An Overview of the Canadian Oil Sands Industry

Canadian oil sands are a type of heavy oil resource, mixed with sand and water which forms a substance which resembles an "oily mush." The bitumen from the oil sands -- chemically long hydrocarbon chains that are close in structure to those of asphalt -- can be upgraded, after separation from the sand and water, to syncrude (a type of heavy oil), which then can be further refined to gasoline, jet oil, and other premium petroleum products. The majority of Canadian oil sands are located in the Athabasca region of Alberta, an area covering approximately 30,000 square miles, but significant oil sands deposits are also found in the "Peace River" and "Cold Lake" deposits, which are are also located in Northern Alberta but in distinct regions from Athabasca.

Note also, there are large oil sand deposits in Venezuela and Russia, but this analysis only covers the Canadian oil sands.

Oil Sands Majors:

Canadian oil sands production is up and running currently (in contrast with Venezuelan and Russian oil sand deposits, which are also very large but are not developed), with the majority of the production coming from four firms: (termed "Oil Sand Majors" here):

1. Syncrude -- a consortium of oil majors and the managing Canadian partner Canadian Oil Sands, Inc, which produces approximately 361,000 barrels of syncrude a day (at 6/07) mainly through mining methods

2. Suncor -- the oldest Canadian firm, 100%, publicly held, which produces approximately 270,000 barrels of syncrude at day at 6/07, produced mainly through mining methods.

3. Imperial Oil -- approximately 70% owned by ExxonMobile, which produces 140,000 barrels per day produced in the "Cold Lake" region above (not the Athabasca region above) through in-situ methods, and, in addition, owns 25% of Syncrude.

4. Athabasca Oil Sands Project -- 20% owned by the public Western Oil Sands (ticker WTO), 60% owned by Shell, and 20% owned by Chevron, which produces 180 bpd in mid 2007 produced mainly through mining methods

Note that other firms are up and running, including Encana, Nexen and the Consortiums Western Oil Sands Inc, North American Oil Sands Corporation -- producing firms minority and majority owned by partners Chevron, Statoil and Shell and other oil majors. However, these firms currently (9/07) produce on a significantly lower scale than the four "Oil Sand Majors" listed above, although plan to increase production going forward -- production forecasts are discussed below. Further, note that only three firms, Syncrude, Suncor and the Athabasca Oil Sands Project, are producing oil sands through mining methods (to be described more fully below) on a major scale, while other firms are producing oil sands currently through "in-situ" methods, which involves two methods of pumping hot steam underground and collecting the melted bitumen.

Oil Sands Firms Overview:

The following discloses the major oil sands producers currently and in future years, with the following data.

Data Included: firm name; ticker; total leased oil sands area (square miles); recoverable resources (of syncrude); Oil Sands Current Production; Enterprise Value, P/E ratio TTM/Projected (note -- p/e ratios may include conventional oil production earnings in addition to oil sands earnings)

Data from SEC filings and presentations from the Investing in Alberta's Oil Sand's Conference June 2006: http://www.oilsandsconference.com/program.htm

Syncrude; (investors can purchase indirectly through Canadian oil Sands Trust, 37% owner, COSWF); 386 square miles; 10 billion barrels; 361,000 bpd, 500,000 bpd by 2015 projected; $US43Bn; p/e: 18x (p/e of 37% owner Canadian Oil Sands Trust, inc)/proj p/e: na

Suncor; SU; 772 square miles; 13 billion barrels; 270,00 bpd current, 500 to 550K bpd by 2012; $US45Bn; 19.2x ttm/14.6x proj (oil sands only)

Athabasca Oil Sands Project; 20% owned by Western Oil Sands; WTOIF; 55 square miles; 8.9 billion barrels; 35 kbpd, mainly through mining; projected 500K total bpd produced by 2015; $US30 Billion; 28x/ na

Imperial Oil (25% owner of Syncrude and indep. producer); IMO; 727 square miles (w/Syncrude); 10 billion barrels (3 billion mining, 7 billion in situ)(w/ Syncrude); 140,000 bpd ex Syncrude at Cold Lake 4% growth forecasted, 300K bpd at Kearn by 2020; $US45Bn; 14.8x/16.0x

Canadian Natural Resources; CNQ; 177 square miles; 6 billion barrels; 110K bpd 2008, 232K bpd 2011; (in situ); $US52.13Bn; 15.9x; 17.8x

PetroCanada (12% interest in Syncrude, plus substantial indep projects); PCZ; 9.8 square miles; 10 billion barrels estimated ex Syncrude; 27,000 bpd ex Syncrude current, 320,000 bpd independent projected by 2015; $US29.5Bn; 11.6x ttm/9.90x proj

Encana (mainly natural gas producer but moving into in situ oil sands production); ECA; 77 square miles; resources na; 48 kbpd current oil sands production; future oil sands production na; $US57.7Bn; 12.6x ttm/13.8x proj

Nexen (mainly conventional oil and gas producer but owns 7.23% of Syncrude & small indep oil sands operation); NXY; 7.7 square miles ex Syncrude; 27,000 bpd pro-rata Syncrude, 100,000 bpd independent by 2017; $US15.7Bn; 37x ttm, na

Statoil (national oil co of Norway, bought 100% of North American Sands Corporation in 2006 for $US2Bn); STO; 8.9 square miles; 0 current, 170,000 bpd by 2015; $US82Bn; 9.8x ttm/11.6x proj

Note that the list above is not exhaustive as certain smaller producers have not been included, such as Synenco, Devon Energy, Connacho Oil and Gas, Husky Energy, and CanWest.

What is the difference between Oil Sands Mining and Oil Sands "In Situ" Production?

The majority of oil sands production currently (at mid to late 2007) comes from mining methods, which essentially can be described as follows: huge digging machines, which dig surface oil sand, load this oil sand into huge trucks, and move the oil sand to processing facilities. It is emphasized that these trucks and digging machines and shovels are huge, as the Caterpillar 797 truck used for hauling oil sands has been compared by its manufacturer in size to an entire Wal-Mart store and can crush an SUV underneath and the driver of the 797 will not feel a bump. Mining projects account for over 60% of total oil production and a higher majority of production for Syncrude and Suncor's current oil sand production.

In Situ production is described as the melting of underground oil sands and collection of the resultant melted bitumen by vents. In situ production is utilized when the oil sand resource is located far underground, so that surface mining is not possible -- note, that by area, over 75% of Alberta's oil sands are deep underground and appropriate only for in situ production. According to Imperial Oil, which claims to be the most experienced in-situ producer currently at in situ production of 170,000 barrels per day, there are certain geological requirements for in situ production with current technologies: that is, 1. the reservoir should be "clean" with a high bitumen saturation, and/or 2. the reservoir should have a capping shale cover (to keep the heat contained). It is not known what percentage of underground oil sands in Alberta possess these requirements.

Volumes from "In Situ" Extraction is Most Likely Less Predictable Going Forward than Volumes from Mining Extraction:

There is some uncertainty going forward in the predictability of future volumes from in situ production. Bitumen produced by in situ production from a single location has not resulted (as of late 2007) in more than 170,000 barrels per day -- as is the current production level at Imperial Oil's current Cold Lake operations (although note that Imperial Oil is confident that they can continue to increase the production from this property by 4% per annum going forward). Further, conceptually, it is more straightforward to increase production to increase by mining methods -- that is, it is simple under mining methods to increase the number of shovels and trucks, and upgrading and refining capacity. In contrast, with in situ production, it is unclear (in the author's opinion only) whether heating the underground reservoir at a higher temperature to increase bitumen flow and/or more vents constructed to collect melted bitumen would increase production at a steady rate.

Note also that only a relatively small area of the total Canadian oil sands area -- less than 25% of the geographic area -- can be produced with surface mining methods, as surface mining only is applicable when the oil sands are located near the surface, defined as under less than 75 meters of overburden. The mineable area of the oil sands is already nearly 100% leased according to maps from Alberta Energy: http://www.energy.gov.ab.ca/LandAccess/pdfs/OilSands_Projects.pdf (large pdf warning).

Therefore, in the author's view, the companies with large lease areas and operations in the mineable areas of the Athabasca oil sands territory (Suncor, Syncrude and Athabasca Oil Sands Project) have increased predictability of future resource development, and therefore should (all other factors equal) be valued at premiums to reserves verses in situ-heavy producers.

Is There a Difference in Terms of Profitability between Mining and In Situ Production Methods of Oil Sands?

According to Nexen Inc, overall economics are similar between in situ and mining methods -- with a slight edge to the mining process, estimating an operating margin of 56% for mining methods vs 50% for in situ processes per barrel of oil based on $50 oil. However, costs in individual processes can range widely, from $18 to $30 (at late 07) per barrel of heavy oil, depending on the location and geology of the resource. But, according to Nexen, there are significant differences in components of cost between the two methods: natural gas usage in in situ production is generally more than twice the level than in mining production -- because natural gas is used to heat the bitumen underground. But other production costs are more than three times the level in mining methods verses in situ -- because the mining equipment and trucks are expensive to operate, and the sand component of the oil sand from mining methods must be separated out in an extraction process. Upgrading and refining costs are similar between the two methods. See: the Nexen Presentation on this page for details: http://www.oilsandsconference.com/program.htm

The upshot of the above discussion is that both methods in theory can provide a verystrong return to shareholders, and therefore the main difference (in the author's opinion) between the two methods is the attainability of production levels between the two methods -- that is, the mining method is comparatively more reliable and therefore projected increased numbers can be relied upon more securely, as stated in the section above.

How Profitable are Oil Sands Firms?

Oil sands production is very profitable currently, due to the relatively high (compared to historical) price of oil. According to Morgan Stanley (link: see the Lloyd Byrne Morgan Stanley presentation on the bottom right hand concern at the Canada Institute here: http://www.wilsoncenter.org/index.cfm?topic_id=1420&fuse
action=topics.event_summary&event_id=145364)
oil sands as of 2004 returned an average of 18.0% on capital employed (ROCE of 18%) verses 15.0% for conventional North American oil production. Further, the cost per barrel of oil -- cost defined as cash costs for operation, SG&A, accretion expense, taxes other than income taxes, and DD&A) were $14 per barrel for Suncor's Millennium project verses $16 per barrel for conventional North American oil and gas production. That is to say, at 2004, according to Morgan Stanley, oil sands were actually more profitable per barrel than conventional oil production -- clearly Wall Street and most investors do not appreciate this view, given the relatively low p/e's of the oil sands majors compared to the planned growth rates.

The reasons Morgan Stanley gives for the very competitive costs of oil sands production are: a high degree of "repeatability" -- meaning steady future production and predictable inputs to achieve future production -- due to very large and relatively homogeneous reservoirs, and very low exploration costs, verses conventional oil and gas.

The results of the two, pure play major oil sand producers (Suncor and Syncrude) underscore the profitability of oil sands production demonstrated by the following (source company financial press releases):

Firm; 6 Months 07 Revenue Growth; 6 Mo 07 Net Income Growth (Y/Y); 6 Mo Net Income Margin (%)
Suncor; 4.8% rev growth; -38% net profit growth (due to one time items); 14.3% net profit margin (24.4% net margin in the year earlier period)
Syncrude; 29.2% rev growth; 25.9% net profit growth (before one time items); 19.3% net margin

Will Escalating Costs of Labor, and Equipment Cause Oil Sands Production to Become Unprofitable in Future Years?

A comprehensive analysis of future costs is not presented here, although there has been significant press coverage of rising oil sands labor and equipment costs. However, as shown above, the Oil Sand Majors are still very profitable as the rising price of oil more than offsets the rising operational costs. But in the future, if operational costs go up without a corresponding rise in the price of oil, then this will certainly hurt oil sands firms' profitability.

Will environmental concerns over water usage, environmental degradation and/or CO2 production derail future increased oil sands production?

It is assessment of this analysis that not likely that environmental concerns, particularly concerning water, will derail oil sands growth going forward, as the actual water usage is not extremely large -- only 1% currently of the Athabasca River, which is significantly lower than farming usage. http://calsun.canoe.ca/News/Alberta/2006/11/13/2339858.html Oil Sands extraction uses between 2-4 barrels of water per barrel of oil, and this water can be recycled -- further, the amount of water flowing through a moderately sized (or even small) river is huge compared to normal amounts of oil produced in normal oil sands operations. Even with oil sands production increasing three fold, the water usage is only expected to increase to 3% of the Athabasca River.

The amount of Co2 production is more difficult to estimate, and the largest oil sands producers are now among the largest Co2 producers in Canada. Concerning environmental degrigation, oil sands producers have assured to remediate oil sands mined areas: http://www.suncor.com/default.aspx?ID=2

Source of Value for Oil Sands Firms: Size and Quality of Leased Land

According to Alberta Energy, the total area of the Athabasca oil sands that have been leased for purposes of oil sands extraction has increased dramatically from 31% of the total area to at 6/06 to 61% at 4/07 (and is likely to have increased further as of the time of this writing at 10/07). (according to documents at http://www.energy.gov.ab.ca/OilSands/583.asp) Further, the area of the Athabasca oil sands that can be profitably mined by surface mining has been nearly 100% leased by major oil sands firms. According to Alberta Energy, the leases range in tenure from 15 to 21 years, and can be renewed 1 year before the expiry date -- the legal language gives priority to the existing leaseholders: "Leases are continued if the required minimum level of evaluation has been attained." Evaluation is mainly seismic and other geological evaluation which would normally be done by producing firms (see section 3-7 of Alberta Energy's Alberta Oil Sands Tenure Guidelines http://www.energy.gov.ab.ca/OilSands/pdfs/GDE_ost_chp3.pdf)

The result is that the leases have a "first come, first serve" quality -- they go to the highest bidder at auction, then are able to be withheld (in effect) over the long term by the winning bidder. As such, firms with the most leases and the most geologically valuable leases have a significant advantage over firms that are late to the game and/or do not have significant land holdings -- that is, the largest firms, Suncor, Syncrude, Imperial Oil and the Athabasca Oil Sands Project process significant value due to their large lease holdings.

Conclusion:

The purpose of this analysis was to provide an overview of the producing firms in the Athabasca Oil Sands region, and provide an overview of expected profitability for investors interested in investing in Canadian oil sands. The conclusions of this analysis was that oil sands are currently profitable, and are likely to continue to be profitable -- as long as oil prices continue to stay at elevated levels. Priority was given to the more established firms in the Athabasca region, due to the fact that they have large lease holdings of land, and establish operations -- operations built when prices of equipment were are significantly lower levels than current due to the rise in steel and material costs over the last 3-4 years. Future increases in synthetic oil production is considered likely, although the exact timing of such increases by the firms is difficult to ascertain, but more reliability is given to firms which extract oil sands through mining methods.

Future posts will evaluate the impact of natural gas prices on oil sands production (note, in summary natural gas pricing is not expected to be a significant deterrent to future increased oil sands production), the differences in profitability between firms in the region, and more specifically evaluate the smaller players in the oil sands regions.

Further Credit Crisis Thoughts

Some further thoughts on the current credit crisis:

- We have had something like this every 5 to 6 months or so, with the last one in Feb 07, before than June/July of 06. It seems to me to be due mainly, to overextended funds, if we didn't have funds leveraging, then there wouldn't be such a mass rush for the exits.

- That said, I think this one is a bit more scary than previous downturns, in that it is a real liquidity crunch, not quite the same as last year. Although similar, but a bit more severe. Further, I am not sure about overall economic growth, with the housing market slowing.

Homebuilders:

- In the housing market, I think the homebuilders (as I've followed homebuilders fairly intently for about 4 years) without leverage will make it through, and who haven't committed to these exurb-type developments, while the homebuilders who are overextended and rely on the mass community developments will have a tougher time -- many can go bankrupt. The overhang of houses is the most since at least the 70's. Mainly in the housing communities sector, in exurbs, etc -- "KB Home's new development, many cookie cutter houses which all look the same, 50 miles from downtown" isn't nice at all, long commute times, and now harder to get financing.

- Really, something like WCI should do ok over the long term -- if it wasn't for their leverage -- since they do luxury apartments, in or near city centers. I am not a fan of KB Homes or Pulte Homes, for example -- which do a lot of community developments.

- Further, on housing, it is odd to think that housing globally will go down. It is hard for me to see that happening -- in China, for example, interest rates are buffered from external developments, and people are used to spending upwards of 50%, more like 60% of their monthly income on housing payments. Demand is huge for housing there because the whole country wants to live in the cities. In the US, there should also be a vast difference between real estate valued in attractive areas -- financing will be easier to be obtained, and people will spend a bit more on monthly housing payments from a relatively low level as compared to other countries. Overall, if housing declines and interest rates go up, undesirable areas will get hit, but more attractive areas, people will pay up and not sell, and demand will still be there.

Thoughts on the Current Subprime and Liquidity Problems in the Markets

Some thoughts on the current market crisis in both subprime and overall markets:

- In and of itself, the subprime problem is a moderate problem, but not a huge problem. That said, not a lot of analysts know exactly to what degree many hedge funds are levered, and, if there are large losses from subprime loans, if they can meet their commitments -- and this is what is scaring investors. In other words, we would not be having these problems if funds were not highly leveraged. If I recall correctly, in the Long Term Capital Management crisis of 98, the main problem, was that the result of the 80 or so to 1 leverage to equity could cause a string of bank failures. Unfortunately we didn't learn from that crisis to pass laws that would limit leverage of hedge funds.

- The domestic Chinese market is oblivious to the liquidity problems here: (Shanghai) http://finance.yahoo.com/q/bc?s=000001.SS&t=6m&l=on&z=m&q=l&c=

But India is down a modest amount (but 4% today meaning 4/16) http://finance.yahoo.com/q/bc?s=%5EBSESN&t=6m

The reason I believe is that the Indian Rupee trades while the Chinese Renminbi is non-convertible -- so US and EU based funds can't withdraw money from the domestic Chinese market. This underscores that this crisis (and I think we are in crisis mode now) is a liquidity problem.

- Fundamentally, China and India are in good shape (I think) but the US, is certainly slowing, but to what extent, is difficult to ascertain. Personally, I have made sure to get rid of financial stocks, and retail, and of course housing related stocks, and actually opened some short positions -- might as well over this next month while the market doesn't have much upside but possibly -- and would venture to say probably -- some more downside as of 8/16/07.

- A clarification is needed, the Central Bank's "pumping in money" is not really sending in money into the banks without questions asked, but rather repurchase agreement sales -- so the central banks (Fed and other Central Banks) are buying mortgages for cash, in which the central banks expect to be paid back. So it is really trying to get the markets running again. A description is here: http://www.voxeu.org/index.php?q=node/466

So what the Central Banks are doing is completely appropriate. This seems to be misunderstood by the many members of the media.

CNOOC

China National Offshore Corporation (CNOOC, ticker CEO) is responsible for the current and future development of China's offshore oil and natural gas reserves. With a market capitalization of approximately $50Bn as of 6/07, CNOOC is undervalued.

Chinese Majors Valuation Comparison Chart:

Ticker: PTR
PetroChina [E&P: 100% 05 income, Marketing: minimal inc Refining: loss]
Proven Reserves: 19.56 BBoE (41% gas, 59% oil)
Reserves/Production: 18.4 years
Market Capitalization: $236Bn
Standardized Measure: $175.2Bn (YE Chinese Prices)
Standardized Measure/Enterprise Value: 0.74x

Ticker: CEO
China Ntnl Offshr Oil Co [E&P 100% 05 Income]
Proven Reserves: 2.36 BBoE (68% oil)
R/P: 5.6 years
Market Capitalization: $50.0Bn
Standardized Measure: $25.2Bn (YE Chinese Prices)
Standardized Measure/Enterprise Value: 0.504x

Ticker: SNP
Sinopec (China) [E&P: 70% 05 income, Marketing 15%, Chem: Refin: 15% loss]
Proven Reserves: 3.362 BBoE (14.7% gas, 85.3% oil)
R/P: 10.6 years
Market Capitalization: $95Bn
Standardized Measure: $44.1Bn (YE Chinese Prices)
Standardized Measure/Enterprise Value: 0.46x

Notes: Market Capitalization values are from 6/07, but annual reserve and standardized measures are from 12/31/05, due to the fact that the year end 06 annual reports for the Chinese Majors are not available as of early 6/07.

Standardized measure is defined by FASB 69 as future expected cash flows from proven oil and gas properties, discounted by 10%. M0re information on the Standardized Measure can be found here: http://oilandnaturalgasreserves.blogspot.com/2006/11/
what-is-standardized-measure-of-oil.html

Brief Overview of the Chinese Oil Industry:

The Chinese oil industry is comprised of three firms: PetroChina, CNOOC and Sinopec. CNOOC, Petrochina and Sinopec were created in the early 1980's when the Chinese government split its emergent oil industry into three pieces based on geography: Petrochina in the Northeast, Sinopec in the South and CNOOC for offshore operations. This move by the Chinese government has been explained by Chinese analysts as an effort to foster internal competition based on a American model of the oil industry.

China fully intends for each of its three oil firms to become "Supermajors" in order to compete successfully internationally. China sees its domestic oil industry mainly responsible for securing oil and natural gas supplies, which is a top concern given China's ravenous appetite for energy. Note that this assertion concerning China and the Big 3 is based on comments from Chinese officials and also based on the latest presentations from the Baker Institute of Energy Studies, found here: http://www.rice.edu/energy/publications/nocs.html. PetroChina can be considered already nearly a Supermajor (at 6/07) with a market capitalization of approximately $US240Bn and proven oil and gas reserves of over 17 billion BOE, in a large part due to PetroChina's ownership of the Daquing oil field in Northern China, which is one of the four largest oil fields in the world. CNOOC is the smallest in terms of market capitalization of the Big 3 at approximately $US50Bn (at 6/07).

The question comes to mind: Does CNOOC's relatively low market capitalization mean that the firm has the most room to grow in becoming a Supermajor compared to Sinopec and PetroChina? The answer to this question is a qualified "yes," in that, with the lowest reserve base of the Big 3, and with very favorable prospects domestically and internationally (as explored in this post), it is possible that CNOOC's reserve base could increase at the highest rate. Note also that it has been the case in the past that the Chinese government -- which owns the majority of all Big 3 Chinese oil firms -- has given assistance to one of the Big 3 in order to help the firm become a more vigorous competitor to the largest firm, PetroChina. That is to say, based on its intended industry model, China will likely prefer to have three very competitive international supermajors and not just one (PetroChina) in the future.

Two examples come to mind in support of a multi-firm model for the Chinese oil industry: first, the Chinese government is directly paying Sinopec funds in order to offset losses in Sinopec's refining division, as the price of gasoline in China is at low levels, in order to support Sinopec's financial competitiveness. This transfer of funds to Sinopec can be viewed as support of Sinopec's competitive position vis-a-vis PetroChina.

Second, typically only one oil company in China will bid for oversees projects, in order for one Chinese Big 3 firm to not "outbid" another and make the project more expensive than it could be with multiple Chinese firms bidding -- sort of an understood cooperation between the firms -- because the base owner of all firms is the Chinese government. As an example of this understanding, Sinopec was given favor over PetroChina in bidding for the development of Iranian oil fields in 2005 through 2007.

In summary, it is the author's opinion that it is unlikely that PetroChina will win a significant majority of all oversees Chinese projects in the future, as China will most likely want to spread around future oversees projects in order to maintain meaningful competition between its Big 3.


CNOOC Producing Areas:

CNOOC mainly operates in offshore exploration and production (upstream operations). CNOOC currently derives approximately 94% of its oil and gas production from domestic (Chinese) offshore production. Going forward, Bohai Bay and oversees areas, mainly Africa and the Middle East (Iran) offer very high potential for reserve increases. The major producing areas are listed as follows:

Field Name 2006 Production (0il KBpd/gas mmcf/d) Reserves (oil MBoE/gas bcf) Notes
Bohai Bay 200.9 /64.5 933.4/765 Largest overall producing area, competes with PetroChina for development in Bohai, future prospects positive
Western South China Sea 40.4/251.8 190.5/2,648 Largest natural gas area, mainly develops reserves with oversees partners
Eastern South China Sea 105.9/23.1 200.2/792.0
East China Sea 1.5/21.2 20.4/390.0 Smallest area and reserves have not been increasing y/y
Oversees 24.0/130.3 145.3/1,636.5 Oversees represents mainly Indonesia and Australia, as Africa and Middle East deals are not counted in reserves as of 6/07

Bohai Bay:

Bohai Bay in Northern China is CNOOC's largest production area currently, and, over the near term, is the Company's highest priority development area. The area has significant potential, as in March, 2007, PetroChina discovered 7.3 Billion Barrels of Oil equivalent in Bohai Bay, the largest discovery in China over the last 30 years. (Development costs for the exploratary wells totaled $780M for PetroChina)(Note also PetroChina's stock moved up 12% with the announcement of the discovery). CNOOC has stated that it has several prospects for Bohai Bay going forward.

Near Term Production:

CNOOC has forecasted low production growth in 2007, of between 0% and 5%, as it brings new projects online. 5 projects are forecasted to come online in 2007 and are projected to reach full potential in 2008, 75% of these projects offshore China. CNOOC has forecasted investment expenses of $US512M development expenses.

Overseas:

CNOOC's two most substantial oversees projects are offshore Nigeria and offshore Iran. These two projects are discussed below.

Offshore Nigeria:

CNOOC in 2006 purchased 45% of Nigeria's offshore Alcpo Field for $US2.7Bn from the majority owner Nigeria National Oil Corporation (the national oil company of Nigeria). The field is classified as a "giant" field, with 620M barrels of oil proven total and 3.75 tcfe of natural gas (approximately 600MBOE), and oil numbers represent light, sweet oil. The reserve numbers are not consolidated in CNOOC's reserve numbers as the deal was completed in late 2006. The purchase price based on existing reserves represents $4.60 per barrel of equivalent. CNOOC's share of oil is expected to be 79,000 bpd of oil and liquids and 96,000 BOE per day of natural gas, according to PFC Energy. Further, the field has been lightly explored to date so further increases in reserves and production are possible going forward -- CNOOC has expressed the opinion that it is hopeful that oil only reserves will increase higher than 1 billion barrels.

CNOOC can consolidate more 45% of the purchase onto its books which means approximately a 20%-25% increase in overall reserves at the end of 2008 from this deal alone from CNOOC's current reserves base.

Offshore Iran:

The project with the most reserve upside for CNOOC is the development of the Pars natural gas field off offshore Iran, which was announced in late 06, amid opposition from the United States (due to sanctions, discussed below). The Pars gas field is the largest single, known natural gas field in the world, with Iranian reserves of an estimated 280 trillion cubic feet of natural gas, and an additional 17 billion barrel of natural gas liquids. The natural gas portion of the field is equivalent to an incredible 46 billion barrels of oil equivalent., which in turn, represents 17.7x total reserves of CNOOC at year end 05 (!).

Production is slated to start in 8 years (2014-2015), initially producing 20M tons of LNG a year -- equivalent to approximately 433,000 barrels per day. The numbers would presumably (although the author has not seen anything confirming this, the author's opinion only) move higher to the 1 million BOE range, as the field is of supergiant size.

Details of the joint development plan between Iranian National Oil Corporation and CNOOC -- including reserve recognition and income agreements -- have not been fully disclosed at as the date of this writing (6/07), although there have been contradictory reports out of China concerning the details of the agreement -- in late May 07, CNOOC reported that a final agreement was due in August 07, while a few days later, CNOOC denied that the Pars field agreement would be signed then. Most likely, CNOOC is trying to keep a low profile on this project due to the opposition from the US government, which has economic sanctions initiated against Iran. The US, for its part, is holding hearings in the US Congress and Senate to determine if CNOOC should face sanctions for this deal with Iran.

The question that is most important to investors is, will the agreement between Iran and CNOOC move forward? China, with its ravenous appetite for energy, is unlikely to drop the deal with anything less than extreme pressure from the US -- and even with extreme pressure, it is not clear that China will drop this deal. Iran is also not likely to drop the deal with China as it views cooperation with American, and to a lessor extent, European firms as unattractive, given its geopolitical situation. The question therefore becomes, will and can the US bring extraordinary pressure on CNOOC?

Typical pressure includes high level meetings and economic sanctions. It is beyond the scope of this analysis to completely judge if the deal will go forward. At this point, with the limited information available, the odds of the deal are placed at an even 50/50%.

Note however, even if the deal does not go through, more and more Islamic states are looking to cooperate with China verses the West on energy development due to geopolitical concerns, which is a positive for CNOOC and the Chinese Big 3.

Conclusion:

CNOOC represents a significant portion of future Chinese offshore oil production. CNOOC will see increasing competition from the other two Chinese Majors, Sinopec and PetroChina, as these firms move offshore, but CNOOC is forecasted to obtain its fair share of offshore reserves going forward. As such, CNOOC represents a compelling buy at its current market capitalization at 6/07 of $US50Bn.

Petrobras

Petrobras (PBR), the national oil company of Brazil, is the most undervalued public major oil company (outside of Russia) on the basis of proven reserves of oil and natural gas. Petrobras is unique in the oil major universe in that it not only has a low valuation on the basis of proven reserves, but also has strong prospects for increasing oil and gas reserves and production. Further, Petrobras is the first oil major to move significantly into ethanol distribution and production. These factors are discussed in more detail below.

Valuation Comparison Chart:
Ticker: Company Name
Proven Reserves
Proven Reserve to Production (R/P)(years)
Probable & Possible Reserves
Enterprise Value (US dollars)
Standardized Measure (from 10-K 2005 -- PBR has not published its 2006 10-k as of 6/07)
Standardized Measure (proved)/Enterprise Value

PBR: Petrobras (Brazil) [E&P: 90% 05 income];
11.775 BBoE (17% gas, 83% oil);
15.4 years;
N/A;
$108Bn
$109Bn (YE 05 prices of oil and gas -- 06 values not available at 5/07)
Standardized Measure/Enterprise Value: 1.01x

PTR: PetroChina[E&P: 100% 05 income, Marketing: minimal inc Refining: loss]
19.56 BBoE (41% gas, 59% oil)
18.4 years
N/A
$198Bn
$175.2Bn (YE Chinese Prices)
Standardized Measure/Enterprise Value: 0.88x

CEO
China Ntnl Offshr Oil Co [E&P 100% 05 Income]
2.36 BBoE (68% oil)
5.6 years
N/A
$34.3Bn
$25.2Bn (YE Chinese Prices)
Standardized Measure/Enterprise Value: 0.73x

SNP
Sinopec (China)[E&P: 70% 05 income, Marketing 15%, Chem: Refin: 15% loss]
3.362 BBoE (14.7% gas, 85.3% oil)
10.6 years
N/A
$81Bn
$44.1Bn (YE Chinese Prices)
Standardized Measure/Enterprise Value: 0.54x

XOM
ExxonMobile
[65% 05 income E&P, 22% ref & marketing]
13.37 BBoE (42% gas, 58% oil and NGL’s) reserves exclude oil sands
9.0 years
N/A
$392Bn
$99.2Bn (YE prices of oil and gas) (55% of standardized measure in US/Can/EU)
Standardized Measure/Enterprise Value: 0.25x

(Note: the figures above are dated as the market capitalization values are from mid 2006 and the reserve valuations are from year end 2005).

Petrobras operates in three main divisions: 1) Upstream: PBR develops oil and natural gas reserves mainly off the coast of Brazil, 2) Downstream: PBR refines and markets petroleum products mainly in Brazil, and 3) Ethanol: the Company distributes and exports ethanol.

PBR Upstream Operations Analysis:

Petrobras derived approximately 90% of its net income from its upstream operations (Exploration and Production) according to its latest annual report (05). PBR produced an average of 1.77mbpd of oil -- out of a world average production of approximately 86 mpd of oil -- and expects to produce 1.919 mbpd of oil in 2007, as new projects come on line offsetting existing declines in existing oil fields.

Petrobras has good prospects for increasing oil and natural gas reserves on offshore Brazil as the company can explore more fully the Campos Basin, and then move down to the Santos Basin, to the south, of a similar geographic size to Campos (although the geology obviously differs). The Campos Basin is 100,000 square miles but has had significantly less exploration than the Gulf of Mexico, which produces a similar quantity of oil -- GoM produced approximately 1.8 mbpd of oil in 2005 while Campos produced approximately 1.7 mbpd of oil in 2005 -- and further exploration is promising. There is high interest from majors in all blocks offered in Campos for the purposes of oil and gas exploration.

Petrobras has a very large amount of territory to explore off the coast of Brazil -- as a comparison, the country is approximately the same size as the United States ex Alaska. Although Petrobras does not explicitly state that it hasn't fully explored the Amazon basin, the author has not seen anything that shows that PBR has spent a large amount of funds exploring this area. Note that most large offshore oil deposits occur in basins in a near proximity to rivers -- Campos and Santos basins notwithstanding, as these are not close to rivers (note that this last statement concerning is this author's opinion only, and the author is not a petroleum geologist).

Historically, the government of Brazil has awared Petrobras the vast majority of territory claims on offshore Brazil, and this is expected to continue in the intermediate term -- all blocks are opened by the Brazilian government to bids to cooperate with Petrobras and only one block is independently produced by a firm other than PBR -- although this could change as the Brazilian government has moved towards opening up the oil sector. Note however that most Brazilian domestic oil firms besides PBR do not currently have the capital to compete with PBR -- Petrobras estimates that in 2005 it developed more than 98% of Brazil's oil and gas reserves, according to its Annual Report filed with the SEC.

Oil Field Analysis:

Over 90% of Petrobras' reserves are located in the Campos Basin, 50 miles off the coast of Brazil, in deepwater (over 1000 meters). PBR's major fields in the Campos Basin are reported as follows:

Campos Basin:
Field Name: Estimated Size (oil barrels): 2006 Production Notes:
1a. Marilin 1.229 Billion 414,200 bpd Largest Field to date, peaked in 2002 at 586,312 barrels per day
1b. East Marlin see Marlin above 160,000 bpd 09 (0 now) Extension of the Marlin Field
1c. South Marlin see Marlin above 430,186 bpd 11 (185,740 now)
2a Barracuda 1.229 Billion 169,903 bpd Connects with Caratinga listed below
2b Caratinga connects w/ Barracuda above 141,198 bpd Both Caratinga and Barracuda have not peaked
3a. Albacorra N/A 114,878 bpd Peaked in 1998 at 199,800 bpd
3b. East Albacorra N/A 61,000 bpd Under development
4. Espadarte N/A 24,500 bpd Under development
5. Roncador N/A 84,000 bpd Under development

Petrobras' largest discovered field to date has been the Marlin field, which contains an estimated 1.7 billion barrels of remaining oil. This field has been in decline since 2002, from 586,312 bpd of production to 414,200 bpd currently. In the immediate area of Marlin are the East Marlin and South Marlin fields, which are forecasted to combine to produce a combined 590,200 barrels of oil in 2008. These two fields are forecasted to more than offset the projected declines from the main Marlin field in the near term.

Santos Basin:
Field Name: Estimated Size (oil barrels): 2006 Production Notes
1. Jubarte 600MBoe 180,000 (2011) Mainly heavy oil
2. Tupi 1.7 BBoe to 10 BBoe (initial) No Production time frame as of 6/2007

The Santos Basin has only been relatively lightly explored to date (mid 2007), although the basin lies in close proximity to Sao Paolo and therefore is a very good prospect to be developed economically. The largest potential discovery was made in October 2006 when PBR's partner UK's BP Group PLC discovered light oil in the Tupi field, initially estimated at between 1.7 to 10 BBoE, however, PBR later reported in 2.07 that it is too early to estimate the economically recoverable reserves of the Tupi discovery.

Notes on Petrobras' SEC vs SPE Reserves:

Petrobras' SPE stated oil reserves stand around 12Bn barrels of oil -- in comparison with its SEC stated reserves of slightly under 10 billion barrels. The significance of this fact is that SPE allows for the reporting of more "probable" oil reserves -- oil reserves that are commercially produceable with less than 90% certainty -- compared to SEC oil reserves guidelines, which mandate only proven (90% certainty) reserves are reported. Note that 12 billion barrels of oil are very large numbers -- in comparison, KMG -- the national oil company of Kazakhstan, reports approximately 8 billion barrels of oil in proven reserves according to the Baker Institute for Energy Studies (Kazakhstan is one of the hottest areas of the world for investment into the oil sector).

PBR Ethanol Production:

Petrobras is the world's largest distributor and exporter of ethanol fuel, exporting approximately 60% of global exports of ethanol. PBR has since 1980 purchased ethanol from Brazilian farms and distributed it for Brazil's own use and for export. Ethanol is at mid-2007 a relatively low percentage of overall net income, at less than 5% ($R189M/$R4.2Bn) of total 1Q 07 net consolidated income. Petrobras intends to expand its exports of ethanol from 850m litres in 2007 to 3.5bn litres a year by 2011 (367% total growth). Petrobras forecasts that ethanol will be Brazil's top commodity export in 2017, overtaking soya -- estimates are that ethanol will contribute $US24Bn to the Brazilian economy in 2015 (up from $US6Bn currently).

Petrobras is entering the production of ethanol by purchasing sugar fields -- integrating its distribution and marketing functions in the ethanol industry -- which may improve margins. Overall, Petrobras is forecasted to significantly improve profits going forward from ethanol fuel, although E&P will remian the largest segment for Petrobras in terms of profitability over the medium term.

Risk: Is Petrobras at Risk Due to Its Exposure to Deepwater Oil Production?

The largest risk to Petrobras is its deepwater oil and gas exposure: deepwater production is more expensive than onshore oil production, and deepwater production tends to undergo faster peak times and stronger declines. These factors are partially mitigated by Petrobras positive prospects, and overall undervaluation based on existing reserves, with faster depletion rates -- the standardized measure takes into account development costs.

Banking Institutions Valued By Net Tangible Assets

Banking Institions mainly derive their revenues and income from three sources: 1. net interest spread between assets and liabilities, 2. fees, and 3. Trading. Large Banking Institutions nowadays have several operating divisions accross several financial service areas but this general rule income derived from net interest spread, fees and trading generally holds. Bank of America, for example, reports its results in three divisions: 1. Consumer and Small Business Banking, 2. Corporate and Investment Banking, and 3. Wealth and Investment Management. BofA derives the largest percentage of its income from Net Interest Margin and Fees, and only in Investment Banking does the third catagory "trading" comprise a relatively large percentage of income (besides fees and net interest margin) -- trading as defined as gains on trading and holding of equities, bonds, options and other investments in its trading division.

Note further that a Bank is generally not a hedge fund so trading is presumably -- although perhaps not always -- a large percentage of income (but note that trading is a very large source of income for many if not most investment banks). Also note that the Wealth and Investment Management mainly accrues income from annual fees on assets under management, typically around 0.5% to 1.5% of total assets.

It follows from that the total amount of tangible assets on the bank's balance sheet -- generally to a banking institution, mainly investments and loans -- is a key source from which revenue and income is derived. It follows, with cavaets and exceptions (explored in detail below), that the size of a banking institution can be approximated by the value of the tangible assets on its balance sheet.

Which Banking Institution Boasts the Largest Tangible Asset Base?

From the above discussion, it is interesting to compare the largest publicly held banking institutions worldwide in terms of assets, as the size of the asset base has a large effect on profitability. A comparison of the largest publicly held banks worldwide at 5/07 shows some surprises in terms of which Banks are the largest (to a US based analyst), as shown below:

Largest Banking Institutions Listed By Tangible Assets:

Ticker; Company Name; PE (TTM/Proj); Tangible Assets; Price/Book Value; Price/Tangible Assets; Market Capitalization
DB; Deutsche Bank; 9.2/10.0; $2.20Tr; 1.60x; 3.4%; $74.9Bn;
BCS; Barclays; 10.4/9.7; $1.8Tr; 2.36x; 5.2%; $94.4Bn
ING; ING; 9.6/9.3; $1.58Tr; 1.76x; 6.2%; $96.8Bn
AZ; Allianz; 9.6/9.0; $1.46Tr; 1.34x; 6.5%; $94.5Bn
UBS; UBS; 13.5/10.7; $1.90Tr; 2.92x; 6.5%; $125Bn
CS; Credit Suisse; 9.2/10.5; $1.03Tr; 2.09x; 7.3%; $74.9Bn
ABN; ABN AMRO; 14.4/14.7; $1.18Tr; 2.65x; 7.5%; $88.7Bn
HBC; HSBC; 13.0/10.7; $1.68Tr; 1.99x; 12.8%; $215.8Bn
JPM; JP Morgan; 11.7/11.1; $1.30Tr; 1.53x; 13.8%; $179Bn
RY; Royal Bank of Canada; 15.9/na; $496Bn; 3.52x; 14.2%; $70.3Bn
C; Citigroup; 13.1/10.9; $1.84Tr; 2.24x; 14.7%; $271.1Bn
BAC; Bank of America; 10.9/9.7; $1.39Tr; 1.72x; 16.3%; $227.5Bn
WBK; Westpac (Australia); 15.5/13.6; $222.5Bn; 3.35x; 18.7%; $41.7Bn
WFC; Wells Fargo; 14.3/12.1; $482Bn; 2.63x; 25.1%; $121Bn

Notes on the above chart: in $US, at exchange rates as of 5/07, listed in ascending order of market capitalization/asset base, source: company SEC filings, and yahoo finance.

Surprising: Deutsche Bank Holds the Largest Asset Base:

Deutsche Bank at 3/07 posted assets of $2.20Trillion, significantly larger than Citigroup, which held assets of $1.84 Trillon at 12.06 -- that is, at an exchange rate of 1.35 Euro/Dollar, Deutsche Bank holds almost 20% more tangible asset than Citigroup. Deutsche Bank also holds 58% more assets than Bank of America. However, Deutsche Bank's profitability is significantly lower than Bank of America and Citigroup, and the market capitalization of Deutsche Bank is only $US74.9Bn compared to $227.5Bn for Bank of America and $271.1Bn for Citigroup. Why is the profitability of Deutsche Bank so much lower than Citigroup and Bank of America when DB posts a significantly higher asset base?

Deutsche Bank and Bank of America Operating Results Analysis:

It is clear that Bank of America and Citigroup are returning a much higher rate on their asset base than Deutsche Bank. In order to answer the conundrum of Deutsche Bank's relative low performance, a comparision by operating division is utilized here.

Bank of America 2006 Operating Performance by Division (Source: 2006 10-K)(note: Bank of America reports in three operating divisions)

I. Global Consumer and Small Business Banking: Assets: $382.4Bn; Return on Assets(06): 2.92%
2006 2005 2006 2005
Revenue: $41.7Bn $28.4Bn Net Income: $11.2Bn $7.0Bn

II. Global Corporate and Investment Banking: Assets: $689.3Bn, Return on Assets(06): 0.99%
2006 2005 2006 2005
Revenue: $22.7Bn $20.6Bn Net Income: $6.8Bn $6.4Bn

III. Global Wealth and Investment Management: Assets: $137.7Bn; Return on Assets(06): 1.74%
2006 2005 2006 2005
Revenue: $8.0Bn $7.3Bn Net Income: $2.4Bn $2.3Bn

2006 2005 2006 2005
Total Rev:$72.4Bn $56.3Bn Total Net Inc: $20.4Bn $15.7Bn


Deusche Bank 2006 Operating Performance (source: 2006 20-F, Euro/US$ exchange rate of 1.35)
(note: DB reports in two main divisions)

I. Corporate and Investment Banking Division: Assets: $1.37Bn; Return on Assets(06): 0.58%
2006 2005 2006 2005
Revenue: $25.2Bn $21.5Bn Net Income: $7.94Bn $6.42Bn

II. Private Clients and Asset Management Division: Assets: $166.9Bn; Return on Assets(06)1.56%
2006 2005 2006 2005
Revenue: $12.4Bn $11.5Bn Net Income: $2.6Bn $2.35Bn

2006 2005 2006 2005
Total Rev:$37.6Bn $33.0Bn Total Net Inc: $10.5Bn $8.77Bn

Discussion of DB and BAC 2006 Operating Performance:

The two most striking differences in operating performance between Deutsche Bank and Bank of America is 1) the low return on Assets in DB's Corporate and Investment Banking Division compared to the counterpart at BAC -- DB accrues only approximately half of BAC's return on assets, and 2) DB does not boast a strong retail banking and credit card network, but BAC does -- and BAC receives a return on assets of an incredible 2.73% on its retail and credit card banking division.

Credit Cards Have Largely Driven Bank of America's Improved 2006 Performance:

BAC's credit card division, according to the Company's 2006 10-K, returned an unbelievable 3.94% on assets in 2006. BAC's credit card division profits -- reported within BAC's Consumer and Small Business Division -- were $5.64Bn in 2006 (28% of total BAC company net income) on credit card assets of $143.2Bn. BAC credit card net income was up 442% from 2005. BAC explains that some of this growth was due to the merger with MBNA and some was due to organic growth, but does not elaborate further in its 10-K. However, it can be inferred with resonably certainty that pricing and/or organic growth was strong for BAC in 2006 as in 2005 the credit card division returned 1.57% on assets, growing to the abovementioned 3.94% in 2006.

Deutsche Bank contrasts with BAC, in that DB does not focus on credit cards, due in part to its historical lack of focus on consumer banking. DB was originally created over 80 years ago to finance trade between large German and International corporations -- and has never focused on consumer retail banking. Therefore credit cards are not a large source of income for DB and not likely to become one in the near future, as DB does not mention credit cards in its investment presentations and only mentions "credit cards" in passing reference 10 times in its 2006 annual report with the SEC.

Reasons for Low Return on Assets for Deutsche Bank's Corporate and Investment Banking Division:

DB funds its corporate banking activities mainly from both money markets and customer deposits, while Bank of America funds its corporate banking activities mainly from low interest cost deposits. As mentioned above, DB lacks the retail presence of Bank of America. This is significant as Bank of America has a significant source of low cost funding from retail banking accounts, on which they pay a low interest rate.

Bank of America maintained approximately $700Bn of deposits worldwide, representing nearly 100% of assets in its corporate and investment bank, while DB maintained $US550M of deposits worldwide, approximately 42% of assets in DB's corporate and investment bank. It remains the subject of another post if DB is generating an acceptable rate of return from its mix of deposits and money market funding, but it is clear that under similiar interest rate conditions it won' t match the returns on assets of Bank of America.

Note also, provisions for loan losses at Bank of America and DB are approximately equal and do not account for the differences in returns on assets.

Conclusion:

As analysed in this post, the difference in how the assets are funded and in what activities makes a difference in the profitability of the firm. Still it is a useful analysis to determine how, more exactly, the banking institutions derive income. In the case of Bank of America and Deutsche Bank, the differences in profitability mainly stem from the sources of funding (deposits vs money markets) and credit cards. Deutsche Bank remains interesting as an investment due to its high amount of assets that represent earning power and its relatively low market capitalization currently (5/07). Bank of America's credit card division should be closely watched as it is a major determinant of future income.

Insurance Companies Valued By Net Tangible Assets

Insurance companies derive income mainly from two sources: 1) income derived from policy sales -- insurance policy and annuity sales -- and 2) income derived from their investment portfolios. The insurance business has been described by Warren Buffett (who knows the insurance business extremely well) in his legendary annual reports as follows (here paraphrased): an insurer collects funds from policy holders, invests those funds, and then over time pays claims to policy holders from its received funds. And, as usually over time competition drives the sum of payments for claims to equal or exceed the total amount of funds received from policy payments (ie the "Combined Ratio" tends to trend towards 100), the rate of return on the funds is a key driver of the overall earnings for an insurance company.

The Significance of a Large Investment Portfolio to Market Capitalization for Insurance Companies:

The larger the investment portfolio compared to the market capitalization of the insurer may mean that the insurer is undervalued, with caveats (caveats are discussed below). That is, an intelligent investor would like to see a large sum of tangible assets and net assets (assets-liabilities) on the balance sheet compared to the market value of the firm for a possible value investment.

Note that on the balance sheet of insurance companies, most of the tangible assets of an insurance company will be the insurer's investment portfolio, while on the liabilities side, the main liabilities will be estimated future claims by policy holders and debt. Valuation of the asset side is relatively straightforward -- as most of the investment portfolio is invested in bonds, which are written at cost or at market value. The liability side of the insurance company is the larger source of uncertainty, as the estimate of future liabilities is the assessment of the insurer's actuary and may be different depending on low probability events ("acts of God") and possible miscalculations by the actuary. But note that generally the larger the firm, the better the law of averages works for the valuation of the liabilities side. For example, more confidence can generally be placed on AIG's future expected policy claims (liabilities) vs a sub-$50M asset insurance company.

Caveats -- mentioned above -- concerning this measure of the assets to market value of the insurance firm include:
A. Whether the insurer is gaining market share, (that is, an insurance company with a declining market share may not be an attractive investment even if it has a large and profitable investment portfolio)
B. has a quality credit rating --lower rated insurers should sell at a lower multiple than higher rated insurers
C. has estimated its future policy claims appropriately, (the investor does not want to see too many "surprises" in policy claims)
D. has written appropriate policies -- is pricing risk appropriately.

Analysis of the Largest Insurance Companies Worldwide:

An analysis of the largest publicly held insurers (including life and P&C and excluding reinsurance only)-- shows that there is a large discrepancy between the largest insurers in terms of price to tangible assets, but less of a discrepancy in price to tangible book value, as shown in the following chart (companies listed from lowest to highest price/tangible assets):

Ticker; Company;P/E (Hist/Proj); Tangible Assets ($US); Price/Book Value; Market Cap/Assets; Market Capitalization
ING; ING; 9.6/9.3; $1.58Tr; 2.08x; 6.2%; $96.8Bn
AZ, Allianz; 9.6/9.0; $1.46Tr; 2.28x; 6.5%; $94.5Bn
MET; Metlife; 8.6/11.5; $527.5Bn; 1.76x; 9.6%; $50.8Bn
PRU ; Prudential; 14.9/12.7; $454.3Bn; 2.03x; 10.5%; $47.9Bn
AIG; AIG; 12.6/10.4; $869.8Bn; 2.02x; 21.5%; $187Bn
ACE; Ace Ltd; 8.2/8.6; $65.0Bn; 1.65x; 31.3%; $20.4Bn
CB ; Chubb Corp; 10.0/9.0; $50.2Bn; 1.65x; 44.0%; $22.1Bn
LFC; China Life; 10.2/22.4; $69.4Bn; 2.56x; 51.0%; $35.4Bn

Discussion of the Largest Insurance Companies' Asset Values:

A few figures are striking from the above chart. First, the total assets of the German based Allianz and the Netherlands-based ING are huge -- larger than AIG in the United States (AIG is the largest insurer in the US) by a significant margin -- Allianz holds tangible assets of $US1.46 Trillion at current Euro/Dollar exchange rates compared to AIG's $US869.8Bn in tangible assets. In other words, Allianz holds 68% more tangible assets than AIG, and ING holds a similar number of assets as Allianz.

Discussion of the Significance of the Higher Asset Values at AZ and ING vs AIG:

The first observation concerning the higher asset numbers is that AZ and ING are much more levered (hold more liabilities to equity) than AIG -- AZ is levered at 21.8x assets to equity, ING is levered at 29.0x assets to equity, while AIG is levered at a much lower 8.6x assets to equity. In other words, if AIG was levered at the same level as ING (29.0x), AIG would hold an incredible $2.9 Trillion of assets. Note also that AIG's net equity value (assets minus liabilities) is approximately $100Bn compared to $70.2Bn for Allianz; AIG on this measure can be considered a larger company.

However it would not be straightforward for AIG in the above example to add a very large sum of tangible assets. Note that these are the two ways in which insurance companies gain assets, by selling either 1. insurance policies and/or 2. annuities (it is generally not the case that an insurance company will borrow money from the bond market or banks only to invest in bonds). In order for AIG to gain the number of assets of either Allianz or ING, AIG would have to either 1) underwrite a sum total of 70% more insurance policies than AIG currently has on its books and fund these policies from debt, and/or 2) sell a very large number of annuities. It would likely be very difficult to gain an incredible $700M of new policies for any firm, at an acceptable risk/pricing profile.

It follows that, the high value of tangible assets reflects that both AZ and ING are huge firms, which dominate their respective country's insurance markets and the EU. Further, one could say that the tangible assets that both AZ and ING are most likely "quality" -- meaning assets in which the companies can derive increased earnings from investment earnings -- although the high leverage places more importance on the soundness of the company's respective underwriting policies and liability and interest rate management policies.

Do the Higher Asset Values of AZ and ING Mean that they are Undervalued?

It is argued here that both AZ and ING are somewhat undervalued, compared to the large insurance universe. The price/tangible book value of AZ and ING are equivalent to AIG at approximately 2x, but the assets are as mentioned above higher, leading to higher earnings leverage with more variability. The S&P credit rating of AZ and ING are AA- and AA respectively, compared to AIG's AAA rating -- so all insurers have very strong ratings, although it is possible AZ is in line for a credit upgrade with a few more quarters of strong profitability. The European economies are improving currently (mid-2007) with reforms instituted.

Lower Differences in Price/Tangible Book Value in the Large Insurance Universe:

The second salient feature of the above is that the differences in the price/tangible book value is less dramatic than the price/asset values. Possibly an interpretation of this is that the market will give limited credit to a higher risk profile -- more asset leverage. Further, all the large insurers listed above have many analysts following them, so the likelihood of hidden value between the firms is less.