Economic Backdrop

There remains significant downside risk to world GDP and oil consumption estimates. In its most recent World Economic Outlook Update (November 2008), the International Monetary Fund (IMF) slashed its 2009 world GDP growth estimate from 3.0% to 2.2%. This is significant because it now implies a worldwide recession for 2009, according to the IMF's informal definition of a recession as growth of less than 3%, and it is the first time a coincident recession has occurred in the United States, Japan, and Europe in 60 years. The IMF further revised down its OECD growth estimate from 0.5% to -0.3% and its non-OECD estimate from 6.1% to 5.1% (Exhibit 1 & Exhibit 2). Leading indicators in the OECD and non-OECD are also not encouraging.

The Year in Review

It has been a year of record misery: the largest bankruptcy, largest bank failure and biggest Ponzi scheme in U.S. history; $720 billion in write-downs and losses by financial institutions; Global stock markets lost about half of their value in 2008, or $30.1 trillion dollars in market valuation wiped out.

The government is now deciding who gets access to capital.

This is the first full-fledged credit collapse and debt deflation since 1930, bringing with it a violent economic decline and a surge of unemployment.

For half a decade, a toxic stew of abusive and explosive mortgages, sub-prime securitization and complicit ratings companies was allowed to simmer, piling leverage on leverage, while credit default swaps spread risk until risk no longer could be traced. This was market failure.

If market losses weren’t bad enough, as much as $50 billion went up in smoke when New York money manager Bernard L. Madoff confessed to authorities to what may be the biggest swindle in history -- an alleged Ponzi scheme that spanned the globe.

Bear Stearns Cos. was taken over by JP Morgan Chase & Co. in March after a funding crisis triggered by losses from sub-prime mortgage investments. Merrill Lynch & Co., facing a crisis of its own, sold itself to Bank of America Corp. and the last two major investment banks, Goldman Sachs Group Inc. and Morgan Stanley, converted to bank holding companies and got capital injections from the U.S. government.

Lehman Brothers Holdings Inc., with assets of $639 billion, filed the largest bankruptcy in U.S. history on Sept. 15. Its creditors may have lost as much $75 billion. The Treasury and Federal Reserve sought to minimize “intervention to preserve market discipline.”  Thus the decision to let Lehman fail. The result was suspicions of cronyism and more panic.

In the largest U.S. bank failure, Seattle-based Washington Mutual Inc. collapsed in September with $307 billion in assets. There were 25 bank failures in 2008, the most in 15 years, according to the Federal Deposit Insurance Corp.

Citigroup Inc., whose shares lost 78 percent of their value this year, needed $20 billion in U.S. bailout funds in November on top of an earlier $25 billion infusion of capital. The government also guaranteed $306 billion of the bank’s troubled assets.

The wave of write-downs and losses that swamped financial institutions around the world reached $720 billion this year. It also eroded employment: 221,360 job cuts in the financial-services industry were announced.

The U.S. government was forced to rescue the world’s largest insurance company, American International Group Inc., with a $152.5 billion package of investments, loans and capital infusions. It had to start purchasing corporate commercial paper to give companies the capital they needed to meet payrolls and conduct routine business.

Overall, the U.S. federal government has committed $8.5 trillion in trying to jumpstart a shrinking economy. General Motors Corp. and Chrysler LLC will get $13.4 billion in federal loans to stay afloat until President-elect Barack Obama’s administration can devise a rescue plan of its own.

The debacle amounted to a loss of faith, especially for individual investors. They pulled $215.7 billion from equity mutual funds in the first 11 months of the year, according to Investment Company Institute. That compares with a $91 billion inflow of funds for the same period of 2007. The total net assets in all types of mutual funds fell by $2.67 trillion in the first 11 months of 2008, the institute reported.

Energy

The price of oil has reached the price of demand destruction only twice in the last 18 years. The first occasion was during the Iraq conflict, although this was temporary and hence the net impact on demand was limited. The second has been the most recent rally driven by a combination of strong demand from emerging markets, loose fiscal policy, weak supply growth and money flow into commodities.

Demand for crude oil in the United States fell by the most in September, in percentage terms, since August 1980, according to the Financial Times. In absolute value, demand fell by an astounding 2.6 million barrels per day.

Oil demand in China may be softer than many expect. A recent government report showed confidence among Chinese businesses is rapidly waning. Meanwhile, in November, oil demand was down 3.9% from a year ago.

Given the declining outlook for demand, it was therefore unsurprising that in its November Oil Market Report, the IEA revised down its 2008 oil demand estimate by 330 kbpd to 0.2% growth and its 2009 oil demand growth estimate down by 670 kbpd to 0.4% growth to reflect the IMF's lower GDP projections. However, despite the fact that these cuts are possibly the largest one-month revisions made by the IEA, we still believe that they don't go far enough.

Declines in demand have been offset by weaker production from the North Sea and Russia as the credit crunch hits investment. Until Russia overhauls its fiscal system it is unlikely that Russian oil production will stop its decline.

Impact of Non-OPEC Production – “The Stripper Wells”

While OPEC has arguably modeled itself as the world's swing producer, it is actually non-OPEC production, such as North American onshore volumes, that has tended to swing global supply the most during severe upturns or downturns in the cycle.

A staggering 18% of U.S. oil production came from wells that produced less than 15 barrels of oil a day. Micro-caps and privates today account for around 55% of North American gas production and 46% of oil production and have a significantly higher cost structure than any of the top 45 E&P’s. This group accounted for over 85% of all the oil wells in the U.S. in 2006, and investment in these wells is highly dependant on oil prices. Production from these so called "Stripper Wells" are considered some of the most marginal in the U.S. Output from these wells has responded significantly in the past to oil prices hitting the cash cost.

This supply dynamic is particular to the North American oil industry, due to the industry structure where

such a high proportion of production comes from wells that produce hardly any oil.

Non-OPEC shut-ins and accelerated declines will have a greater effect in stabilizing and reversing oil prices in 2009 versus the less secure OPEC cuts.

As the largest non-OPEC producer, Russia's oil output can significantly impact the global crude market. The fiscal environment in Russia is more influential on domestic production than oil prices.

With oil prices dropping to the cash cost it is unlikely that the North Sea will receive the extra investment necessary to stimulate higher production rates and stave off decline over the longer term. However, a crucial distinction with U.S. onshore production is that while future investment in the industry may be impacted during low oil price periods, current production is, in our opinion, unlikely to be shut-in to the same extent as the U.S. due to the higher well volumes of offshore fields and the greater difficulty in partially shutting in production from offshore fields.

As for OPEC, average OPEC spare capacity was less than four million barrels per day (bpd) from 1996 to 2007, according to the International Monetary Fund using data from the International Energy Agency.

Assuming that the Saudis do cut production, this suggests that OPEC spare capacity is likely to grow 3.3 Mbpd in 2009 and 3.6 Mbpd in 2010, up from 2.3 Mbpd in October of this year. OPEC spare capacity is then forecast to grow steadily over the next few years albeit at a slower rate as demand rebounds (Exhibit 3).

Therefore, oil demand would need to rise by more than two million bpd to take us back to a position of tight OPEC capacity, assuming no net additions to OPEC capacity and no additional supply from non-OPEC producers. This event could be as much as two to three years off.  The IEA is forecasting a total rise in oil demand of 350,000 bpd for 2009 after a scant 120,000 bpd increase in 2008.

Even if oil demand recovers to growth rates projected in the IEA's World Energy Outlook 2008, it will not be until 2012 that OPEC spare capacity declines to levels that would take away OPEC's ability to drive prices lower. The assumption here is that oil production capacity does not rise over the next three years. In reality, the IEA expects non-OPEC demand to rise by 600,000 barrels in 2009. So even if capital spending in the oil sector slows over the next few years --and it surely will-- we will still see some increases to production capacity.

Exhibit 3

Given the fact that demand over the next two quarters will remain negative, and that numbers need to be revised down, the recovery looks unlikely to occur before mid-year 2009 at the earliest. Moreover, global consumption will need to go positive, the U.S. will need to post solidly positive GDP growth and the U.S. dollar will need to weaken before this can occur.

Looking further out however, it is increasingly clear that the next up-cycle could be as violent as the current one had been given the reductions in long term capacity that are currently occurring as financing becomes restricted. In this respect the outlook appears very similar to the first U.S. gas cycle in 2000/2001 and suggests that by mid-2009 investors could become more constructive on energy in anticipation of this event.

The Canadian Dollar

The Canadian dollar declined this year after it reached parity with its U.S. counterpart in September 2007 following a 60 percent climb in the prior five years that was fueled by rising commodity prices. Commodities account for about half of Canada’s export revenue.

The Canadian currency dropped 18 percent against the U.S. dollar this year, the biggest decline since the start of records in 1972. The loonie was one of 14 of 16 major currencies that fell against the U.S. greenback. The Canadian dollar fell 33 percent to 74.39 yen, also the biggest all-time drop.

The North American Majors

The key components that have driven earnings per share growth in energy companies are (in order of importance): commodity price movements, production growth and share buybacks.

When commodity prices recently rocketed, the share prices of the Major Integrated Oil Companies (the Majors such as Exxon and Chevron) did not necessarily follow suit, as investors opted to lever up their exposure to commodities through Exploration & Production companies instead (the E & P’s such as Chesapeake, XTO and Ultra Petroleum).  This was largely because the E & P's had much greater leverage to commodity price growth through their significantly higher production growth.  Hence, going into the next commodity up-cycle, it makes sense that the Majors should weight themselves more heavily towards upstream exploration and production potentially through acquiring cheap/distressed E & Ps with strategic assets.

ExxonMobil, the largest of the Integrateds, has been pursuing the most aggressive share buy-back scheme. The company had minimal production growth from 2002-2007 and is forecast to have limited production growth out to 2012. However, Exxon can still improve EPS significantly by using excess cash to buy back large numbers of shares but investors have criticized the company for spending more on share buybacks than energy exploration and refinery expansions as they prefer growth through production. We suspect that ExxonMobil will use the bottom of this oil price cycle to cherry-pick assets, or form strategic JV’s to bolster production growth in the future as production per share growth through buybacks on top of a flat production profile will not be as competitive as pure organic growth itself.

Therefore, if a large integrated energy company currently did not have a growth profile, we believe the strategic acquisition of assets (or companies) with a strong production growth profile would be a smart move at the bottom of the cycle. 

Natural Gas

Exxon Mobil abandoned the second-largest U.S. natural gas region after the commodity price tumbled 44% since July 2.  It sold its stakes in gas fields and a pipeline in Texas’s Barnett Shale to Harding Energy Partners LLC. Harding, in turn, sold the gas fields and 130-kilometre pipeline to Chesapeake Energy, the second-largest U.S. natural gas producer

The Barnett Shale may hold 39 trillion feet of recoverable gas, or enough to supply the entire U.S. for almost two years, according to a 2005 study by the U.S. Energy Department. The region trails only the Rocky Mountains in terms of gas production according to the U.S. Geological Survey

Regarding lower prices and the outlook for gas in Canada - this is a tale of two provinces. Alberta's gas business, with its uncertain regulatory environment, is becoming increasingly marginal and current prices make much of Alberta's gas sub-economic. In contrast, British Columbia has more favorable terms and attractive shale plays, which have caused horizontal drilling and acreage costs to rise quickly.

While oil prices could remain low for some time, gas prices cannot remain below the marginal cost of production for more than a few quarters.

Alberta Royalty Changes

In order to promote drilling in the province, the Alberta Government has offered a transitional royalty scheme that would apply to new wells drilled between 2009 – 2013 that are at depths of between 1,000 to 3,500 metres. Producers will have a one-time option of selecting new transitional royalty rates as an alternative to the royalties proposed under the new royalty framework (NRF). Oil & Gas Producers are better off or, at worst, unchanged under the new program with high rate natural gas wells obtaining the most favourable treatment. Rates are capped at 30% on natural gas, allowing investors to participate in higher commodity prices to a greater degree than under the NRF that has royalty rates of up to 50%. This program does not affect oil sands nor does it apply to existing natural gas and oil wells.

Reserves Revisions

With the oil price at the end of 2008 likely to be almost half the level it was at the end of 2007, there is a real risk that many E&P companies may be forced to make negative revisions to their booked reserves.  The reasoning behind this is that, under current SEC regulations, oil companies must re-calculate their proved reserves estimates by re-running project economics under the assumption that future oil/gas prices match those on the last day of the year. The implication is that the steadily climbing oil and gas prices have been masking a trend of declining reserve additions from exploration activities by gradually enhancing the economics of existing projects.  However, now that commodity prices have dropped so rapidly, we are left wondering exactly what quantity of the recent reserve revisions and improved recovery will have to be revised down again under a $40-$45/bbl year-end price scenario. 

The results could be a wide scale reserve de-booking and potentially the impairment of capital costs associated with them, or indeed impairments to acquisitions that occurred over that period. This kind of reserves revision volatility is not helpful for investors or the market place in general, and as such, the SEC has addressed the subject in its recent proposals for the modernization of oil and gas reporting requirements. (See Appendix A).

Oil Sands Economics

On Dec. 31, 2007, oil sands companies booked their bitumen reserves at a healthy $70 a barrel (U.S.), a price at which most projects appeared viable. But this year, even though bitumen prices spiked to more than $100 in June, the global economic downturn and subsequent commodity price collapse means a barrel of heavy crude from the oil sands will now only fetch around $25 today. At that price, many oil sands developments are too expensive to be viable, preventing companies from booking such reserves as proven.

Assuming higher commodity prices next year, any write-downs on reserves taken by companies this year likely won't significantly affect share prices, as producers should be able to rebook their oil at the end of 2009. However, decreased reserve values could make it even harder for producers to acquire financing, given that banks use reserves as a key indicator of a company's long-term viability.

A major theme now is the breakeven point for oil sands projects. We often dispute the claim that oil sands production is marginal since, once facilities have been constructed they have operating costs of only $20-40/bbl. Since E&P executives think (rightly) of construction costs as sunk, even at $50 oil most oil sands projects would continue to operate.

Looking at specific projects, Canadian Natural estimates that the cost for Horizon Phase I will be $84,000 per flowing barrel, and Nexen's costs for Long Lake Phase I will surpass $100,000/bbld. It is estimated that at $80,000/bbld, an oil price above $90 a barrel would earn a competitive return, but at $70 a barrel oil, returns would be just at the cost of capital. If costs rise to $140,000/bbld, the cost of Petro-Canada's new Fort Hills mining project, then only oil prices above $100/bbl could justify building such a facility.

According to a recent research report by Peters & Co., the break-even oil price using a 10% after-tax discount rate for a new project starting in 2012 is US$60/bbl. for a SAGD project and US$100/bbl for an integrated mining project.

The Peters report suggests that, based on current oil prices, it is evident that costs need to decline sharply to enhance the economics. Although SAGD projects carry more technical and project execution risk, these projects are the mostly likely to proceed given the lower crude oil price required to break even.

Conclusion

Oil prices clawed their way back up to the mid $40 per barrel range in the last days of thin holiday trading. That is a big change from the low $30s/b levels they had sunk to after the latest OPEC meeting. However, fundamentals remain soft. Worse news about the real economy is likely still to come. In the U.S., and globally, low prices are probably beginning to slow the rate of demand declines. OPEC production cuts are real and significant. Across the industry, spending has been cut back and upstream activity will suffer.

Israeli bombing of Gaza raises Mid-East tensions, as do low oil prices that constrain budgets in these countries. In addition, Russia cut natural gas exports to the Ukraine (as in early 2006).

All of these factors and issues would appear unable to make a real tangible difference in the short term. So we see any price relief as just that, a lull in the selling. The down-trend still needs to be broken. We don’t think we are there yet. But by raising the risk of short-selling the commodity, the downward momentum is beginning to ebb.

It’s still all about the macro-economy. Recall that growth in oil demand is closely correlated with the rate of GDP growth.

Four week trailing average deliveries of oil products are down -6.1% from year earlier, the slide may be slowing, but only a little and only tentatively despite the positive effect of much lower prices. Jet fuel demand, which with diesel is the most directly correlated to the broader economy, is falling at a -12% rate below last year’s levels.

In the U.S., national retail gasoline averages have fallen to $1.60 per gallon – compared with more than $4/gal. in June, July and August. Futures markets trade gasoline at $1/gal.

Many companies have pushed back or cancelled major expansion projects as a result of the global economic slowdown This is not likely to have a major impact outside the industry as long as the global economy remains weak. But once economic growth picks up and fuel consumption rises, reduced industry capacity will create bottlenecks and push energy prices higher. If the incoming Obama administration moves toward cleaner fuels (see Appendix B – Carbon Dioxide Controls are Coming), that could trigger more expensive upgrades in the downstream segment (i.e. refineries) which would drive gasoline prices higher.

APPENDIX A

U.S. Securities & Exchange Commission Oil Reserves Reporting

While reserve write-downs will almost certainly be negatively received by the market, the oil companies will

point to the SEC's impending reserve reporting changes that could bolster reserves in 2009, as well as increasing the level of acquisitive activity as the Majors try to pick up currently un-booked reserves that could easily migrate to proved reserves with little extra effort in 2009.

The U.S. Securities and Exchange Commission has said that, as of Jan. 1, 2010, oil and gas producers can use a 12-month average price to book the value of their reserves, instead of the price on a single day, Dec. 31, as they do now.

Specifically, the SEC proposes a switch from year-end prices to year-average prices for the calculation of economically recoverable reserves. This would significantly reduce volatility in reserve booking associated with short-term fluctuations in commodity prices, and be more consistent with the long-term nature of oil and gas extraction activities. 

They also propose updating regulations with respect to the use of reliable technology in the definition of proved reserves, which would allow reserves to be booked on the basis of reliable technical data rather than purely on the basis of proximity to a proven producing well. This change would be of particular importance for deep-water projects where wells are expensive to drill.

Of great importance is the proposal to include Oil Sands and other unconventional resources into the proved category. This would even the playing field in terms of company comparability and increase transparency, such that companies with large unconventional resource bases would be directly comparable to companies with conventional resources.

The SEC also proposed the optional disclosure of un-proved reserves, such that investors could obtain and compare information on the "most likely" quantities of reserves.  This would greatly increase the ability of investors to assess the longer-term prospects of companies and also allow them to see what volumes companies are using to plan their capital budgets.

Canadian firms have long campaigned against the old SEC regulations, arguing that using a price from a single day unreasonably exposes them to market volatility. They also say it's unfair to use a December price to evaluate their oil sands holdings; the value of bitumen falls in winter as demand for heavy crude drops.

The move will come too late for Canadian energy producers facing significant write-downs on their reserves this year as the changes won't apply to this year's reserves reports, causing a major headache for oil companies. But oil sands producers will be harder hit, because prices for bitumen, a heavier crude that is more expensive to refine, have fallen farther and faster than have prices for light, sweet crude.

Any write-downs on reserves taken by companies this year likely won't significantly affect share prices, as producers should be able to rebook their oil at the end of 2009. However, decreased reserve values could make it even harder for producers to acquire debt, given that banks use reserves as a key indicator of a company's long-term viability, according to Chris Feltin, a Calgary-based analyst at Tristone Capital.

The new rules will also allow companies to disclose possible and probable reserves, as opposed to the current system that allows only proven reserves to be reported.

Oil sands mining companies will be able to book their reserves as oil and gas resources, instead of mining reserves as was the case previously, improving clarity for investors.

APPENDIX B

Carbon Dioxide Controls are Coming

To quote Congressman Rick Boucher (D-VA), Chairman of the House Subcommittee on Energy and Air Quality: “The debate is over about whether or not we are going to have a mandatory federal program to control carbon dioxide emissions. We certainly will.”

CO2 regulation is the number two priority after economic sustainability legislation. Healthcare reform would be number three. But all three of these measures will be promoted roughly simultaneously by the administration. It is very possible that the White House will send a cap and trade proposal, probably not a fully developed bill but at least a statement of administration principles to the Congress, and ask that those be acted upon by the passage of legislation.

The Obama administration will propose more federal support for renewable energy and for transportation that is based on something other than petroleum whether that’s electricity or fuel cells.

Congressman Boucher believes that debate over CO2 regulation in the next Congress will focus primarily on the timing of mandatory cuts in CO2 emissions and the method of allocation of emissions allowances.  Boucher andthe energy industry in general favor a slow transition to restrictive CO2 caps, while the House Democratic leadership will push for more stringent limits.

A U.S. federal cap-and-trade program to limit emissions of CO2, and particularly one that would auction

allowances to emitters, will materially increase the supply costs of fossil fueled utilities, eroding the future

earnings power of unregulated coal fired generators such as Mirant (MIR), Reliant (RRI), NRG (NRG) and

Dynegy (DYN).  Unregulated nuclear generators, such as Exelon (EXC) and Entergy (ETR), are expected

to enjoy a significant improvement in generation gross margin, as the increase in their competitors' supply

costs drives power prices higher.

A federal renewable portfolio standard will likely have negative implications for conventional generators, whether fossil fueled or nuclear, and particularly for unregulated utilities.  First, we would expect rapid growth in renewable generation to limit the growth in power output of conventional plants, as mandated increases in renewable generation crowd out conventional supply.

The Electric Power Research Institute projects the costs of developing new technology at $10 billion over a ten year period-- about a billion annually for ten years -- in order to develop carbon capture and sequestration technologies by 2020. And that’s assuming they get the program into operation in 2010.

Congressman Boucher’s proposed legislation would have the funding raised and administered by an external corporation. It would carry the power of a compelled tax. But the actual collection of that money and the administration of it would not occur within the normal governmental processes.

It would impose a millage fee of one mill per kilowatt-hour which derives about $1 billion annually. These

charges would be imposed on the consumers of fossil fuel generated electricity, with a slightly higher charge for coal and somewhat lesser charge for petroleum powered electricity and then a lesser charge still for natural gas powered electricity. But the average is 1 mill per kilowatt-hour. That works out to about $12 annually for the typical homeowner.

Boucher says that the legislators have to acknowledge the reality that coal use is essential to the American economy. It is 51% of U.S. electricity generation. They don’t have reliable alternatives that are available to take the place of coal. Renewables are just not ready, and renewable resources are not present in some parts of the United States such as the Southeast. And while there are promising projections now of new reserves of natural gas that potentially could be developed, they have not been developed yet. They have not yet been proven. And given what is known today about the natural gas supply, it cannot yet take the place of the coal that fires 51% of U.S. electricity generation.

According to Boucher, if you design the program properly you don’t have victims. He believes that, if the program is properly designed, it will be economically sustainable, it will not dislocate any sector of the economy, it will spread the burden of carbon dioxide reduction uniformly across the economy, not advantaging or disadvantaging any sector as compared to any others. But there will be a price for this. Energy’s going to cost more but they think that it’s a sustainable increase although the legislators say it’s hard to predict exactly how much that’s going to be as a percentage increase.

The electricity sector in the European Union is essentially unregulated and the result is that when the generators received their emission allowances for free they treated the free receipt of these emission allowances as a cost. They placed the value of these allowances in their marginal cost and then they passed them along in the form of a rate increase on the theory that what they were passing along was the opportunity cost of not selling these emission allowances in the emissions trading market. To the typical bystander it looked like manipulation. It looked like a manufactured cost. Allowances that were obtained for free and then converted into a cost which were passed along in the form of a rate increase. The U.S. legislators want to make sure that doesn’t happen and have taken some measures to assure that it doesn’t. But in the European Union it did.

Electric utilities are going to be factoring into their plans a variety of ways to meet the CO2 reductions the law specifies once they see what’s required of them. Among those will be carbon capturing and sequestration and adding efficiency.

Many utilities that today are largely fossil fuel fired may decide to build nuclear units as newer versions of nuclear technology are more reliable and safer. They’re more efficient than the older plants that were last built in the 1970’s. The U.S. Energy Policy Act of 2005 does incent the development of new nuclear plants. It provides generous tax benefits for nuclear plant development and the U.S. Nuclear Regulatory Commission now has four or five applications pending for the first new nuclear plant builds since 1977.

However, there are also members of Congress who are very concerned about the inadequacy of the nuclear waste disposal program and the fact that they would only worsen the problem of a high volume of nuclear waste being stored at reactor sites if they encourage a lot of new nuclear generation. So there is a real contingent in the Congress, which may be strengthened as the result of this past election, that would oppose nuclear generally and doing anything at the federal level to incent new facilities.

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