CERI Commodity Report Crude Oil

Transcription

1 CERI Commodity Report Crude Oil January-February 2014 Social Licence to Operate You don t get your social license by going to a government ministry and making an application or simply paying a fee It requires far more than money to truly become part of the communities in which you operate. - Pierre Lassonde President of Newmont Mining Corporation There is no doubt that the natural resource industry has been a catalyst in the advancement of societies needs and well-being, and the economic growth and industrialization of some countries. Natural resources are also an important part of the Canadian economy. For generations, natural resources have brought opportunity, jobs and growth to every region. Experts have found that resource development has positive benefits across the country, including indirect jobs in manufacturing and other industries. In 2012, close to 1.6 million Canadians were employed in the natural resources sector, which makes up 10 percent of all employment in Canada. Revenues stemming from natural resource development contribute on average 10 percent to total Canadian GDP and this does not include the exports of those resources. 1 The resource sector is generally accepted by the public at large because of the role it plays and benefits it provides, however, at the level of individual projects, this acceptance is neither automatic nor unconditional. Today, there is a need to gain and maintain the support of the communities that live and work in the area of impact and influence any given project, or in other words, to have the Social Licence to Operate. Social licence to operate is seen as a critical success factor for 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 resource development in many regions, and, increasingly, gaining social licence is seen as an important aspect of managing environmental and social risks. There is ample evidence that a failure to gain and maintain this social licence can lead to conflict, delays or cost for the proponents of a project. Furthermore, acting beyond the minimum requirements of regulatory approvals is an important component of establishing a company s long-term reputation and brand among stakeholders and communities. This process of acquiring social licence demands early and ongoing investment of effort by proponents to develop and maintain social capital within the context of trust-based relationships with aboriginal people, local communities, and other interested groups. What is Social Licence? Social licence is said to be granted when a project has the ongoing approval within the local community and other stakeholders, ongoing approval or broad social acceptance and, most frequently, as ongoing acceptance. Usually informal and intangible, 2 social licence is buried in the beliefs, perceptions and opinions held by the local population and other stakeholders about the project. It is therefore granted by the community. Finally, it is dynamic and non-permanent because beliefs, opinions and perceptions are subject to change as new information is acquired. Hence social licence has to be earned and then maintained. Social licence can be expressed in a variety of ways, ranging from absence of opposition to vocal support or even advocacy. These various levels of social licence, as well as an absence of one, may occur at the same time among different interested parties. What Makes Up Social Licence? It is believed that the components of social licence comprise the community/stakeholder perceptions of the social legitimacy and credibility of the project, and the presence or absence of true trust. These elements are acquired sequentially and are cumulative in building Relevant Independent Objective

2 Page 2 towards earning social licence. The project must be seen as legitimate before credibility is considered, and both must be in place before meaningful trust can develop (see Figure 1). Figure 1: Gaining Social Licence Source: On Common Ground Consultants Inc The best way to illustrate the nature of social licence is through an example. The following shows how one energy company pursued social licence with the community that is directly impacted by the proposed development. Since its inception, Kitimat LNG has been developing the project with community and First Nations consultation and strict adherence to both provincial and federal government environmental review processes. In 2005, Kitimat LNG and the Haisla Nation signed an agreement in principle and entered a mutually supportive and precedent-setting partnership for the development of LNG in the Haisla s territory. One of the key aspects of the partnership was Kitimat LNG s willingness to alter the location of the facility to an industrial site already developed by the Haisla. By engaging with the Haisla Nation early in the process, Kitimat LNG has secured a partner in and advocate for the project, as well as further LNG development, and established the company s social licence to operate in the Haisla s territory. Likewise, through working effectively with Kitimat LNG, the Haisla Nation has emerged as a substantial beneficiary of LNG development in its territory. The relationship includes a range of project-related benefits, such as economic growth, training opportunities, employment, and community and social benefits. How to Measure Social Licence? Energy development in Canada affects a wide range of stakeholders. These stakeholders can be characterized into three different groups. Developers and investors who provide capital for energy projects and expect a reasonable return for their investment; local communities who reside in the area of development and bear a disproportionately larger share of the costs/ impacts associated with a project; and consumers or the public at large who benefit from the product or service produced by the development. Hence, social licence can be said to affect all three categories of stakeholders. The debate revolves around how the benefits and costs are distributed, and what is in the best public interest in terms of environmental protection, energy security, and economic growth. From a simple economic efficiency perspective, social licence should be granted only to those projects, for which all-in benefits exceed all-in costs. That means that all project costs associated with access to the land and negative environmental externalities, such as social and health costs are included. Under some circumstances, market forces on their own might lead to the right decision as to whether a project proceeds or not: for example, the locals could be in position to refuse access to their land unless the compensation they receive is sufficient to offset all of the costs associated with such access. If compensation proves prohibitively expensive, the project does not proceed. If tolerable given the expectations of investors, it does. However, in some instances market forces alone will not bring about an appropriate distribution of the net benefits generated by the project across our three groups. Consequently, it would appear that there is room for enhancing regulation, even if it is simply to protect consumers and related downstream public interests such as security and economic competitiveness. Regulation should be enclosed in policy objectives that are created by governments. From that perspective, it is insufficient for law makers to state that regulation should be in the public interest without clearly defining what the public interest means. Once policy objectives are defined and included in regulation, one of which could be a definition of public interest, for example the role of regulatory agencies should then be one of implementation. It is the responsibility of the relevant regulatory agencies to

3 Page 3 execute these objectives through the design and application of specific regulatory instruments. Whoever is responsible for these instruments must be credible not only in the eyes of both developers and locals, but also with consumers of the final product, since the price of that product will need to incorporate these additional costs. These agencies must therefore be seen to operate in a transparent manner, be unbiased, and have access to the latest methodologies and approaches in assessing/measuring whether projects are deemed to be in the public interest, one of which conditions could be whether the project has earned its social licence. This is where the compliance of the interests of proponents, locals, and consumers would take place. Unless all three groups could put their trust in the integrity of the decision-making processes, the regulatory bodies would not find support or legitimacy in the public arena. For trust to develop, stakeholders need to see and understand the true costs and benefits associated with a project. One regulatory instrument could be explicitly aimed at requiring proponents to count all costs, whether private, social or environmental. Through full -cost accounting requirements with third party verification, regulators could ensure that projects only proceed when benefits exceed costs from the perspective of society as a whole. While not all costs can readily be monetized, some progress in this area has started taking place. Another complementary instrument would ensure that locals are adequately compensated for access to their land and for any other costs, such as those associated with environmental externalities. The determination of adequate compensation levels is still not a straightforward matter. To be fair, compensation should reflect the fact that governments may already have acted at a broader policy level to address some of the negative externalities associated with individual projects. For example, mandated technology adoption or limits on polluting emissions could well by themselves act to reduce projectrelated costs borne by locals and, by extension, decrease the compensation that locals should expect to receive if a specific project were to proceed. Furthermore, if economic instruments (such as for-fee permits and emissions charges, for example) are already in use, then the government revenues generated by the application of such instruments should be considered legitimate sources of funding for the needed compensation to locals. In such cases, public funds could, at least in part, finance local, project-related compensation. Valuation is also not straightforward, in spite of the growing use of valuation instruments. Contingent valuation has had mixed results to date, in part because not all costs can be readily monetized and ecosystem services encompass things we depend on (e.g., water filtration) and things some but not all of us value (e.g., a pristine view). Any regulation-determined valuation will likely be subject to dispute in a predictable manner, in spite of any kind of third party verification regime one institutes. Locals will likely argue that the valuations are too low, and project developers will likely argue that these are too high. At this stage in the process, projects are still largely conceptual and measures of costs (and benefits, for that matter) are thus estimates, subject to some degree of uncertainty, no matter how carefully these estimates are assembled. This is where the credibility of the regulatory agencies is critically important in addressing this issue. Conclusion At the end of the day, regulatory mechanisms and decisions are rarely sufficient to build public support. Companies need to go beyond the regulatory approval to earn the social licence to operate. The key relationship here is arguably between project proponents and local communities: it is in the best interest of proponents to earn the trust of locals if the latter are ever to support a project, of which they would bear a disproportionate share of the costs, even when fully compensated. From that perspective, proponents should attempt to make local population partners in all stages of the project, from inception (pre-regulatory) and initial design work, through to the development of the formal proposal, and its execution in the event that approval is earned. Partnerships can extend to specific projects where local stakeholders are included. Or, some developers have gone further than this, and have formed relationships with communities that are much broader in nature than engagement around individual projects. An example of that is Trident Exploration, a company that combined coalbed methane extraction with asset-based community development in the Fort Assiniboine area. Many other examples of creative partnerships thrive in Canada, especially in those provinces where resource development is done in close proximity to locals, such as Alberta.

4 Page 4 One should not underestimate the inherent complexity in mandating full-cost accounting practices as part of an energy project approval process. Yet a simple underlying principle holds true: to the extent that social licences to operate are seen as products of the resolution of the interests of proponents, locals, and consumers, regulatory agencies, guided by well-articulated policy objectives, must provide inclusive and transparent decision-making environments where the interests of all three groups can be fairly assessed. Endnotes 1 Statistics Canada 2 It is intangible, unless effort is made to measure these beliefs, opinions and perceptions. References R.G. Boutilier and I. Thompson, Modelling and Measuring the Social Licence to Operate: Fruits of a Dialogue between Theory and Practice. 20and%20Measuring%20the%20SLO.pdf. Accessed on March 19, P. Klein, Three Ways to Secure Your Social License to Operate in 2013, Forbes, December 28, csr/2012/12/28/three-ways-to-secure-your-social-license-tooperate-in-2013/. Accessed on March 20, A.Plourde and E.Whittingham, A Complicated Tale Developing Energy in Canada is not a Simple Matter. A Policy Perspective on Pillar 4 of the Energy Framework Initiative (EFI). B.F. Yates and C.L. Horvath, Social License to Operate: How to Get It, and How to Keep It, Pacific Energy Summit 2013 Working Papers.

5 Page 5 US$/bbl Spot Crude Prices Differential WTI Brent US$/bbl US$/bbl WTI - Edmonton Light Price Differentials Differential WTI Edmonton Light Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 Feb-08 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 Spot Prices WTI Brent Edm.Light H.Hardisty Year-to-Date Quarter-to-Date March 11, SOURCE: EIA. SOURCE: EIA. US$/bbl WTI - Hardisty Heavy Price Differentials US$/bbl NYMEX WTI Crude Forward Curve 12 months 160 Differential WTI Hardisty Heavy Jan Feb Mar Feb-08 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 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$/gal 3.50 CDN/US$ RBOB Gasoline Heating Oil Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar Feb-08 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 NYMEX Prices Unleaded Gasoline Heating Oil Year-to-Date Quarter-to-Date March 11, Oil Demand Global in Selected Oil Demand Countries US Products Demand February Febraury 2014 Y-on-Y change MMbpd % % 20% % % 49% 10% 5% 0% -5% % 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14-10% -15% 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 Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 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, Q13 4Q13 1Q14 2Q14 3Q14 AB L/M/H AB Bitumen SK Other NGLs Synthetic 62.0% 61.5% 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 3Q13 4Q13 1Q14 2Q14 3Q14 Alaska California Texas Federal GOM Other Lower 48 NGLs Other OECD Commercial Stocks by region Dec-10 Dec-11 Dec-12 Dec-13 OECD North America OECD Europe OECD Pacific Relevant Independent Objective

8 Page 8 MMb US Commercial Stocks January 31- Febraury 28, 2014 Crude Gasoline Distillate Products Total MMb Canadian Stocks on Land 3Q12 4Q12 1Q13 2Q13 3Q13 SOURCE: EIA Weekly Petroleum Status Report. SOURCE: IEA Oil Market Report.

9 Page 9 World Supply and Demand Balance (MMbpd) Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 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 Nov-13 Dec-13 Jan-14 Nov-13 Dec-13 Jan-14 Saudi Arabia Iran UAE Kuwait Qatar Nigeria Libya Algeria Ecuador OPEC Iraq Total OPEC WTI Price Projections ($US/barrel) Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 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. 10.6% 10.3% 11.5% 8.8% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. 9.0% 6.6% 2.4% -0.6% 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 % -8.3% -5.9% -2.6% -3.1% -2.8% -3.4% -2.8% Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Yr-on-Yr Chg. -4.3% -4.6% -9.1% -8.2% 3.9% 3.5% -2.8% -5.7% 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. -1.8% -0.6% -0.6% -0.7% -0.8% -0.1% 0.4% -0.8% -4.5% -3.5% 0.5% -3.4% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -4.4% -3.6% -2.7% -4.2% -3.8% -4.7% -2.5% -4.2% -7.8% -9.5% -4.5% -5.4% 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. -2.9% -3.5% -0.8% 11.3% 12.0% 13.3% 11.3% 11.3% 12.5% 12.5% 2.7% -7.2% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. 1.1% -3.4% 0.1% 10.3% 10.9% 12.1% 10.3% 10.4% 11.3% 10.5% -18.6% 26.8% 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. -1.8% -0.4% -3.5% -3.3% -3.0% -12.4% 13.3% 12.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -4.4% -3.6% -9.5% -12.4% -6.8% -9.0% 0.6% -0.3% 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. 10.7% -0.8% -0.6% -0.4% -0.8% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 0.1% -4.2% -3.6% -4.7% -4.2% 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. Relevant Independent Objective

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. -4.3% -3.2% 0.5% -4.6% -2.5% -2.0% -4.2% -1.9% -1.5% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. -4.5% -8.6% -6.1% -6.7% -4.9% -9.0% -4.0% -4.3% -3.9% 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. -5.0% -2.7% -5.4% -4.0% -3.8% -4.0% -5.2% -4.1% Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Yr-on-Yr Chg. -8.5% -3.4% -0.3% -7.8% -7.9% -7.1% -13.9% -7.3% Notes: 1. Reformulated regular unleaded gasoline. Spot prices are based on average daily prices over a specific timeframe. Source: EIA Weekly Petroleum Status Report.

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. 7.0% -0.6% -11.3% 5.3% -2.5% 0.1% 1.9% 0.2% 2.0% -13.5% -2.6% 0.2% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 9.4% -4.6% 17.5% 7.2% -0.9% 0.5% 1.3% 0.5% 4.4% -11.4% -0.4% 1.7% 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 , ,408 2, , ,413 2, , ,325 2,559 4Q , ,413 2,665 1Q , ,374 2,657 2Q , ,376 2,662 3Q , ,401 2,697 4Q , ,325 2,559 Yr-on-Yr Chg. -0.8% -5.0% -3.2% 1.3% -9.6% -4.7% -10.9% -0.6% -4.8% -1.8% -6.2% -4.0% Dec , ,413 2,665 Jan , ,415 2,681 Feb , ,382 2,643 Mar , ,374 2,657 Apr , ,013 1,370 2,677 May , ,016 1,350 2,656 Jun , ,376 2,662 Jul , ,393 2,673 Aug , ,411 2,678 Sep , ,401 2,697 Oct , ,010 1,348 2,660 Nov , ,329 2,615 Dec , ,325 2,559 Yr-on-Yr Chg. -0.8% -5.0% -3.2% 1.3% -9.6% -4.7% -10.9% -0.6% -4.8% -1.8% -6.2% -4.0% 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. 3.0% 0.0% 2.2% 0.7% 1.4% 2.9% -4.0% -78.9% -1.7% -8.4% 4.0% -3.3% -1.3% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Yr-on-Yr Chg. 5.5% 4.9% 6.2% -1.4% -2.7% -1.6% -3.0% -63.8% -3.4% -6.8% 6.0% -1.4% 0.7% Quotas Over/Under % -16.8% 24.3% 25.2% -1.4% 23.6% 16.2% -66.0% -6.7% 8.6% 23.3% -10.0% 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. 2.0% % -9.4% -73.7% -1.1% 116.2% -2.3% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. 3.0% % -7.3% -48% -3.1% 29.9% -1.4% 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% 4.2% -18.1% 41.2% 8.3% 17.1% 5.2% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. 10.5% 5.2% -15.5% 44.9% 9.3% 14.7% 5.3% % of Total % 100.0% 1.9% 28.2% 24.1% 25.6% South-Central North-West West Supply Demand Balance Supply Demand Balance Supply Demand Balance Q Q Q Q Q Yr-on-Yr Chg. 10.9% -0.1% 7.4% 5.9% 0.2% 3.0% Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yr-on-Yr Chg. 9.8% -0.1% 6.0% 4.2% 3.9% 8.8% % of Total % 28.0% 6.8% 3.8% 11.3% 14.5% 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.