CERI Crude Oil Report

Transcription

1 March 2017 CERI Crude Oil Report Oil Sands Energy Intensities, Dynamics, and Efficiency Opportunities Alpha Sow If you can t measure it, you can t manage it. This maxim has become a slogan for oil sands operators since the drop of oil prices caused by the global supply glut. Companies are looking to survive in a new normal environment of low prices, weak demand growth, and carbon regulations. Reducing energy intensity of hydrocarbon development is paramount for many stakeholders, policy makers, investors, and the public at large. As it pertains to the oil sands industry, the new regulations stipulate an absolute emissions cap of 100 Mt CO 2eq per year. Policy makers and the provincial regulator are facing the task of allocating the remaining 30 Mt CO 2eq emissions; what approach will be adopted is not yet clear. While the new regulations take place, the oil sands industry is looking for a fundamental way to reduce production costs and improve profit margins. Energy and emissions intensities are strongly linked to operational costs. Reduction in oil sands energy and emisisons intensities leads to some reduction in operating costs. The intent of this article is to review the oil sands operations energy intensities and the potential energy and emissions reductions in the current economic and carbon policy environment. A brief discussion is provided on how the allocation of the remaining 30 Mt CO 2eq can be achieved. Introduction Oil sands is a mixture of sand, clay or other minerals, water, and bitumen, which is a heavy and extremely viscous oil at room temperature. The Alberta estimated reserve is about billion barrels 1 under the current economic assumption. Oil sands can be surface mined using truck and shovel to move sand saturated with bitumen from the mining area to an extraction facility. However, if the deposit is deeply buried more than 75 meters below the surface, in situ thermal or solvent-based operation is used to reduce the viscosity of the bitumen and then pumped to the surface. The most common in situ processes in Alberta are Cyclic Steam Simulation (CSS), and Steam Assisted Gravity Drainage (SAGD). Once separated from the gas, water, and other materials, the bitumen product is diluted and shipped for sale or upgraded. Each of those operational steps requires a significant amount of energy, and there is a wide variability of energy consumption among oil companies depending on the geology, process design, and operational framework. Figure 1 highlights average annual energy intensities by project type expressed as GJ of energy per barrel of extracted bitumen. Figure 1: Alberta Oil Sands Energy Intensities by Project Type CERI Commodity Report Crude Oil Editorial Committee: Ganesh Doluweera, Paul Kralovic, Dinara Millington, Megan Murphy, Allan Fogwill 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. For more information about CERI, please visit our website at or contact us at info@ceri.ca. Source: CERI, AER ST98, ST39, AESO, CAPP Relevant Independent Objective

2 Page 2 Oil sands energy demand is a mix of thermal, electricity, hydrogen, and diesel. The proportions of these energy forms vary according to bitumen extraction method and processing type. Thermal energy comes from burning natural gas, synthetic, fuel or associated gas. It is primarily used to produce steam, hot process water, and heating fuel during operations. Steam, for example, is generated through boilers and injected in-situ (SAGD and CSS) for bitumen mobilization, and is used in combination with hot process water in the mining during the separation process. Steam can also be generated during the bitumen upgrading phase from integrated heat recovery process in coking and hydrocracking unit and used in sulfur plant or hydrotreating unit. Heating fuel is used in upgrading to drive fractionation, distillation and cracking processes, and hydrogen production. Electricity is used to power pumps, compressors, heaters, mixers, and valves in oil sands operations. Hydrogen is mainly produced from steam methane reforming and used for the upgrading process. Hydrogen is essentially used for the primary upgrading stage in hydro-cracking and later in the secondary upgrading phase to produce a higher value, sweet synthetic crude oil. Diesel is widely employed in mining operations as fuel for trucks and shovels, and to a large extent for transportation of oil and gas operation staff and materials. Oil sands energy intensities 2 are subject to variability. As shown in Figure 2, the variability is a function of reservoir characteristics, operation and project phase. The stack of each energy type is directly related to the processes operation. Diesel is mostly related to mining, and hydrogen for upgrading, but each process uses electricity and thermal energy (natural gas, fuel gas, etc.). Figure 2 highlights the share of each energy type, the blue point represents the median energy use while its variability is represented by the length of the vertical bar from different oil sands projects in Alberta. The green point shows the average empirical data for the industry in 2014; energy consumption data is sourced from the Alberta Energy Regulator. Figure 2: Median Energy Intensities, Energy Mix, and 2014 Median Energy Intensities Source: CERI Study 151 Potential Energy Efficiency Gains Given the unstable and current low oil price environment, US shale oil production, global oil supply glut, increasingly stringent emissions regulations, and social pressure to reduce GHG emissions, the growth of the oil sands industry will depend on how quickly it reduces the energy intensity of its operations. Oil companies are looking to address these challenges through energy efficiency in the existing facilities and piloting new technologies for upcoming projects where energy intensity and cost reduction drive the decision process. Brownfield projects: Oil sands operators are looking to increase efficiency by using steam solvent process and retrofitting existing infrastructure to draw down costs. The most promising energy efficiency reduction method for brownfield SAGD 3 facilities constitutes trimming energy consumption at each stage of the process. Energy savings start at the water treatment step where magnesium from produced water is separated and used to absorb silica (silica removal) in the lime softening process unit reducing the need for additional magnesium. The treated water is boiled in an Once-Through Steam Generator (OTSG) to generate steam at 80% steam quality, while the remaining 20%, which is known as blowdown is sent to an evaporator where 50% of it is converted to steam and the remaining is retained in the sludge. Through a combination of steam flood management that relies on analytics of data physics, an optimum mix of steam and solvent is sent at the right temperature and pressure into the reservoir. The total cumulative impact of processes and technologies that

3 Page 3 can be applied to the existing field/facilities is able to achieve 48% (CERI Study 164) reduction of natural gas consumption. In-situ greenfield facilities offer more flexibility in the early design of the project, reducing capital costs and providing more opportunity for energy intensity reduction. Steam solvent and pure solvent-based processes can achieve greater performance when combined with steam flood management. bitumen with less energy consumption and cost than full upgrading. Figure 3 shows the potential energy efficiency achievable through process and technology changes. Figure 3: Potential Energy Efficiency Achievable by Process Type The greenfield steam-solvent configuration combines energy efficient processes at each step of the operation. The Rifle Tube Once Through Steam Generator (RT- OTSG) for generating the steam, steam solvent extraction such as the Solvent-Aided Process, Steam Assisted SAGD and the front-to-back (FTB) water treatment process for filtration by electrocoagulation can achieve cumulatively 65% (CERI Study 164) natural gas use reduction. Pure solvent technology such as the NSolv process which uses a solvent for bitumen recovery need limited thermal energy 80% less than the standard requirement. The thermal energy is used for solvent heating and purification and the treatment of produced water. A 2012 Suncor and Jacobs study 4 on oil sands mining operations estimates potential reduction of energy consumption by 13% for mining and upgrading. The energy efficiency in mining operations is achieved by introducing energy monitoring, heat exchanger and efficient fire heater, control systems and some process technologies that change the mining and extraction process. In the same way, upgraders energy consumption can be reduced by integrating heat exchange, process technology changes, control system, better energy monitoring, change of fuel type use and avoiding flaring and hydrocarbon loss. For greenfield upgrading, operators are considering partial upgrading technologies. The most promising processes are cavitation, catalyst-induced refining, desulfurization, deep conversion, pyrolysis and thermal cracking. This results in a bitumen product (API 19 to API 22.9) 5 that is lighter and less sweet than fully upgraded synthetic crude oil (SCO) but less viscous than pure Source: CERI Studies 151, 164, Suncor & Jacobs Emission Allocation Under the 100 Mt CO 2 eq. Cap To extend the analysis to a macro level, the oil sands industry ranks as one of the major GHG emitters among the Canadian sectors, and it s estimated that GHG emissions from the sector will continue to grow from current 70 Mt/year CO 2eq. CERI estimates that emissions will reach 100 Mt/year CO 2eq. in Alberta had successfully adopted a regulatory framework to limit oil sands emissions at the 100 Mt CO 2eq cap 7 and applied an economy-wide carbon tax in its recent Climate Change Leadership Plan. The cap includes operating upgrading facilities and excludes future upgrading or partial upgrading and future co-generation. There is speculation on how the provincial regulator and the Alberta Government will allocate the remaining 30 Mt CO 2eq. without distorting competition and inducing sustainable behaviors for oil companies. Since 2013, the AER has been working with the University of Pennsylvania Penn program on regulation to become a world class regulator. 8 The working document suggests flexible regulatory approaches promise more cost-effective outcomes, as they give regulated entities the opportunity to choose lower-cost means of achieving regulatory outcomes. But as followup research 9 shows, relying on this assumption as a working framework, and relying on tools such as Industry Wide Best Practices 10 will not always lead to significant

4 Page 4 change in private sector firms environmental performance. Although it can achieve a positive outcome, these results are unlikely to be significant or reliable enough to make such strategies the mainstay of society s approach to environmental protection. 11 The challenge is to set a regulatory mechanism complying with best-in-class standard. The standard should be flexible, leaving choices to oil companies to comply at the lower cost and delivering full potential of their oil resources for Albertans. Many methodologies can be considered on how to allocate the remaining 30 Mt CO 2eq ; the discussion sets an assumption that the current GHG emissions and onstream production are fixed (70 Mt CO 2eq ) and the emissions room left by decommissioned fields is replaced by higher intensity of depleting oil fields. The following options can be assessed, but one of them seems to fulfill the best in class regulator standard and the spirit of the 100 Mt CO 2eq cap achieving a sustainable oil sands growth. 1- First come first self-serve basis: emissions are allocated as companies applications are approved. This approach will lead companies to hedge by using a multiphase application process and will hold credit for the future. Future development will be limited, and few companies will be allowed to invest because of limited emissions credit. 2- Best in class based on emission intensities of the first quartile: allocating the remaining emissions cap to the first quartile of more efficient entities. This approach will distort concurrence because emissions are directly tied to the energy consumption and geology condition. Companies with high SOR operations will face restrictions to grow; companies who have good leases will thrive. In such a system, the best in class regulator metrics such as fairness will be strained. The best in class might promote an implicit carbon cost differential among the industry, the barrier for new entrance and burden the development of some oil deposits. 3- Continuous Improvement: the regulator might find it challenging to implement this method due to difficulty of setting up a baseline (base year), measuring the progress, and monitoring changes. This type of approach could fail to satisfy fair cost regulation and verifiability. 4- Weighted Production approach: will cause past dependence and favour big players with more diverse oil plays; it allows major companies to choose a mix between oil deposits, project phase-startup, production ramp up, and older fields. Production growth will be achieved by incremental extensions of the existing fields. 5- Moving Threshold and Fair sharing approach: companies will be granted temporary emissions right (3- year period) at the current carbon price as it seeks regulatory approval from the AER. The right to pollute is bounced back for adjunction every three years to replenish the 30 Mt CO 2eq reserve. The new round of emissions allotment will be based on the Shamir Secret Sharing Scheme, 12 where each company s GHG emissions are set as an incomplete share of the secret. The regulator sets a goal to achieve a unique composite metric combining the four major environmental impacts: land use, water, GHG emissions, venting and flaring. The composite metric is set as a secret unknown to oil producers and built up from oil companies performance data, collected during the three-year period. Each company s pollution right in the new GHG allocation round will be based on production and the overall environmental performance during the last three-year phase of the project development. The threshold being unknown to oil companies, they will try their best to reach the best performance achievable in each area, because its future oil production depends on the pollution rights gained. There is no threshold target, so companies will compete to get the bigger share of the 30 Mt CO 2eq with the best knowledgeable practices. The moving threshold and fair sharing are reliable, and not subject to bias. When the 100 Mt CO 2eq cap is exceeded, a specific carbon rate is applied to transfer the excess emissions to the economy. When a new company comes in without history, a statistical attribution factor is assigned to the company for the next three years. The current regulations carbon tax and oil sands cap targets are framed to incite innovation adoption without burdening Alberta oil producers in the North American market. Allocating the 30 Mt CO 2eq without giving preferential treatment of picking winners and losers might be challenging.

5 Page 5 None of the approaches above are perfect. However, some of them limit the structural burden linked to unfavorable reservoir and medium quality lease resources. Less energy-intensive oil sands means a more sustainable and competitive industry. CERI Study 164 shows emissions and cost reduction objectives are not adversely related and can be achieved through technology and process innovation. Endnotes Study_151_Full_Report.pdf 3 Study_164_Full_Report.pdf 4 Suncor_GHG_Reduction_Roadmap-Final_Jacobs_Report.pdf 5 Study_164_Full_Report.pdf 6 Study_164_Full_Report.pdf pprfinalconvenersreportpdf 9 article=1104&context=faculty_scholarship management 11 article=1104&context=faculty_scholarshipibid 12 How to share a secret, Shamir A. Communication ACM-1979 vol 22.

6 Page 6 US$/bbl WTI Spot - WTI Edmonton Crude - Brent Prices Light Price Price Differentials Differentials (US$/bbl) Brent-WTI Differential WTI Brent Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 US$/bbl US$/bbl WTI - Edmonton Light Price Differentials (US$/bbl) Differential WTI Edmonton Light Mar-14 Mar-15 Mar-16 Mar-17 Spot Prices WTI Brent Cdn.Light* Cdn. Heavy* Year-to-Date Quarter-to-Date SOURCE: EIA. April 18, SOURCE: EIA. US$/bbl 120 WTI - Canadian WTI - Hardisty Heavy Heavy Benchmark Price (US$/bbl) Differentials US$/bbl 55 NYMEX WTI Crude Forward Curve 4 contract months Differential WTI WCS Feb 08, 2017 Mar 08, 2017 Apr 07, Mar-14 Mar-15 Mar-16 Mar-17 SOURCE: NRCan, EIA, Baytex. SOURCE: EIA, CERI.

7 SOURCE: EIA, CERI. SOURCE: NRCan. Page 7 NYMEX Petroleum Products CDN/US$ Exchange Rate US$/gal 2.00 CDN/US$ RBOB Gasoline Heating Oil Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr Mar-14 Mar-15 Mar-16 Mar-17 NYMEX Prices Unleaded Gasoline Heating Oil Year-to-Date Quarter-to-Date April 18, Oil Demand Global in Selected Oil Demand Countries US Products Demand March March 2017 Y-on-Y change MMbpd % 52.5% % 40% 30% % 20% % 10% % 0% % 50.0% 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17-10% -20% 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. Relevant Independent Objective

8 SOURCE: IEA Oil Market Report, CERI. SOURCE: IEA Oil Market Report. SOURCE: IEA Oil Market Report. SOURCE: IEA Oil Market Report. Page 8 Global Oil Supply MMbpd Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 non-opec Supply OPEC Supply non-opec Share of Global Supply Canadian Oil Production by product Mbpd 6,000 5,000 4,000 3,000 2,000 1, Q16 1Q17 2Q17 3Q17 4Q17 AB L/M/H AB Bitumen SK Other NGLs Synthetic 60.5% 60.0% 59.5% 59.0% 58.5% 58.0% 57.5% 57.0% Mbpd 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 Mbpd 3,500 3,000 2,500 2,000 1,500 1, US Oil Production by region 4Q16 1Q17 2Q17 3Q17 4Q17 Alaska California Texas Federal GOM Other Lower 48 NGLs Other OECD Commercial Stocks by region Feb-14 Feb-15 Feb-16 Feb-17 OECD North America OECD Europe OECD Pacific

9 SOURCE: EIA Weekly Petroleum Status Report. SOURCE: IEA Oil Market Report. Page 9 MMb US Commercial Stocks February 24 - March 31, 2017 M-on-M Change Crude Gasoline Distillate Products Total MMb Canadian Stocks on Land 4Q15 1Q16 2Q16 3Q16 4Q16 Relevant Independent Objective

10 Page 10 World Supply and Demand Balance (MMbpd) Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 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 Spare Capacity vs Production Capacity Jan-17 Feb-17 Mar-17 Jan-17 Feb-17 Mar-17 Saudi Arabia Iran UAE Kuwait Qatar Angola Nigeria Libya Algeria Ecuador Venezuela Gabon OPEC. Excl. Iraq Iraq Total OPEC WTI Price Projections ($US/barrel) Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 High Price Case Reference Case Low Price Case

11 Page 11 Data Appendix Relevant Independent Objective

12 Page 12 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. 71.1% 68.1% 52.2% 43.4% Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Yr-on-Yr Chg. 14.2% 19.5% 40.3% 31.5% 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. 38.0% 39.6% 39.9% 33.6% 52.8% 54.4% 53.5% 46.7% Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Yr-on-Yr Chg. 18.4% 15.9% 16.4% 14.4% 32.8% 33.5% 28.7% 25.4% 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).

13 Page 13 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. 74.3% 74.3% 68.8% 58.5% 56.4% 62.1% 102.9% 84.3% 81.5% 73.5% 60.3% 58.2% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. 45.9% 45.7% 39.7% 34.0% 32.9% 35.4% 70.9% 51.2% 48.9% 47.4% 34.7% 39.7% 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. CDN Sweet 2 CDN Heavy Q Q Q Q Q Yr-on-Yr Chg. 27.3% 59.2% 68.0% 53.7% 63.8% 66.9% 53.7% 55.0% 71.8% 60.4% 73.1% 111.0% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg % 39.9% 41.9% 31.5% 36.6% 38.1% 31.5% 31.4% 40.5% 31.2% 79.5% 96.4% Notes: 1. ANS is Delivered price on US West Coast. 2. As of August 2016, Edmonton Light Sweet is referred to as Canadian Sweet. 3. As of August 2016, Western Canadian Select is referred to as Canadian Heavy. Posted prices are based on price at the end of each month. Sources: Oil & Gas Journal; Natural Resources Canada. Relevant Independent Objective

14 Page 14 A5: Crude Oil Quality Differentials (FOB, $US per barrel) Light vs. Heavy Sweet vs. Sour Arab Lt Arab Hv Diff. Isthmus Maya Diff. CDN Sweet 1 CDN Heavy 2 Diff. GCS WTS Diff Q Q Q Q Q Yr-on-Yr Chg. 74.3% 85.9% 73.5% 73.7% 73.1% 111.0% 66.9% 63.8% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. 45.9% 49.4% 47.4% 49.3% 79.5% 96.4% 38.1% 36.6% Notes: 1. As of August 2016, Edmonton Light Sweet is referred to as Canadian Sweet. 2. As of August 2016, Western Canadian Select is referred to as Canadian Heavy. 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. 57.6% 60.6% 76.2% 64.6% 73.7% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. 36.1% 38.4% 51.7% 40.8% 45.2% 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.

15 Page 15 A7: World Petroleum Product Spot Prices ($US per barrel) US Gulf Coast, Pipeline Rotterdam, Barges Singapore, Cargoes Gasoline 1 No. 6 3% 2 Jet/Ker. Gasoline 1 Gasoil Resid. 3 Gasoline 1 Gasoil Resid Q Q Q Q Q Yr-on-Yr Chg. 46.2% 115.4% 53.9% 47.2% 58.1% 135.9% 39.7% 63.4% 101.9% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. 23.1% 87.5% 38.1% 34.9% 37.6% 95.7% 24.1% 43.3% 76.6% Notes: 1. Regular unleaded gasoline. 2. Waterborne 3. High Sulfur ( %) 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. 37.8% 51.3% 49.0% 46.9% 51.6% 52.5% 33.3% 50.5% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. 24.2% 31.8% 28.4% 25.5% 35.2% 33.3% 12.6% 31.3% Notes: 1. Reformulated regular unleaded gasoline. Spot prices are based on average daily prices over a specific timeframe. Source: EIA Weekly Petroleum Status Report. Relevant Independent Objective

16 Page 16 B1: World Petroleum Supply and Demand Balance (million barrels per day) OECD Non-OECD OPEC World Americas Europe Asia Ocean. 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.

17 Page 17 B2: World Petroleum Production (million barrels per day) OECD Non-OECD OPEC World Americas Europe Asia Oc. Total Asia Non-Asia FSU Total P. Gulf Non-Gulf Total Total Q Q Q Q Q Yr-on-Yr Chg. -1.5% 0.0% -4.7% -1.4% 7.2% 2.2% 1.5% 3.0% 2.0% -16.5% -2.5% -0.5% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. -1.2% -0.3% -4.7% -1.1% 7.9% 1.4% 1.2% 2.8% 2.3% -17.8% -2.0% -0.3% 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) Americas Europe Asia Oceania OECD Crude Product Total Crude Product Total Crude Product Total Crude Product 1 Total , ,020 1,401 2, , ,208 1,502 3, , ,177 1,500 2,985 4Q , ,208 1,502 3,015 1Q , , ,235 1,509 3,046 2Q , , ,208 1,529 3,052 3Q , ,176 1,556 3,060 4Q , ,177 1,500 2,985 Yr-on-Yr Chg. 0.7% 0.4% 0.6% -6.1% -0.3% -1.9% -6.9% -2.4% -4.6% -2.6% -0.2% -1.0% Feb , , ,225 1,522 3,052 Mar , , ,235 1,509 3,046 Apr , , ,207 1,510 3,025 May , , ,215 1,525 3,050 Jun , , ,208 1,529 3,052 Jul , , ,205 1,572 3,101 Aug , , ,181 1,578 3,086 Sep , ,176 1,556 3,060 Oct , ,196 1,522 3,048 Nov , ,182 1,522 3,028 Dec , ,177 1,500 2,985 Jan , , ,212 1,543 3,064 Feb , , ,221 1,522 3,055 Yr-on-Yr Chg. 0.9% -1.3% 0.4% -0.2% 1.7% 0.7% -4.5% 0.3% -2.4% -0.3% 0.0% 0.1% 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. Relevant Independent Objective

18 Page 18 B4: OPEC Crude Oil Production and Targets (million barrels per day) Persian Gulf Non-Persian Gulf OPEC-12 Arabia Iran UAE Kuwait Qatar Angola Nigeria Libya Algeria Venez. Ecuador Gabon Total 1 Iraq Q Q Q Q Q Yr-on-Yr Chg. -3.0% 20.3% 4.6% -4.2% -9.1% -7.9% -21.0% 83.3% -4.5% -12.8% -3.7% -9.1% -3.7% 3.5% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. -2.6% 16.6% 6.6% -4.6% -10.4% -10.0% -22.0% 79.4% -5.4% -13.6% -5.5% -9.1% -3.4% 5.3% Notes: 1. Does not include NGLs; OPEC production targets apply to crude oil only. 2. Iraq does not have an official OPEC target. Source: IEA Oil Market Report. B5: OECD Refinery Activity Crude Input (MMbpd) - Utilization (percent) - Refining Margins ($US/barrel) Americas Europe Asia Oceania OECD Input Util. Margin 1 Input Util. Margin 2 Input Util. Margin 3 Input Util Q Q Q Q Q Yr-on-Yr Chg. -2.7% 46.9% 0.6% 1.0% 3.4% 90.1% -0.6% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. -1.8% 58.5% 1.9% 49% 1.8% 12.9% 0.1% 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.

19 Page 19 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. -1.9% 2.0% 8.7% 20.6% -0.9% -4.0% 4.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -1.4% 0.9% 3.1% 15.3% 0.4% -3.9% -1.4% % of Total % 100.0% 3.5% 27.7% 24.3% 25.8% South-Central North-West West Supply Demand Balance Supply Demand Balance Supply Demand Balance Q Q Q Q Q Yr-on-Yr Chg. -2.0% 3.7% -3.5% 5.5% -1.0% 0.3% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -0.2% 0.9% -5.2% 1.2% -4.0% 6.4% % of Total % 28.1% 7.0% 3.5% 9.0% 14.9% 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. Relevant Independent Objective

20 Page 20 C2: US Petroleum Demand by Product (million barrels per day) Finished Petroleum Products NGLs Petroleum Gasoline Jet Fuel Distil. Resid. Total 1 Total Total Q Q Q Q Q Yr-on-Yr Chg. 0.5% 3.6% 4.7% 15.8% 2.4% 0.3% 2.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -1.9% 9.9% -0.9% 35.7% 0.5% 2.7% 0.9% Notes: 1. Total includes other finished petroleum products. 2. Total petroleum demand includes refinery feedstocks, additives/oxygenates and other hydrocarbons. Source: EIA Petroleum Supply Monthly. C3: US Petroleum Stocks (million barrels) Petroleum Stocks 1 Crude Oil Finished Products East Mid-West S-Cent N-West West U.S. Total 2 Gasoline Jet Fuel Distil. Resid. Total , ,856 1, , ,015 1, , ,031 1, Q , ,015 1, Q , ,052 1, Q , ,077 1, Q , ,048 1, Q , ,031 1, Yr-on-Yr Chg. 1.5% -2.2% 2.1% -2.2% -3.9% 0.8% 0.2% 0.6% 6.3% 2.9% -1.5% 1.4% Jan , ,041 1, Feb , ,045 1, Mar , ,052 1, Apr , ,063 1, May , ,079 1, Jun , ,077 1, Jul , ,062 1, Aug , ,063 1, Sep , ,048 1, Oct , ,050 1, Nov , ,054 1, Dec , ,031 1, Jan , ,053 1, Yr-on-Yr Chg. 5.7% -2.4% 1.8% -2.9% -9.1% 0.6% 0.4% 6.3% -0.2% 5.2% -8.2% 1.0% Notes: 1. Petroleum stocks include crude oil, finished products, NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. 2. Includes Strategic Petroleum Reserves. 3. Total includes other finished petroleum products. All stocks are closing levels for respective reporting period. Source: EIA Petroleum Supply Monthly.

21 Page 21 C4: US Petroleum Net Imports by Source (million barrels per day) Region of Origin OPEC Canada Mexico Lat. Am. Europe Africa M.E. Total 1 Venez. S. Arabia Nigeria Total 2 P. Gulf Q Q Q Q Q Yr-on-Yr Chg. 11.6% 3750% -11.8% -53.2% 163.4% 6.7% 8.7% -13.3% -9.5% 180.3% 11.6% 5.8% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 10.2% 1342% -37.9% -67.6% 141.5% 37.3% 3.1% 1.4% 27.7% 160% 26.8% 37.4% % of Total % -6.9% 7.7% -1.1% 11.0% 41.3% 100.0% 13.1% 26.8% 6.4% 71.5% 41.4% Notes: 1. Total includes net-imports from Russia and Asia-Pacific region. 2. Total OPEC includes the other eight cartel members. 3. As of latest month. Source EIA Petroleum Supply Monthly. C5: US Regional Crude Oil Production (million barrels per day) PAD District U.S. Major Producers East Mid-West S-Cent N-West West Total Alaska Calif. 1 Louis. Texas G. of Mex Q Q Q Q Q Yr-on-Yr Chg. -7.0% -9.2% -6.1% -13.2% -2.5% -6.9% 2.1% -6.3% -9.9% -7.2% -4.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -1.6% -9.4% -1.8% -11.8% -5.2% -4.4% -1.9% -8.3% -13.1% -6.0% 8.5% R/P Ratio Notes: 1. California includes Federal Offshore crude oil production. 2. Gulf of Mexico includes Federal Offshore production adjacent to Texas and Louisiana. 3. Crude oil Reserve-Production ratio as of latest production month. Crude oil production does not include NGLs. Source: EIA Petroleum Supply Monthly. Relevant Independent Objective

22 Page 22 C6: US Refinery Activity Crude Input (MMbpd) - Utilization (percent) East Mid-West South-Central North-West West U.S. Input Util. Input Util. Input Util. Input Util. Input Util. Input Util Q Q Q Q Q Yr-on-Yr Chg. -5.6% 7.2% 0.1% 0.1% -7.3% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -7.5% -0.1% 1.8% 7.0% -0.4% 0.6% % of Total 1 6.4% 22.6% 51.9% 3.7% 15.4% 100.0% Notes: 1) As of most recent month. Source: EIA Petroleum Supply Monthly. C7: US Refinery Margins ($US per barrel) NY Harbor Chicago US Gulf Los Angeles (East Coast Comp.) (WTI) (WTS) (ANS) Q Q Q Q Q Yr-on-Yr Chg % 20.8% 26.4% 10.7% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg % -11.5% 10.5% -21.4% Note: Based on specific crude being processed in average cracking refinery in a given area. As of February 2010, NY Harbor Arab Med. is now East Coast Composite. Source: Oil and Gas Journal.

23 Page 23 D1: Canada Petroleum Supply and Demand Balances (million barrels per day) Canada East West Supply Demand Net-Exp Stk. Chg. Supply Demand Balance Supply Demand Balance Q Q Q Q Q Yr-on-Yr Chg. 4.0% 2.6% 4.1% 28.4% -8.7% 2.6% 20.6% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 6.9% 7.1% 10.1% 18.4% -2.0% 6.1% 19.5% % of Total % 100.0% 6.8% 52.6% 93.2% 47.4% Notes: 1. As of most recent month. See notes for Table C1 for additional comments. Source: Statistics Canada s Energy Statistics Handbook. D2: Canada Demand by Product (million barrels per day) Finished Products Gasoline Distil. Resid. Total Q Q Q Q Q Yr-on-Yr Chg. 4.9% 2.4% -7.6% 1.3% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -8.5% 4.8% -94.7% -0.8% Notes: 1. Total includes other finished petroleum products. 2. Total petroleum demand includes refinery feedstocks, additives/oxygenates and other hydrocarbons. Source: Statistics Canada s Energy Statistics Handbook. D3: Canada Petroleum Stocks (million barrels) Finished Products Crude Oil Petrol. Gasoline Distil. Resid. Total 1 Total Total Q Q Q Q Q Yr-on-Yr Chg. -5.3% -13.2% -32.0% -12.6% -30.2% -24.5% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 1.5% -11.0% -27.2% -6.3% -28.2% -21.1% Notes: 1. Total includes other finished petroleum products. 2. Total petroleum stocks include NGLs, refinery feedstocks, additives/ oxygenates and other hydrocarbons. All stocks are closing levels. Source: Statistics Canada s Energy Statistics Handbook. Relevant Independent Objective

24 Page 24 D4: Canada Crude Oil Production (million barrels per day) Major Producers Canada Petroleum Type Alta. Sask. B.C. N.W.T. Atlantic Total 1 Light SCO Heavy Bitumen NGLs Q Q Q Q Q Yr-on-Yr Chg. 5.3% -9.5% -0.2% -7.2% 42.3% 4.5% -3.6% 17.8% -8.4% 3.9% 6.4% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 5.5% 1.8% -13.8% -3.4% 22.2% 5.2% % % % % % Note: Total includes small amounts of production from Manitoba and Ontario. Source: Statistics Canada s Energy Statistics Handbook. D5: Canada Petroleum Imports by Source (thousand barrels per day) Non-OPEC OPEC Imports Mexico U.S. U.K. Norway Total 1 Algeria Nigeria S. Arabia Venez. Total 2 P. Gulf Total Q Q Q Q Q Yr-on-Yr Chg 0.0% 35.2% 14712% 18.4% 6.0% -10.0% % 0.0% 0.0% -30.7% 0.0% 2.8% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 0.0% 0.0% 0.0% 25.0% % 0.0% 0.0% 0.0% % 0.0% 11.0% % of Total 3 0.0% 41.5% 9.1% 3.0% 100.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0% Notes: 1. Includes all non-opec production. 2. Includes production by the other seven OPEC members. 3. As of most recent month. Sources: Statistics Canada s Energy Statistics Handbook.

25 Page 25 E1: World Drilling Activity (active oil and gas rigs) OECD Non-OECD OPEC World N. A. Europe Asia-Pac Total Asia Non-Asia Total 1 P. Gulf Non-Gulf Total Total , , , , , , ,592 1Q ,729 2Q ,412 3Q ,538 4Q ,690 1Q , , ,966 Yr-on-Yr Chg. 39.2% -6.5% 32.3% 34.4% 4.6% -15.0% -7.0% -1.8% -13.4% -5.5% 13.7% Mar ,550 Apr ,424 May ,404 Jun ,407 Jul ,482 Aug ,547 Sep ,584 Oct ,620 Nov ,678 Dec ,772 Jan-17 1, , ,918 Feb-17 1, , ,994 Mar-17 1, , ,985 Yr-on-Yr Chg. 79.1% -9.6% 62.5% 68.1% 5.7% -9.8% -3.3% 1.3% -13.8% -3.6% 28.1% % of Total % 3.8% 0.7% 57.8% 9.3% 11.1% 20.4% 15.5% 6.3% 21.8% 100.0% Notes: 1. Does not include active rigs in the Former Soviet Union and onshore rigs in China. 2. As of latest month. Source: Baker Hughes, Inc. E2: North American Drilling Activity (active oil and gas rigs) United States Canada North America 1 East Mid-West S-Cent N-West West Total Land 2 Offshore Total Oil Gas Total , ,861 1, , , , Q Q Q Q Q ,027 Yr-on-Yr Chg. 63.1% 10.3% -6.3% 45.8% 15.4% 35.2% 38.1% -21.0% 76.6% 46.5% 35.4% 44.7% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb ,053 Mar ,042 Yr-on-Yr Chg % 26.9% -6.3% 79.6% 37.5% 65.4% 70.8% -26.8% 187.5% 88.1% 65.6% 84.4% % of Total 3 6.2% 14.5% 2.9% 41.4% 11.6% 75.7% 73.9% 1.9% 24.3% 85.2% 14.8% 100.0% Notes: 1. Excluding Mexico. 2. Includes drilling on inland waterways. 3. As of latest month. Source: Baker Hughes, Inc. Relevant Independent Objective

26 Page 26 Geographical Specifications 1. The World: OECD is comprised of countries from three regions: North America (Canada, Mexico, US); Europe (Austria, Belgium, Czech Republic, Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Luxembourg, the Netherlands, Norway, Poland, Portugal, the Slovak Republic, Spain, Sweden, Switzerland, Turkey, UK); and Asia-Pacific (Australia, Japan, New Zealand, South Korea). OPEC is comprised of Persian Gulf (Iran, Iraq, Kuwait, Qatar, Saudi Arabia, United Arab Emirates) and non-persian Gulf countries (Algeria, Indonesia, Libya, Nigeria, Venezuela). Non-OECD is comprised of countries from three regions: Former Soviet Union (Armenia, Azerbaijan, Belarus, Georgia, Kazakhstan, Kirghizstan, Moldova, Russia, Crude Oil Qualities Producing API Country or Gravity Region F) Sulfur Content (%) BBLs/Metric Tonne Crude Stream Tapis Blend Malaysia Ekofisk Blend Norway WTI Texas GCS Gulf of Mexico Oklahoma Sweet Oklahoma Kansas Sweet Kansas Wyoming Sweet Wyoming ELS Alberta Brent Blend United kingdom Bonny Light Nigeria Oman Blend Oman Arabian Light Saudi Arabia Minas Indonesia Isthmus Mexico Michigan Sour Michigan WTS Texas Urals Russia Tia Juana Light Venezuela Dubai U.A.E Lost Hills California Cano Limon Colombia Arabian Heavy Saudi Arabia ANS Alaska Oriente Ecuador Hardisty Heavy Alberta Maya Mexico Kern River California Tajikistan, Turkmenistan, Ukraine, Uzbekistan); Asia (including non-oecd Oceania); and non-asia (Africa, Middle East, Latin America, and non- OECD Europe). 2. United States: East (PADD I) New England (Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont); Central Atlantic (Delaware, Maryland, New Jersey, New York, Pennsylvania, and the District of Columbia) and Lower Atlantic (Florida, Georgia, North Carolina, South Carolina, Virginia, and West Virginia). Mid -West (PADD II) Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin. South-Central (PADD III) Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas. North-West (PADD IV) Colorado, Idaho, Montana, Idaho, Montana, Wyoming. West (PADD V) Alaska, Arizona, California, Hawaii, Nevada, Oregon, Washington. 3. Canada: East is comprised of Ontario, Manitoba, Quebec and the Maritime provinces (New Brunswick, Newfoundland and Labrador, Nova Scotia, and Prince Edward Island). West is comprised of Alberta, British Columbia, Saskatchewan and the northern territories (NorthWest Territories, Nunavuut, and Yukon). Additional Notes 1. Petroleum and oil refer to crude oil and natural gas liquids (NGLs), whereas crude oil refers to its namesake and field condensates. Condensates derived from natural gas processing plants are classified as NGLs. 2. The spot price is for immediate delivery of crude oil or refined products at a specific location. Spot transactions are generally on a cargo by cargo basis. In contrast, a futures price is for delivery of a specified quantity of a commodity at a specified time and place in the future. 3. Crude oil sold Free-On-Board (FOB) is made available to the buyer at the loading port at a particular time, with transportation and insurance the responsibility of the buyer. Crude oil sold Cost-Insurance-Freight (CIF) is priced at a major destination point, with the seller responsible for the transportation and insurance to that point. A Delivered transaction is similar to a CIF transaction, except the buyer in the former pays based on the quantity and quality ascertained at the unloading port, whereas in a CIF transaction, the buyer accepts the quantity and quality as determined at the loading port. 4. Processing gain is the volume of which refinery output is greater than crude oil inputs. The difference is due to the processing of crude oil products, which in total have a lower specific gravity than crude oil. 5. Unaccounted for crude oil reconciles the difference between crude input to refineries and the sum of domestic production, net imports/exports, stock changes and documented losses (in the U.S.). 6. Totals may not equal the sum of their parts in the statistical tables due to rounding. For more information, please contact Dinara Millington at dmillington@ceri.ca. Canadian Energy Research Institute 150, Street NW Calgary, AB T2L 2A6