CERI Crude Oil Report

Transcription

1 April 2018 Policy Debates and Business Timelines Allan Fogwill Concerns regarding the balance of economic and environmental objectives continue to be part of the policy debate in Canada. We see concerns raised by Indigenous Peoples concerning the Site C hydroelectric facility in BC and similarly with the Muskrat Falls project in Labrador. We have seen the delay or cancellation of natural gas electricity generation projects in Ontario due to concerns from local citizens, and we have seen delays and regulatory changes associated with oil and natural gas pipelines across the country. These concerns create delays in the timeline for various projects. While businesses or proponents indicate that these delays cost money, it is not clear how they determine the cost of these delays. CERI suggests that if we want to understand the economic impacts of delays we need to have a common framework for assessing it. Otherwise, the estimates put forward can be countered with alternative numbers that can vary significantly. Agreeing on the facts is the first step in attempting to reach consensus on issues of concern. A delay in a project has three overall economic impacts that can be supported in the academic literature. These include: Additional interest charges on the overall upfront costs of the project. Normally when firms determine the cost of the project, they estimate how long it will take to pay back those costs either to investors (if internally financed) or financial institutions. A oneyear delay means more interest on the same money that had been borrowed. Editorial Committee: Ganesh Doluweera, Dinara Millington, Megan Murphy, Allan Fogwill About CERI Founded in 1975, the Canadian Energy Research Institute is an independent, registered charitable organization specializing in the analysis of energy economics and related environmental policy issues in the energy production, transportation, and consumption sectors. Our mission is to provide relevant, independent, and objective economic research of energy and environmental issues to benefit business, government, academia and the public. For more information about CERI, please visit our website at or contact us at info@ceri.ca. Reduction in present value of net revenues from a project. When considering these impacts, it is important to separate out the revenues collected to pay for operating costs. Those will tend to balance out over time. However, the net profit from a project can be delayed. Such a delay means the revenue stream collected by a company has a lower present value. Delayed economic impacts from the project under consideration - additional jobs, provincial taxes, GDP again, these impacts do not disappear. They are delayed, and it is the time value of money that creates the cost associated with changing the timeline of a project as delayed future benefits in the same dollar amount are less valuable to society. Aside from the economic costs, there are some specific financial expenses which are difficult to quantify. These include the risk associated with stock market valuations and legal costs associated with policy debates that move toward a provincial or federal court. The extent of these costs can vary widely but are a consideration by a firm as it looks to pursue a project. Let us consider the Trans Mountain Pipeline Expansion Project to illustrate the framework. We know that there is a debate underway regarding the policy implications of this project. The principle argument is the jurisdictional authority of a provincial government (in this case BC) versus the federal government. In the past, jurisdictional concerns have often been resolved through negotiations. In the case of the Trans Mountain Pipeline, that does not seem to be a realistic option. As such, a reference to the Supreme Court on jurisdictional authority appears to be the path which is being followed. Moreover, given that there are other matters of overlapping jurisdiction such as in health care and environment, such a reference would provide clarity to how the Canadian Federation is to function in the future.

2 Page 2 Source: So, let's return to the Trans Mountain case as an example of the costs of project delays. The Trans Mountain Pipeline Expansion Project is an expansion of an existing oil pipeline from 300,000 barrels per day to 890,000 barrels per day (b/d). As shown on the map, the route starts in Edmonton and ends in Vancouver. From that point, oil is placed onto oceangoing tankers and can be sold to markets in Asia and North America. The major policy concern is the risk of oil spills in the coastal waters around BC. CERI collected information on the project from Kinder Morgan s regulatory filings. 1 This information can be considered credible as the company must attest to it in hearings in front of an adjudicator (NEB) and to which the company and management can be held accountable for its accuracy. The capital cost of the project is listed as CAD$5.5 billion to be spent over seven years ( ). When it was adjusted for inflation and brought into constant 2012 dollars, the cost is CAD$4.9 billion. As we noted earlier, the cost of the delay is the additional carrying cost of the project. If the project is delayed one year, for example, the net capital costs will have to fund an additional year. Think of it as an additional set of mortgage payments when you delay paying off your home mortgage by one year. A key assumption is what interest rate you use. Standard practice is to use the weighted cost of capital which is a combination of the return to debt holders and a return to equity investors. Ten percent (10%) is the standard rate used most often. Using this rate gives us the cost of a 1-year delay in the project of CAD$490 million (constant 2012 dollars). If the pipeline is not in operation, it does not generate revenues. It also does not incur operating costs except for ongoing funding of the internal operations and project management. These are difficult to estimate. As such, it is the net revenues which would be a cost factor of a delay.

3 Page 3 Some Trans Mountain shippers contract for firm pipeline commitments and others for intermittent or spot service. Of the 590,000 b/d new capacity, most is committed to firm contracts with 180,000 b/d assigned to the spot market. Annual revenues associated with these contracts were estimated by the Conference Board to be $944 million based on the projected capital costs of the Project and the toll structure that would be applied. This revenue estimate only includes the fixed component of the toll. 2 However, that includes the full pipeline and not just the expansion. The existing pipeline generates CAD$300 million annually, which is ongoing. Therefore, the total incremental revenue lost from a delay is CAD$644 million. That fixed component for firm shippers would be the all-in costs of the pipeline operations. That said, the net revenues would approximate the return on equity (ROE) which can vary. If we assume an ROE of 15%, that means the net revenue would be CAD$96.6 million per year. It gets complicated when the intermittent shipping annual revenue of $191 million 3 is considered. Often firms include a smaller portion of these revenues toward fixed costs. If we assumed that 50% of these revenues are net of cost, then the lost annual net revenue is $95.5 million. The final element of the cost of a delay is the delay in a Gross Domestic Product (GDP) contribution of the project to the provincial and national economies. Again, it is important to note that a delay only means that the benefits happen later. The cost is losing those benefits for one year, in this example. The Conference Board of Canada in their assessment determined an annual GDP benefit of CAD$693.1 million. 4 Here we would have to consider that a social discount rate is more appropriate, as our society takes a longer view of costs and benefits compared to financial markets and companies. If we assume a discount rate of 5%, we get the cost of a one-year delay in this project of CAD$34.7 million. Overall, we see that policy debates that impact business timetables have an impact on the firm and the economy. In this case, for the Kinder Morgan expansion project, we see the cost of a one-year delay as CAD$490 million plus $96.6 million plus $95.5 million plus $34.7 million for a total of CAD$716.8 million. So, during a policy debate, the delay of this pipeline being constructed for one year is more than CAD$700 million. This number does not take into consideration provincial, and federal taxes which would be paid if the pipeline was operational or the value people place on additional employment. This is but one example. Similar calculations can be done using any major project for which delays in the process occur. It is, therefore, important that when decision makers consider these debates and listen to the concerns of stakeholders and project proponents that a similar calculus occur. Are we done with this example? No. In the case of our oil supply system, the market dynamics are complicated. One of the challenges is the price discount by which Canadian producers sell their product to customers. Normally the price discount between Canadian crude and the West Texas Intermediate price is in the CAD$15 range. This goes higher and lower depending on the availability of transport capacity and the quality of the crude exports. For instance, since December 2017, the differential was in the rage of US$15-30 (CAD$20-40). At the same time, Kinder Morgan s existing pipeline was oversubscribed in January by 35% and in February by 32%, 5 while the Keystone pipeline was full in 2017 except for November. 6 In 2017, CERI analyzed how that differential might affect the economic contribution to Canada of crude oil exports. Our rule of thumb is that for every CAD$1 per barrel of crude change in the annual average differential, the economic contribution to Canada changes by CAD$1 billion. So, as we consider the policy implications of whether additional crude oil pipelines are in the national or provincial interest, we should also be aware that additional capacity improves the economic contribution of these activities to the country. It cannot be stated that additional capacity of a pipeline will result in reducing the crude price discount experienced by Canadian producers. However, it is another consideration when determining the scope and timeliness of resolving our policy debates in Canada.

4 Page 4 Endnotes 1 Kinder Morgan s application to the NEB for the project, specifically Volumes 1, 2 and 4. The documents available include all the necessary information. Two studies that made Appendices A and B in Vol. 2 of the Application are used: IHS Global Canada Ltd. Trans Mountain Expansion Project Direct Written Evidence of Steven J. Kelly and Conference Board of Canada report The Trans Mountain Expansion Project: Understanding the Economic Benefits for Canada and its Regions. 2 The variable component is primarily based on the electricity costs associated with shipping through the pipeline and is passed directly through to shippers. As such, the variable component would not have an impact on the labour or material inputs that the pipeline would use, or on the profits that it generates, and is not included when estimating the economic effects. 3 Conference Board of Canada estimate, in TMEP Application. 4 ibid crdl/kstn-eng.html

5 Page 5 US$/bbl 80 WTI Spot - WTI Edmonton Crude - Brent Prices Light Price Price Differentials Differentials (US$/bbl) US$/bbl 9 US$/bbl 70 WTI - Edmonton Light Price Differentials (US$/bbl) Brent-WTI Differential WTI Brent Differential WTI Edmonton Light Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar Feb-15 Feb-16 Feb-17 Feb-18 Spot Prices WTI Brent Cdn.Light* Cdn. Heavy* Year-to-Date Quarter-to-Date SOURCE: EIA. April 9, SOURCE: EIA. US$/bbl 70 WTI - Canadian WTI - Hardisty Heavy Heavy Benchmark Price (US$/bbl) Differentials US$/bbl 68 NYMEX WTI Crude Forward Curve 4 contract months 60 Differential WTI WCS Feb 09, 2018 Mar 09, 2018 Apr 10, Feb-15 Feb-16 Feb-17 Feb SOURCE: NRCan, EIA, Baytex. SOURCE: EIA, CERI.

6 SOURCE: EIA, CERI. SOURCE: NRCan. Page 6 NYMEX Petroleum Products CDN/US$ Exchange Rate US$/gal CDN/US$ RBOB Gasoline Heating Oil Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar Feb-15 Aug-15 Feb-16 Aug-16 Feb-17 Aug-17 Feb-18 NYMEX Prices Unleaded Gasoline Heating Oil Year-to-Date Quarter-to-Date April 10, Oil Demand Global in Selected Oil Demand Countries US Products Demand March March 2018 Y-on-Y change MMbpd % 52.0% 51.5% 51.0% 50.5% 50.0% 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 % 25% 20% 15% 10% 5% 0% -5% -10% -15% -20% -25% 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 Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 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, Q17 4Q17 1Q18 2Q18 3Q18 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 16,000 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 3Q17 4Q17 1Q18 2Q18 3Q18 Alaska California Texas Federal GOM Other Lower 48 NGLs Other OECD Commercial Stocks by region Jan-15 Jan-16 Jan-17 Jan-18 OECD North America OECD Europe OECD Pacific

8 SOURCE: EIA Weekly Petroleum Status Report. SOURCE: IEA Oil Market Report. Page 8 MMb US Commercial Stocks February 23 - March 30, 2018 M-on-M Change Crude Gasoline Distillate Products Total MMb Canadian Stocks on Land 4Q16 1Q17 2Q17 3Q17 4Q17

9 Page 9 World Supply and Demand Balance (MMbpd) Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 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 Dec-17 Jan-18 Feb-18 Dec-17 Jan-18 Feb-18 Saudi Arabia Iran UAE Kuwait Qatar Angola Nigeria Libya Algeria Equatorial Guinea Ecuador Venezuela Gabon OPEC. Excl. Iraq Iraq Total OPEC

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. 15.6% 16.3% 16.5% 11.9% Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Yr-on-Yr Chg. 33.9% 30.1% 21.2% 17.6% 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. 15.8% 16.9% 14.4% 11.4% 22.7% 23.1% 20.6% 16.9% Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Yr-on-Yr Chg. 18.7% 19.6% 19.6% 19.6% 28.8% 29.7% 25.8% 23.6% 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).

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. 25.0% 22.8% 21.6% 24.0% 25.6% 26.8% 27.4% 24.9% 26.6% 20.5% 24.0% 20.2% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 19.4% 15.2% 14.3% 18.3% 19.4% 17.4% 22.6% 17.6% 20.4% 15.6% 19.5% 13.6% 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. 19.0% 29.8% 33.8% 17.7% 19.9% 20.5% 17.7% 18.3% 21.4% 17.8% 15.6% 11.9% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 2.2% 27.0% 26.1% 20.0% 22.2% 22.9% 20.0% 21.0% 23.8% 20.6% 11.7% -10.5% 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.

13 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. 25.0% 26.7% 20.5% 24.4% 15.6% 11.9% 20.5% 19.9% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 19.4% 18.5% 15.6% 21.8% 11.7% -10.5% 22.9% 22.2% 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. Page 13 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. 12.4% 24.3% 22.9% 27.2% 24.9% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 16.4% 18.3% 15.2% 17.4% 18.9% 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. Source: OPEC Monthly Oil Market Report.

14 Page 14 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. 17.5% 26.9% 22.6% 24.5% 20.2% 28.5% 17.2% 20.3% 22.1% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 15.6% 17.9% 19.7% 25.4% 11.1% 17.1% 10.2% 16.8% 13.4% 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. 14.8% 21.7% 21.3% 16.9% 21.7% 19.9% 15.2% 19.1% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 17.5% 18.6% 19.3% 14.4% 19.5% 17.8% 6.9% 17.5% 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 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.

16 Page 16 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. 7.4% -6.0% -7.3% 5.1% -2.9% -3.5% -1.0% -2.2% -3.9% 2.0% -2.2% -0.3% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 6.5% -2.2% 7.9% 5.2% -4.5% -3.4% -0.1% -2.2% 0.1% 1.6% 0.5% 0.9% 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 , ,208 1,502 3, , ,177 1,500 2, , ,098 1,444 2,853 4Q , ,177 1,500 2,985 1Q , , ,245 1,479 3,030 2Q , ,211 1,483 3,016 3Q , ,161 1,475 2,970 4Q , ,098 1,444 2,853 Yr-on-Yr Chg % -5.1% -6.3% -2.9% -3.3% -2.9% -1.4% 1.7% -0.6% -6.7% -3.7% -4.4% Jan , , ,212 1,544 3,067 Feb , , ,228 1,521 3,056 Mar , , ,245 1,479 3,030 Apr , , ,223 1,516 3,054 May , , ,228 1,504 3,057 Jun , ,211 1,483 3,016 Jul , , ,206 1,495 3,031 Aug , ,166 1,511 3,014 Sep , ,161 1,475 2,970 Oct , ,140 1,450 2,926 Nov , ,145 1,430 2,903 Dec , ,098 1,444 2,853 Jan , ,114 1,439 2,871 Yr-on-Yr Chg % -8.1% -8.3% -3.1% -6.1% -4.6% -2.8% -3.4% -3.2% -8.1% -6.8% -6.4% 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-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. -5.3% 0.0% -7.3% -5.6% -4.7% 0.6% 9.6% 75.4% -8.9% -17.5% -1.9% -4.5% -2.7% -4.1% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 0.0% 0.3% -4.4% -0.4% 1.7% -4.8% 17.2% 52.2% -1.0% -24.4% -3.8% 0.0% 0.0% 0.7% 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. 3.5% -6.5% 0.6% 0.4% 3.9% 59.0% 2.6% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 1.2% -42.2% 0.4% -28% -1.2% -60.6% 0.5% 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.

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. 10.9% 1.5% -44.8% 21.3% 8.1% 12.6% -0.1% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 11.2% 6.4% -26.9% 14.9% 17.2% 13.6% 2.4% % of Total % 100.0% 3.6% 30.5% 24.8% 24.9% South-Central North-West West Supply Demand Balance Supply Demand Balance Supply Demand Balance Q Q Q Q Q Yr-on-Yr Chg. 10.6% -4.1% 18.0% -2.7% -1.6% 4.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 10.3% 1.5% 24.8% 6.9% -1.9% 2.3% % of Total % 26.8% 7.8% 3.5% 8.0% 14.3% 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.

19 Page 19 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. 0.1% 6.4% 0.2% 13.7% 0.6% 0.1% 1.5% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 2.8% -0.4% 16.2% -26.1% 4.4% 2.6% 6.4% 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 , ,015 1, , ,031 1, , ,895 1, Q , ,031 1, Q , ,033 1, Q , ,009 1, Q , ,978 1, Q , ,895 1, Yr-on-Yr Chg % -5.9% -7.3% -2.4% 4.1% -6.7% -8.1% -13.9% -3.6% -12.0% -29.3% -11.5% Jan , ,053 1, Feb , ,049 1, Mar , ,033 1, Apr , ,033 1, May , ,039 1, Jun , ,009 1, Jul , ,998 1, Aug , ,986 1, Sep , ,978 1, Oct , ,943 1, Nov , ,923 1, Dec , ,895 1, Jan , ,879 1, Yr-on-Yr Chg % -11.5% -7.4% -4.5% 4.7% -8.4% -9.6% -11.5% 0.7% -16.5% -20.0% -11.5% 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.

20 Page 20 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. 4.7% 32% -80.0% 338.9% 9.5% -13.0% -44.8% -32.0% -31.5% 70.2% -12.6% -14.8% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -0.4% 101% 36.2% 692.9% 3.3% -25.0% -26.9% -36.3% -44.8% 2% -23.0% -25.3% % of Total % -19.0% 14.4% -12.1% 15.6% 42.4% 100.0% 11.4% 20.3% 8.9% 75.4% 42.3% 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. 21.4% 10.5% 8.8% 15.4% -2.8% 8.4% 2.4% -7.4% -14.4% 12.7% 1.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 33.6% 14.2% 13.9% 22.9% -3.1% 12.7% -0.6% -5.5% -8.0% 21.8% -0.9% 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.

21 Page 21 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. 3.2% -0.1% 4.1% -0.7% 9.1% 3.6% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 1.7% 0.1% 4.7% 2.3% 0.9% 2.8% % of Total 1 6.3% 22.0% 52.9% 3.7% 15.1% 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. 1.9% 20.0% -2.9% 1.8% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. -7.4% -5.7% -11.6% 19.2% 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.

22 Page 22 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. 4.8% 12.0% -0.8% -4.5% 11.6% 5.4% 12.5% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. 9.4% 8.2% 17.0% -0.9% 6.7% 10.1% 10.1% % of Total % 100.0% 5.9% 54.1% 94.1% 45.9% 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. 1.9% 9.9% 14.7% 3.6% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. -0.2% -3.4% -94.1% -2.9% 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. -0.6% 8.4% 6.4% 5.7% 2.1% 3.5% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. -0.6% 8.4% 6.4% 5.7% 2.1% 3.5% 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.

23 Page 23 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. 5.9% 4.9% 7.5% -80.1% -5.5% 4.9% 6.9% -6.6% -1.9% 9.8% 31.9% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. 11.3% 3.4% 4.8% -46.0% -1.6% 9.4% 9.3% 10.1% -2.6% 9.2% 27.0% 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% % 0.0% 0.0% 17.8% -99.9% 0.0% 0.0% 0.0% -99.9% 0.0% 10.7% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. 0.0% % % 0.0% 18.9% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 18.9% % of Total 3 0.0% 0.0% 0.0% 0.0% 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.

24 Page 24 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 , , , , , , ,027 1Q , , ,966 2Q , , ,965 3Q , , ,102 4Q , , ,075 1Q , , ,208 Yr-on-Yr Chg. 20.5% -14.3% 17.1% 18.0% 6.7% 9.2% 8.1% 2.0% -0.3% 1.3% 12.3% Mar-17 1, , ,985 Apr , ,918 May-17 1, , ,935 Jun-17 1, , ,041 Jul-17 1, , ,110 Aug-17 1, , ,116 Sep-17 1, , ,080 Oct-17 1, , ,077 Nov-17 1, , ,058 Dec-17 1, , ,089 Jan-18 1, , ,175 Feb-18 1, , ,271 Mar-18 1, , ,179 Yr-on-Yr Chg. 15.8% -2.7% 30.8% 14.8% 1.1% 6.8% 4.2% 2.9% -1.6% 1.6% 9.8% % of Total % 3.4% 0.8% 60.5% 8.6% 10.8% 19.4% 14.5% 5.6% 20.1% 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 , ,079 1Q ,027 2Q ,007 3Q ,155 4Q ,125 1Q , ,238 Yr-on-Yr Chg. 84.0% 18.0% -2.2% 25.1% 25.7% 30.6% 32.2% -24.1% -5.2% 19.8% 25.0% 20.6% Mar ,042 Apr May Jun ,081 Jul ,151 Aug ,164 Sep ,150 Oct ,126 Nov ,116 Dec ,135 Jan , ,215 Feb , ,292 Mar , ,207 Yr-on-Yr Chg. 72.3% 14.6% -6.7% 21.8% 19.8% 25.3% 26.7% -33.0% -13.8% 14.7% 22.3% 15.8% % of Total 3 9.3% 14.3% 2.3% 43.5% 12.0% 81.9% 80.8% 1.1% 18.1% 84.4% 15.6% 100.0% Notes: 1. Excluding Mexico. 2. Includes drilling on inland waterways. 3. As of latest month. Source: Baker Hughes, Inc.

25 Page 25 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