CERI Commodity Report Crude Oil

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1 CERI Commodity Report Crude Oil North American Crude Oil Industry and Market Overview By Carlos A. Murillo 2011 was an interesting year for the North American oil industry and the global oil market. From continued oil sands production growth in Canada, to the emergence of light tight and shale oil plays in North America, to the disconnect between a North American benchmark (WTI) and world crude oil prices, and not to mention pipeline geopolitics; 2011 was indeed, anything but uneventful. This article aims to provide a brief overview of some of the events, highlights, stories, and trends that are shaping the oil industry and the market in North America, as well as to provide a quick commentary on things to come and the focus of CERI s current and upcoming work. Oil sands production continues to thrive Canadian crude oil and equivalent (COE) production (which in the context of this article includes pentanes plus, conventional crude oil, synthetic crude oil (SCO) and diluted crude bitumen) reached a level of 3,031 thousand barrels per day (kb/d) of production in 2011 (annual average). Canadian Association of Petroleum Producers (CAPP) data from 1971 to the present confirms that the previous highest production level in this timeframe was reached in 2010, when a level of 2,846 kb/d was produced, thus making 2011 a record year for Canadian production. Figure 1 illustrates the composition of monthly Canadian COE production over the 2008 to 2011 timeframe. On a monthly basis, 2011 s production level is the highest at 3,287 kb/d. This is the case mainly due to CERI Commodity Report Crude Oil Editor-in-Chief: Dinara Millington (dmillington@ceri.ca) About CERI The Canadian Energy Research Institute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in Our mission is to provide relevant, independent, objective economic research in energy and related environmental issues. We strive to build bridges between scholarship and policy, combining the insights of scientific research, economic analysis, and practical experience. In doing so, we broaden the knowledge of young researchers in areas related to energy, the economy, and the environment while honing their expertise in a range of analytical techniques. higher oil sands production, combined with a surge in light tight oil (LTO) production in North America. Oil sands production (in the context of this article) is composed of the sum of both SCO (upgraded bitumen brought up to light crude oil quality) as well as blended non-upgraded crude bitumen (Dilbit or Synbit) for which Western Canadian Select (WCS) has become an indicative price benchmark. Historically, SCO has been the main output from oil sands operations from the early days of the industry, as most oil sands projects were integrated mining and upgrading projects. By the 2000s, non-upgraded crude bitumen became a significant component of the oil sands output, and by 2003, combined diluted bitumen volumes from mining (in excess of upgrading capacity), thermal, and primary/enhanced oil recovery (EOR) in-situ operations, exceeded SCO production volumes. Figure 1: Canadian Crude Oil & Equivalent (COE) Production by Source, (thousands of barrels per day, kb/d) 3,200 3,000 2,800 2,600 2,400 2,200 2,000 1,800 1,600 1,400 1,200 1, Alberta Non-Upgraded Bitumen (Dilbit/ Synbit) Conventional Light Eastern Canada Total Total Canadian Crude Oil & Equivalent Production Alberta Upgraded Bitumen (Synthetic Crude Oil) Conventional Heavy Pentanes Plus Source: National Energy Board (NEB) data, figure by author. Over the 2000 to 2009 timeframe, oil sands production increased at a healthy 10% annual average, while other Canadian production has exhibited a 1% annual average decrease over the same timeframe. 3,200 3,000 2,800 2,600 2,400 2,200 2,000 1,800 1,600 1,400 1,200 1, For more information about CERI, please visit our website at Relevant Independent Objective

2 Page 2 As seen in Figure 2, by 2009 (highlighted) oil sands production levels officially exceeded the 50% mark of total COE production and have since remained above that level and edging close to the 60% mark. Figure 2: Canadian COE Production by Source (%), % 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Source: NEB data, figure by author. Non Oil Sands Production (Conventional & Tight Oil) Oil Sands Production (SCO, Dilbit, Synbit) What this implies is that oil sands production has become a significant contributing component in Canadian COE production and the Canadian oil industry. In 2011, Canadian COE production grew by 7% (or close to 200 kb/d) compared to the previous year (year over year percentage change, Y/Y %Δ). This increase was in turn led by a 14% (98 kb/d) increase in the supply of non-upgraded bitumen (making this source the fastest growing production source in Canada), and an 11% (87 kb/d) increase in SCO output; once again, highlighting the magnitude and contribution of the oil sands industry in the Canadian context. Meanwhile, Eastern Canada s production declined by 5% (14 kb/d) in 2011, mainly due to natural declines in offshore fields (NL), while conventional heavy crude oil and pentanes plus production levels declined by 1% respectively. However, 2011 saw a surprising 6% (33 kb/d) increase in Canadian light oil production. Light crude oil production increases are the next part of the North America story as this trend is not only apparent in Canada, but also in the United States (US)....and, Light Tight Oil (LTO) is the new kid on the block Production of conventional (non oil sands) crude oil from the Western Canadian Sedimentary Basin (WCSB, including British Columbia, Alberta, Saskatchewan, Manitoba, and the Northwest Territories) peaked in the early 1970s at over 1,700 kb/d. At that point, conventional WCSB production accounted for close to 100% of Canadian production, with the balance made up of some SCO volumes (from oil sands mining operations), as well as small conventional volumes from both Ontario and New Brunswick. Over the 1980s and 1990s (conventional) production continued on a decline trajectory, led by decreases in both Alberta and British Columbia. However, two regions of Canada were contributing to a leveling off of this trend in the 1990s. That is, increased conventional production from both Saskatchewan and offshore Newfoundland projects arrested the decline trend over the 1990s and 2000s. Yet, conventional crude oil production from the WCSB has been on a steady decline since the late 1990s. That is, until the last couple of years (see Figure 1). In 2010, conventional light oil production (excluding offshore production) in Canada increased by 2% (Y/Y %Δ) compared to a 5% decline (-) in the previous year. By 2011, the Y/Y %Δ increase was 6% as mentioned previously. Between 2009 and 2011, conventional light oil production increased by a total of 41 kb/d (8%) from 517 kb/d to 558 kb/d, led by increases in production in both Alberta and Saskatchewan. This trend shows what has been called the light oil revival, a phenomenon that has come about by breakthroughs and widespread applications in improved drilling and production techniques such as horizontal directional drilling and hydraulic fracturing; better understanding of shale and tight formations; as well as improvements in seismic technologies. This shift and boom has been attributed to the development of shale gas resources in North America. Figure 3 illustrates production of crude oil from tight formations in the WCSB from early 2005 until early As it can be observed, not only are there a wide number of formations/plays (12) being targeted by producers in the WCSB, but the increase in production levels has been exponential over the last couple of years. CERI Commodity Report - Crude Oil

3 Page 3 Figure 3: Canadian Tight Oil Production by Play to reach a level of 5,881 kb/d by 1999, and by the 2000s the decline trend stabilized. In 2009 crude oil production levels were around the 5,400 kb/d mark. By 2010, total US crude oil production reached a level of 5,475 kb/d compared to 5,360 kb/d in 2009 (a 115 kb/d or 2% increase), and by 2011 a level of 5,635 kb/d was reached (or a 160 kb/d, 3% annual increase). Behind the latter decades stabilizing trend was continued and increased production from offshore federal waters in the Gulf of Mexico (GOM), which grew from an average production level of 860 kb/d in the 1980s to close to 1,000 kb/d by the 1990s, and over 1,400 kb/d in the 2000s. Source: NEB. The Bakken, Torquay, Three Forks, and Shaunavon formations have so far seen the highest level of activity in the region (mainly in Saskatchewan but also in Manitoba) with other important formations such as the Cardium, Viking, and Montney (mainly in Alberta), also displaying a healthy level of activity. Last year saw not only a healthy increase in the production of light tight oil through increased level of activity as measured by rig counts, but also a potential for prolonged activity as hectares of land around these and other promising LTO formations (such as the Duvernay in Alberta) saw record numbers of crown land bonus revenues for provincial governments across Western Canada. Further, a recent NEB report indicates that the Bakken/ Exshaw, Cardium, Viking, and Lower Shaunavon plays may contain as much as close to 500 million barrels (MMb) of oil reserves, as reported by currently active companies in these regions. Meanwhile, potential for several million barrels of reserves is possible, as companies move to assess resources in the Montney/Doig, Duvernay/Muskwa, Beaverhill Lake, and Lower Amaranth plays in the WCSB. The potential development of these resources not only presents great opportunities for producers in Western Canada but also the possibility of increased supply of light oil over the medium to long term. Yet, the story does not end there. Light tight oil (LTO) is also on the rise in the US. US crude oil production peaked in 1970 at just over 10,000 kb/ d. Over the remaining years of that decade, crude oil production declined at a monthly average rate of 0.10% (1.2% annually) reaching a level of just over 8,500 kb/d by 1979, followed by a faster decline of 0.12% monthly (1.4% annually) over the 1980s (declining to 7,600 kb/d by 1989). By the 1990s this trend followed at a monthly pace of 0.16% (1.9% annually) In 2009, GOM offshore crude oil production reached a historical peak of 1,740 kb/d, essentially doubling production levels from that source compared to levels in the 1980s. Figure 4: US Crude Oil Production, Overall and Top 5 Producing Regions (kb/d), ,800 1,700 1,600 1,500 1,400 1,300 1,200 1,100 1, US Offshore Production North Dakota Texas Alaska California Total US Production (Right Scale) Source: Energy Information Administration (EIA) data, figure by author. While offshore crude oil production has been important in the US, offshore production is highly vulnerable to abnormal weather events such as hurricanes (due to its location). As seen in Figure 4, US offshore crude oil production was heavily impacted in late 2008 during hurricane season as the threat of hurricane Ike loomed. To complicate matters, over the last couple of years offshore crude oil production has leveled around the 1,500 kb/d mark as activity slowed down in the aftermath of the BP Macondo incident and has since been slow to pick up. With the prospect of tougher regulations and less permits being issued for production in the region, it is hard to foresee production from this region to surge considerably over the coming years. Outside the GOM, other major crude oil producing regions in the US have shown signs of natural declines in major fields 6,000 5,900 5,800 5,700 5,600 5,500 5,400 5,300 5,200 5,100 5,000 4,900 4,800 4,700 4,600 4,500 4,400 4,300 4,200 4,100 4,000 Relevant Independent Objective

4 Page 4 such as in California and Alaska, which are producing around the 600 kb/d level (Figure 4). However, both Texas and North Dakota have shown significant rising trends in production over the last couple of years as seen on Figures 4 and 5. Offshore crude oil production decreased from 1,557 kb/d in 2009 to 1,552 kb/d in 2010, and 1,475 kb/d by Therefore, recently increased onshore crude oil production is in fact responsible for the upward trend in overall US crude oil production. Figure 5: North Dakota and Texas Crude Oil Production, (kb/d) North Dakota Texas Source: EIA data, figure by author. North Dakota s production, driven by production from (tight) shale oil formations in the Bakken s Williston basin (an extension of Western Canada s Bakken/Exshaw formation) has grown threefold from a level of around 150 kb/d in early 2008, to close to 450 kb/d by late And while the Bakken formation extends into Montana, activity in that state has been somewhat slower (yet significant) with production levels rising from 40 kb/d in 2000 to just over 100 kb/d in 2006, and declining to a 60 kb/d level by late It is worth noting that, as pointed out by recent EIA analysis, the North Dakota Department of Mineral Resources estimates that crude oil production in the Bakken could reach levels of as high as 750 kb/d by Texas has also seen an impressive surge in production over the 2008 to 2011 time period, with production growing from the 1,050 kb/d mark in early 2008, to 1,500 kb/d by late 2011 (a 42% increase). While not completely responsible for the increase in Texas production, the Eagle Ford formation s shale oil production has grown from a level of 0.4 kb/d in 2008 to close to 38 kb/d by late 2011, according to data from the Railroad Commission of Texas. 1,500 1,450 1,400 1,350 1,300 1,250 1,200 1,150 1,100 1,050 1,000 While beyond the scope of this article, production of natural gas condensate from this formation (Eagle Ford) was at the 0.3 kb/d level in 2008 and reached 46 kb/d by late Meanwhile, natural gas production levels of less than 1 billion cubic feet (bcf) were recorded in 2008 yet reached 212 bcf by late This highlights the importance of this particular play not only for light crude oil production but also natural gas and natural gas liquids (NGLs). With that in mind, these two plays (Bakken and Eagle Ford) together with other potential shale oil plays identified by the EIA, such as the Avalon & Bone Springs (Texas) and the Monterey/Santos, are estimated to hold a total of close to 24 billion barrels (Bb) of technically recoverable shale oil resources in the US. Now, while increases in oil sands production in Canada together with increases in the supply of LTO in North America have indeed been good news for the industry over the last year, there are however, infrastructure, logistical, and market access issues that might in fact dampen that upbeat sentiment. but, North Americans are using less and inventories are building up According to EIA data, in 2010 (latest available data), estimated world petroleum demand (crude oil/refined products) was over 87 million barrels per day (Mb/d) out of which approximately 22% or over 19 Mb/d (19,000 kb/d) corresponded to US demand. Therefore, the US is not only a significant consumer in the global context, but it is also worth noting that the US being Canada s main trading partner and export destination for crude, there is a high degree of regional integration in the crude oil supply channels and infrastructure. In 2004, petroleum demand in the US was around the 21 Mb/d mark but by late 2011 demand was hovering around a level just below 19 Mb/d. As it can be observed in Figure 6, demand peaked at close to 22 Mb/d in 2005 and has since been on a downward trajectory. It can also be observed that current demand levels in the US have been persistent since late 2008, on the aftermath of the financial crisis. Now, keeping in mind that demand in the US has been fairly flat over the last few years, increases in US production could eventually lead to reductions in imports. If that was to be the case, Canada could potentially see its share of the US market curtailed over the long term, hypothetically. Knowing this, a logical next step would be to have a look at the Canadian supply and demand picture. As seen on Figure 7, Canadian consumption of petroleum products has been around the 2,000 kb/d level (2 Mb/d, or about 10% compared to US levels) over the last few years, CERI Commodity Report - Crude Oil

5 Jan Sep-2004 Jan Sep-2005 Jan Sep-2006 Jan Sep-2007 Jan Sep-2008 Jan Sep-2009 Jan Sep-2010 Jan Sep-2011 Jan-2008 Mar Jul-2008 Sep-2008 Nov-2008 Jan-2009 Mar Jul-2009 Sep-2009 Nov-2009 Jan-2010 Mar Jul-2010 Sep-2010 Nov-2010 Jan-2011 Mar Jul-2011 Sep-2011 Page 5 while both Canadian production and exports (primarily to the US) have increased at a healthy pace. Figure 6: US Crude Oil & Petroleum Products Demand (kb/d) and Cushing, Oklahoma (OK) Tank Farm Stocks (kb), ,000 42,000 40,000 38,000 36,000 34,000 32,000 30,000 28,000 26,000 24,000 22,000 20,000 18,000 16,000 14,000 12,000 10,000 Cushing, OK Stocks Cushing, OK Crude Stocks AVG US Demand AVG Cushing, OK Crude Stocks AVG US Demand AVG US Crude Oil & Petroleum Products Demand 22,000 21,750 21,500 21,250 21,000 20,750 20,500 20,250 20,000 19,750 19,500 19,250 19,000 18,750 18,500 18,250 18,000 17,750 17,500 17,250 17,000 Figure 8: US Crude Oil & Petroleum Products Imports by Source, and US Demand, ,000 14,000 13,000 12,000 11,000 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 - U.S. Imports from OPEC Countries of Crude Oil and Petroleum Products (Thousand Barrels per Day) U.S. Imports from Non-OPEC Countries of Crude Oil and Petroleum Products (Thousand Barrels per Day) U.S. Imports from Canada of Crude Oil and Petroleum Products (Thousand Barrels per Day) U.S. Imports of Crude Oil and Petroleum Products (Thousand Barrels per Day) US Petroleum Demand (Right Scale) Source: EIA data, figure by author. 20,500 20,000 19,500 19,000 18,500 18,000 17,500 17,000 Source: EIA data, figure by author. Figure 7: Canadian Consumption of Petroleum Products, COE Production, and Crude Oil Exports, (kb/d) 2,500 2,450 2,400 2,350 2,300 2,250 2,200 2,150 2,100 2,050 2,000 1,950 1,900 1,850 1,800 1,750 1,700 1,650 1,600 1,550 1,500 Canadian Consumption of Petroleum Products Total Canadian COE Production (Right Scale) Total Crude Oil Exports Export to the United States Source: EIA, NEB, and Statistics Canada data, figure by author. Given that US demand has subsided over the last few years and that Canadian demand has remained steady while Canadian crude exports to the US have increased over the last few years, then it must be true that (crude oil and petroleum) imports from other countries to the US must be decreasing. This is in fact seen in Figure 8, which illustrates that overall petroleum imports to the US have declined over the last few years in tandem with the demand trend. 3,050 3,000 2,950 2,900 2,850 2,800 2,750 2,700 2,650 2,600 2,550 2,500 Worth noting is that the trend also displays a decline in the Organization of Petroleum Exporting Countries (OPEC) share of US imports (2008: 46%, 2011: 40%) while there has been an increase in non-opec imports (2008: 54%, 2011: 60%), with Canadian imports increasing their share of total imports from 19% in 2008 to almost a quarter of total imports (23%) by Thus, Canadian exports to the US continue to increase while overall US imports have decreased. While this is good news for Canada, it is important to keep in mind some of the issues we have just reviewed. To sum up: Canadian and US crude oil production have increased due to increased oil sands and LTO output, while US demand has subsided and Canadian demand has remained flat. Meanwhile, close to all of Canadian crude oil exports go to the US while small volumes are destined to other countries, and as the US has reduced overall imports, the trend seen is one of reduced OPEC imports and increased non-opec imports led by imports of Canadian crude. Next, large inventory levels of crude oil have been building at Cushing, Oklahoma (OK) over the last few years (Figure 6). Cushing, OK is the major trading hub for pipeline transported crude oil in North America and the receipt point for West Texas Intermediate (WTI) contracts traded in the New York Mercantile Exchange (NYMEX). Basic economics dictate that oversupply of (or lackluster demand for) a commodity puts downward pressure on prices and that might partly explain some of the price behavior for crude oil observed in North America over the last year. Data from 2008 to 2011 for crude oil stocks at Cushing and the price of WTI indicates a weak correlation (r) of and an R 2 (coefficient of determination) of 11%. Relevant Independent Objective

6 Jan-2008 Mar Jul-2008 Sep-2008 Nov-2008 Jan-2009 Mar Jul-2009 Sep-2009 Nov-2009 Jan-2010 Mar Jul-2010 Sep-2010 Nov-2010 Jan-2011 Mar Jul-2011 Sep-2011 Nov-2011 Page 6 This simply indicates that 11% of the changes in prices can be explained by changes in inventories and vice-versa, and that a movement in one is partially responsible for an opposite movement in the other (r). Simply put, oil inventories buildup is one part of the recent price movement story, but definitely not the only one. meanwhile, the music has stopped for the WTI-Brent waltz While many geopolitical, economic, and other unpredictable events took the world by surprise in 2011 (including but not limited to the Arab spring, associated supply disruptions, fiscal quagmires in Europe and the US, emergency IEA s members crude stock releases, maintenance in the North Sea, increased demand in Japan after the Fukushima Daiichi incident, the talk of economic sanctions to Iran, amongst others), the relationship between WTI and North Sea Brent (a global waterborne crude benchmark), seems to have changed, at least over the short to medium term. Brent and WTI have historically moved in tandem, with the price difference (known as the price differential and measured on a $/b basis) usually reflecting differences in transportation costs to demand centers in the global market. From 2008 to 2010 the WTI-Brent differential averaged $0.92/ b, the data for the same time period displays an r of 1.00 and an R 2 of 99% percent. However, for 2011, the differential widened substantially to an annual average of -$16.39/b (peaked at -$27.31/b in ), while the data for this time period (monthly data) shows an r of 0.65 and R 2 of 42% indicating that the close relationship between Brent and WTI prices has changed as seen on Figure 9. Figure 9: West Texas Intermediate (WTI) & North Sea Brent (Brent) Spot Prices and Differential, , ($/b) $ $ $ $ $ $ $ $ $ $95.00 $90.00 $85.00 $80.00 $75.00 $70.00 $65.00 $60.00 $55.00 $50.00 $45.00 $40.00 $35.00 $30.00 WTI - Brent Differential ($/b) (Right Scale) West Texas Intermediate Price ($/b) Europe Brent Spot Price ($/b) $10.00 $5.00 $- $(5.00) $(10.00) $(15.00) $(20.00) $(25.00) $(30.00) Data analysis indicates that the price differential can be partially explained by a buildup in Cushing, OK inventories (r=0.47, R 2 =22%), which in turn can be partially explained by increased oil sands and US production (Canada: r=0.68, R 2 =46%; US: r=0.73, R 2 =54%). While increased production and lower demand have led to the buildup of inventories, financial markets also play a role. The futures market, where oil is traded for future delivery dates, plays a role in pricing crude based on future market expectations. A futures curve dictates the prices for crude oil to be delivered at a future date ranging from the end of the present (front end) month, to even a couple of years down the road. One measure of speculation is the differences between the prices for upcoming months. If the prices for the months ahead of the front month (earliest futures delivery date, Contract 1) is lower than say the upcoming months (Contracts 2 to 4), and therefore the difference between future and frontmonth contracts is positive, then there is an expectation that prices will rise in the future and the market is said to be trading in contango. As it can be observed in Figure 10, this has been the situation from early 2009 until the most recent months. This is important because if the contango is large enough (to cover physical and financial costs of storage), there is an incentive to hold on to stocks to receive further higher prices in the near term. This has in fact contributed to the stocks buildup over the last few years. Yet, as it can be observed, this situation has narrowed down over the last few months. Figure 10: WTI Futures Price Differences in Contracts, $9.00 $8.50 $8.00 $7.50 $7.00 $6.50 $6.00 $5.50 $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- $(0.50) $(1.00) $(1.50) $(2.00) $(2.50) $(3.00) Difference Contract 2 & 1 Difference Contract 3 & 1 Difference Contract 4 & 1 12 per. Mov. Avg. (Difference Contract 4 & 1) Source: EIA data, figure by author Source: EIA data, figure by author. CERI Commodity Report - Crude Oil

7 Spot Price Jan 10, 2012 '12 '12 '12 '12 '12 '12 '12 '12 '12 '12 '13 '13 '14 ' % 18.06% 17.24% 30.52% 26.44% 27.40% 39.64% 39.31% 2008Q1 2008Q2 2008Q3 2008Q4 2009Q1 2009Q2 2009Q3 2009Q4 2010Q1 2010Q2 2010Q3 2010Q4 2011Q1 2011Q2 Page 7 Another further consideration in understanding the price differential is the volatility (change) of the prices for both price benchmarks. Figure 12: US Gross Domestic Product, WTI Prices, Dow Jones Industrial Average, and Standard & Poor s 500 Index (Quarter over Quarter % Change), In this context, the price volatility (as seen in Figure 11) is measured by CERI as the annualized monthly changes in prices for both WTI and Brent crude. The shaded areas indicate the maximum and minimum month over month percentage changes that occurred in a given year, while the bar indicates the difference between the two extremes (the range). Finally, the dots indicate the median annualized month over month percentage change for a given year. 55% 45% 35% 25% 15% 5% -5% -15% -25% -35% -45% -55% S&P 500 Q/Q % Δ DJIA Q/Q % Δ WTI Q/Q % Δ Real GDP Q/Q % Δ 2.50% 2.00% 1.50% 1.00% 0.50% 0.00% -0.50% -1.00% -1.50% -2.00% -2.50% Figure 11: Benchmark Crude Oil Prices Volatility, (%) WTI Crude Prices Volatility Range WTI Maximum Annual Volatility WTI Annual Median Price Volatility 40.00% 35.00% 30.00% 25.00% 20.00% 15.00% 10.00% 5.00% 0.00% -5.00% % % % % % Source: EIA data, figure by author. Brent Crude Prices Volatility Range Brent Maximum Annual Volatility Brent Annual Median Price Volatility 40.00% % 30.00% 25.00% 20.00% 15.00% 10.00% 5.00% 0.00% -5.00% % % % % % The story here is simple, volatility was quite high in 2008, has been on a declining trend both in 2009 and 2010, yet increased again by 2011 for WTI but not Brent. WTI has seen wider price swings than Brent and this further reflects on local events that are affecting prices such as fiscal problems in the US, increased crude production and rising inventories, as well as a whole array of announcements of crude oil transportation infrastructure investments and changes that occurred in 2011 and that have become very much politicized. Further, it is important to iterate that the above mentioned issues are not the only issues linked to changes in oil prices and divergence across benchmarks. As seen in Figure 12, there are also important relationships amongst changes in local crude oil prices and factors such as economic growth (as measured by GDP) (r=0.66, R 2 =43%), as well as with major stock market indices performances such as those of the Standard & Poor s 500 index (S&P500) (r=0.83, R 2 =86%) and the Dow Jones Industrial Average (DJIA) (r=0.53, R 2 =28%). Source: US Federal Reserve Economic Data (FRED), EIA data, figure by author. However, in terms of the future of price differential (Figure 13), Brent futures curve presents signs of backwardation (the opposite of contango) which is an indication that prices are expected to fall in the future. On the other hand, WTI is expected to continue to trade in contango over the next year, while a backward-dated end of the curve points to expectations of decreasing prices over the long term which might eventually lead to a narrowing in the Brent premium in the future. Figure 13: Inter Continental Exchange (ICE) Brent Crude & West Texas Intermediate (WTI) Futures Prices and Differential ($/b) on 10, 2012 Deliveries from 2012 to 2015 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $99.00 $98.00 $97.00 $96.00 $95.00 $94.00 Futures Contract Spread ($/b) (Right Scale) 10, 2012 ICE WTI Crude Futures 10, 2012 ICE Brent Crude Futures Source: InterContinental Exchange data, figure by author. $(3.00) $(3.50) $(4.00) $(4.50) $(5.00) $(5.50) $(6.00) $(6.50) $(7.00) $(7.50) $(8.00) $(8.50) $(9.00) $(9.50) $(10.00) $(10.50) $(11.00) $(11.50) $(12.00) Relevant Independent Objective

8 Page 8 while, producers are having trouble moving their product North America has one of the longest and most integrated networks of energy pipelines, yet there seems to be increased capacity constraints in the system. Figure 14: Canadian & US Crude Oil Pipelines In the US, the US Gulf Coast (USGC) is the largest refining centre in North America (with a total of 56 out of a 167 refineries in the US (148) and Canada (19) combined), yet there are other major refining centers such as the US West Coast and the mid-continent. Canadian refiners are well connected to local supplies by pipelines in the west part of the country while imports and some local supply volumes supply refineries in Eastern Canada. The remaining excess Canadian production is exported to the US (mainly to the Rockies and mid-continent). But continued production (primarily from oil sands operations) is expected to exceed the export capacity of the infrastructure to move increasing volumes of Canadian crude to other refining centers in the US including the USGC. The type of product is also an important consideration, as more sour and heavy crude is being extracted while not all refineries have the capacity to deal with this type of crude. Crude moves to the US Midwest (Cushing) from the USGC and from Canada. Moving crude into the Midwest is not a problem, but moving it out is. Most pipelines (including Keystone) run towards the Midwest and not away from it. Production projections from CERI, the National Energy Board (NEB), the Canadian Association of Petroleum Producers (CAPP), and the Alberta Energy Resources Conservation Board (ERCB) indicate that there will be a rapid increase of crude oil production from the oil sands industry over the next decades. Meanwhile, there is also the prospect of increased supply from LTO both in Canada and the US, which will further put pressure on the pipeline transportation network. As the current increased supply has found short-term alternative routes to reach refining centers including moving crude by rail, barges, and truck, the North American industry and in particular the Canadian industry are looking at opportunities to expand the pipeline network to reach existing (USGC) as well as emerging demand centers (such as the Asia- Pacific region). Source: Canadian Association of Petroleum Producers (CAPP). Various pipeline projects are currently either at the drawing board, the regulatory process, or shovel ready. These projects are displayed on Figure 14. Other proposals involve the reversal of pipelines for which current flows are exacerbating the issue. All of these projects have been featured front and centre over the last year, surrounded with controversy, and caught up at the crossroads of ideological and political debates. One will expect that the industry will face an uphill battle against pipeline opposition over the coming years while infrastructure and market diversification for the Canadian crude oil industry will become a centre piece of the public debate over the coming year. but CERI continues to be front and centre! Meanwhile, CERI will continue to monitor markets and industry conditions and will remain at the forefront of the debate by providing in-depth analysis which is factual, objective, relevant, and independent whether it is in regards to the Keystone XL pipeline (see Geopolitics of Energy, ), the oil sands industry, or other topics such as those featured in our upcoming studies regarding Canadian crude oil and natural gas access to the Pacific and NGLs supply in North America was an exciting year. New trends are emerging in the energy industry in North America and CERI will continue to deliver relevant and objective energy-related analysis which is accessible to the public and that we hope contributes to a balanced debate. Stay tuned for more.! CERI Commodity Report - Crude Oil

9 Page 9 References: Canadian Association of Petroleum Producers, Crude Oil Forecast, Markets & Pipelines ( getdoc.aspx?docid=190838), accessed on 10, Canadian Association of Petroleum Producers, Statistical Handbook. ( Pages/default.aspx#DNm2uxp2LyN3), accessed on 5, Canadian Energy Research Institute, Economic Impacts of Staged Development of Oil Sands Projects in Alberta ( ) ( 24_CERI_Study_125_Section_1.pdf), accessed on 10, Canadian Energy Research Institute, Geopolitics of Energy Special Edition on Keystone XL Pipeline. Volume 33, Issue 11& Energy Resources Conservation Board, ST Alberta s Energy Reserves 2010 and Supply/Demand Outlook ( accessed on 12, Federal Reserve Bank of St. Louis, Economic Research, Federal Reserve Economic Data (FRED) ( fred2/), accessed on 10, InterContinental Exchange, Energy Futures and Options ( ProductGroupHierarchy.shtml? groupsummary=&group.groupid=5), Accessed on 10, National Energy Board, Canada s Energy Future: Energy Supply and Demand Projections to 2035 Energy Market Assessment ( nrgyftr/2011/nrgsppldmndprjctn2035-eng.html), accessed on 10, National Energy Board, Energy Reports, Crude Oil, Tight Oil Developments in the WCSB ( rnrgynfmtn/nrgyrprt/l/tghtdvlpmntwcsb2011/ tghtdvlpmntwcsb2011-eng.html), accessed on 5, National Energy Board, Statistics, Crude Oil and Petroleum Products, Estimated Production of Canadian Crude Oil and Equivalent ( crdlndptrlmprdct/stmtdprdctn-eng.html), accessed on 5, North Dakota Department of Mineral Resources, Presentation ( accessed on 12, Railroad Commission of Texas, Eagle Ford Shale Play, Eagle Ford Information ( accessed on 9, Statistics Canada, E-stat for Education, Energy ( estat.statcan.gc.ca/cgi-win/cnsmcgi.exe? LANG=E&EThemePath=ESTAT/&ESTATTheme=1741), accessed on 10, United States Energy Information Administration, Review of Emerging U.S. Shale Gas and Shale Oil Plays ( accessed on 9, United States Energy Information Administration, Petroleum & Other Liquids, Data ( accessed on 9, Relevant Independent Objective

10 Page 10 US$/bbl Spot Crude Prices Differential WTI Brent US$/bbl US$/bbl WTI - Edmonton Light Price Differentials Differential WTI Edmonton Light Dec-05 Dec-06 Dec-07 Dec-08 Dec-09 Dec-10 Dec-11 Dec-10 Jan-11 Feb-11Mar-11 Apr Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Spot Prices WTI Brent Edm.Light H.Hardisty Year-to-Date Quarter-to-Date , SOURCE: EIA. SOURCE: EIA. US$/bbl WTI - Hardisty Heavy Price Differentials Differential WTI Hardisty Heavy US$/bbl NYMEX Crude Forward Curve 12 months Dec Oct Nov Dec-05 Dec-06 Dec-07 Dec-08 Dec-09 Dec-10 Dec SOURCE: NRCan, EIA. SOURCE: EIA, CERI. CERI Commodity Report - Crude Oil

11 SOURCE: EIA, CERI. SOURCE: NRCan. Page 11 NYMEX Petroleum Products CDN/US$ Exchange Rate US$/gal 4.00 CDN/US$ 1.55 RBOB Gasoline Heating Oil Dec-05 Dec-06 Dec-07 Dec-08 Dec-09 Dec-10 Dec-11 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 NYMEX Prices Unleaded Gasoline Heating Oil Year-to-Date Quarter-to-Date , Oil Demand Global in Selected Oil Demand Countries US Products Demand Y-on-Y change MMbpd % % 5% % 0% 70-5% 60 49% 50-10% 40 48% -15% % -20% % -25% 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 Total Gasoline Jet Fuel Distillate Residual Propane Other OECD Demand non-oecd Demand non-oecd Share of Global Demand SOURCE: IEA Oil Market Report. SOURCE: EIA Weekly Petroleum Status Report. Relevant Independent Objective

12 SOURCE: IEA Oil Market Report, CERI. SOURCE: IEA Oil Market Report. SOURCE: IEA Oil Market Report. SOURCE: IEA Oil Market Report. Page 12 Global Oil Supply MMbpd Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 non-opec Supply OPEC Supply non-opec Share of Global Supply Canadian Oil Production by product Mbpd 4,000 3,500 3,000 2,500 2,000 1,500 1, Q11 3Q11 4Q11 1Q12 2Q12 AB L/M/H AB Bitumen SK Other NGLs Synthetic 61.0% 60.5% 60.0% 59.5% 59.0% 58.5% 58.0% 57.5% 57.0% Mbpd 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 Mbpd 3,000 2,500 2,000 1,500 1, US Oil Production by region 2Q11 3Q11 4Q11 1Q12 2Q12 Alaska California Texas Federal GOM Other Lower 48 NGLs Other OECD Commercial Stocks by region Oct-08 Oct-09 Oct-10 Oct-11 OECD North America OECD Europe OECD Pacific CERI Commodity Report - Crude Oil

13 Page 13 MMb US Commercial Stocks 25-30, 2011 Crude Gasoline Distillate Products Total MMb Canadian Stocks on Land 3Q10 4Q10 1Q11 2Q11 3Q11 SOURCE: EIA Weekly Petroleum Status Report. SOURCE: IEA Oil Market Report. Relevant Independent Objective

14 Page 14 World Supply and Demand Balance (MMbpd) Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 World Demand OECD non-oecd World Supply Non-OPEC OPEC NGLs OPEC Crude Supply - Demand OECD Stocks (MMbbls) Days Cover OPEC Crude Oil Production (MMbpd) Sustainable Production Over (+)/Under (-) Target Capacity Sep-11 Oct-11 Nov-11 Sep-11 Oct-11 Nov-11 Saudi Arabia Iran UAE Kuwait Qatar Nigeria Libya Algeria Ecuador OPEC Iraq Total OPEC WTI Price Projections ($US/barrel) Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 High Price Case Reference Case Low Price Case CERI Commodity Report - Crude Oil

15 Page 15 Data Appendix Relevant Independent Objective

16 Page 16 A1: Historic Light Sweet Crude Futures Prices ($US per barrel) NYMEX Light Sweet Crude Last 3 Day Avg. When 12-Month Spread Close Average Near Mo. Strip Avg. (1-2 Mo.) Q Q Q Q Q Yr-on-Yr Chg. 14.6% 14.6% 11.4% 8.9% Jan Feb Mar Apr Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 8.2% 6.7% 12.5% 11.3% A2: Historic Crude Product Futures Prices ( US per gallon) NYMEX Unleaded Gasoline NYMEX Heating Oil Last 3 Day Avg. When 12-Month Spread Last 3 Day Avg. When 12-Month Spread Close Average Near Mo. Strip Avg. (1-2 Mo.) Close Average Near Mo. Strip Avg. (1-2 Mo.) Q Q Q Q Q Yr-on-Yr Chg. 22.2% 23.7% 28.0% 26.7% 30.6% 31.6% 33.5% 30.1% Jan Feb Mar Apr Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 9.3% 10.7% 10.2% 12.2% 14.7% 15.6% 16.7% 16.1% Notes (Tables A1 and A2): Prices are listed by contract month. Close: final contract close on the last day of trading. Last 3 Day Average Close: simple average contract close on last three days of trading. Average When Near Month: simple average closing price on trading days when contract was near month. 12-Month Strip Average: simple average of daily near 12-month contract closing prices in a given contract month. Spread: difference between one-month and two-month forward prices in a given period. Source: New York Mercantile Exchange (NYMEX). CERI Commodity Report - Crude Oil

17 Page 17 A3: World Crude Oil Contract Prices (FOB, $US per barrel) Saudi U.A.E. Oman U.K. Norway Russia Venez. Colombia Ecuador Mexico Nigeria Indon. Arab Lgt Dubai Oman Brent Ekofisk Urals 1 T.J. Light C.Limon Oriente Isthmus Bonny Lgt Minas Q Q Q Q Q Yr-on-Yr Chg. 45.3% 44.5% 44.5% 46.2% 47.5% 48.0% 40.1% 44.8% 47.1% 40.2% 47.0% 50.1% Oct Nov Dec Jan Feb Mar Apr Jun Jul Aug Sep Oct Yr-on-Yr Chg. 31.0% 30.3% 30.9% 32.0% 34.6% 33.6% 31.2% 30.8% 36.8% 33.7% 34.8% 33.8% Notes: 1. Urals is Delivered price at Mediterranean. Contract prices are based on prices at the end of each month. Source: Weekly Petroleum Status Report. A4: North American Posted Crude Prices (FOB, $US per barrel) United States Canada ANS 1 Lost Hills Kern R. WTI WTS GCS Okla. Sw. Kans. Sw. Mich. So. Wyo. Sw. ELS 2 HH Q Q Q Q Q Yr-on-Yr Chg. 54.1% 43.0% 45.0% 14.0% 14.7% 15.4% 14.0% 14.5% 15.7% 17.3% 23.3% 16.4% Nov Dec Jan Feb Mar Apr Jun Jul Aug Sep Oct Nov Yr-on-Yr Chg. 54.1% 37.6% 38.8% 16.2% 17.3% 17.7% 16.2% 21.2% 18.0% 18.8% 25.2% 25.7% Notes: 1. ANS is Delivered price on US West Coast. 2. Edmonton Light Sweet. 3. Hardisty Heavy. Posted prices are based on price at the end of each month. Sources: Oil & Gas Journal; Natural Resources Canada. Relevant Independent Objective

18 Page 18 A5: Crude Oil Quality Differentials (FOB, $US per barrel) Light vs. Heavy Sweet vs. Sour Arab Lt Arab Hv Diff. Isthmus a Diff. ELS 1 HH 2 Diff. GCS WTS Diff Q Q Q Q Q Yr-on-Yr Chg. 45.3% 44.5% 40.2% 46.3% 33.9% 26.3% 15.4% 14.7% Nov Dec Jan Feb Mar Apr Jun Jul Aug Sep Oct Nov Yr-on-Yr Chg. 29.9% 29.9% 32.7% 38.5% 23.5% 24.0% 17.7% 17.3% Notes: 1. Edmonton Light Sweet. 2. Hardisty Heavy. Based on contract prices at the end of each month. Sources: EIA Weekly Petroleum Status Report: Oil & Gas Journal; Natural Resources Canada. A6: Crude Oil spot Prices and Differentials (FOB, $US per barrel) Spot Prices Differentials WTI Brent Dubai Urals Basket 1 WTI-Brent WTI-Dubai WTI-Urals WTI-Basket Q Q Q Q Q Yr-on-Yr Chg. 17.7% 47.6% 45.0% 47.5% 47.0% Nov Dec Jan Feb Mar Apr Jun Jul Aug Sep Oct Nov Yr-on-Yr Chg. 15.4% 29.7% 30.3% 30.4% 32.9% Notes: 1. OPEC-Reference Basket is average price of seven crude streams: Algeria Saharan Blend, Dubai Fateh, Indonesia Minas, Mexico Isthmus, Nigeria Bonny Light, Saudi Arabia Light and Venezuela Tia Juana Light. Spot prices are average daily prices over a specific timeframe. Source: International Energy Agency (IEA) Oil Market Report. CERI Commodity Report - Crude Oil