TSX Group -- An Undervalued Takeover Candidate

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

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.

Who Will Own the Most Profitable Heavy Oil Production Technology?

Heavy oil accounts for more than double the resources of conventional oil, according to Schlumberger. Most of the current and historical oil production has come from conventional reservoirs, which contain oil that is sufficiently viscous to be pumped utilizing well pressure and non-specialized pumps. Heavy oil is more viscous (thicker, like molasses) than conventional oil so is much more difficult to extract from the ground. Currently, the volume of heavy oil production is currently only a fraction of the production from conventional oil. However, going forward, it is almost certain that the world's dependence on heavy oil production will increase due to the massive resource base of heavy oil and projected increased demand from Asian and developing countries.


Source: Schlumberger

There are several methods of heavy oil extraction currently, but, as the heavy oil industry is still in its beginning stages, there is not a de facto "standard" of heavy oil extraction for the industry -- one that is low cost and efficient, that can be applied across most heavy oil deposits. The question that is most relevant for investors is: will there be a dominant, patented technology for the development of heavy oil reserves? And secondly, if so, which firm will capture and patent this technology? These questions will be explored in this article.

Relevance of Heavy Oil Production Technologies to the Historical Success of Howard Hughes, Sr
There is (in the author's mind) a relevant comparison of the new technologies for the development of heavy oil to the historical example of Howard Hughes, Sr, who made his fortune mainly by inventing and patenting a drill bit that could drill through hard rock, which was, in turn, utilized by the majority of the oil industry to develop conventional oil reserves. Hughes Sr's drill bit became the foundation for Hughes Tool company which later merged to become the oil services firm Baker Hughes. Hughes Sr. patented drill bit design was so profitable and necessary for the development of conventional oil reserves that Daniel Yergin, writing in his epic book "The Prize" described Hughes' pricing leverage as "highway robbery." This article will explore if there is a similar technology, such as Howard Hughes Sr's patented drill bit, that is applicable to heavy oil extraction.

Background on the Heavy Oil Industry:

The interested reader is encouraged to read the heavy oil sections of Rigzone and wikipedia, as well as Schlumberger's excellent heavy oil website for a background to this very important topic of heavy oil. A brief discussion and summary of heavy oil is presented as follows. The majority of heavy oil deposits are found in two countries, Canada -- in its Albertan oil sands, and Venezuela -- in its Orinoco belt -- both of which contain reserves of recoverable oil comparable to those of Saudi Arabia. Approximately 90% of heavy oil is found in the Western Hemisphere -- mainly in Canada and Venezuela, although significant deposits exist in California, Alaska, Mexico and Brazil, as well as in Russia -- while 90% of conventional oil is found in the Eastern Hemisphere -- mainly in the Middle East. Most of both heavy oil deposits in Canada and Venezuela are underground, below where they can be mined by mining methods -- although approximately 10% of the surface area of the Albertan oil sands can be mined (and this area is already nearly 100% leased by firms, as I discussed in my earlier Canadian oil sands article). The Venezuelan heavy oil deposits are a bit less viscous -- able to flow more easily -- than the majority of the Canadian oil sands -- and therefore, so far, different and methods have been used to extract Venezuelan heavy oil deposits than the Canadian oil sands deposits.

Oil Sands Carbonates:

Note that approximately 50% of the Albertan Oil sands by area are in the form of carbonates, which means the oil sands are trapped in rocks, in a similar way to oil shale. The carbonate formation forms a "triangle" in geographic terms across the Canadian heavy oil deposits. The carbonates require different technologies for extraction than traditional heavy oil, as will be discussed below.

Source: Geological Survey of Canada

Heavy Oil Extraction Technologies in Usage Currently:

There are 5 main technologies currently in operation in the heavy oil industry for the development of traditional heavy oil (not heavy oil carbonates), with varying cost efficiencies and recoverability factors: Cold Heavy Oil Production with Sand, Steam Assisted Gravity Drainage, Mining, Cyclic Steam Stimulation, and Vapor Extraction. Note that most of the techniques were pioneered in Canada due to Canada's relatively early development of its Albertan Oil Sands. These technologies are described briefly as follows.

1. Cold Heavy Oil Production with Sand (CHOPs) -- this technique utilizes a submersible pump that can pump thick fluids, down to the heavy oil and pumps from there, allowing sand and other rocks up the wellbore -- as it is difficult to separate out the sand from the heavy oil. CHOPs is usually utilized without additional heating or chemical treatment. As such, it can be considered the most simple extraction method for heavy oil that is deep below the surface. It is believed the majority of Venezuela's heavy oil is produced using CHOPs. (Venezuela produced an estimated 625,000 barrels per day of heavy oil in 2006 through its national oil company, PDVSA.)

- CHOPs Advantages: Straightforward, relatively simple production method, continuous production, cost effective if heavy oil is viscous enough (as in Venezuela)

- CHOPs Disadvantages: Inefficient if the heavy oil is too thick (as in many areas of Canada), expensive to maintain and/or replace specialized submersible pumps, estimated only 5-10% of total heavy in place can be recovered with CHOPs, "technology stretched to the limits" according to Schlumberger so low future productivity improvements likely possible

2. Steam Assisted Gravity Drainage (SAGD) -- this method of heavy oil extraction involves melting the heavy oil with steam, then collecting the melted heavy oil by vents. A video demonstration of SAGD can be found at Rigzone. Imperial Oil of Canada (majority owned by Exxon Mobile) has done much of the pioneering work on SAGD in its Canadian Oil Sands properties, and is the largest producer of heavy oil by SAGD methods currently. According to Imperial, SAGD works well when the heavy oil is able to move vertically with relative ease (in petroleum geology terms, "good vertical permeability") -- therefore the usage of SAGD depends on the underground geological conditions of the heavy oil resource.

- SAGD Advantages: Continuous production, technology able to cost effectively access less viscous heavy oil (bitumen), room for efficiency improvement in process

- SAGD Disadvantages: Concerns over CO2 emissions and water usage [although water can and is recycled], uses natural gas (to heat the water into steam), relatively low recovery rate of oil in place of less than 50% [but future improvements of recovery rate are possible according to Imperial Oil], mainly only applicable to heavy oil reservoirs of at least 40 meters thick

3. Mining Methods -- this technique involves digging the oil sands which are available near the surface and transporting the heavy oil to processing facilities. The majority of the Canadian oil sands currently (12.07) are produced in using this method, although heavy oil produced in Canada by in situ methods is increasing. Suncor and Syncrude are by far the largest producers of oil sands in Alberta by mining methods, although Imperial Oil has new mining projects coming on line.

- Mining Method Advantages: Proven, cost effective with efficient use of equipment, straightforward to increase production, recovery rate 80-90% of heavy oil in place

- Mining Method Disadvantages: concerns over CO2 usages, heavy equipment and labor intensive, only a small amount of heavy oil sands can be produced by mining methods, possible concerns over environmental damage

4. Cyclic Steam Stimulation (CCS) -- this technology involves a multi-step process of first, steam injection, then a period of up to several weeks of steam "soaking" (heavy oil mixing with the steam), then a period of recovery of the melted heavy oil. This technology is demonstrated in video format at Rigzone. Imperial Oil was the pioneer of this technology, and holds patients with regards to usage of CCS. CCS is an older technology than SAGD, but still produces a majority of its "Cold Lake" operations using CCS due to geological considerations at Cold Lake (Cold Lake is Imperial Oil's largest in situ producing region). In theory, SAGD is the more efficient technology due to the fact that heavy oil recovery is continuous and, further, SAGD is newer, but CCS is more efficient than SAGD in geological formations in which the oil can move relatively easily horizontally (good "horizontal permeability"), according to Imperial. Imperial Oil also announced an improvement to CCS in 2007, which involves adding a hydrocarbon solvent to the bitumen to improve efficiency and recoverability, and is now using this solvent in its operations.

- CSS Advantages: Cost effective, applicable to heaviest grades of bitumen

- CSS Disadvantages: CO2 and water intensive [although water can be recycled], heavy oil is only collected periodically, not continuously, recovery rate is somewhat low at 15-20% [but possible to improve according to Imperial Oil], mainly only appilcable to heavy oil reservoirs of 40 meters thick and above

5. Vapor Extraction (VAPEX) -- VAPEX involves injecting the in situ heavy oil with chemicals, CO2 and/or hydrocarbons, in order to make the heavy oil more viscous -- and cut down on water, energy usage and pollution -- which can then be extracted efficiently, and possibly also improve total oil recovery rates. A video demonstration of VAPEX can be found at Rigzone. According to the technology editor of worldoil.com, VAPEX is the most promising of the new in situ heavy oil production technologies, although it has not been utilized on a large scale yet. In theory, VAPEX can be combined with SAGD and/or CCS above, and, in fact, Imperial Oil has started utilizing a hydrocarbon solvent to improve efficiency in its Cold Lake operations in 2007.

- VAPEX Advantages: Possible higher recovery rates, efficiency and less pollution than other above methods, applicable to all grades of heavy oil

- VAPEX Disadvantages: compared to other methods, relatively untested, some combinations of solvents will probably not work so possibly expensive to carry out trials of method technology

Future Heavy Oil Technologies Proposed:

These technologies for the extraction of heavy oil have been proposed but have not undergone significant field testing, on the scale of the five technologies listed above, as of late 2007:

1. In situ combustion: proposed by both India's Oil and Gas Corp and the independent firm PetroBank, this technology involves "burning" the heavy oil underground and using the heat and the force of the combustion to move oil and gas through collection vents. Petrobank provides an overview and video demonstration of its in situ combustion "THAI" technology on its website. A few years ago, in situ combustion was viewed with skepticism by heavy oil insiders such as Schlumberger, who considered in situ to be undesirable due to the fact that it does not leave oil for future recovery (combustion rates of the total oil resource were thought at first to be high), and, further, in situ combustion did not have a large number of successful demonstrated successes (the oil industry tends to be conservative and new technologies face an uphill battle). Further, many industry insiders scoffed at the notion that the oil could be "upgraded" underground -- upgraded meaning shortening the hydrocarbon chains -- which is what the in situ production proponents were proposing that combustion could do.

However, in situ combustion has fared well on several small scale trials as reported by Schlumberger's heavyoil.com. Recovery rates have been shown at 80%, with less than 10% of the total resource consumed in the combustion flood, while some upgrading of heavy oil resource as been shown. Start up costs are about half that of SAGD according to Petrobank. Petrobank stated that it expects its THAI to be economical up to $30 per barrel of oil. Perhaps most impressively, the in situ combustion proposes to make the production of heavy oil resources with less than 40 meters thickness economic -- Imperial Oil's SAGD and CCS are only economic at 40 meters and greater resource thickness levels. There are many areas in which the heavy oil resource is only 20 or 10 meters thick, which means in situ combustion could have a large number of applicable areas. So far, the trials have not produced more than 1,000 bpd per well
and the temperatures for larger production may be difficult to control, as temperatures at the 1,000 bpd well ranged between 400 degrees C and a very high 1,000 degrees C. Further, it is critical in in situ combustion to understand in detail the geological characteristics of the resource through seismic and survey data, before the beginning of the procedure. Operators also have a negative memory associated with in situ combustion stemming from failures in California in the 1970's (Petrobank insists that these failures have been fixed with the new method). With SAGD, It is likely many more trials will be needed before in situ combustion becomes a major new producing technology, but the possibilities are certainly intriguing.

- In Situ Combustion Advantages: Relatively low start up costs, higher recovery rates than SAGD in trials, less water and natural gas used than SAGD, partial upgrading of heavy oil resource, utilization of under 40 meters thick heavy oil resource

- In Situ Combustion Disadvantages: "one time through only" -- resource will be produced fully and no further extraction by other methods is possible after utilization, unproven application to large deposits, unproven scalability, possible difficulty in controlling fire flood across larger reservoirs

2. Electricity and Microwave Heating -- Two smaller firms (to the author's knowledge) have proposed electromagnetic radiation and electric heating of the bitumen for improved recovery -- Global Resource Corporation (microwave technology) and E-T Energy Ltd (electric heating of the oil sands). Only E-T Energy has initiated a trial of its technology -- with moderately successful results, as recounted on its homepage. E-T Energy estimates that 500 MW would be necessary to successfully produce 120,000 bpd of oil in the Albertan oil sands. Depending on the excess supply of power in the area, E-T Energy's technology likely has applications. Global Resource Corporation -- whose propriety technology consists of altering the frequency of the microwave in order to optimally heat certain substances -- is focusing mainly currently on microwaving used tires to produce carbon black, gas and synthetic oil -- so thus has been somewhat distracted in the near to medium term on a trial for microwaving oil sands. (note that Global Resource Corporation is currently a very small company, with less than $1M of assets on its balance sheet according to its latest 10-Q). A trial is likely a few years away for Global on microwaving oil sands. In theory, however, the microwave technology appears more efficient than passing simple electric current through the oil sands, so perhaps E-T Energy, or another heavy oil firm who wants to heat the oil sands would be interested in Global's microwave technology -- but at this point both technologies are in the theoretical stage.

Will there be a dominant oil sands production technology?

Taking in the lessons learned from the above survey, perhaps a more appropriate question than the above is: which technology will be the most profitable for underground deposits going forward? That is, when one asks, "Will there be a Howard Hughes of the heavy oil industry," one is mainly referring to technologies to develop underground heavy oil deposits, due to the fact that mining methods are firmly entrenched as the technology of choice for extraction of heavy oil deposits near the surface.

Much of the choice for the extraction technology depends on the characteristics of the underground heavy oil resource. For large (over 40 meter in thickness) non-carbonate deposits, it is the author's opinion that some combination of VAPEX and SAGD or CSS will be the most effective method, which would benefit Imperial Oil, which has patents on all three processes. Note also SAGD and CSS need capping shale, but preliminary geological data show that only 10% of Albertan non-carbonate oil sands lack capping shale. It is tentatively concluded that the majority of underground heavy oil is appropriately produced using Imperial Oil's technology. As noted above, Imperial Oil is the oldest producer of heavy oil and the largest currently, and therefore it makes sense that Imperial should have the most proven expertise with heavy oil extraction technologies. Imperial oil is not expensive currently at 15x earnings and a $45Bn market capitalization, which makes IMO an intriguing long term buy based on its heavy oil potential. Winner: Imperial Oil.

Heavy Oil Service Firms:

Schlumberger (SLB), and to a lessor extent, Halliburton (HAL), stand to benefit greatly from the coming heavy oil boom. All the in situ technologies are optimized by extensive 3-D mapping, resource characterization and understanding of the resource, in which both Schlumberger and Halliburton have world leading technologies. Further, most in-situ technologies require submersible pumps, which Schlumberger is the world leader in terms of technology (the submersible pump industry is a good subject for another post, but in summary, Schlumberger makes world-class, technologically advanced oil pumps). However, Schlumberger is already slightly pricey currently at 23x earnings -- but is a buy candidate based on its heavy oil potential if the stock drops further.

Notes on Firms with In Situ Combustion Technology:

Petrobank is a higher risk, high return play -- the stock has already increased 250% this year, and now boasts a 100x p/e ratio and a market capitalization closing in on $4.0Bn. If the author was forced to predict the future viability of the in-situ combustion process, the author would say that it will find short term success in heavy oil resources that are not viable by other means -- so this would include heavy oil seams of under 40 meters. Most likely the customers of the Petrobank's process will be smaller companies -- and of course Petrobank itself, as it has its own oil sands territory -- with more less attractive lease areas of the Albertan oil sands. It is unclear if Petrobank will be successful in Venezuela, because Venezuela is negotiating heavy oil in situ combustion agreements with India's Oil and Natural Gas Corp -- which boasts an in situ combustion technology similar to Petrobank's technology. Further, Petrobank's technology is likely not applicable to heavy oil deposits which exist in permafrost, in the far North, due to the fact that the high heat generated will destabilize the permafrost and the heavy oil deposit. In situ combustion is also most likely not applicable to oil sands carbonates, due to the high concentration of rock with the heavy oil (so a fire flood would not likely be able to be generated). But there are still many areas around the world that would be interested in a relatively low set-up cost production method with high recoverability factors.

Oil Sands Carbonates Production:

One firm (that the author is aware of) has proposed and is in the process of implementing a production technology for heavy oil from oil sands carbonates -- OSUM Oil Sands Corporation. The 100% privately held OSUM is proposing an underground collection method that would heat the oil sands carbonates (carbonates are, as described above, heavy oil trapped in rocks) above a long tunnel, then collect the melted bitumen below in the tunnel and pump the heavy oil to the surface. Most of the work force would be underground leaving a low environmental footprint on the surface. OSUM is proposing to use steam to heat the bitumen, although it is possible they could be interested in other heating methods (microwaves, electricity) in the future. The first production trials are set for 2008, with full production of up to 100,000 bpd thereafter. This underground method looks quite promising for the production of oil sands carbonates, but unfortunately most investors cannot participate as OSUM is 100% privately owned.

Political Issues Concerning Heavy Oil in Venezuela:

Note that it is difficult to see foreign firms making tremendous profits in Venezuela under the current (Hugo Chavez) administration. Schlumberger is working on Venezuelan heavy oil, but Total -- which had developed Venezuelan oil sands -- was kicked out of the country in 2002 and replaced with PDSVA without significant compensation. The heavy oil resource is huge but it is the author's opinion that firms with appropriate technology catered to the specific geological characteristics of the Orinco belt face very significant political obstacles. The same rule also applies to firms operating in Russia. This also limits the overall profit potential for a firm such as Imperial Oil, which may have the best technology -- its market is Canada first and other areas a distant second.

Conclusion:

This article has discussed the current and emergent technologies for the production of heavy oil. It is concluded that, due to the wide range of heavy oil deposits, several technologies will be very useful in the future, and allow for high profitability to the designers and executers of these technologies -- including VAPEX, SAGD and CSS, as well as in situ combustion. These technologies point to future profitability for Imperial Oil and, for a higher risk, higher return play, Petrobank. Also noted was the fact that Schlumberger should see its share of profits from its expertise in servicing the heavy oil industry. However, it should be noted that it is possible that a certain up and coming technology has been missed by the author which could revolutionize the heavy oil industry. Further, axillary technologies, such as steam production equipment, carbon trapping and water recycling equipment, which are necessary for the production of heavy oil but not directly addressed by the main heavy oil production technologies, was not addressed in this article and is an important subject for a future article.