CERI Commodity Report Crude Oil

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1 CERI Commodity Report Crude Oil March 2013 Potential Netbacks for Oil Sands Crudes and Pricing Dynamics Prior to the shale and tight oil boom in the US and significant expansion of oil sands in Canada, Canadian crude oil deliveries to market were stable and relatively predictable. In general, the Canadian crude oil pipeline network was originally designed to transport crude to the US Midwest (PADD II). As production started to rise in both countries pushing against pipeline capacity limits, it flooded the US Midwest with Canadian heavies and North Dakota s Bakken oil. While the PADD II region will remain a large market for Canadian crudes, this article will look at the other market options for dilbit crudes, 1 which in CERI s view, are the most feasible in the shortto medium-term. They are US PADD III US Gulf Coast (USGC), and US PADD V US West Coast (USWC). Figure 1 presents Canadian heavy crude oil supply and disposition in 2011, which is the latest actual data available. Figure 1: Canadian Heavy Crude Oil Supply and Disposition, 2011 Source: Background images from RASC and EIA, 2 data from NEB, 3 analysis and figure by CERI 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. For more information about CERI, please visit our website at In 2011, dilbit accounted for over 1.0 million barrels per day (MMBPD) or 60 percent of Canadian heavy crude oil supplies, 4 or 33 percent of the total supply of 3.2 MMBPD. Furthermore, only about 12 percent of the total heavy crude oil was consumed domestically while the remaining 88 percent was accounted for by exports (87%) and a statistical difference (1%). This is the case both as a function of crude oil transportation (pipeline) infrastructure but also downstream or refining capabilities for processing heavy crudes. CERI estimates that between 2005 and 2011 the price differential between West Texas Intermediate (WTI, North America s light sweet crude benchmark) and WCS at the US Midwest, was reflective of differences between WCS refining margins for a very complex (coking) refinery and a complex (cracking) refinery. In 2012, the WTI-WCS differential in the US Midwest was more reflective of differences in refining margins between coking and simple refineries (wider). This means that Canadian heavy crude volumes are exhausting the necessary required refining capacity in this market, and for as long as this situation continues, Canadian heavy crudes coming into such markets above and beyond very complex and complex refinery demand levels will need to be sold at steep discounts in order to access the simple refinery market. This supports the ongoing debate of opening new markets for oil sands crudes. Looking ahead, given that coking capacity is a good measure of the type of refineries which are able to handle heavy crude types such as Canadian dilbits, as well as the US proximity and long-standing trading relationship, CERI believes that the closest markets will be accessed first and the US will continue to be the largest market for such crudes. Within that context, and based on the information presented in Table 1, CERI believes that beyond PADDs II and IV (the current largest markets for Canadian heavy crudes), PADDs III and V 5 represent the best market prospects for Canadian oil sands producers in the coming years. While CERI is aware of the expansions to refining and coking capacities in existing markets, our view is that going forward the supply will exceed demand in those Relevant Independent Objective

2 Page 2 markets and new markets will be needed for oil sands expansion to be feasible. Within this context, CERI has developed an analysis of possible prices that could be realized by oil sands producers in such markets together with their respective transportation options and an analysis of what that means to local prices for heavy crudes in the Western Canadian Sedimentary Basin (WCSB). Table 1: US Refining & Coking Capacity, Region Refining Capacity (kb/d) Percentage of US Refining Capacity Source: EIA data, 7 analysis and table by CERI Coking Capacity (kb/d) Coking/ Refining Capacity PADD I 1,205 7% 94 8% PADD II 3,648 22% % PADD III 8,516 50% 1,318 15% PADD IV 620 4% 80 13% PADD V 2,948 17% % Total US 16, % 2,396 14% Figure 2 shows the calculated netbacks for WCS crudes from two markets: the USGC and the US West Coast. The analysis starts with the red vertical bar which represents an average annual WCS price for 2011 in US dollars per barrel 8 at Hardisty, AB, which we assumed to be a reflective price for oil sands producers. 9 The prices for crudes which are of similar quality to WCS in the target market regions are represented by the blue vertical lines. 10 For the USGC market, a median landed cost 11 for various waterborne imported heavy sour crudes, mainly from Latin America 12 was used. 13 For USWC, a median price for Kern River and Midway-Sunset Crudes first purchase prices in PADD V was used. 14 A quality adjustment ($2.50/bbl for the USGC, and $8.00/bbl for the USWC) was calculated for each of this representative crude versus WCS quality crude in order to better reflect the potential prices for WCS/dilbit crudes in the respective market. 15 The quality adjusted prices are shown by the lighter red bars (USGC: $95.79/bbl; USWC: $93.98/bbl). The difference between WCS at Hardisty, and the estimated dilbit equivalent price (after a quality adjustment) at the target market, is the gross possible price uplift to oil sands producers (USGC: $17.80/bbl; USWC: $15.99/bbl). Gross because it represents dilbit prices at Hardisty versus the potential dilbit price at the target market. This is in turn the maximum possible uplift to WCS prices but also the maximum transportation costs that an oil sands producer will be willing to pay in order to be indifferent between selling at Hardisty or the target market. Netting transportation costs 16 (given for various transportation options) from the maximum price uplift, yields the estimated netback price the oil sands producer receives in Alberta for selling its crude at the target market. As an example, if a producer has access to pipeline capacity to the USGC under a 10-year toll commitment at a cost of $9.95/bbl, then $17.80/bbl (gross possible price uplift) - $9.95/ bbl (transportation costs) = $7.85/bbl (price uplift) + $77.99 Hardisty) = $85.84/ bbl, which is the price the producer receives for selling its crude in the USGC versus Hardisty, AB. The $7.85/bbl is the price improvement for the Canadian producer versus the price at Hardisty, which is in turn reflective of the refiner s willingness to pay for Canadian heavy crude in the existing PADDs II and IV markets. The same calculation can be done for the USWC market where the maximum price uplift is $15.99/bbl. The Figure also shows various transportation options of getting to these markets and the associated profit margin on a per barrel basis. It is clear that producers are willing to spend more on various alternate (non-pipeline) transportation means such as rail, barges, ships, and any combination of those, as long as the price at the target market minus the transportation costs exceeds the market price at Hardisty. A simple example illustrates that if a producer with a project producing 100,000 barrels per day (BPD) could realize a price that is $1/bbl higher at a different market, it could be improving profits by $100,000 per day or $36.5 million per year. This type of analysis can give us some insight. First, prices for dilbit equivalent or heavy sour crudes, given that they are priced at coastal locations in large refining centers, will continue to be influenced by global crude oil prices, and as long as global prices remain strong, these locations will remain attractive markets to Canadian producers. Another factor is that of infrastructure development and transportation costs. As long as the heavy crude oil price differentials between locations remain wide, there will be an incentive for producers to use non-traditional transportation avenues to access markets. That is, producers will not stop producing if prices are lower at their location, rather they will find new ways to get to better/premium markets.

3 Page 3 Furthermore, as pipeline transportation remains one of the most economic means to transport crude it will continue to be the dominant transportation mode. Tying into this is the fact that stronger prices at other market locations translate into better prices at the production basin via the lowest transportation costs, thus pipeline connections to new markets remains the best means for improving pricing for Canadian oil sands producers. This is important because as prices are lifted companies can realize better returns and re-invest in order to grow the industry. This further translates into more economic activity, higher taxation revenue for provincial and federal governments, but most importantly, it improves the economic value of the resource being extracted (bitumen) for the resource owner, that is, Albertans and Canadians. Endnotes 1 The focus will be on dilbit-type crudes since our analysis indicates that going forward, the largest share of oil sands production will be non-upgraded or diluted bitumen as opposed to upgraded or synthetic crude oil. Furthermore, Western Canadian Select (WCS) will be used as the representative price for dilbit. While WCS is not technically a pure dilbit blend, CERI s analysis indicates that between 2005 and 2013 WCS prices exhibit a correlation with Cold Lake Blend (CLB), which is in turn a dilbit blend representative of oil sands crudes 2 Canada Map: Royal Astronomical Society of Canada (RASC), Education: US Map: US Energy Information Administration (EIA), Gasoline and Diesel Fuel Update, Petroleum Administration for Defense Districts (PADDs): 3 National Energy Board (NEB), Statistics, Crude Oil and Petroleum Statistics: crdlndptrlmprdct/crdlndptrlmprdct-eng.html 4 Within this context, dilbit supply includes non-upgraded bitumen produced volumes as reported by the NEB plus diluent volumes estimates by CERI 5 Various reports argue that biggest challenge to enter this market is California s Low Carbon Fuel Standards (LCFS) 6 Refining Capacity = Atmospheric Crude Oil Distillation Operating Capacity, barrels per Calendar Day as of January 1, 2011 Coking Capacity = Downstream Charge Capacity of Operable Petroleum Refineries, Thermal Cracking (Coking), barrels per Calendar day as of January 1, 2011 A good rule of thumb is that for each barrel of coking capacity available, about 3 barrels of heavy crude can be processed. Therefore, if a refinery has a coking capacity of 33 kb/d, it is estimated that it could absorb about 100 kb/d of heavy crude. This a simple generalization and it will vary from refiner to refiner and from region to region 7 EIA, Petroleum & Other Liquids, Data, Refining and Processing: 8 All figures in US dollars per barrel unless otherwise specified. 9 Not all oil sands crude is priced of WCS. CERI s analysis indicates that in 2011, of the total primary/ EOR, thermal, and mining oil sands projects producing dilbit/ synbit supplies, about 43 percent of the volumes were estimated to have exposure to WCS based prices. 10 This assumes that Canadian heavy crudes compete for space in refineries with other crudes for which pricing benchmarks exist in the target market. While in various markets benchmark prices are determined by spot prices and market transactions, prices for Maya crude are based on a formula which Pemex could use to lower the price if the threat of significant volume displacement from Canadian heavy crudes exists in the USGC. 11 Landed costs are used as they reflect the actual price of the crude once is delivered to the market area, in this case the USGC market. 12 These include Mexican Maya (API: 21.5, Sulfur: 3.4%), Venezuelan Merey (16, 2.5%), Venezuelan BCF-17 (13.5, 2.3%), Ecuadorian Napo (19.2, 2.0%), Brazilian Marlim (19.6, 0.7%), and US landed costs for API < 20, and API> 20 & < 25, all retrieved from EIA: It is estimated that in 2011, 87 percent of the total 2.2 MMBPD of heavy crudes to the USGC were from Latin America. Hart Energy, Refining Unconventional Oil, US Resource Invigorate Mature Industry: Consulting/Refining-Unconventional-Oil/ 14 Midway-Sunset (API: 13, Sulfur: 1.6%), and Kern River (13.3, 1.1%). These crudes represent the largest share of California s crude oil production according to the California Energy Commission: 15 For the USGC, since the price for Mexican Maya was almost identical ($98.81/bbl) to the median USGC heavy sour landed crude ($98.29), a quality/ price adjustment was done based on the total acid number (TAN) for WCS being higher than that of Maya API and sulfur parameters for WCS and Maya are almost identical. For the USWC, the adjustment was based on WCS having a higher sulfur content that California heavy sour crudes, TAN levels are about the same while API or California crudes tend to be lower than for WCS. Adjustment based on an econometric model developed by the UNDP/ World Bank: files/08105.technical%20paper_crude%20oil%20price% 20Differentials%20and%20Differences%20in%20Oil%20Qualities% 20A%20Statistical%20Analysis.pdf 16 Transportation costs are based on various costs presented on the US Department of State Keystone XL Draft Environmental Impact Statement (DEIS), as well as a recent analysis performed by IHS CERA, and a presentation from Gibsons: pdf 20TD%20Rail%20Forum%20October% pdf 17 Pipeline transportation costs to the USGC are given by Keystone/ Seaway combination for the existing option and Keystone XL for the proposed pipeline option. Intermodal to USGC: Pipeline/ Tanker = Transmountain to Vancouver + Panama/ Suezmax tanker via Panama Canal. Rail to USGC = AB hub to Lloydminster, SK + Rail to Port Arthur, TX via CPRS-St.Paul-UP. Intermodal to USGC: Rail/ Tanker = Rail to Prince Rupert + Panama/ Suezmax tanker via Panama Canal. Intermodal to USGC: Rail/ Barge = AB hub to Lloydminster, SK + Rail to Wood River, Ill + Barge. Intermodal to USWC: Pipeline/ Tanker/ Barge = Transmountain to Vancouver + Tanker or Barge to USWC.

4 $/bbl Page 4 $ $ $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 $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 -$5.00 -$10.00 $98.29 $77.99 Hardsity Median USGC Heavy Sour Crude Landed Costs Figure 2: Dilbit Pricing Dynamics, 2011 ($/bbl) 17 $2.50 $8.00 $9.95 $10.00 $9.00 $6.00 $14.05 $17.80 $16.62 $17.70 $18.50 $13.00 $15.99 $16.00 $7.85 $7.80 $8.80 $9.99 $3.75 $1.18 $2.99 $0.10 Costs ($/bbl) Netback Improvement ($/bbl) $ $95.79 Estimated Dilbit Netback ($/bbl) $93.98 WCSB Parity USGC Heavy Sour Crude - Dilbit Quality Adjustment Estimated Dilbit Eq. USGC (No Transportation Costs) Estimated Dilbit Price USGC (No Transportation Costs) Pipeline (10-YR Committed Tolls) Intermodal: Pipeline/ Tanker Pipeline (Uncommitted Tolls) ($/bbl) Rail (Unit Train) ($/bbl) Intermodal: Rail/ Tanker ($/bbl) Intermodal: Rail/ Barge ($/bbl) Proposed Pipeline ($/bbl) Median USWC Heavy Sour Crude (Dilbit Eq.) Acquisition Costs ($/bbl) USWC Heavy Sour Crude - Dilbit Quality Adjustment ($/bbl) Estimated Dilbit USWC (No Transportation Costs) ($/bbl) Estimated Dilbit Price USGC (No Transportation Costs) ($/bbl) Intermodal: Pipeline/ Tanker or Barge ($/bbl) Rail (Unit Train) ($/bbl) Rail (Manifest Train) ($/bbl) USGC Pricing Dynamics AB -> USGC Transportation Costs USWC Pricing Dynamics AB -> USWC Transportation Costs Sources: Data from EIA, IHS CERA, Gibsons, and US Department of State, figure and analysis by CERI.

5 Page 5 US$/bbl Spot Crude Prices Differential WTI Brent US$/bbl US$/bbl WTI - Edmonton Light Price Differentials Differential WTI Edmonton Light Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Apr Mar-07 Mar-08 Mar-09 Mar-10 Mar-11 Mar-12 Mar-13 Spot Prices WTI Brent Edm.Light H.Hardisty Year-to-Date Quarter-to-Date April 22, SOURCE: EIA. SOURCE: EIA. US$/bbl 160 WTI - Hardisty Heavy Price Differentials US$/bbl 102 NYMEX Crude Forward Curve 12 months 140 Differential WTI Hardisty Heavy Mar-07 Mar-08 Mar-09 Mar-10 Mar-11 Mar-12 Mar Feb Mar Apr SOURCE: NRCan, EIA. SOURCE: EIA, CERI. Relevant Independent Objective

6 SOURCE: EIA, CERI. SOURCE: NRCan. Page 6 NYMEX Petroleum Products CDN/US$ Exchange Rate US$/gal 4.00 CDN/US$ RBOB Gasoline Heating Oil Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Apr Mar-07 Mar-08 Mar-09 Mar-10 Mar-11 Mar-12 Mar-13 NYMEX Prices Unleaded Gasoline Heating Oil Year-to-Date Quarter-to-Date April 22, Oil Demand Global in Selected Oil Demand Countries US Products Demand March March 2013 Y-on-Y change MMbpd % % 25% 90 20% 80 50% 70 15% % 48% 10% 5% 30 0% % 46% 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13-5% -10% Total Gasoline Jet Fuel Distillate Residual Propane Other Total OECD Total Non-OECD non-oecd Demand share SOURCE: IEA Oil Market Report. SOURCE: EIA Weekly Petroleum Status Report.

7 SOURCE: IEA Oil Market Report, CERI. SOURCE: IEA Oil Market Report. SOURCE: IEA Oil Market Report. SOURCE: IEA Oil Market Report. Page 7 Global Oil Supply MMbpd Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 non-opec Supply OPEC Supply non-opec Share of Global Supply Canadian Oil Production by product Mbpd 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Q12 1Q13 2Q13 3Q13 4Q13 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 12,000 10,000 8,000 6,000 4,000 2,000 0 Mbpd 3,000 2,500 2,000 1,500 1, US Oil Production by region 4Q12 1Q13 2Q13 3Q13 4Q13 Alaska California Texas Federal GOM Other Lower 48 NGLs Other OECD Commercial Stocks by region Feb-10 Feb-11 Feb-12 Feb-13 OECD North America OECD Europe OECD Pacific Relevant Independent Objective

8 Page 8 MMb US Commercial Stocks February 22 - March 28, 2013 Crude Gasoline Distillate Products Total MMb Canadian Stocks on Land 4Q11 1Q12 2Q12 3Q12 4Q12 SOURCE: EIA Weekly Petroleum Status Report. SOURCE: IEA Oil Market Report.

9 Page 9 World Supply and Demand Balance (MMbpd) Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 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 Jan-13 Feb-13 Mar-13 Jan-13 Feb-13 Mar-13 Saudi Arabia Iran UAE Kuwait Qatar Nigeria Libya Algeria Ecuador OPEC Iraq Total OPEC WTI Price Projections ($US/barrel) Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 High Price Case Reference Case Low Price Case Relevant Independent Objective

10 Page 10 Data Appendix

11 Page 11 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. -6.9% -6.0% -7.2% -6.5% Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Yr-on-Yr Chg % -13.1% -13.7% -13.7% 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. 1.7% 1.2% 1.8% 2.0% -0.2% -0.4% 0.7% 1.3% Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Yr-on-Yr Chg. -8.4% -8.4% -6.7% -7.4% -8.0% -8.6% -9.3% -7.6% 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). Relevant Independent Objective

12 Page 12 A3: World Crude Oil Contract Prices (FOB, $US per barrel) Saudi U.A.E. Oman U.K. Norway Russia Venez. Kuwait Ecuador Mexico Nigeria Indon. Arab Lgt Dubai Oman Brent Ekofisk Urals 1 T.J. Light Blend Oriente Isthmus Bonny Lgt Minas Q Q Q Q Q Yr-on-Yr Chg. 0.3% 0.9% 0.3% 0.6% 0.4% 0.2% -7.7% 0.0% -5.1% -7.4% -0.8% -4.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -1.9% -1.7% -2.7% 2.2% 1.3% 1.6% -3.7% -3.3% -2.6% -3.2% 2.1% -2.9% Notes: 1. Urals is Delivered price at Mediterranean. Contract prices are based on prices at the end of each month. Source: OPEC Monthly Oil Market 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. -3.5% -8.4% -10.6% -9.5% -10.1% -10.3% -9.5% -10.7% -10.4% -11.9% -13.6% -16.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -8.9% 2.9% 2.7% -1.8% -1.9% -2.0% -1.8% -1.8% -2.0% -3.8% -9.8% -21.3% 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.

13 Page 13 A5: Crude Oil Quality Differentials (FOB, $US per barrel) Light vs. Heavy Sweet vs. Sour Arab Lt Arab Hv Diff. Isthmus Maya Diff. ELS 1 HH 2 Diff. GCS WTS Diff Q Q Q Q Q Yr-on-Yr Chg. 0.3% 0.0% -7.4% -9.9% -10.8% -13.3% -10.3% -10.1% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -1.9% -4.6% -3.2% -8.3% -7.8% -19.6% -2.0% -1.9% Notes: 1. Edmonton Light Sweet. 2. Hardisty Heavy. Based on contract prices at the end of each month. Sources: OPEC Monthly Oil Market 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. -8.4% -5.0% -7.2% -5.1% -2.0% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg % -13.4% -13.9% -13.3% -9.0% 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. Source: OPEC Monthly Oil Market Report. Relevant Independent Objective

14 Page 14 A7: World Petroleum Product Spot Prices ($US per barrel) NY Harbor, Barges Rotterdam, Barges Singapore, Cargoes Gasoline 1 No. 2 H.O. Resid. 2 Gasoline 1 Gasoil Resid. 3 Gasoline 1 Gasoil Resid Q Q Q Q Q Yr-on-Yr Chg. -5.4% -10.2% 5.0% -2.9% -3.6% -10.8% -3.5% -5.1% -12.1% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. -9.2% -14.2% 0.0% -12.0% -10.8% -14.8% -9.2% -10.5% -14.4% Notes: 1. Regular unleaded gasoline. 2. High Sulfur (3.0%) Residual Fuel Oil. 3. High Sulfur (3.5%) Residual Fuel Oil. Spot prices are based on average daily prices over a specific timeframe. Source: IEA Oil Market Report. A8: Product Spot Prices in Selected American Cities ( US per gallon) NY Harbor US Gulf Los Angeles Gasoline 1 No. 2 H.O. Distill. Gasoline 1 Jet Fuel Distill. Gasoline 1 Distill Q Q Q Q Q Yr-on-Yr Chg. -2.4% -3.0% -2.4% -5.1% -2.8% -2.4% -3.6% -3.3% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. -8.0% -8.5% -8.0% -8.5% -8.8% -8.0% -10.5% -10.8% Notes: 1. Reformulated regular unleaded gasoline. Spot prices are based on average daily prices over a specific timeframe. Source: EIA Weekly Petroleum Status Report.

15 Page 15 B1: World Petroleum Supply and Demand Balance (million barrels per day) OECD Non-OECD OPEC World N. A. Europe Asia-Pac Total 1 Asia Non-Asia FSU Total 1 P. Gulf Non-Gulf Total 2 Total 3 Demand Q Q Q Q Q Q Q Q Q Supply Q Q Q Q Q Q Q Q Q Balance Q Q Q Q Q Q Q Q Q Notes: 1. Totals for OECD and non-oecd supply include net refining gains; specific regions/groupings within each do not. 2. OPEC demand is an estimate based on historical annual data. 3. Balance for World equals global stockbuilds (+) and stockdraws (-) for crude oil and petroleum products and miscellaneous gains and losses. Regional surpluses (+) and deficits (-) are balanced through net-imports and stock changes in the short-term, and net-imports in the longer term. Supply includes crude oil, condensates, NGLs, oil from non-conventional sources and processing gains. Demand is for petroleum products. Source: IEA Oil Market Report. Relevant Independent Objective

16 Page 16 B2: World Petroleum Production (million barrels per day) OECD Non-OECD OPEC World N. A. Europe Asia-Pac Total Asia Non-Asia FSU Total P. Gulf Non-Gulf Total Total Q Q Q Q Q Yr-on-Yr Chg. 7.3% -11.1% -13.5% 3.3% 0.1% -2.7% 0.8% -0.3% -3.2% 0.0% -2.0% -0.2% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. 9.0% -9.2% 0.0% 5.4% 0.3% 0.2% 0.4% 0.3% -3.4% -2.5% -2.7% 0.1% R/P Ratio Notes: 1. Production includes crude oil, condensates and NGLs. 2. Reserve-Production ratio is based on latest month production and British Petroleum reserve estimates. Sources: IEA Oil Market Report and BP Statistical Review of World Energy. B3: OECD Commercial Petroleum Stocks (million barrels) North America Europe Asia-Pacific OECD Crude Product Total Crude Product Total Crude Product Total Crude Product 1 Total , ,422 2, , ,408 2, , ,409 2,666 4Q , ,408 2,601 1Q , ,388 2,659 2Q , ,010 1,374 2,699 3Q , ,430 2,738 4Q , ,409 2,666 Yr-on-Yr Chg. 7.7% 0.8% 3.8% 8.3% -2.0% 0.9% 1.7% 3.8% 1.8% 6.9% 0.1% 2.5% Feb , ,388 2,629 Mar , ,388 2,659 Apr , ,379 2,681 May , ,007 1,375 2,693 Jun , ,010 1,374 2,699 Jul , ,000 1,412 2,726 Aug , ,431 2,731 Sep , ,430 2,738 Oct , ,394 2,698 Nov , ,004 1,380 2,693 Dec , ,409 2,666 Jan , ,419 2,697 Feb , ,390 2,664 Yr-on-Yr Chg. 8.9% -2.6% 2.0% 4.2% -0.1% 0.9% -12.0% 12.6% 0.2% 3.8% 0.1% 1.4% Notes: 1. Product includes only finished petroleum products. 2. Total stocks include NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. All stocks are closing levels for respective reporting period. Source: IEA Oil Market Report.

17 Page 17 B4: OPEC Crude Oil Production and Targets (million barrels per day) Persian Gulf Non-Persian Gulf OPEC-11 OPEC-11 Arabia Iran UAE Kuwait Qatar Venez. Nigeria Libya Algeria Angola Ecuador Total 1 Target Iraq Q Q Q Q Q Yr-on-Yr Chg. -6.8% -20.5% 2.3% 3.3% -1.3% -0.4% -3.9% 6.2% -0.9% -0.6% 4.2% -4.3% 11.9% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. -7.0% -18.8% 1.9% 4.4% -1.3% -2.0% -4.9% -6.2% 0.0% 1.1% 4.2% -4.7% 6.1% Quotas Over/Under % -19.8% 21.6% 27.9% 1.4% 25.6% 16.8% -7.5% -5.0% 16.4% 16.3% -8.4% Notes: 1. Does not include NGLs; OPEC production targets apply to crude oil only. 2. Iraq does not have an official OPEC target. 3. OPEC-10 production targets. 4. As of latest month. Source: IEA Oil Market Report. B5: OECD Refinery Activity Crude Input (MMbpd) - Utilization (percent) - Refining Margins ($US/barrel) North America Europe Asia-Pacific OECD Input Util. Margin 1 Input Util. Margin 2 Input Util. Margin 3 Input Util Q Q Q Q Q Yr-on-Yr Chg. -0.1% -50.3% -2.5% 66.3% 2.2% % -0.6% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. -3.4% % -0.5% 605% 2.5% % -1.3% Notes: 1. Based on dated Brent being processed in average US Gulf cracking refinery. 2. Based on dated Brent in average Rotterdam cracking refinery. 3. Based on spot Dubai in average Singapore hydroskimming refinery. Source: IEA Oil Market Report. Relevant Independent Objective

18 Page 18 C1: US Petroleum Supply and Demand Balance (million barrels per day) United States 1 East Mid-West Supply Demand Net-Imp. Stk. Chg. Supply Demand Balance Supply Demand Balance Q Q Q Q Q Yr-on-Yr Chg. 11.2% -1.0% -16.2% 6.3% -9.0% 9.2% -1.5% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 8.5% 2.1% -11.7% 17.7% -1.6% 6.4% 5.1% % of Total % 100.0% 1.5% 28.2% 23.2% 26.0% South-Central North-West West Supply Demand Balance Supply Demand Balance Supply Demand Balance Q Q Q Q Q Yr-on-Yr Chg. 17.3% 8.9% 2.5% 0.7% -2.7% -3.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 14.8% 5.3% -4.8% 4.3% -4.9% -2.3% % of Total % 28.0% 7.2% 3.8% 12.2% 13.9% Notes: 1. Does not balance because of unaccounted for crude oil. Regional surpluses (+) and deficits (-) are balanced through net-imports/transfers and stock changes in the short-term, and net-imports/transfers in the longer term. 2. As of most recent month. Supply includes crude oil, condensates, NGLs, oil from nonconventional sources and processing gains. Demand is for petroleum products. Source: EIA Petroleum Supply Monthly.