number 1 in the Forbes Global 200 list, as it is clearly a larger energy firm than Exxon Mobil.

Other national oil firms also boast very high oil and gas production numbers. The majority stated owned Gazprom -- the equity of which can be purchased as the government only holds a majority share, and the rest trades -- produces approximantely 9.5M barrels per day oil equivalent in natual gas, not counting Gazprom's oil production subsidiary. Oddly, according to Forbes' Global 200 ranking, Gazprom places only 19th in 2006, even through in the energy world it is one of the heavy weights (PIW has been steadily increasing Gazprom's ranking in the top 50).

The relevence of this discussion is the fact that KazMunaiGas and Gazprom Neft are not currently on the radar of either the PIW 50 or the Forbes Gloabl 200. These firms are not very well known in international circles. However, KazMunaiGas boasts very high reserve numbers, as mentioned in the previous article - over 2 Billion barrels of oil equivalent. In comparison, Marthon Oil, which is ranked 34th on the PIW 50, has reserves of approximately 1.2 Billion barrels of oil equivalent. Gazprom Neft also has reserves over 2 billion barrels, and, as argued in both previous articles, both KazMunaiGas and Gazprom Neft and growing rapidly in terms of reserves and production, while most western oil firms are struggling to maintain production. Going forward, it is expected that both KazMunaiGas and Gazprom Neft should gain recognition on both the Forbes Global 2000 and the PIW 50, which should boast investor recognition and probably market capitalization.

Kazakhstan's Flagship Oil Company "KazMunaiGas" E&P Expected to Significantly Increase Reserves and Production

2008-07-10T12:06:00.000-07:00

KazMunaiGas Exploration & Production ("KMG E&P", ticker (GDR) KMG.L) is the publicly held subsidiary of National Company (NC) KazMunaiGas, the national oil and gas company of Kazakhstan. KazMunaiGas E&P went public on both the London Stock Exchange and the Kazakhstan Stock Exchange in 2006, and, at the current date of the writing of this article, has a market capitalization of slightly under $US12Bn (and enterprise value of approximately $US9Bn, with approximately $US3Bn in net cash) and a P/E ratio on market capitalization of approximately 8x. KMG E&P produced approximately 242,000 bpd of oil in the first quarter of 2008, up 26.4% year over year. KMG E&P's proved and probable reserves of oil and gas were approximately 2.1 Billion barrels of oil equivalent at year end 2007, an increase of 43% year over year.

The key question for interested investors is, will the public KazMunaiGas E&P serve as the government of Kazakhstan's main acquisition vehicle for Kazakhstan's domestic oil and gas industry? This question is relevant in that if the answer is "yes," then KMG E&P has a higher probability of being equivalent in Kazakhstan to, for example, Petrobras in Brazil and Gazprom in Russia -- both public, majority state owned oil and gas firms which have increased substantially in market capitalization over the past few years due to their country's large reserves of petroleum wealth. This article will argue that there is a high probability that KazMunaiGaz will be the major acquisition vehicle for onshore Kazakhstan, and has a moderate probability of serving as the main acquisition vehicle for offshore Kazakhstan.

Oil and Gas Potential in Kazakhstan:

The oil and gas potential within Kazakhstan has been well documented -- Kazakhstan contains the second largest area of oil reserves outside of OPEC according to the EIA -- so only a few brief points will be included here. Kazakhstan as a whole has 24 fields according to the EIA with reserves close to 1 billion barrels or more, which are shown at this page at the EIA . Kashagan -- the offshore oil development which has very large reserves (over 20 billion, with close to 9bn barrels estimated recoverable) but has been repeatedly delayed -- and Tengiz -- operated by Chevron -- are largest and the most well known oil fields within Kazakhstan, but there are several other areas of large potential oil and gas reserves within Kazakhstan. Kazakhstan's section of the Caspian Sea is estimated to hold the largest reserves of any country around the Caspian, and the Caspian Sea is estimated to be one of the largest oil reserve regions in the world. Overall, more reserves are estimated to lie in offshore Kazakhstan than onshore, but both areas are expected to produce large volumes of oil. Kazakhstan is not a mature oil producing country by any means, with production only starting up on a large scale in the early 2000's. Historical and projected oil production to 2009 is presented in Figure 1 below.

Source: EIA

In the future, Kazakhstan holds very good potential for new oil and gas discoveries, as Kazakhstan is as large in terms of territory (as large as Western Europe and/or three and a half times the size of Texas), and the country is relatively lightly explored.

Overview of Kazmunaigas E&P:

KazMunaiGas E&P is 61% owned by KazMunaiGas National Oil Company, which, in turn, is 100% owned by the Kazakhstan government. KazMunaiGas National Oil Company (the parent of KMG E&P) was formed in 2002 by the combination of Kazakhoil (Kazakhstan's state owned upstream assets prior to 2002) and NC Oil and Gas Transportation (Kazakhstan's state owned downstream oil assets prior to 2002). KazMunaiGas E&P's ownership structure is potentially somewhat more confusing than, for example, Petrobras' ownership structure, as there is an additional firm between the government ownership and the public oil company. That is to say, Petrobras is directly, 55.7% owned by the government of Brazil, while KazMunaiGas E&P is 60% owned by KazMunaiGas NA which is owned by the government. Currently, there is only one state owned national oil company of Kazakhstan -- KazMunaiGaz NA -- and only one publicly owned, majority state owned national oil Company in Kazakhstan, KazMunaiGaz E&P.

As KazMunaiGaz NA (the parent firm) is well entrenched as the national oil company of Kazakhstan, the one of the main questions for investors -- above stated above -- is the extent to which KazMunaiGaz E&P (the public subsidiary) will own the current and future holdings of KazMunaiGaz NA. KazMunaiGas NA, by law within Kazakhstan, must hold a percentage of all oil and gas projects in Kazakhstan, and therefore future oil and gas reserve growth at the parent level is very likely. There are several indications that KazMunaiGaz E&P will hold a large percentage of future oil and gas fields from the parent company. The evidence for this assertion is presented as follows.

In KazMunaiGaz's investor relations sector of its website, in the May 08 KMG E&P investor presentation titled "Acquisition Strategy Strong Foundation for Future Growth" KMG E&P comes close to outright stating that it will be able to acquire assets with certainty from the parent. The presentation states at the end that KMG E&P will be the "producer and developer onshore" with an "interest offshore" and mentions an "Article 71" in Kazakhstan oil and gas law that states that KMG E&P first rights to "request" to bid on any of the parent's existing or future assets. The language of this Article 71 is taken by the author to encourage but not outright guarantee future transfer of assets from the parent KMG NA to the public KMG E&P.

Further, in the KazMunaiGas E&P's 2007 annual report, the chairman of KMG E&P Uzakbay Karabalin stated that the publicly held KazMunaiGaz E&P is the "flag carrier of the oil industry in Kazakhstan" and indicated that one of its main strategies is to acquire oil and gas properties within Kazakhstan from the parent firm. Further supporting the relationship between the national oil company and KMG E&P, on page 12 of the Annual Report, KMG E&P stated that it has a "strong relationship with its parent company, NC KMG, which gives KMG EP preferential access to onshore assets in Kazakhstan."

KMG NA and KMG E&P have stated that there role model firm is the Norwegian Statoil (ticker STO), which is majority owned by the Norwegian government, but the majority operator of Norway's oil and gas reserves. According to Rice University (large pdf warning) the government's purpose in making KMG E&P public in 2006 was for the government to "realize the value" of KMG's oil onshore assets. As such, this implies a sensitivity to market valuations by Kazakhstan's government for its oil and gas reserves. Also note, that several analysts, including the Economist's Intelligence Unit, have compared KMG E&P with Rosneft -- both went public in 2006 -- and both are majority owned by their respective governments but strong forces in the consolidation of the country's respective oil industries. These factors suggest a large role for KMG E&P in the future oil and gas industries of Kazakhstan.

Kazmunaigas E&P Producing Fields:

KMG E&P mainly holds two major oil fields - Uzenmunaigaz (where the majority of reserves and production occurs) and Embamunaigaz. Over the last year Kazmunaigas E&P has acquired 50% ownership in Karazhanbasmunai and Kazgermunai -- which are both currently relatively minor oil producing regions , but with solid reserves Uzen and Embamunaigaz are both relatively mature production areas, although outlook appears for relatively stable production over through 2013. KMG E&P also acquired two additional oil operations within Kazakhstan in 2007, a 50% share in
Kazgermunai in April and a 50% share in CCEL(Karazhanbasmunai) in December. The impact of of the 2 acquisitions was an increase in production by 25% and an increase in proved and probable reserves of 20%, according to KMG E&P's 2007 annual report.

KMG E&P Potential Acquisitions:

Going forward, KMG E&P has specifically targeted several acquisitions within Kazakhstan, which are explored in this presentation dated May 2008. KMG E&P has targeted a 33% stake in PetroKazakhstan for the second half of 2008. PetroKazakhstan, partially owned by PetroChina, produced approximately 123,000 bpd of oil in 2007. In the Feb 08 investor presentation, KMG E&P has targeted "Kazakholl Aktobe" which has proven reserves of 275M barrels of oil equivalent, but according to the EIA link above has reserves of a bit more than 1 billion barrels, and is starting up production. Potentially the strongest acquisition target for KMG E&P by production and reserves in the near term is Mangistaumunaigas, which produced 174,000 bpd in 2007, and which, according to the EIA, holds 1.4 billion barrels of recoverable oil equivalent of reserves.

Table 2: Near Term Acquisition Targets for KMG E&P:

Firm Name	Reserves (est)	Production (2007)	KMG E&P Ownership Percentage
Mangistaumunaigas	1.4 Billion BOE	114,000 bpd	51%
Kazakholl Aktobe	275M BOE	20,000 bpd	50%
PetroKazakhstan	550M BOE	144,000 bpd	33%
Kazakhturkmunai	54M BOE	7,000 bpd	51%

Will KMG E&P Move Into Offshore Projects in the Caspian Sea?

In an interview with CEO Askar Balzhanov of KMG E&P in October 2007 (reference: Kazmunaigas E&P Looks to Tap into Caspian Offshore, NEFTE Compass, October 11, 2007), Balzhanov stated that he is targeting offshore work in the Caspian Sea, and will present this idea formally to KMG NA. Originally KMG E&P was set up to target onshore oil and gas fields in Kazahkstan. Askar Bakzhanov previously was the CEO of the parent KMG NA's offshore oil activities before his appointment to the CEO position of KMG E&P, and knows offshore Kazakhstan's oil fields very well. The acquisition by KMG E&P of the offshore activities of KMG NA would be a natural fit according to Balzhanov.

Risks:

The main risk for investors is the relationship between the parent company KMG NA and KMG E&P, as discussed above. The risk exists that KMG NA could deny oil and gas projects or even create a completely separate oil and gas company to represent the state's interests in Kazakhstan's oil and gas sector. This risk is partially mitigated by the factors discussed above.

Taxation issues represent another risk to the operating performance of KMG E&P. In early 2008, Kazakhstan issued new oil taxes, which represent approximately 12% of the revenue from oil at $130 per barrel. The taxes were motivated by the government to increase revenues to support Kazakhstan's domestic spending and country credit rating. It is possible, with a downturn in economic activity within Kazakhstan, that the country could continue to increase the tax burden on the oil sector to bring in revenues. This risk is partially mitigated by the fact that Kazakhstan's economy is currently performing strongly, with approximately 8% growth in 2008. Further, Kazakhstan's debt to GDP is a relatively low 14% in 2007.

The third risk is risk of a lower oil price, which is a risk shared by KMG E&P with almost all other upstream oil and gas firms. According to KMG E&P's 2007 Annual Report, the Company does not hedge its exposure to oil and gas prices.

Conclusion:

KMG E&P represents the flagship oil firm of Kazakhstan, and, as such, represents a strong long term buy at the current market capitalization of $US12Bn. KMG E&P has made statements that it has a first priority on future onshore oil and gas activities in Kazakhstan, and has a good chance to move into offshore oil and gas projects in the Caspian Sea. As Kazakhstan holds high reserves of oil and gas, KMG E&P will benefit alongside Kazakhstan's oil and gas industry. Risks include political risk, including the risk of a change in the relationship between KMG E&P and the government of Kazakhstan, but this risk is mitigated by the Oil and Gas law of Kazakhstan, which specifically states that KMG E&P has a first right of refusal for oil and gas projects in Kazakhstan, and the stated relationship by KMG E&P and KMG NA management on the close ties between the two companies. Taxation risk is partially mitigated by the relatively strong growth and debt position of Kazakhstan.

Note on Purchasing GDR's by US Citizens:

KMG E&P trades as a GDR in London, and almost all GDR's (Global Depository Receipts) have restrictions on their purchase by individual investors who are US citizens. American institutions can buy GDR's -- and in fact, approximately 9% of the total float of KMG E&P is owned by American institutions. Interested individual American investors in KMG E&P (and other GDR's) are encouraged to ask several brokerages to find one that has the capability to purchase GDR's.

Gazprom’s Oil Subsidiary “Gazprom Neft” Aims to Become Russia’s Leading Oil Producer

2008-06-09T12:52:00.000-07:00

Gazprom Neft (ADR: GZPFY), the oil production subsidiary of Gazprom has stated in its 2007 Annual Report that it expects to more than double oil output to 2.0 million barrels per day by 2020 from a production average of 864,000 bpd in 2007. A production figure of 2.0 million bpd would be higher than all other Russian oil producers, if they do not achieve significant production growth going forward. Lukoil’s production in 2006 was 1.92 million bpd and Rosneft’s annual production average in 2006 was 1.6M barrels per day. Gazprom Neft's production target is assessed to be attainable, mainly due to the Company's ownership of the massive, and largely undeveloped South Priobskoye oil field, one of Russia's largest known oil fields, known in Russia as "the Pearl of West Siberia." Additionally, Gazprom Neft has also indicated that Gazprom will transfer its oil fields -- containing an estimated 5 billion barrels of possible oil reserves -- to Gazprom Neft. Further, Gazprom Neft has signed a 51%/49% joint venture with Lukoil in early 2008 to develop and produce undeveloped oil fields. Lastly, it is possible that Gazprom Neft will continue to consolidate large to medium sized producers of oil -- Gazprom Neft acquired 50% of mid-sized Slavneft (420,000 bpd) and 50% of Tomskneft (260,000 bpd production) within the last 12 months.

The factors suggest that Gazprom Neft's oil production and reserves have a high probability of more than doubling by 2020, and the stock price, at a current market capitalization of $38Bn (at early 6/08), should increase over the intermediate to long term.

Gazprom Neft Overview:

Gazprom Neft is the gas giant Gazprom's oil production subsidiary, with production of 864,000 bpd and proven reserves of approximately 4.5 billion barrels of oil equivalent in 2007. Most of Gazprom Neft's current assets are represented by the predecessor oil firm Sibneft, which Gazprom acquired in 2005 for approximately $US13Bn. The name of "Gazprom Neft" is interesting in that the name "Gazprom" means "Gas Company" (Gaz = gas and Prom = industrial company) in the Russian language-- Gazprom was organized by the Russian government in 1991 to hold the vast majority of Russia's gas producing fields and transport infrastructure. Gazprom added the name "Neft" to its oil production subsidiary in 2005 -- "Neft" in Russian translates to "Oil," and as such "Gazprom Neft's" name is illustrative of the Russian government's move towards currently -- it will be argued in this article -- consolidating the Russian oil industry in addition to the previous, successful moves which consolidated the Russian natural gas industry.

It should be noted that Russian oil production is very large, as the IEA reported on June 11, 2008 that Russia has passed Saudi Arabia as the world's #1 oil producer, with production of 9.5M bpd verses Saudi Arabian production of 9.2M bpd. As such, Gazprom Neft, with current production of under 1 million barrels per day of oil production, has significant room for production increases if it serves as the Russian's government vehicle of the consolidation of the oil industry.

Gazprom Neft's Planned Development of South Priobskoye, "The Pearl of Western Siberia:"

The Priobskoye oil field is a relatively new oil field in Russia, with oil production only starting up on a large scale in 2001 in the Northern portion of the field. Production for the field is ramping up rapidly on a large scale. Gazprom Neft produced approximately 125,000 barrels per day of oil from Priobskoye in 2007, and announced in mid 2007 that it plans to increase production by 2.6 times to over 300,000 bpd in 2010. ("Russian Gazpromneft-Khantos Oil Output To Rise 2.6-Fold by 2010, Energy and Commodities Digest, 8/21/07). Gazprom Neft also announced a development budget of $US11.22Bn for the next three years for all undeveloped fields, with a large chunk to South Priobskoye.

It should be note that the entire Priobskoye field is divided into two segments, North Priobskoye, which is owned and being developed by Rosneft, and South Priobskoye, which is being developed by Gazprom Neft. Rosneft's portion of Priobskoye is listed as its largest field by a factor of 4 in terms of reserves in its latest annual report, and is also Rosneft's largest producing field. Rosneft produced approximately 550,000 bpd of oil from its northern portion of the field in 2007, while Gazprom Neft produced approximately 125,000 bpd from its Southern portion in 2007. The northern region of Priobskoye is larger, although Gazprom Neft's area is not a "quarter" (ie, 25%) of the field as has been reported in some publications -- Gazprom Neft's area of the field is approximately 40% (see this map at JPT Online for a visual split of ownership area between Gazprom Neft and Rosneft at the Priobskoye oil field -- Gazprom Neft's ownership is Sibneft's former ownership and shaded in green). Gazprom Neft has not devoted significant resources to the development of South Priobskoye -- at least in terms of capital expenditures -- as of early 2008, although plans to devote the majority of future development expenses to this field from 2008 onward.

Can production increase further beyond 2010 at Priobskoye? The entire Priobskoye oil field is very large, measuring 5466 square kilometers as a whole in size compared to Ghawar (world's largest oil field, located in Saudi Arabia), which totals approximately 7,500 square kilometers in size. It should be noted that Ghawar is known within the petroleum geology as the "King of Kings" of oil fields, and any oil field coming close to Ghawar's size in terms of geographical area shows high promise. Priobskoye's size has wowed even the respected consulting firm Schlumberger, as shown in on page 3 of this Hart's E&P issue, in which refers to Priobskoye as so large that it is "startling." Oil reservoirs are in reality volumes of rocks with varying volumes of oil -- at this point the author has not seen information concerning the technical details of Priobskoye concerning porosity (volume of area that is filled with oil verses rock), permeability (ability of the oil to flow) - however from a first impression the field appears very large and capable of sustaining oil production volumes of well over 1 million barrels per day.

Note that for reservoir characterization purposes, not only the porosity and permeability but also the reservoir thickness levels would preferably be known, to determine the economics of production of the oil field. Rosneft has stated that its region of Priobskoye has low reservoir thickness as stated on page 136 of its IPO prospectus, which can be found here (large pdf warning). The low reservoir thickness makes horizontal drilling "virtually impossible" according to Rosneft -- but initial flow rates are kept high by immediate fracturing. Translation - the field will require some capital expenditures to ensure high oil flow and development, but due to the massive area of the field, the overall reserves and production with advanced levels of development are likely high.

Chart 1 shows the relative size of Priobskoye compared to the metropolitan area of Houston, Texas, for a unique perspective on the size of the oil field.

Chart 1: Priobskoye Oil Field Size Comparison:

Source: Hunt's E&P

A geological assessment of the total oil potential of Priobskoye was completed in 2004 by the former Russian oil company Yukos (the now bankrupt Yukos owned the development rights to Priobskoye in 2004), and audited by the petroleum geological firm DeGolyer & MacNaughton, which can be found here. The study indicated 27.6 Billion barrels of recoverable oil at Priobskoye -- it is ambiguous, however, if the study refers to all of Priobskoye or the Northern portion of the field. In the case that the number refers to the total field, the number of 27.6 Billion recoverable barrels would place Priobskoye as one of the 10 largest oil fields in the world. In fact, 27.6 Billion barrels of recoverable oil would place Priobskoye as a larger oil field than Samotlor -- the largest producing oil field in Russia to date, with 20 billion barrels of recoverable oil. Note that Samotlor produced a peak of 3 million barrels per day of oil in the early 1980's, and, based on resource size, it is possible that Priobskoye could produce a similar number at its production peak, which would imply an increase of 2.3M barrels per day for the total field from a current production figure of 675,000 bpd.

In summary, it can be assessed that South Priobskoye will likely achieve its planned 2010 production rate of 330,000 bpd by 2010, and likely has the geological resources to achieve 1 million barrels per day of production by 2020 -- which would imply that all of Gazprom Neft's 2020 production target of 1.8 Mbpd of oil production would come solely from increased production at Priobskoye. But it should be noted that in addition to Priobskoye, Gazprom Neft has other oil production projects and acquisition targets, as will be discussed below.

Gazprom Neft's 51%/49% Joint Venture with Lukoil:

Gazprom Neft signed a joint venture agreement with Lukoil for at least 6 undeveloped oil and gas fields in early 2008 -- details of particular fields in early June, 2008 were undisclosed, but the JV is likely to provide substantial growth opportunities to Gazprom Neft. Lukoil is known within the Russian oil sector as having licences to many potential oil fields, but slow to develop them -- the deal should provide Gazprom Neft with access to Lukoil's potential oil fields. It is tentitively assessed that the Gazprom Neft/Lukoil JV will target the relatively new oil province of Timan-Pechora, which lies over 1000 km to the west of Gazprom Neft's current producing regions, but has tremendous potential. The petroleum consulting firm Blackbourn Consulting has provided a oil and natural gas reservoir map of Timan-Pechora which can be found here. Most of these oil fields are undeveloped -- the larger fields tentively hold approximately 1 billion barrels of oil equivalent in reserves, and the region holds at least 10 billion barrel reserve fields according to the Blackbourn Consulting map. Further detail on the Gazprom Neft-Lukoil JV will be disclosed in late June/early July, at which point field names and data will be better known. At this point the JV points to likely additional reserves of over 1 billion barrels oil equivalent proportional interest to Gazprom Neft.

Transfer of Oil Assets From Gazprom to Gazprom Neft:

The president of Gazprom Neft, Alexander Dyukov, told reporters on June 8, 2008, that Gazprom could put its oil fields on Gazprom Neft's balance sheet by end 2008 ("Gazprom Neft Could Get Gazprom Oil Fields by the End of 2008," Russia and CIS General Newswire, June 8, 2008). Petroleum Intelligence Weekly reported in April of 2008 that Gazprom holds oil fields with 5 billion barrels of possible oil reserves, the majority of which are currently undeveloped (Gazprom Neft's Grand Plans for Growth, PIW, April 28, 2008). Gazprom's undeveloped oil fields lie mainly in the far northern Siberia, in both onshore and offshore locations -- development would be technically challenging, but not prohibitively so. The transfer of oil assets would add significant value to Gazprom Neft.

Gazprom Neft's Potential Acquisition Targets:

The Russian oil firms Russneft, Bashneft, TNK-BP and even Surgutneftegas -- all large oil firms with over 200,000 bpd of oil production -- have been have been mentioned by Russian investment banks as potential acquisition targets for Gazprom Neft. It is the assessment of the author that the full acquisition of any of these targets is not extremely likely -- with the exception of Russneft -- due to factors discussed below. However, one off acquisitions of oil producing assets of these firms is more probable.

Of the names on the list of potential acquisition candidates, Russneft is assessed to be the most likely in terms probability of acquisition by Gazprom Neft -- Russneft is an independent producer of oil in Southern Western Siberia, over 1,000 km from the majority of Gazprom Neft's current producing areas. Russneft's production is approximately 290,000 bpd of oil equivalent (mainly oil) and counts reserves of slightly over 1 billion barrels of oil equivalent, according to Russneft's website. Russneft has been hit over the last year with fines and taxes totaling over 20 Billion rubles, in a move similar to the government's targeting of Yukos in 2004 and 2005. There is a high chance that the ownership of Russneft will change hands, however, what is unknown is which firm will acquire Russneft's oil producing assets once Russneft is in bankruptcy. Reuters reported on 10/24/07 that either the Russian billionaire Roman Abromovich or Mittal Steel -- a Russian steel producer -- were behind the taxes on Russneft, although this has not been confirmed (note that Roman Abromovich was the majority owner of Sibneft, which was the predecessor company to Gazprom Neft, so there could be some connection here with Gazprom Neft). Russian aluminum billionaire Oleg Deripaska has also been rumored to be interested in acquiring Russneft. Overall, summing up these trends, the likelihood of a near to intermediate term acquisition of Russneft by Gazprom Neft is assessed as "moderate."

The acquisition of Bashneft by Gazprom Neft has been also mentioned by several sources, including the Russian investment bank Antanta Capital. According to Antanta Capital, Russian federal (Moscow) authorities have been reviewing the legality of the ownership of Bashneft by the Russian republic of Bashkortostan, and this process is ongoing currently (mid 2008). At stake is the ability of the republic of Bashkortostan to own assets -- currently Bashkortostan -- located in south western Siberia -- has semi-autonomous status, similiar to the Russian republics of Chechnya and Tatarstan. Bashkortostan has its own foreign ambassador and embassy and ethnic group, Bashkir, who speak their own unique language. The outcome of this process is difficult to judge at this point -- if ownership of Bashneft is overturned, then Gazprom Neft would be first in line to acquire the assets, however, it is difficult to say if the Russian government will overturn its long standing (Bashkortostan has had semi-autonomous status since 1992) relations with the republic of Bashkortostan. Probability of the acquisition of Bashneft is therefore assessed as moderately low at this time.

The last two acquisition targets, TNK-BP and Surgutneftegas, are both assessed to be moderately-low to low probability acquisition targets for Gazprom Neft in the intermediate term. While TNK-BP has been hit with tax fines and tax raids over the last year, signaling that it is possible that the government will seize assets, this development is mitigated by the fact that Vladimir Putin personally gave his blessing to the BP-TNK merger early in his presidency. Putin still serves as Russia's Prime Minister and is widely viewed as having significant power, and generally has been known to keep his intentions concerning oil and gas producers. The acquisition of Surgutneftegas by Gazrpom Neft is at this stage merely a rumor circulating in certain Russian publications, and no details concerning concrete facts have been made known at this time. The president of Surgutneftegas, Vladimir Bogdanov, has generally good relations with Putin and Moscow.

Note that even if Gazprom Neft does not acquire 100% of the equity of any of the aforementioned Russian oil firms, it is still possible for Gazprom Neft to acquire individual oil producing fields that are currently owned by these oil producers. In the author's opinion, this scenario is more likely -- also it is the scenario which occurred in the case of Yukos -- Yukos was taxed and fined, then its main producing subsidiary was purchased by Rosneft. Table 2 below gives the names, production and probability of acquisition of the Russian firms that have been discussed in this section.

Table 2: Acquisition Probability by Gazprom Neft of Russian Independent Producers:

	2007 production (bpd)	Likelihood of Acquisition (total firm)*	Likelihood of Acquisition (oil field)**
Russneft	290,000	Moderate	Moderately High
Bashneft	240,000	Moderately-Low	Moderately-Low
TNK-BP	1,700,000	Moderately-Low	Moderate
Surgutneftegas	1,300,000	Low	Moderate

* "Likelihood of acquisition (total firm)" is the author's opinion only, defined as the probability going forward that Gazprom Neft will acquire a majority stake in the independent Russian oil producer.
** Likelihood of acquisition (oil field) is the author's opinion, defined as the probability going forward that Gazprom Neft will acquire an individual oil field from the respective Russian oil producer.

Conclusion:

Gazprom Neft has several routes to increase production in line with its planned output goal of 2.0M barrels per day by 2020 -- it is likely that Gazprom's development of South Priobskoye will add a significant percentage of the expected increase of 1 million barrels per day of oil production. In addition, acquisition of existing oil fields from independent producers of oil within Russia is also a probable outcome going forward for Gazprom Neft, and Gazprom Neft's JV with Lukoil is likely to target new, massive oil fields in the Timan-Pechora region with significant potential. Finally, Gazprom's expected transfer of its oil assets to Gazprom Neft should add further value to Gazprom Neft over the long term. All in all, Gazprom Neft has potential to more than double production and increase reserves more than 3 times over its current proven reserve base of 4.5 Billion barrels of oil equivalent.

It should be noted that this article did not discuss taxation issues within Russia -- Russian oil producers pay high taxes on oil production, significantly limited the profits from higher oil prices (although the tax regime favors refiners of oil products, and Gazprom Neft refines a comparatively large percentage of its oil production). Further, risks of asset appropriation by the government was not discussed -- however this risk is mitigated by the fact that Gazprom Neft is majority owned by the government. Interested investors are encouraged to do their own due diligence with regards to these issues.

Reserve Growth Expected Soon at Sinopec's Upstream Segment

2008-05-19T13:02:00.000-07:00

It is argued in this article that Sinopec should see significant reserves growth over the next 1 to 5 years, more than doubling current reserves, due to reserve additions in both domestic (Chinese) and international areas. Sinopec as covered in an earlier articl e has a substantial exploration and production division with proven reserves under SEC reporting guidelines of approximately 3.77 Billion Barrels of oil equivalent (86% oil)- compared on a reserve basis to Conoco Phillips (at 6.85 Bn BOE (42% oil) ex affiliates -- mainly Lukoil) and Chevron (7.85 Bn BOE, excluding affiliates). Expected growth in Sinopec's reserves and production, based on Sinopec's statements concerning oil and gas development activities, should make Sinopec approximately equivalent to both Conoco Philips and Chevron on a reserves basis over the next five years.

Potential Reserve Additions Within China:

Domestically, Sinopec has two very promising areas within China for reserve growth: Sinopec's Puguang Gas field in Sichuan -- the second largest known gas field in China -- and the Tahe Oil Field in Xinjiang. Both have high estimated reserves (over 1 billion barrels of oil equivalent) and are in production or close to production currently (mid-2008), but have not been consolidated on Sinopec's reserves statement.

Puguang Gas Field:

The giant Puguang gas field, with between 300-400 bcm of recoverable reserves (approximately 2-3 billion barrels of oil equivalent) is expected to come online at the end of 2008, at which time the pipeline to Shanghai will be completed. The reserves have not been consolidated in Sinopec's 2007 Annual report filed with the SEC, due to the fact that only proven and producing oil and natural gas reserves can be consolidated according to SEC guidelines. Initial production per year is expected at 4 bcm per year -- approximately 68,000 barrels per day of oil equivalent, and increase to a final production figure of 8 bcm (136,000 barrels per day oil equivalent) by 2010 by Rigzone -- this is estimated to add approximately 15% to Sinopec's 2007 production of approximately 900,000 barrels per day of oil equivalent by 2010.

Tahe Oil Field:

In the far West, in the Chinese province of Xingang the Sinopec's Tahe field, located in the Tarim Basin, is up and producing an estimated 100,000 barrels per day at the end of 2007 according to Sinopec's 2007 annual report (large pdf warning), although the Tahe field has not been consolidated in Sinopec's 2007 annual report (there are no direct references of Tahe or Tarim on Sinopec's 2007 reserves statement, and the production has not been included in the oil production in the 2007 Annual Report, in at least a review by the author). The overall field is estimated at 1 billion tons of oil equivalent (approximately 7.4 Bn barrels of oil) -- what is ambiguous in reports concerning Tahe is whether or not this number refers to recoverable oil or oil in place -- it is more likely that the oil reserve number refers to total oil in place (as Chinese reports typically indicate total oil reserves, as is the case with the recent oil and gas discoveries in Bohai Bay). At a recoverable percentage of 35% for Tahe of total oil, the reserves booked would be 2.6Bn barrels. The author cannot find additional information concerning final production rates, but at 200,000 bpd in 2010 (estimated), this would add 22% to Sinopec's 2007 production of 900,000 barrels per day of oil equivalent production. Chart 1 below shows the Tarim Basin in Xinjiang, where the Tahe Oil Field is located, in comparison with the other oil and gas fields in China. (note that this chart was completed in 1999, before the Puguang Gas Field was discovered, so this field is not indicated below):

Chart 1: China's Oil Fields, Including the Tarim Basin in Xinjiang:

Source: FromtheWilderness

It should be noted that there has been some criticism of Xinjiang's oil potential in the past by analysts. Chinese officials had throughout the 1990's and early 2000's made optimistic claims about the region's oil and gas potential, even claiming that Xinjiang could potentially overtake production from China's eastern Daquing and Bohai Bay areas (Daquing is one of the four largest oil fields in the world, owned and operated by PetroChina). Some analysts have poked holes in this argument about Xinjiang's oil potential -- it is likely according to Beijing based petroleum geologists that there is not one single, giant field in Xinjiang but rather a series of medium sized fields, and the oil is more viscous (closer to heavy oil), that the depths needed to drill are several kilometers deep. However, this does not mean that Xinjiang should be taken to the opposite extreme, that there no little or no economically recoverable oil in the region, as has been done in certain publications -- the achievement of initial production of 100,000 barrels per day from the Tahe Oil field in 2007 shows that the Tarim basin has significant potential, if not as high as China's eastern coast.

Overall, from domestic areas -- Puguang and Tahe -- Sinopec can expect to book an additional 4.5Bn to 5.5Bn barrels by the end of the 2009 to 2010, which compares to an existing reserve base of 3.77Bn barrels at 2007, and add an additional 200 -300,000 barrels per day of oil equivalent production, taking Sinopec over 1 million barrels of oil per day by 2010 -- a very high production number for a firm selling at around $US80Billion in market capitalization.

Potential Reserve Additions Internationally:

Internationally, Sinopec has three main areas which have high potential, Angola, Iran and Venezuela, and two areas of good potential: Russia and Africa. The larger areas of reserve potential, Angola, Iran and Venezuela, will be discussed below.

Angola:

Angola is one of the world's hottest areas for oil investment, with projected daily production by 2010 of 2.6 M bpd by Rigzone, and Angola is projected to overtake Nigeria after 2010 in terms of oil production. Sinopec Group -- the parent of Sinopec Corp, the publicly listed subsidiary (ticker SNP) has a 37.5% interest in Angola's offshore Greater Plutonio field, which is up an running in 2007 with production of 240,000 barrels per day (Sinopec's proportional interest of 90,000 bpd). This production number has not been consolidated into the publicly held Sinopec Corp at the end of 2007, although Sinopec Group has indicated that overseas properties will be transfered to the publicly listed subsidiary (see this article for details). Total reserves of this field are estimated at 750M barrels, which translates to a productive field life of 8-9 years at current production rates.
Sinopec also owns equity shares in other offshore oil fields -- ranging from 20% to 40%, in offshore Angola Blocks 17, 18, and 15, which, as reported by the University of Alberta, contain a total of 3.2 Billion Barrels of oil. Production dates are expected within the next 5 years., with initial production undisclosed. Overall, Sinopec's Angola oil fields can potentially add approximately 1 billion barrels to reserves when the oil fields are developed, in the 2010 time frame.

Chart 2 shows the relative distribution of Blocks in offshore Angola -- it is noted that the majority of blocks have not been awarded as of 2007 (when this map was constructed) -- Sinopec, having won positions in three blocks is strongly positioned over the long term for future block bidding in Angola.

Chart 2: Map of Blocks in Offshore Angola:

Source: SubseaIQ

It should be noted that there is some resentment of Sinopec by certain international oil majors over Angola, due to the fact that Sinopec bid very high rates for the rights to participate in Angola's oil fields -- the amount Sinopec paid was approximately 10x higher than Exxon Mobil's bids for the same fields. Critics have stated that Sinopec "will pay any price to participate in international oil" and that Sinopec could not possibly develop Angola's oil fields profitably due to the high prices paid for the fields. However, the respected consultancy Woods McKenzie has stated that's Sinopec's international activities should be profitable at current prices, despite the high acquisition prices paid -- further, with the current, very high (in mid 2008) oil prices, it is more likely that Sinopec's Angolan operations will be profitable.

Iran:

One of Sinopec's most promising international ventures is Iran, and particularly Iran's Yadavaran oil field, which has an estimated 3 billion barrels of recoverable oil in place, and is currently undeveloped. Sinopec has signed agreements to develop this oil field in early 2008. The reserve numbers will likely not be able to be consolidated on Sinopec's reserve statements, however, due to the fact that under Iranian law, foreign firms are not allowed to own Iranian properties of oil and gas. However, Iranian law does provide a guaranteed return of between 10-20% per annum to oil firms on production -- with essentially no risk, as there are no exploration costs. The details of Sinopec's deal with Iran are opaque currently, but it has been rumored that Iran has intended to provide good terms for Sinopec in order to attract interest by International majors in undeveloped oil fields going forward. Terms are rumored to be 15% with a 4 year payback period, according to the Oil and Gas Journal (Yadavaran Buyback Contract Signals Better Iranian Terms, Oil and Gas Journal, Jan 14, 2008), which is considerably better than other deals in Iran in recent years. Overall, the Iranian Yadavaran oil deal should boast profitability at Sinopec for several years going forward.

Venezuela:

Sinopec -- along with PetroChina -- have moved into Venezuela on a large scale after Exxon Mobil, Conoco Philips, and many other Western oil majors were expelled of the country in 2007 without significant compensation. Venezuela has publicly stated that its massive Orinoco oil heavy oil belt - with comparable recoverable oil reserves to those of Saudi Arabia -- will be developed mainly by Venezuela's national oil company PDVSA with a large contribution from Sinopec and PetroChina, as reported by YaleGlobal. Sinopec has taken a 32% interest in certain regions of Venezuela's Orinoco's heavy oil belt -- with 60% owned by PDVSA (Venezuela's national oil company). Current production is estimated by Schlumberger of Venezuela's total oil sands territory at 600,000 barrels per day, while Venezuela would like to increase this number to at least 2 million by 2020.

As the reserve numbers are very large in Venezuela's heavy oil belt, more informative is to look at potential production numbers. Venezuela has indicated that it wants to increase combined production with Chinese (both Sinopec and PetroChina) to 200,000 bpd by 2010 and 400,000 bpd by 2011, with further increases thereafter (Venezuela-China Team Sets Orinoco Target, Platt's Oilgram News, August 25, 2006). Assuming 50% of the Chinese production goes to Sinopec, at 32% equity ownership, this translates to 64,000 barrels per day by 2011.

Overall, Venezuela is a growing source of petroleum production for Sinopec over the long term. There is some doubt that Sinopec will receive a high margin on oil operations in Venezuela, as Hugo Chavez has stated: "The days of private enterprise in oil in Venezuela are over," (during the expulsion of Exxon and other western majors in 2006) but the operations should add some value to Sinopec.

Chart 3: Potential Reserve and Production Additions to Sinopec over the Next 1 to 5 Years:

	Potential Reserves	Potential Production (est)	Expected Date of Production
Puguang	2-3 Billion BOE	136,000 bpd	2009-2010
Tahe	2-3 Billion BOE	200,000 bpd	2008-2011
Angola	1 Billion BOE	200,000 bpd	2008-2012
Iran	1.5 Billion BOE*	n/a	n/a
Venezuela	n/a	100,000 bpd **	2012
Total	5-7 Billion BOE	636,000 bpd

Notes: * Under Iranian law, the Yadavaran Oil field, will not be able to be consolidated as reserves, and potential production numbers of this field have not been disclosed as of 5/08.
**Venezuelan heavy oil production can go much higher than 100,000 bpd proportional interest to Sinopec, but a 100,000 bpd number is used here to indicate potential taxation/expropriation issues.
Potential Reserves are presented as a mean number for estimates of resource size. Potential production numbers are estimated in peak production years based on preliminary data from reports and articles cited above.

Conclusion:

Sinopec has several areas both domestically and internationally that show high promise for substantial reserve additions going forward. In particular, Sinopec's domestic Puguang and Tahe gas and oil fields are almost certainly going to add substantially to reserves in the next 1 to 3 years. Internationally, Angolan production is currently up and running, with potentially for further production and reserve addition increases. Iran and Venezuela also show high promise for Sinopec profitability. Note that this article did not discuss potential problems with the Shengli oil field after 2010 -- many analysts believe Sinopec's main oilfield -- Shengli, which is decades oil -- could decline after 2010. Also, other divisions within Sinopec, namely Sinopec's refining division, was not discussed in this article, but was addressed in an earlier article. Finally, cost projections were not discussed, in that Sinopec's potential may exist, but profitability of these potential oil fields was not discussed.

Payback Period Calculations for Gazprom's Yamal Peninsula Projects

2008-05-12T13:26:00.001-07:00

The previous post did not analyze cost factors for Gazprom's proposed Yamal Peninsula projects, but rather argued that it was more likely than not that Gazprom would produce significant quantities of gas from this region in the intermediate term. An investor would be most interested in whether or not the field would be economical to develop. As such, a range of payback periods (a payback period is defined as the amount of time required to "repay" a project's investment) are presented as follows, with differing assumptions of average production, gas prices and costs.

Note that oil and gas firms would like to see a payback period of 5 years or lower, but will go beyond 5 years if the reserve is a a long lived asset (over 15 years) -- the fields in Yamal appear to qualify as long lived assets as the largest field, Bovanenko, has estimated reserves of 4.4 tcm and a projected annual production of 115 bcm, which implies a field life of 38 years at peak production rates.

Forecasts by the respected consulting firm Oxford Analytica has estimated development costs of all areas of the Yamal Peninsula to total in the range of $US160Bn, spread over the time period from 2008 to 2020. Gazprom has forecasted annual production of 170Bcm by 2020 from all fields in the Yamal Peninsula.

Payback Period Calculation: Base Case

Assumptions: natural gas price per mcfe received of $10, average production of 170 bcm, total costs $US160Bn, operating margin of gas production at 40%: payback period: 6.13 years.

Payback Period Calculation: Cost Overrun Case:

Assumptions: natural gas price per mcfe received of $6, average production of 150 bcm, total costs $US220Bn, operating margin of gas production at 30%: payback period: 21.2 years.

Payback Period Calculation: High Gas Price Case:

Assumptions: natural gas price per mcfe received of $14, average production of 170 bcm, total costs $US160Bn, operating margin of gas production at 40%: payback period: 4.65 years.

Notes: In all calculations, the payback periods are simply done, by taking final total production and not accounting for time periods to reach total production -- so for example, if Gazprom takes 6 years to reach final production of 170 bcm, the payback calculations above do not account for this. Further, natural gas prices are assumed to be constant.

Conclusion:

Gazprom's Yamal projects appear positive under expected cost and production figures, leading to economic development of the Yamal Peninsula, with the exception of the "Cost Overrun Case," which assumes higher costs and a lower price for natural gas ($6 per mcfe). It should be noted that 170 bcm (billion cubic meters) is a huge amount of natural gas, approximately equal to in oil barrel equivalent to 2.9M barrels of production per day -- with high energy prices, this produces a very high future income stream. Note that it is not expected that natural gas prices will fall significantly to the $6 level going forward -- this would be equivalent under an energy equivalent basis to $36 per barrel oil prices -- but it is possible. Further, note that domestic Russian prices of natural gas are expected by Gazprom to reach parity with exported prices by 2012 -- Gazprom is raising Russian prices of natural gas by 20% annually over the next several years -- which means that a calculation requiring separate prices for domestic and exported gas after 2012 is not critical.

Gazprom Releases Official Projections of Natural Gas Production: Is It Realistic That Gazprom Increases Output Through 2030?

2008-05-07T13:36:00.000-07:00

Gazprom, Russia's largest company and the world's largest natural gas producer, has released projections for future expected production of natural gas until 2030 on its website, which overall show moderately growing production and comfortable maintenance of gas export capacity. Gazprom's projections stand in contrast to doubts raised by several analysts (the reports of whom will be discussed below) as to whether or not Gazprom can maintain production at current levels. Criticism of Gazprom's future production has been mainly directed toward potential decline rates at current producing fields and the perceived lack of initiative by Gazprom to bring new fields online. The questions concerning decline rates and new fields have led to a significant segment of the media questioning Gazprom's ability to increase future gas production. Newsweek, as an example, published an article in 12/07 titled: "Russia's Big Secret" which states as a subheadline: "Russia Can Barely Meet its Own Demand," implying heavily (although not outright stating) that Russia's future gas production will decline while domestic consumption continues to rise.

This article will analysis Gazprom's ability to meet its future projections, and address Gazprom's response to criticism. All in all, a review of Gazprom's evidence shows that Gazprom makes a strong case against key criticisms -- and it is more likely than not that Gazprom's future natural gas production will increase through 2030. The question of future production at Gazprom holds significant importance to interested investors. Is Gazprom a firm in decline or ascension? Key points will be discussed below.

Gazprom Overview:

Gazprom is currently the world's largest natural gas producer, producing approximately 20% of the world's natural gas by volume. Gazprom is Russia's largest company -- the newly elected President Medvedev currently serves as Gazprom's chairman of the board, although a replacement is expected soon. Gazprom's currently ranks as the world's third largest publicly held firm by market capitalization at approximately $US315Bn, and has a trailing p/e ratio of approximately 13x. Gazprom is also a major oil producer through the acquisition of the Russian oil firm Sibneft in 2005, and is the fifth largest oil producer in Russia, behind TNK-BP.

How should a firm the size of Gazprom be analyzed? The main approach taken in this article -- and incidentally in criticisms of the company -- is by analyzing first and foremost the main producing natural gas fields of the firm, that is, its Exploration and Production segment. Although Gazprom does not break out revenues and earnings by division in its Annual Report or on its website, it is likely that Gazprom's internal structure is like most integrated majors in that its Exploration and Production segment comprises the majority of overall firm profits.

Overview of Gazprom's Exploration and Production Activities:

Gazprom produces currently a majority (over 70%) of its Gas from four main fields -- three of which (Yamburg, Urengoy, Medvezhye) are over a decade old and are in decline -- although at what degree of decline is a key question -- and one field (Zapolyarnoye) which was brought online in 2001. (an interesting fact is that the unusual names of the fields are due to the fact that Gazprom has named them after words in local native tribal languages -- Urengoy, for example, can mean "an island in a former riverbed" in the northern Siberian Khanty language). Historical production from these fields can be seen in Figure 1 below -- note that this chart is cited most often by critics of the company -- what's important in the chart below is the historical production -- future production is in question, as will be discussed below.

Criticisms of Gazprom's Future Natural Gas Production:

A summary of the criticism leveled at Gazprom can be found at the consultancy Stratfor
titled: "Gazprom's New Field and Enduring Supply Problems." Much of the data -- including the chart below -- is taken from data presented by Jonathon Stern of the Oxford Institute for Energy Studies in his book titled: The Future of Russian Gas and Gazprom (published 2005). Chart 1 has also been published by the EIA. The criticism are summarized in Chart 1 below, which shows high rates of decline at existing fields, only one new, major field brought online in 2001 (Zapolyarnoye), and in many versions (as the one below) the forecast does not list new potential fields.

Chart 1: Critical View of Gazprom's Future Natural Gas Production (Historical until 2004, Projected 2005 Onward)

As can be seen in Chart 1, there are two main sources of controversy over future natural gas production: 1) the rate of decline of the three decade old fields -- critics point to high rates of depletion without stabilization or expansions of the 3 decade old fields, and 2) the potential to bring online new fields -- critics state at the most extreme that no new fields of giant size from the Yamal Peninsula will come online going forward, due to economic issues, difficult terrain, and/or lack of project management expertise at Gazprom -- but more commonly state that new giant fields will come online but be delayed past the planned 2011 start date. Note that the above chart sometimes is presented as forecasting new giant fields in future years by drawing a higher line going forward but with a "?" or something to this effect (implying significant doubt as to whether the fields will be brought online).

Gazprom's View of Its Future Natural Gas Production:

Gazprom -- not unexpectedly -- takes a more optimistic view of its future natural gas production, which is summarized in Chart 2 below.

Chart 2: Gazprom's Projections:

Source: Gazprom's Website

Gazprom's official projections of Gas production by area in Chart 2 presents several items that differ from Chart 1. First, Gazprom projects production will be heavily dependent on the onshore Yamal Peninsula -- as distinct from the offshore Yamal (Shtokman gas field) with production starting in 2011 and then comprising about 50% of Gazprom's production by 2030. Gazprom's core current producing areas -- represented by the light blue area above and dependent on Gazrpom's current four major gas fields (Urengoy, Yamburg, Medvezhye and Zapolyarnoye) will decline gradually going forward, but still make up a large (approximately 60%) of total company production in 2020, and comprised approximately 350 bcm of annual production in that year. Note that in contrast, in the projections presented in Chart 1, the three decade old fields, only make up approximately 30% of total Gazprom production, and only produce approximately 100 bcm of gas in 2020. Gazprom as a whole is projected to produce approximately 300 bcm of gas in 2020 in Chart 1 -- as compared with approximately 580 bcm in Chart 2 -- a difference of 93% between the two forecasts in 2020.

Gazprom's Proposed Stabilizing Measures at Existing Fields:

Gazprom's additions to these core fields -- to the approximately two decades old Urengoy, Yamburg and Medvedyze fields -- is projected by Gazprom to make up a significant contribution to total Company production. These additions are represented by the yellow area above -- estimated at 5% of total production in 2010 at approximately 50 bcm of annual production, and also by a lower decline rate in the light blue area in Chart 2. Certain critics (to the author's knowledge, having read the EIA, Oxford Institute for Energy Studies's presentations and material) do not address Gazprom's stabilizing measures at its Urengoy, Yamburg and Medvedyze fields. According to Gazprom, a key strategy of the firm is to stabilize production at its core fields -- production at the three core decade old fields can be stabilized by exploiting new areas of these existing fields. According to Gazprom's website:

"A production decline in 2006 was mainly offset via production growth in the Pestsovaya area of the Urengoyskoye field, Zapolyarnoye field, Aneryakhinskaya area of the Yamburgskoye field, Komsomolskoye field."

"Up to 2010, scheduled gas production rates will be maintained through the development of existing and new fields in the Nadym-Pur-Taz region: Yuzhno-Russkoye field, Neocomian deposits in the Zapolyarnoye and Pestsovoye fields, Kharvutinskaya area in the Yamburgskoye field, Achimov deposits in the Urengoyskoye field."

Recent production data points to more evidence for Gazprom's stabilization of existing fields: the rapid decline rates for Urengoy did not occur in 2006, (the last date for which production data is available). Urengoy produced approximately 138 bcm according to Gazprom's "Facts and Figures" Datasheet compared to the projections in Chart 1 which projected Urengoy to produce approximately 110 bcm -- a difference of 25% in only two years (chart 1 was completed with data historical data from 2004).

Russian petroleum geologists V. I. Marinin and V. A. Isotomin presented two papers in 2006 at the 23 World Gas Conference addressing expansion of the Urengoy gas field: Prospects of Resource Increase of Urengoy Complex and New Technologies of Gas Production at the Urengoy Gas-Condensate Complex which both argue that new areas of the Urengoy gas field can be developed, which will stabilize overall production. The papers present data that the Urengoy gas field is a multi-layer, complex and geographically large (the Urengoy gas deposit is over 120 km long) with several undeveloped segments.

Gazprom's Proposed New Fields: The Yamal Peninsula:

According to Gazprom's website, production is projected by Gazrpom to hold steady through about 2013 without the contribution of the Yamal Peninsula, which is forecasted to come online in 2011 -- giving Gazprom a significant cushion in which to bring online Yamal before production declines. The Yamal Peninsula has three major fields, the largest of which is the giant Bovanenkovskoye gas field with reserves at an estimated 4.4 tcm (equivlent to approximately 23 bn barrels of oil equivalent) (Reference see page 26 of Gazprom's stats and figures 2002-2006 data sheet here). The Bovanenkovskoye field is approximately the same size as Urengoy and Yamberg according to Gazprom -- reserves of these fields are estimated at 5.3 tcm and 3.8 tcm, respectively. Production is estimated to come online at 2011 and produce 115 bcm per year by 2019.

Gazprom has budgeted approximately $4Bn to Bovanenkovskoye in 2008 out of a total capital budget of $25Bn, and has budgeted approximately half the Company's exploration and production budget on other areas associated with the Yamal Peninsula in 2008.

Can Gazprom Bring Yamal Peninsula Production Online?

There is less debate as to whether or not the natural gas exists in meaningful quantities in the Yamal Peninsula -- the US Geological Survey has consistently rated Gazprom as having the largest reserves of natural gas in the world, with only a fraction developed -- more debated by critics is whether or not Gazprom has the project management expertise and/or initiative to bring these new fields online. 2008 the first year that Gazprom has dedicated significant funds towards developing infrastructure and field development in the Yamal Peninsula. There were earlier reports that the Bovanenkovskoye field would be developed as early as 2000, however, Gazprom has not included Yamal-based projects as a major expenditure in its budget as the firm as been more busy doing acquisitions (which has subjected the firm to criticism apart from the decline rates and "lack of prospects" as described above). Additionally, Gazprom has focused on bringing its massive Zapolyarnoye field online in 2001. According to the Deputy Chairman of Gazprom, Alexander Ryazakov, Gazprom has been confident of the productive capacity of its 3 major fields so Yamal has not been a priority until recently. (quote by Ryazakov below is from a question and answer session in 2004 which can be found here):

"We still see prospects in withdrawing gas at the Yamal Peninsula containing huge reserves. We’re very likely to do it but, in my opinion, the local gas production and marketing home and abroad are not that interesting for us, at present. We’ve endeavored so far to operate on the traditional extraction sites, developing there the existing fields. And some 5, 6, may be 8 years later we’ll move on to the Yamal Peninsula."

Gazprom bought online the massive Zapolyarnoye field in 2001, which is currently producing approximately 100 bcm per year of natural gas -- some critics have alleged that Gazprom has not brought online any fields since 1991 (as in the Newsweek article cited above) but this is incorrect.

Note: Other Projections of Gazprom's Future Gas Production:

Jean Laherrere, who has worked for over 30 years as a Petroleum Geologist at Total (biography here) has provided the following Chart of forecasted natural gas production at Gazprom. As seen below, Laherrere has forecasted overall increasing production, driven by the development of new fields -- note that Laherrere's decline rates are faster than Gazprom's projections, but, as a knowledgeable petroleum geologist, he does not discount the extent of production from new fields. It should be noted that other sources have Laherrere projecting declines for Gazprom past 2030 (source here) -- the projections below only go out to 2020.

Chart 3: Laherrere Forecast of Gazprom Natural Gas Production:

Source: 321 Energy

Laherrere is a member of the Association for the Study of Peak Oil and Gas, and has projected a near term peak in oil production, so his projections may lie on the conservative side -- it is noted that Laherrere has projected only 60 bcm in final annual production while Gazprom has reported that Zapolyarnoye production reached 100 bcm in 2004 (the projections are a bit dated with historical data beginning in 2001). Even with the conservative projections, Laherrere has projected an increase in Gazprom production through 2020.

Note: Gazprom Does Not Produce from a Single Dominant Field:

It should be noted that Urengoy has been labeled by some as "Gazprom's Ghawar" -- Ghawar as the largest oil field in the world, held by Saudi Aramco (

Saudi Arabia

's national oil company). Saudi Aramco is heavily dependent on its massive Ghawar oil field -- the world's largest oil field -- which produces slightly more than 50% of Saudi Aramco's total oil production. Gazprom, despite certain reports to the contrary, does not hold a single dominant gas field to the same degree as Saudi Aramco, as shown in Chart 1 and 2 above. This distinction is important in that the declines from Urengoy and other Gazprom fields can be more easily replaced going forward verses potential declines from one massive field, without another single, massive field ready to be brought online in the near future.

Further, Urengoy -- or any other Gazprom owned Gas field -- cannot be compared in size to Ghawar. In the natural gas world, only the Pars natural gas field, which is held by both

Iran

and

Qatar

, can be compared to Ghawar in terms of reserves (note that the Pars natural gas field is approximately 5 times larger from a reserve basis than Urengoy). Gazprom's Yamal Peninsula and Northern Siberian regions are major gas reserve regions as shown in Chart 4 below, but this region does not contain a single field where the majority of reserves are located:

Chart 4: Reserve Distribution of Gazprom's Gas Assets:

Source: Gazprom's website
Note: Dark blue areas represent undeveloped resources of natural gas under the Russian classification system for reserve reporting.

Conclusion:

Gazprom has provided projections and supporting evidence that address the extent of production declines at existing fields, and the timing and size of future field production rates. Gazprom has made a persuasive argument that Gazprom's three decade old fields -- Urengoy, Yamburg and Medvezhye are large in terms of territory -- each approximately 100 km in length -- allowing for development of subsections of each field, which, in turn, allows for some stabilization of natural gas production. Gazprom is currently allocating a high percentage of its current budget to the development of the Bovanenkovskoye gas field and the Yamal Peninsula, and has shown ability to bring new projects online as evidenced by the commissioning of Zapolyarnoye in 2001. Overall, the majority of evidence points to additional natural gas production stabilization and moderate growth for Gazprom. Note that this article did not cover economic costs of developing new fields -- including pay back periods under certain cost and natural gas price assumptions, and did not fully address the timing and risk of delays of production at the Yamal Peninsula.

Gazprom: Favored to Win a Majority of Russia's Future Oil and Gas Projects

2008-04-21T12:54:00.000-07:00

Newly elected Russian president Dmitry Medvedev is currently serving as Gazprom's (ADR: OGZPY) Chairman of the Board, and while Medvedev has served as Chairman of Gazprom prior to his election as President in March of 2008, the continued service of Medvedev appears to be an official endorsement (to say the least) for Gazprom's domestic position in terms of future hydrocarbon acquisitions.

Medvedev made statements in the past - - in mid 2007-- that Gazprom should be worth over $US1Trillion in terms of market capitalization -- currently Gazprom is worth approximately $US315Bn, which is approximately 13x estimated 2007 earnings. As Russia is the world's largest natural gas producer, with Gazprom producing approximately 90% of Russia's production, the current market value of $US315Bn is not excessive by any valuation measure.

Future Acquisition of Russian Gas and Oil Assets Likely to go to Gazprom:

It is probable that most new discoveries in Russia in both oil and gas will go to as a first priority to Gazprom, instead of its rival state owned firm, Rosneft, or privately owned Russian firms such as Lukoil. The intelligence consultancy Stratfor has commented in the past on Gazprom and Rosneft (Russian state owned oil firm)'s rivalry in terms of gaining oil producing assets (articles here and here). With Medvedev in power, the balance appears to shift to Gazprom verses Rosneft -- as analyzed by Stratfor in January of 2008.

Recently Gazprom has been moving to acquire assets from on TNK-BP, Russia's #4 oil producer, signing an agreement to buy its newly acquired Kovyka gas field for a below market value of $1Bn. It should be noted that TNK-BP is a huge oil producer, even as only Russia's #4 oil firm, producing approximately 1.4 million barrels per day of oil (out of a world's average of approximately 83 million barrels per day of oil). Russia is essentially even with Saudi Arabia in terms of daily oil production, sharing the top spot as the world's largest oil producer -- as both Saudi Arabia and Russia producing between 9 and 10 million barrels per day of oil. Much of Russia remains underexplored and as such, future reserve additions to Gazprom going forward appear very promising.

Sinopec 2007 Results

2008-04-11T11:50:00.000-07:00

Sinopec (SNP) announced 2007 year end results on April 6, 2008 with overall earnings up 5.5% to RMB 58.7Bn. In terms of segment results, most notable was the fact that SNP's Exploration & Production division's operating profits were lower by 22.8% to RMB 48.7Bn, even though oil output was up 2.3% y/y and natural gas output was up 10.2% y/y. This result is assessed to be mainly due to one time charges and events -- mainly due to a lower than market realized price for oil and higher depreciation charges -- that are not expected to negatively impact higher expected E&P segment earnings going forward with the realization of higher oil prices.

Chart 1: Sinopec Key 2007 Financial and Operating Results

	2007	% Change
Sinopec Earnings RMB Bn	58.7	5.50%
Segment Operating Income: (RMB Bn)
Exploration & Production	48.6	-22.80%
Refining	-13.66	n/a
Marketing	33.6	18.20%
Chemical	13.4	-8.00%
Operating Statistics:
Oil Produced mm bbl	291.7	2.30%
Gas Produced bcm	8.06	10.20%
Exploration Expense RMB Bn	11.1	39.10%
Crude Processed mn/d day	3.13	6.30%

Brief Commentary on SNP's Refining and Marketing Divisions:

Sinopec Marketing boasted higher profits, driven by expansion in the Marketing division's number of outlets and volumes of product sold, and in the case of the Refining segment, lower losses due to the higher average prices of gasoline in China for most of 2007 verses the world oil price. Sinopec's Marketing division is expected to have a record year in 2008 even as Sinopec's refining segment is expected to post pre-subsidy losses (Sinopec's forecasted refining losses are the subject of this previous article).

E&P Division: Received a Lower than Market Price for Oil in 2007

Sinopec did not receive a significantly higher oil price during the fourth quarter -- Sinopec's E&P division's overall realized oil price during the full year was approximately 3.1% lower in 2007 than in 2006. The rise in the oil price during 2007 mainly occurred in the 4th quarter of 2007, as shown in chart 2 below:

Chart 2: Increase in World Oil Price in 2007:

The rapid rise in the oil price during the 4th quarter of 2007 meant that Sinopec's short term contracts for oil sale resulted in a significantly lower realized oil price for the year.
Note that going forward, Sinopec should expect to realize higher oil prices as long as oil prices continue to remain elevated as contracts reprice based on market levels, which should more than offset the higher costs associated with extracting oil and gas as E&P divisions generally receive higher revenue proportionally with higher oil prices verses costs.

Sinopec's E&P's Division: 2007 Deprecation Charges:

Sinopec recorded one-time non-cash depreciation charges of RMB5.3Bn in the 2007 in Sinopec's E&P division, which would have comprised an estimated 37% of the drop in Sinopec 2007 E&P income (reference: see page 28 of Sinopec's 2007 Annual Report (large pdf warning).

Why was there a large increase in deprecation charges during the 4Q07 at Sinopec? Under successful efforts accounting rules for oil and gas properties, future costs of extracting oil and natural gas over the life of a company's existing oil and gas fields are estimated based on current costs, and a charge is taken if the extraction costs during the current year have risen (reference, see Section 3 under the Full Cost Method of this University of Cincinnati accounting guide)(Note that Sinopec uses Successful efforts accounting vs Full Cost, but the amortization charges for higher future costs is similar under both accounting methods). As extraction costs rose for Sinopec during 2007, due to high inflation in drilling, materials, labor, etc, an increase in deprecation as defined as for extraction costs for all future years was recorded in 2007. Note that Exxon and BP and most oil firms, for example, took higher oil and gas extraction deprecation charges in 2007 -- Exxon and BP took higher deprecation charges of approximately $US800M and $US1.2Bn in 2007, respectively. As Sinopec currently produces a higher percentage of its reserve base each year -- ie Sinopec's reserve life is lower than Exxon and BP's reserve lives -- Sinopec's depreciation charge impacted its earnings to a higher degree. Note however that Exxon and BP's E&P segments did not perform extremely well in 2007 due to the same drivers that drove (temporary) lower operating profit performance in Sinopec's results, which will be explored below.

How Did Other Integrated Major's E&P Segments Perform in 2007?

Overall, the Integrated Major E&P divisions did not perform strongly as a group in 2007 in terms of operating income and production, mainly due to higher depreciation charges due to higher lifting costs, and lack of realization of higher oil prices as shown in the chart below. It is also noted that oil production (excluding natural gas production) was not strong for the Integrated Oil major universe in 2007 as a whole -- Sinopec's results of +2.3% for oil production growth actually placed it in the higher half of production growth for integrated majors. However, note as the realized price continues to stabilize at a higher level in 2008, reported earnings should be stronger in 2008 verses 2007 for the Integrated major's E&P divisions as a whole.

Chart 3: Selected Integrated Majors' 2007 E&P Segment Key Operating Metrics

in $US Bn	2007	% Change
Exxon Mobil
E&P Operating Income	26.497	1.01%
E&P Depreciation	12.25	7.30%
Oil Liquids Production*	2.6 mbpd	-1.90%

BP plc
E&P Operating Income	26.938	-10.10%
E&P Depreciation	7.72	18.20%
Oil Liquids Production*	2.5 mbpd	-2.10%

Royal Dutch Shell
E&P Operating Income	14.686	1.00%
E&P Depreciation	9.338	7.70%
Oil Liquids Production*	1.8 mbpd	-6.70%

Conoco Philips
E&P Operating Income**	4.615	-53.40%
E&P Depreciation	8.298	13.90%
Oil Liquids Production*	0.854 mbpd	-12.10%

Chevron
E&P Operating Income	14.816	12.70%
E&P Depreciation	8.708	16.01%
Oil Liquids Production*	1.7 mbpd	0.08%

Total
E&P Operating Income	29.26	-3.89%
E&P Depreciation	8.14	7.30%
Oil Liquids Production*	1.2 mbpd	2.30%

Sinopec
E&P Operating Income	6.59	-22.80%
E&P Deprecation:	2.45	40.60%
Oil Liquids Production*	0.8 mbpd	2.30%

* "Oil Liquids Production" is defined as oil and natural gas liquids production, and excludes natural gas production
** Conoco Philips recorded a write down of their Venezuelian assets in 2007, which was the main driver of COP's lower E&P Operating Income

Note: Other SNP E&P Division Costs: Dry Hole Costs and Special Taxes Are Not Expected to Significantly Impact Sinopec's Earnings Going Forward:

Higher exploration expenses, in particular, dry hole expenses -- defined as drilling that did not result in economic quantities of oil and gas) of RMB 3.1Bn, higher general costs in the E&P division of RMB3.6Bn y/y and higher special oil taxes of RMB 2.5Bn y/y also accounted for the change in 2007 E&P earnings (note that the special oil tax are mainly enacted by the Chinese central government to gain revenue to repay subsidies to Sinopec's refining division, so can be viewed as a realignment of revenue). Dry hole expenses -- costs associated with unsuccessful drilling -- are not high for a large integrated oil major, as for example, Chevron announced dry hole expenses of $US507M in 2007 (equivalent to approximately RMB 3.8Bn). Note that Sinopec still has not reported its massive Puguang Gas field in its reserves statement, so drilling and exploration costs associated with this field can be capitalized in 2008 -- the dry hole expense indicates that outside of Puguang, several wells drilled in 2007 were unsuccessful. Note that Sinopec's dry hole expenses a Drilling in 2008 with the Puguang field will be reported as more successful. But overall, in assessing the cost and revenue drivers of lower income, the largest contributor of the lower E&P division's operating performance is assessed to be the lower realized oil price.

Notes on Alternative Energy

2008-04-08T13:12:00.001-07:00

Most analysts expect alternative energy to continue to attract significant capital going forward -- one example of this forecast is the 2008 Prediction of Venture Capital Trends by the National Venture Capital Association (NVCA). The question comes to mind: how is alternative energy defined? A definition search on Google provides several definitions, most of which define alternative energy by energy source. Below is a simple chart on alternative energy based on source for the benefit of interested readers.

The key to the chart is -- in the author's opinion -- **very promising * somewhat promising "?" not enough information "??" skeptical and ___ (underlined) don't believe will work, as defined as a positive return on energy invested by source and initiative. Rational for the author's opinions are not presented (perhaps will be presented in future posts). There are a few firms listed under each category but these lists are very incomplete.

A few notes on the overall alternative energy industry: first, detailed projections are very important in assessing the economics of each initiative. For example, in the book Wind Power by Paul Gripe -- 700+ pages on wind energy (and extremely interesting reading) -- much of the viability of wind power is expressed location by location, dependent on multi-year assessments of wind patterns and cost drivers. This sort of analysis does not translate easily into a short article in a newspaper or magazine.

Second, in all areas of the chart above, -- somewhat related to the first point concerning projections -- the initiatives have relatively high capital costs. Many power initiatives are described in investor prospectuses as "cost per MW:"" -- with $1000 per MW as a very economical standard for a large scale power plant. This cost translates to a billion dollars for a 1000MW power plant in coal, solar, nuclear, etc.

Lastly, the timing of the ideas appears to be generally of a longer time frame than is customary in information technology and other venture capital business areas - for example, in Nuclear technology, according to the publication Nuclear Engineering International: "2020 is right around the corner" (written in early 2008).

Gauging Sinopec's Refining Losses

2008-04-04T12:40:00.001-07:00

Losses at Sinopec's refining division have been driven by the high world market price of oil and a fixed price for gasoline within the domestic Chinese market. It is noted that Sinopec presents its financial results in an unusual manner -- reporting its refining activities in a separate division from its marketing (gasoline stations and pipelines) activities, in an apparent effort to show losses, in order -- it is argued here -- to influence China's Ministry of Finance for direct subsidies and China's central government for price increases in the domestic price of gasoline. If Sinopec's refining and marketing divisions were kept together, the company would not have shown losses in this division in any year since 1997, without subsidies (up until 2006, the last date for which year end segment data is available). Future increases in the world price of oil is likely to be met with some increases in the Chinese domestic price of gasoline -- according to statements from China's National Development and Reform Commission (NDRC) -- leading to most likely manageable losses at Sinopec's refining division. Future higher world prices for oil and natural gas will benefit Sinopec's underestimated and rapidly growing Exploration and Production division.

Sinopec Segment Analysis:

Sinopec has been historically consistently profitable in all divisions except for refining. Sinopec for financial reporting divides its overall operations into 4 divisions:

1. Exploration & Production -- ownership and production of reserves of oil and natural gas,
2. Refining -- large scale chemical conversion of crude oil to premium petroleum products,
3. Marketing --operation gas stations and pipelines and
4. Chemicals -- production of petrochemicals from oil and natural gas feedstocks.

Note that Sinopec's largest division by profitability is its E&P Division -- as is the case with almost all integrated majors -- by operating profits, which accounted for approximately 75% of operating profit in 2006 (the last date for which information is available as of early 4/08). It is generally standard practice within the integrated oil universe to present financial results in three segments, with refining and marketed combined -- for example, Exxon Mobil reported its 2007 results by segment in as "Upstream" (E&P), Downstream (refining and marketing and pipelines) and "Chemicals." Further, Sinopec's domestic rival firm, PetroChina, combines its Refining and Marketing divisions for financial reporting purposes -- and has not shown a loss in its Refining and Marketing division up until 2006 and has not received state subsidies for refining. The following chart shows division operating profit, without subsidies, for Sinopec's reporting divisions as far back as 1997 (note that at the date of the writing of this article (4/08), the 2007 20-F for Sinopec is not available, so up to 2006 data is shown only).

Chart 1:

Source: Sinopec Annual Reports Note: segment operating profit does not include state subsidies of RMB 10Bn in 2005 and RMB 5Bn in 2006 to SNP's refining division

The chart above with reported Sinopec financial statements looks alarming in terms of losses in the refining division, however, if refining and marketing are included in one segment, Sinopec has not reported losses in the the refining and marketing division since 1997, as shown in the chart below:

Chart 2:

Note: Results above are presented without state subsidies of RMB 10Bn in 2005 and RMB 5Bn in 2006 -- and an estimated RMB 12.5Bn in 2007 (as segment data for Sinopec is not available at the date of this writing).

Chart 2 above shows several interesting facts. First, losses in Sinopec's refining and marketing division have not historically occurred, despite several media reports within China and outside of China that have predicted that refining losses would "wipe out profits for Sinopec as a whole." These reports predict future losses for Sinopec, -- not historical -- so future losses will be analyzed in the next section. As a second interesting fact, it is noted above that Sinopec's Exploration & Production division is the major source of operating profits and value for the firm as a whole. It would not be too far off in the author's opinion to state the following: interested investors in Sinopec should review SNP's Exploration & Production division first and foremost with regards to future valuation, and significantly subordinate in terms of profitability or potential losses Sinopec's refining and marketing and chemical divisions.

Estimates of Future -- 2008 and Onward -- Losses in Sinopec's Refining Division:

Goldman Sachs Sinopec Analyst analyst Kelvin Koh in a March 17, 2008 report titled: "China Petroleum and Chemical: How Bad is the Refining Squeeze?" forecasted losses of RMB 20Bn for Sinopec's refining division in 2008, after subsidies of RMB 25Bn -- so total refining losses of RMB 45Bn. Koh estimates that Sinopec's refining division lost between RMB 17.8Bn and RMB 18.4Bn in the first quarter of 2008, partially offset by approximately RMB 7.4Bn of subsidies in the first quarter of 2007. The report did not mention Sinopec's marketing division or provide segment calculations -- and did not mention potentially offsetting profitability at Sinopec's Marketing segment.

Sinopec has publicly renounced statements that it its refining segment would suffer huge losses with high oil prices -- these reports have been driven by Sinopec Vice Chairman Zhou Yuan's comments on March 7, 2008 that Sinopec is losing RMB 2000 for every ton of crude oil that it refines. A simple calculation that shows that Sinopec refined approximately 150M tons of crude oil last year would result in an incredible refining loss of RMB 300 Bn for the full year 2008 at oil above $100, from Zhou Yuan's estimates, which is clearly unprecedented in Sinopec's history. Sinopec on March 14, 2008 stated that "All such information [concerning refining losses] is factually incorrect and misleading." (from Platts Commodity News, "Sinopec Refutes Report on Possible 1H 2008 Loss, March 14, 2008). However, reports of massive losses in Sinopec's refining division continue to circulate, including an article from China Knowledge Press on April 2, 2008 titled: "Sinopec's Refining Unit Suffers Huge Loss in First 2 Months" which stated Sinopec as a whole "booked an amazing loss of RMB 1.37Bn" in the first 2 months of 2008. However, Goldman Sachs analyst Koh has called these reports of overall Sinopec firm losses "factually incorrect."

Which estimate of losses for 2008 and beyond should the investor trust? As a rule, Investment Banks tend to be more well informed than other commentators, so Goldman Sachs' estimate of RMB 45Bn loss pre-subsidy to RMB 20Bn loss post subsidy is more likely to be correct than other estimates. As Goldman has not published Sinopec's Marketing division's expected profitability for 2008 to the author's knowledge, a very rough estimate will be presented here. If we assume continued operating profits in the RMB 30Bn range in 2008 as in 2006 for SNP's marketing division -- likely the profits will be higher due to expansion in the number of outlets and higher levels of product sold -- then refining and marketing combined will show a manageable loss for the year (RMB 15Bn) without subsidies and will be show a net operating profit (RMB 5Bn) with the assumed RMB 20Bn subsidies (again with the conservative assumption that marketing's operating profits do not grow year to year). Note that this calculation does not include Sinopec's E&P division, which had over RMB 60Bn in operating profit in 2006, when oil prices were at approximately $60 -- with oil prices at $100, Sinopec's E&P division's operating profits should increase substantially.

Is Sinopec at Risk due to the Fact that Sinopec's Refining Division has to Source the Majority of its Oil from Outside (non-Chinese) Sources?

Sinopec's Exploration & Production segment supplies only approximately 21% of the crude oil supplied to Sinopec's refining division -- and crude oil sourced from Chinese firms (PetroChina and CNOOC and Sinopec combined) supplied 30% of Sinopec's refining divisions throughput. However, it should be noted that this ratio of company supplied crude oil to refining products is closer to the norm than for integrated oil majors than the exception. According to Exxon Mobil's 2007 10-k, Exxon Mobil produced approximately 2.6M barrels per day of oil and natural gas liquids (excluding equity interest oil production) and refined approximately 5.7M barrels per day of crude oil, for a ratio of Company supplied crude oil of 45%. Chevron produced 460K barrels per day in 2007 of crude oil and refined approximately 1.8M barrels per day of oil, translating to a ratio of company supplied oil of approximately 26%.

Company	Company Supplied Oil to Refining Segment*
Petrobras	110%
PetroChina	106%
BP	87%
Exxon Mobil	45%
Chevron	26%
Sinopec	21%
Conoco Philips	14%
Royal Dutch Shell	10%

* This ratio is calculated as the crude oil and liquids production of the company -- excluding natural gas production -- divided by the company's refining throughput for the last reported financial year

It is standard practice in the oil industry that Exploration & Production divisions are segregated from refining divisions for financial reporting purposes and refining divisions are charged a market price for oil, even if the oil is sourced from the parent company's E&P division. As such, the exploration & production division of any oil major should report record profits with higher oil prices, regardless of how the refining and marketing segments perform. If there is a higher ratio of non-parent Company sourced oil, losses in the refining division could more than offset overall company profitability. (note that this fact stresses that a large exploration and production division is the key indicator of a profitable integrated oil major). One could paraphrase, that a larger ratio in Chart 3 above shows that the respective integrated majors have higher percentages of revenues and income from their E&P divisions verses their downstream divisions.

In the case of Sinopec, the potential for losses in refining are partially mitigated by the fact that China has been raising the price of gasoline year to year with higher oil prices, although not as high as the US and EU, but at a faster rate than Malaysia and Indonesia and several other countries. China's National Development and Reform Commission (NDRC) released an outline in February 2007 of a more market-based formula for gasoline pricing based on a basket of international crude prices, with the aim of bringing China's domestic gasoline prices more in line with western levels. ("Outline Emerges of China's Freer Products Price Formula" 2/5/07, International Oil Daily) According to the International Oil Daily, NDRC 's process of setting gasoline prices appears to be opaque, but China appears intent on allowing continued rises in the price of gasoline going forward, in order to support its refining industries and encourage economical use of fuel, balanced with economic considerations.

Further, Sinopec is also likely to continue to subsidize Sinopec, which is the consensus view of investment banks such as UBS and Goldman. Note that many countries around the world, including Russia, many Middle Eastern countries, India, for example keep domestic gasoline prices artificially low to benefit their economies, and also have a practice of subsidizing their domestic oil refining companies.

Note: Exploration and Production is Unusually the Major Source of Value for Most Integrated Oil Companies:

Upstream divisions generally comprise the majority of profits for most integrated oil companies, and Sinopec is no different in this regard. For example, Exxon Mobil's exploration and production segment comprised 65.3% of total Exxon net income in 2007, according to Exxon's 2007 10-k. It is argued here that Sinopec should be viewed as an typical integrated oil major, with an emphasis on upstream assets. With this idea in mind, how attractive is Sinopec's E&P division?

Quick Overview of Sinopec's Exploration & Production Segment:

Sinopec's Exploration and Production division is large currently with 3.7Billion Barrels of proven oil and natural gas reserves (87% oil, 13% natural gas) at the end of 2006-- in comparison ConocoPhillips reported 3.1 Billion Barrels of proven reserves including affiliates at the end of 2007. Further, Sinopec's exploration and production division is likely to almost double reserves at the end of 2008 due to inclusion in SNP's reserve statement of the very large Puguang natural gas discovery in China's Sichuan province. Sinopec expects to maintain high international upstream growth in states such as Iran, Angloa, Australia and Venezuela.

The fact that Sinopec's upstream assets are sizable and likely to grow significant is probably a surprise to many investors who are not familiar with the Company. Sinopec (SNP) is commonly viewed by investors as primarily a downstream oil company, with profitability mainly dependent on refining, petrochemicals and marketing. This perception stems to a large degree from the historical (pre-1998) division of China's oil industry -- with the restructuring in 1998, Sinopec took over previously CNPC's southern oil fields, including the Shengli oil field -- the second largest oil field in China -- while CNPC took ownership of previously Sinopec's northern refining and marketing operations -- which, incidentally, were and are less efficient and technologically advanced than Sinopec's southern refining divisions.

Sinopec as mentioned in a previous article has stated that it will obtain overseas assets from its parent company, Sinopec Group -- the most attractive of these assets that is upcoming in the short to intermediate term is the Yadavarian Oil field in Iran with reserves of over 3 Billion barrels of oil, which is currently undeveloped. Sinopec is active in Angola, Venezuela and Russia, among other international locations. Further, Sinopec discovered the largest gas field in China's history, the Puguang field in Sichuan, with approximately 2-3 BBOE of natural gas, and further domestic exploration within China is promising. A fuller discussion of Sinopec's Upstream assets and prospects will be upcoming in a future article.

Conclusion:

Apprehension on the part of investors towards future losses in Sinopec's refining division has resulted in a relatively low market capitalization for Sinopec of approximately $US85Bn -- a low valuation by most measures for a major National Oil Company. It is likely that these fears are overblown due to the unusual segment reporting and also underestimation by investors of reserve and production growth at Sinopec's Exploration & Production division.

Correction: Sinopec and PetroChina Likely to Participate in China's Overseas Quest for Oil

2008-03-28T11:59:00.000-07:00

The previous article concluded that it was not very likely that Sinopec and PetroChina would participate in "China's Overseas Quest for Oil." However, this conclusion should be corrected as, from further analysis, it appears that that both PetroChina (PTR) and Sinopec (SNP) will participate in China's overseas oil quest, based on senior management's comments, as discussed below.

Sinopec's Comments Concerning Overseas Oil and Natural Gas Acquisitions:

Sinopec management has made several comments that indicate that overseas properities acquired by Sinopec Group would be transfered to the publicly listed subsidiary, Sinopec Corp (SNP). As a first example, in the First Quarter 2006 earnings conference call, the Sinopec Analyst for Citigroup Tom Hilbolt asked if Sinopec Corp would receive rights to Sinopec Group's international properties. The response by Zhang Jiaren , Senior Vice President of Sinopec Group indicated that Sinopec Corp would receive rights to overseas properties:

"As for the Sinopec Corp we haven't made our steps in the international acquisition of E&P assets, however as soon as the assets acquired by the parent company is generating stable return and risk is minimized the listed company or Sinopec Corp has the priority to buy the assets from the parent company."

More recently, a similar comment was made during the Third Quarter 2007 Sinopec Conference Call, by Dai Houliang, CFO of Sinopec Group, in a response to a question by Credit Suisse analyst Prashant Gokhale concerning Sinopec Group's ability to transfer international assets to Sinopec Corp.

"With regard to the purchase of overseas assets of the parent company, Sinopec Corp has the first right of refusal to purchase the overseas assets of the parent. But currently we have no concrete plan or proposal on that. "

In the last few months, Sinopec appears to be aiming to increase its activity in acquiring international assets. According to the article "CIC Intends to Increase Investment for Sinopec" from the January 18, 2008 issue of the China Chemical Reporter, China Investment Corporation plans to assist Sinopec Corp in acquiring overseas assets, and specifically:

"A senior manager of Sinopec Corp. had ever expressed that the company intends to increase an investment in oil upstream business, including acquiring oil assets in overseas markets from its parent Sinopec Group. Sinopec Corp. has set its strategy to boost its oil upstream business and focus on integrated businesses with global leadership positions."

PetroChina's Comments Concerning Overseas Oil and Natural Gas Acquisitions:

On March 20, 2008, as reported by the Financial Times, PetroChina announced plans to acquire 50% of parent company CNPC's CNPC Exploration and Development, which holds most of the CNPC's oil fields abroad -- but does not include CNPC's Sudan assets, which are the subject of a campaign (Harvard, EU) to divest holdings of PetroChina by Western investors. Further, Jiang Jiemin, CNPC's and PetroChina's chairman, announced on March 20, 2008, that

"Our company now has the mission to be an international integrated energy company. We need to speed up development of overseas businesses. For our international business, the strategy is that for the existing oil fields we will stabilize production and enhance exploration for new discoveries. As for acquisitions, we will take every opportunity."

CNPC has already set a president for transferring international assets to the publicly listed subsidiary, PetroChina, as CNPC transfered 67% of its acquired PetroKazahkstan assets to PetroChina in 2006 for $US2.76Bn. The purchase price can be considered a transfer of assets in that in 2004, CNPC paid $US4.18Bn for 100% of the assets of PetroKazhkstan, so the purchase price paid by PetroChina to CNPC is actually slightly lower proportionally verses the originally purchase price by CNPC in 2004 (and it is likely that the oil assets would be worth more in 2006 verses 2004 due to the higher price of oil, which probably more than offset any depletion during the period).

Conclusion:

The net effect of the right of Sinopec and PetroChina to participate in China's overseas oil acquisitions is to make the Sinopec and PetroChina more attractive as equity holdings, as the ability to move internationally is expected to expand Sinopec and PetroChina's reserve base substantially. Note that the author will follow up with an analysis of Sinopec and PetroChina as equity investments.

CNOOC: Likely to Benefit from China's Overseas Quest for Oil, PetroChina -- Maybe, Sinopec -- Maybe Not

2008-03-20T10:21:00.000-07:00

A compelling rationale for investment into China's three major oil firms is the ability to participate in China's overseas acquisition of oil and natural gas properties. "China's Quest for Overseas Oil" -- the title of a 2007 Brookings Institution report -- has been driven by China's voracious appetite for energy, and has been aided by Chinese state sponsorship and the relatively favorable attitude of many oil rich countries (particularly Middle Eastern countries) towards China verses towards the West.

Of the three listed Chinese Oil majors, PetroChina (PTR), Sinopec (SNP) and CNOOC Ltd (CEO), CNOOC Ltd is the Chinese firm most likely to directly participate in China's overseas oil quest, due to the fact that PetroChina and Sinopec's parent companies, CNPC and Sinopec Group, respectively, have complex, potentially confusing corporate structures, the net result of which removes most international oil and gas acquisitions from direct ownership of their publicly listed subsidiaries. Both PetroChina and Sinopec were set up and listed internationally in 2000 by their parent companies, CNPC and Sinopec Group, with the express purpose of developing mainly the domestic upstream and downstream sectors of mainland China. In contrast, CNOOC Ltd was expressly set up with the purpose of developing both domestic (Chinese) offshore and international properties. China National Offshore Oil Corporation (unlisted, the parent of CNOOC Ltd) holds CNOOC Ltd as its exclusive offshore exploration and production company. The history page of China National Offshore Corporation's website has more detail on this organizational structure. China National Offshore Oil Corporation also holds three other firms -- China Oilfield Services Ltd., CNOOC Engineering Ltd., and China BlueChemicals Co., Ltd -- in addition to CNOOC Limited, but CNOOC Limited holds the exclusive ability to develop and produce offshore oil and gas fields.

As such, CNOOC Limited already expressly owns oil and gas properties in Indonesia, Australia and Nigeria, and potentially -- in the author's opinion likely -- could be involved in Iran's massive Pars natural gas field, and further future international growth is likely. In contrast, the publicly listed Sinopec does not directly own any international oil and natural gas fields, while PetroChina only owns one major international oil field, the oil field assets of PetroKazakhstan, which it bought from its Parent, CNPC.

Relationship Between Sinopec Group (Parent) and Sinopec Corp (SNP, listed firm):

Sinopec Group's organizational structure can be found on its website. Sinopec specifically lists as the "Non-Listed Part" several subsidies, and probably the most important subsidiary for internationally minded investors, Sinopec International Petroleum Exploration and Production Corp (in the lower right hand corner), which is listed as a subsidiary that is expressly "non (publicly) listed." Sinopec International Petroleum Exploration and Production International Corporation has inked natural gas deals in Saudi Arabia, offshore oil deals in Angola and Australia, all of which are very promising, but due to the current corporate structure . Sinopec Group has signed an agreement with Iran for the development of the massive Yadavaran oil field (over 3.2 billion barrels of oil recoverable), but this most likely (90% probability, in the author's opinion) will not involve the listed company, Sinopec Corp, due to the fact that it is internationally based.

Relationship Between CNPC (Parent) and PetroChina (PTR, listed firm):

A similar relationship exists between CNPC and PetroChina as does that of its Southern neighbor, Sinopec Group and Sinopec Corp. CNPC directly acquires and controls oversees oil and gas properties -- the most infamous being the Sudan oil fields, which are not listed with the subsidiary firm, PetroChina. (note that if one searches PetroChina's 2006 20-F, there are no mentions of the Sudan since these oil and gas properties exist at the parent's level). To date, only CNPC has transfered only one major international oil property (PetroKazakhstan's Kuzmol oil fields) to PetroChina, through an acquisition by PetroChina, for which PetroChina had to pay CNPC over $US4Bn. It is unclear how many more properties CNPC transfered (or more exactly, will sell) to the listed PetroChina in the future.

The low level of participation by Sinopec and PetroChina in International areas does not mean, of course, that their parent firms, Sinopec and CNPC are not active in international acquisitions -- Sinopec Group and CNPC are very active internationally, as note that NPR has listed 74 major deals by CNPC and 32 deals internationally (reference: page 15 of this report by NPR). Many of the deals are of megaproject size and would be very attractive to investors. But it is not clear that investors into the listed firms Sinopec and PetroChina will benefit from such acquisitions. In the author's opinion, it is more likely that CNPC will sell overseas assets to PetroChina, as CNPC has already done so with its PetroKazakhstan assets -- to put the probability of such future sales (in the author's opinion only): 50%. Note further, that PetroChina will have to pay a price for the acquisition of the assets from CNPC -- although such an acquisition will likely be pay with by low interest loans from the Chinese government. Sinopec lacks a precedent of transfering overseas assets from its parent, Sinopec Group, so the author's opinion of the probability of the transfer/sale of assets would be approximately 20%.

Does the low probability of PetroChina and Sinopec Directly Participating in International Oil Acquisitions make them good short candidates?

The in author's opinion, no. Both PetroChina and Sinopec have substantial domestic oil and gas reserve bases -- although PetroChina's reserve base is approximately 5x the size of Sinopec Corp's reserve base, at approximately 19.0 Billion and 3.7 billion barrels, respectively) and huge domestic chemical, marketing and refining businesses. The refining businesses do have issues in that the domestic price of gasoline (Petrol) is fixed and therefore the refining segments are showing losses, but overall the businesses have shown very strong profit growth over the past 8 years, as the price of oil has increased. The Chinese government is also expected to raise the domestic price of petrol and offer subsidies to partially offset refining losses. Reserves at Sinopec Corp are expected to approximately double over the next year as Sinopec brings online its very large Puguang Gas field in southern China -- the largest gas field discovered in China's history -- with an estimated 2.0 to 3.0 billion barrels of oil equivalent of recoverable reserves.

Further, both PetroChina and Sinopec are unusual in the integrated oil majors universe in that they are both expected (with the publication of their 2007 20-F's) to be selling very close to their after-tax Standardized Measures, which is the future expected value of cash flows from sales of oil and gas, as required by FASB 69. Typically, integrated oil majors sell at large premiums -- between 100% to 300% -- to their standardized measures, due to the fact that the standardized measure does not take into account probable and possible oil reserves, and/or future discoveries of oil and natural gas, and does not account for other divisions (downstream) (although it is possible that the market is assuming huge losses within Sinopec and PetroChina's refining divisions, although a more thorough analysis of the company's refining divisions is the subject of a future article). Note that the author will publish the standardized measures once the 2007 20-F's have been published.

TSX Group -- An Undervalued Takeover Candidate

2007-12-27T15:12:00.001-08:00

TSX Group, the stock exchanges group of Canada, is the 7th largest stock exchanges group in the world by market capitalization of listed firms. TSX Group is attractively priced, with positive operating prospects, and therefore represents an attractive acquisition candidate. The exchange industry is rapidly consolidating, driven by the competitive advantage of larger exchanges vis-a-vis smaller exchanges in terms of capital raising for listed firms. Further, exchanges exhibit high operating leverage, and therefore mergers make sense from a financial and competitive standpoint. These factors make TSX Group a compelling long term buy at the the time of the writing of this article (early 1/08)

TSX Group Overview:

TSX Group holds the major stock exchanges of Canada, including the Toronto Stock Exchange, the Vancouver Venture Exchange, NGX, the main Canadian natural gas exchange, and, with the merger announced at 12/07, the Montreal Exchange. TSX Group holds strong positions in listed mining and oil and gas firms, as TSX is the largest exchange for mining as defined as the combined market capitalization of listed firms, and ranks #1 of all stock exchanges in terms of the total number of listed oil and gas firms.

TSX Group accrues income mainly from trading fees, listing fees and market data fees -- trading revenues has been the largest segment by revenue, representing 41% of TSX's 9 months 2007 revenue, while Listing fees (or "Issuer Services") comprised 32% of revenues and market data fees contributed 27% of the group's 9 months 2007 revenue. Note that TSX does not break out margins by operating segment, so trading appears to be the group's most significant segment in terms of profitability. All three of TSX Group's operating divisions grown at a high rate over from 2002 to 2006, with a compounded annual growth rate (CAGR) of revenues of 17%, and an EPS CAGR of 34%.

1: TSX Group Historical Financial Performance from 2000 - 2006

In $C 1,000’s	2006	2005	2004	2003	2002	2001	2000
Total Revenue	$352,847	$287,847	$295,553	$233,680	$215,885	$179,952	$218,090
% Increase	23%	-3%	26%	8%	20%	-17%	n/a
Net Income	$131,524	$103,353	$98,397	$76,353	$53,762	$30,153	$76,910
Net Margin	37.3%	35.9%	33.3%	32.7%	24.9%	16.8%	35.3%

The Trading segment has demonstrated the fastest growth of TSX's three operating segments, growing at a CAGR from 2002 to 2006 of 21%, verses a CAGR of 19% for Issuer Services and 12% for the Market Data segments over the same period.

Trading volumes have increased due to a combination of increased trading by funds -- possibly (probably) hedge funds -- and day trading by smaller investors -- both of which, in turn, have been driven by the expansion, of the overall TSX index. TSX has instituted price cuts in its trading -- mainly in an effort (in the author's opinion) to enhance competitiveness vis-a-vis a proposed alternative trading system (ATS) backed by the major Canadian Banks (note that the risk of an ATS to TSX Group will be discussed in further detail below). However, the large rise in trading volumes, from an average of approximately 100 million shares traded per day in 2001 to an average of approximately 380 million per day at the end of the 3Q 07, has more than offset pricing declines.

2:

Going forward, trading volumes will be a major driver of income for TSX Group, which will be driven by fund activity. It is possible that TSX Group may stabilize its pricing for trades, depending on its competitive position to the proposed ATS system -- this issue is dependent to a degree on the success of its new trading technology and resistance of customers to trade on alternative systems. (again this issue will be explored in more detail below).

In the Issuer Services segment, revenues have been driven by the growth in the market capitalization of existing issuers and a number of new (mainly resource based) Canadian firms that have gone public and/or raised additional capital over the past five years. Issuer services fees are based on new listings and a fee based on the market capitalization of the listed firms. The Canadian economy and stock and commodity markets, have done well, this segment has benefited. The market data segment has been driven by increased numbers of subscribers -- mainly financial firms and funds -- to its real time market data services, from under 100,000 in 2002 to 155,000 in 2007.

Valuation Comparison of TSX Group to Other Exchanges:

A chart of the P/E's and growth rates of many of the worldwide exchanges is included in my other article on the Public Exchange Industry, which can be found here. The data in that article is not too dated at the time of the writing of this article, and, in summary, currently, the P/E ratio of TSX is very reasonable at 23.6x, compared to 37.5x for NYSE Euronext, 60.7x for the NYMEX and approximately 100x for the Hong Kong Exchanges Group. NYSE Euronext's earnings are forecasted to increase at a CAGR of approximately 23.6%, and NYMEX's earnings are forecasted to increase at a CAGR of 40.8%, both according to Yahoo finance. Note that author has not been able to find earnings projections for the TSX Group or the Hong Kong Stock Exchange, but as noted above, 5 year historical EPS CAGR for TSX is 34%.

Valuation Comparison of TSX Group to ASX Limited:

Comparisons of Valuation with ASX Limited (Australian Stock Exchange) appears to be most appropriate on a comparable basis, due to the fact that Canada and Australia have similar economic structures (commodity and financial institution based economies), political systems and demographic situations. As shown in the chart below, ASX sells at a significant premium to TSX Group, as ASX is valued at approximately $US9.45Bn, while TSX Group is valued at approximately $US3.5Bn. The Canadian GDP is approximately $1.18 Trillion, compared to the Australian GDP of $675Bn (according to the CIA World Factbook), while Canada has a population of approximately 33.4 million people compared to Australia's 20.4 million. Based on these metrics, the discount of TSX Group compared to ASX Limited appears unjustified.

in $US	Market Cap	P/E	P/S	Firms on Exchange Capitalization*	Average Daily Volume**	3 Year EPS CAGR
TSX Group	$3.5Bn	23.6x	9.6x	$2.1Trillion	400M	34%
ASX Limited	$9.45Bn	36x	19.0x	$1.44Trillion	194M	25%

* Firms on exchange capitalization is defined as the sum of the market capitalizations of the equities listed on the exchange.
** Average daily volume is defined as the number of equity shares only traded per day -- for TSX Group, this measure only includes the Toronto Stock Exchange
Note that Australian dollars and Canadian dollars are translated at an exchange rate of $Aus/$US of 0.90 and $C/$US of 1.00.

Valuation of TSX Group Compared to Recent Exchange Acquisitions:

Recent Merger activity within the Exchange Industry has priced acquisition targets at levels above TSX Group's current market valuation on a price to earnings basis, implying a premium purchase price to current levels if there is a takeover attempt of TSX. In Chart 2 below, valuations for the recent mergers of OMX (by NASDAQ), the Italian Borse (by the London Stock Exchange), the Montreal Exchange (by TSX Group) and the Takeover of the Philadelphia Stock Exchange by NASDAQ.

3: Valuations of Recent Acquisitions in the Exchange Industry:

Acquired Firm	Acquirer	Acquisition Price (in $US)*	Price/Earnings (Historical)	Price/Revenues	Date
OMX	NASDAQ	$4.76Bn	28.2x	7.24x	Announced 5/07
Italian Borse	London	$3.08Bn	33.0x	7.52x	Announced 6/07
Philadelphia	NASDAQ	$652M	negative	5.74x	Announced 11/07
Montreal	TSX Group	$1.3Bn	43.3x	15.36x	Announced 12/07
TSX Group Comparison		Market Capitalization**	Price/Earnings (Historical)	Price/Revenues
	TSX Group	$3.52Bn	23.6x	9.6x

* Acquisition price, when priced in stock, is adjusted for the market value of the stock at early 1/08.
** Market Capitalization and other ratios of TSX Group do not include the Montreal Exchange.

The average p/e ratio of the 4 acquired firms above (price to earnings ratio defined as the purchase price divided by the historical earnings of the acquired exchange) is 33.8x, which is 43% above the current p/e ratio of the TSX Group (pre-merger with the Montreal Exchange). The price to revenues of the acquired exchanges is lower than TSX Group in 3 of the 4 acquisitions listed above, but note the price to earnings basis is the more appropriate measure to value exchanges, due to differing cost structures between firms -- TSX Group's margins are increasing with higher revenues, due to operating leverage.

Rationale for Acquisitions in the Exchange Industry:

A good discussion of the flurry of merger and acquisition activity in the exchange industry can be found at Knowledge@Wharton. Exchanges are combining to take advantage of economies of scale -- trading technology can be applied to acquired exchanges, lowering overall operating costs, which translates to higher margins with higher revenues. Further, from a competitive standpoint, larger exchanges offer more choice to financial customers, as customers can trade across a larger, more diverse set of investment options, and, with mergers of exchanges located in different countries, across international boarders. Larger exchanges also offer potential listed firms a larger venue in which to raise capital, and higher liquidity for their shares, with tighter bid and ask prices. Additionally, larger exchanges pose stronger competitive advantages vis-a-vis brokerages and investment banks, which have complained that exchange industry fees are getting too high -- so potentially are exploring other trading options for shares and other financial instruments -- alternative trading systems -- that do not rely on the exchange to bring buyers and sellers together. With an large, established exchange, it is more difficult to "circumvent" this exchange verses a smaller, regional exchange.

TSX Group 9 Months ended 9/30/07 Update:

TSX Group posted EPS increases of 22.7% to $C1.73 per share for the first 9 months of 07 compared to the 9 mo 06, on revenue increases of 19.7% to $C313.5M. Net margin increased slightly to 37.7% the first 9 months of 07 from 36.8% for the equivalent period in 06. As shown in the table below, the increase in net income was driven mainly by listing fee increases, and, to a lessor extent, by trading and market data revenue increases.

4: TSX Group 9 Months 2007 Operating Performance:

	9 Months Ended 9/30/07	9 Months Ended 9/30/06	% Increase

Trading Segment Revenues:	$C126.5M	$C110.8M	14%
Trading Segment Volume: (# shares)*	109.4Bn	88.4Bn	23.7%
Issuer Services Segment Revenues:	$C97.2M	$C80.2M	21%
Listed Companies (Number)*	3,908	3,820	2.3%
Listed Companies (Total Market Cap)*	$C2,215Bn	$C1,952Bn	13.5%
Market Data Revenues:	$C81.9M	$C63.0M	30%
Market Real Time Data Subscribers:	155,000	134,000	15.7%

* Trading Segment volume and market data includes the Toronto Stock Exchange and the TSX Venture Exchanges, but not Energy Markets (NGX), Shorcan Brokers (Fixed Income Trading). Note also that the newly acquired Montreal Exchange is not included in the 9 months 07 numbers above.

Risks:

- The largest threat to TSX Group are alternative trading systems (or ATS's) to potentially circumvent Toronto Stock Exchange Trading earlier this year (in 5/07). An announcement concerning ATS developments in Canada sent TSX's market capitalization down 12.5%, details of which can be found in here. Canada may have as many as 8 separate electronic trading systems by the end of 2008 (details here). Note that the ATS that the banks have proposed is initially meant for large block trades -- which makes up less than 10% of the volume of TSX's trades currently -- and is similar to the 30 or so "dark pools" (ATSs) that exist in the United States, which trade mainly large blocks of securities between funds. ATS's could potentially climb to taking pieces of normal trading volumes in both countries with advances in technology and more willingness to place electronic trades.

Partially mitigating this risk of trading volumes going to ATS's is the fact that TSX has recently (in 12.07) launched what is one of the most technologically advanced trading platforms in the world -- named TSX Quantum -- which can complete trades in under 10 milliseconds (TSX's previous technology could complete trades in only several 100's of milliseconds). Details of the TSX Quantum launch can be found here. TSX Quantum is comparable to NYSE Euronext's new service which will be launched in 2008 with processing times of 10 milliseconds Note that NYSE Euronext is generally thought of by financial professionals to be the leader in terms of trading technology, so the favorable comparison with the NYSE is impressive for TSX Group. According to the CEO of the TSX Group, generally the exchange with the faster processing times will win the trade, all other factors equal. Further, faster technology for processing trades allows volumes to go higher without corresponding cost increases.

According to Jackie Chung, president of Competitive Metrics Inc in Canada (which recently completed a report on ATS's in Canada), it is likely that the launch of ATS's in Canada will result in a somewhat smaller piece of a larger trading pie, but Chung also notes that TSX Group will be a fierce competitor with the new "dark pools." However, it is not exactly clear to what extent the ATS's will impact trading volumes at TSX Group, so investors are encouraged to watch developments concerning ATS's closely going forward.

TSX Susceptible, But Resistant to a Market Downturn:

It is believed by some exchange industry participants that the exchange industry "will make money if the market goes up or down." In the recent book "Rigged" by Ben Mezrich published in 2007, the Executive Vice President of Strategy for the MERC expressed this viewpoint -- due to the fact that trading volumes can stay the same or perhaps even rise in a declining market. But the recent history of the TSX shows that a rising market is better for the exchange's profitability, and, as demonstrated in chart 1 above, TSX Group suffered a drop in revenues of 17% and a decline in net margin to 16.8% from 35.3% from 2001 to 2002, mainly due to the market downturn in these periods. Earnings did not decline to negative territory as would have been expected in an industry such as machine tools, but revenues and margins were significantly negatively affected, and therefore the recent history of the TSX shows that a rising market is better for the exchange's profitability.

Partially mitigating recession risk is the diversification of TSX Group, which operates in both commodity-based (mainly through the trading of mining and oil and gas equities, but also through TSX's natural gas exchange, NGX) and equity trading. Diversification was a different issue during the last downturn (2002) due to the fact that commodities were not valued then as highly as they are currently. Certain analysts -- recently the chief economist at BHP has expressed this opinion -- have projected that if there is a slowdown in the US, China and other emerging markets will not be dramatically affected, and commodity prices will continue to stay relatively strong, which would benefit TSX Group.

Conclusion:

TSX Group is attractively priced and is a good acquisition candidate in the exchange industry, which is undergoing significant consolidation. As such, TSX Group represents a compelling medium to long term buy. The largest risk to TSX Group is the proposed Alternative Trading Systems for potential launch in 2008, although this risk is partially mitigated by the fact that most of the systems are designed for mainly large block trades, and the fact that TSX Group has much more advanced (faster and more reliable) trading technology for the completion of trades. Further risks include the risk of recession in the US that chokes off Asian growth and negatively affects the Canadian economy. Interested TSX Group investors are encouraged to closely watch developments with regards to Alternative Trading Systems and the global economy closely going forward.

Petrobras' Tupi Discovery Will Likely be Profitable

2007-12-11T10:20:00.000-08:00

Petrobras announced the Tupi discovery in the Santos Oil Basin of between 5-8Bn barrels at 11.07, which appears to be recoverable numbers of oil and natural gas equivalent, as opposed to total resource numbers (of which recoverable oil is a fraction). The Tupi oil find generated significant enthusiasm both inside and outside of Brazil -- to the extent that the Brazilian President Luiz da Silva declared in a speech concerning the oil find that "God is Brazilian." Not only is the 5-8Bn barrels very large in itself, but, according to Petrobras CEO Gabrielli, Tupi is just a "tiny'' part of the total Santos Basin reserves.

The main questions that come to mind for the interested investor are: first, how much daily production can be expected from Tupi? And when will production come online? Further -- related to the first two questions -- how expensive will the Tupi field be to produce? And, further, what are the technical challenges to production? Overall, these questions can be grouped into an overall question: How profitable will Tupi be for Petrobras? This article will explore these questions, to the extent that the information has been made public as of the date of the writing of this article (12.07). Note that the author is not a petroleum geologist, so it is possible that mistakes will be found herein regarding technical issues -- the author has attempted to cite every assertion concerning technology issues with regards to the Tupi Oil Field.

Overall Significance of the Tupi Discovery to Petrobras:

As a perspective on the Tupi oil discovery, the latest oil production forecast for Brazil at 6.07 was presented by British Petroleum at 7/07 in the chart below. Note that this forecast most likely did not assume the successful production of Tupi specifically but rather some (most likely smaller) production success in the Santos Basin, as Tupi was not announced at 6.07 (and the Santos Basin was previously expected to produce mainly natural gas). From the forecast, one can summarize, Petrobras has several projects in the Campos Basin -- Tupi is located to the south in the Santos Basin -- which are expected to increase production regardless of how Tupi performs, in BP's estimate from approximately 2.0M bpd in 2007 to 4.0M bpd in 2020. Nevertheless, it is a significant positive if Tupi moves forward, from both a production and reserve standpoint -- Petrobras' 2P reserves were approximately 12 bn barrels and the Tupi discovery may move Petrobras' 2P reserves to between 17Bn to 20 Bn barrels (an amount significantly larger than Exxon Mobil's reported 1P reserves of 13.3Bn barrels at year end 2006). But in summary, Tupi is important, but not critical to the overall oil and natural gas production success of Petrobras.

Projected Future Oil Production of Brazil (pre-Tupi discovery):


Source: Historic, BP Statistical Review of World Energy, June 2007;
Forecast, BMI Research

How much oil will Tupi Produce?

Petrobras announced on 11/12/07 that Tupi production will go over 200,000 bpd in 10-15 years, with a pilot production of 100,000 bpd in 2011-2012. In terms of how much production can go over 200,000 bpd, the head of Petrobras exploration and production, Hugo Repsold, has indicated that 1M barrels per day of production is achievable, as a peak production figure.

The question of how much will be produced is related to questions concerning how the field will be produced from technological standpoint. If this field was a typical offshore oil discovery then the production numbers would likely offer little doubt as to their eventual achievability. But the main issue concerning Tupi is an unusually large and deep salt layer deep under the ocean floor, which covers the oil reservoir. A graphical depiction of this salt layer and the overall depth of the Tupi resource has been provide d by the excellent oil website The Oil Drum:

The salt layer combined with the large depths -- the Tupi oil discovery is 4 to 5 miles below the ocean floor -- make certain technologies necessary for the production of the field. The salt layer needs to be understood and effectively drilled through -- with a resulting stable wellbore -- requiring new technology and expertise to effectively manage through the salt layer. Salt at this depth is reported to act like sludge, with some unknown physical properties, meaning that construction of an effective wellbore may be difficult. Petrobras is assessed to have the technology to produce currently, as they have already drilled a number of test wells into the Tupi resource to make their size estimate public -- therefore the main question is cost. The field is likely to be expensive, which will be explored in the next section.

How Expensive will the Tupi Field be to Produce?

The respected consulting firm Wood MacKenzie has estimated that the total field will cost between $50 and $100Bn to produce, all in. Importantly, the cost range does not indicate the final production numbers from the field, so this makes a feasibility calculation (through a payback period, difficult to do (but a range under certain assumptions will be done in a section below, to shed light on Tupi). This amount comes in on top of Petrobras's planned $118Bn in spending announced for the next 5 years for all other projects, including refining, gas and ethanol pipelines, and other oil fields besides Tupi. These numbers indicate that Tupi will be expensive, but not prohibitively so for a firm of the size of Petrobras. But note that cost estimates for Tupi exhibit significant ranges. One Brazilian petroleum geologist has stated that costs for Tupi would be 10x higher than for oil fields produced in the Campos Basin, to the north, where the majority of Petrobras' current production exists. This would result in costs of over $100M per well. However, cost estimates have exhibited a very wide range, from $30M per well (according the the Petrobras CEO) to $250M per well -- the cost per well of the exploratory well. Full production of Tupi -- again Petrobras has not disclosed if this means 200,000 bpd or 1,000,000 bpd (which is a critical piece of information that is lacking currently) -- would require approximately 100 wells. Cost estimates for 100 wells in the Tupi field would then range from $3Bn at $30M per well to $25Bn at $250M per well.

Note that well costs tend to decline with more wells due to expertise and also the fact that some of the costs can be amortized over time -- the first well requires workers to be moved out to the location while more wells mean that labor and equipment are in place and ready to work translating to low transition costs. Therefore it is unlikely there won't be some cost abatement from the first test wells of $250M per well.

Further, there is a need for more Floating, Offloading and Storage Facilities (FOPF) -- which are offshore rigs but based on floating tankers instead of attached to the ground in order to produce the Tupi discovery. The costs of these FOPF's are in addition to the cost of drilling the wells. Petrobras' CEO Gabrielli has estimated that between 6 and 12 FPSO's will be needed to produce Tupi -- but did not indicate what amount of oil each FOPF would produce (in other words, how much production would 6 FOPF's produce verses 12 FOPF's?). There are only 70 FOPF's worldwide according to wikipedia at 2006, so likely shipbuilding facilities will be run overtime to provide several for the production of Tupi. -- with the bill of course going to Petrobras.

Estimate of Payback Period under Certain Assumptions:

Assuming an all in start up cost of between $50Bn and $100Bn - the Wood MacKenzie's estimate stated above - would mean a very wide ranging payback period of between 2 and 35 years, depending on the assumptions for production, oil price, and lifting costs. Note that lifting costs in the North Sea are estimated at under $15 per barrel of oil -- $20 is utilized for the cases below.

Scenario 1: Base Case:
500,000 bpd of total final production, oil price of $70, lifting costs of $20, total start up costs of $80Bn: Payback period: 7.3 years

Scenario 2: Low Case:
200,000 bpd of total final production, oil price of $60, lifting costs of $20, total start up costs of $100Bn: Payback period: 34.5 years

Scenario 3: High Case:
1,000,000 bpd of final production, oil price of $90, lifting costs of $20, total start up costs of $50Bn: Payback period: 2 years

*Note that in all cases, the time period in which capital expenditures are accrued but production has not come online is not included -- for example, if Petrobras takes two years to get to the point where some production is started up, these two years are not included in the payback period. Further, production numbers are assumed to be average numbers over the production period -- when in reality the field will rise to a "peak" then decline. Lastly Oil price is assumed to be constant over the payback period.

Clearly, the scenarios above present a very wide range, ranging from essentially uneconomic in the "Low Case Scenario" to massively profitable on the "High Case Scenario." The most likely case in the author's opinion -- named the base case above -- shows a 7.3 year payback period, which is at the upper limit for a payback period for a typical oil and gas project, as most oil firms would like to see a payback period of under 5 years, to reduce uncertainty and leave capital for other projects. However, for projects with a longer reserve life (larger reserves with more expected years of production), oil firms will likely be more willing to fund a longer payback period project. At 500,000 barrels per day of production, the Tupi oil field is expected to have a reserve life of between 27 and 47 years (at 5Bn and 8Bn barrels of reserves, respectively), which certainly fits the criteria for a long life asset, as, for example, most oil firms operating in the Gulf of Mexico have overall reserve lives of under 15 years.

The long life of the Tupi oil field is similar to oil sands projects, which have reserve lives of over 40 years. Oil sands firms are willing to fund projects with somewhat longer payback periods because of the long producing life -- the 5 year typical payback period is for conventional oil projects. For example, Suncor spent for the 4 year period through 2001, $3.4Bn in capital expenditures to double the capacity at its Millennium Project, which added an additional, approximate 130,000 barrels per day of production. In 2001, the oil price was significantly lower than it is today in late 2007, so it is likely Suncor was only budgeting between $10 and $15 per barrel in profit after the project was completed. These profit assumptions translate to a payback period of between 4.8 and 7.1 years (at $10 to $15 per barrel of profit) for Suncor's Millennium expansion.

As such, with long lived reserves but high initial capital expenditures, Tupi can be viewed similarly to a heavy oil project -- meaning that an expected pay back period of moderately over 5 years is acceptable and likely to be funded profitably.

In terms of the most likely cost and production scenario, the author would lean towards higher start up costs (closer towards the $100Bn estimate), but also a higher oil price going forward, and also somewhat higher than 200,000 barrels per day final production, with more than 6 FOPF's with 100 wells operating in the area. This scenario is reflected as mentioned in the "Base Case" above.

In summary, a cost estimate, roughly, shows that Tupi should be moderately profitable going forward, with risks of a lower realized oil price, cost overruns and lower realized production. These risks are partially offset by Petrobras' expertise in operating in deepwater -- Petrobras is the world's leader in offshore technology, and continued expected pressure on the oil price due to growth in Asian countries and lower expected production from conventional sources. Note that also there is significant upside to the profitability of Petrobras if the oil field is larger than initially reported.

Possible Benefits to Petrobras From Technological Expertise in Developing the Tupi Oil Field:

On the bright side, the technological expertise required to successfully extract the Tupi oil field will likely result in technology that allows for an enhanced ability to drill below deep salt layers, which will likely result in an increased ability to extract deep sea hydrocarbons in many other offshore areas with similar characteristics, such as West Africa and other South America. Further, preliminarily, Petrobras appears to be able to benefit from pioneering this deep sea salt drilling technology due to the ability to license and consult for other offshore projects with similar characteristics.

Conclusion:

The Tupi oil find is quite promising, from a profitability standpoint, under most reasonable assumptions of oil price, cost and production figures. The expected profitability of Tupi is obviously quite positive for Petrobras investors. Further, Petrobras investors may see increased reserves and production from the Santos Basin beyond the initial 5-8 billion reserve estimate, which would boost profitability estimates. However, significant risks exist if oil prices drop going forward and/or the field proves to be too technologically challenging to develop, due to the unprecedentedly deep and thick salt layer. These risks are partially mitigated by Petrobras' expertise in deep water, and positive prospects for the price of oil. However, investors are encouraged to watch developments and news concerning the Tupi oil field closely over the next several years to determine if the technological risks are sufficiently mitigated.