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Energy @ Gowlings |
| July 6, 2010 - Volume 8, Number 4 | |
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Gowlings Welcomes Thomas Timmins
Mr. Timmins’ practice focuses primarily on renewable energy with an emphasis on wind and solar project development, clean-tech company finance and energy regulatory matters. Mr. Timmins has advised successful project developers, Canadian and European banks, original equipment manufacturers, underwriters, private investors, O&M providers and other industry participants on matters pertaining to the establishment, development, financing, acquisition and sale of renewable energy projects across Canada. An expert in this industry, Mr. Timmins has taken numerous companies from the initial idea stage through to the take-out acquisition and public company merger stages and has guided entrepreneurs through all stages of planning and development. Tom can be reach at 416 369-6689 or thomas.timmins@gowlings.com Canada-India Nuclear Cooperation A long-awaited agreement on civil nuclear cooperation was entered into between Canada and India on June 27, 2010. As the prime ministers of Canada and India looked on, the agreement was signed by Lawrence Cannon, Canada's Foreign Minister, and Dr. Srikumar Banerjee, India’s Secretary of the Department of Atomic Energy and Chairman of the Atomic Energy Commission of India. The Agreement for Cooperation in Peaceful Uses of Nuclear Energy provides for cooperation and trade in every aspect of the nuclear cycle, including mining and supply of uranium, design and supply of reactors and fuel products, maintenance of reactors, disposal of waste and decommissioning. The Agreement also provides for cooperation and trade in applications of nuclear technology in other fields such as agriculture, healthcare, industry, nuclear safety and environmental protection. The Agreement closes a foreign policy schism that emerged between the two countries in 1974 when India first tested a nuclear weapon. Before that test, India was a prime deployment ground for Canada’s nuclear energy technology. Canada assisted India in the construction and other development of the CIRUS research reactor which went critical in 1960. In 1972, India began operation of its first nuclear power plant in the Indian State of Rajasthan based on Canada’s (AECL) early CANDU technology. This nuclear project included the supply of technical and design information to India. AECL was assisting in the development of a second reactor at the Rajasthan site when Canada ended its bilateral nuclear cooperation. Since then India continued to use the basic CANDU design as part of the overall development of its indigenous pressurized heavy water (PHWR) reactor technology. At present, India has 19 nuclear reactors in operation, 17 of which, to varying degrees, find their origin in a CANDU design. In signing the bilateral arrangement, Prime Minister Stephen Harper acknowledged that it was time for Canada to move beyond the policies and nuclear realities of the 1970s. This viewpoint appears to be shared globally as India has recently signed similar cooperation arrangements with a number of countries including the United States, France, Russia, the United Kingdom and Kazakhstan. The Agreement presents opportunities for both countries. India’s gain India’s targets for nuclear power production have been steadily revised upwards. The Indian state-run Nuclear Power Corporation of India Limited (NPCIL) has projected a production capacity of 63 GWe by 2032. This goal can only be reached with outside help in terms of capital and technology for reactor construction and uranium fuel supply. Although India is working on a Thorium fuel cycle, the mainstay of its production for the next few decades will likely be uranium based. India has fairly modest, low quality uranium reserves. Due to this resource limitation, and its very ambitious nuclear power production targets, India will require reliable sources of fuel for its nuclear power plants. Also, the Indian nuclear supply chain will probably not be able to keep up with the government’s ambitious nuclear programme. India will now be able to look to Canada to assist in satisfying these nuclear supply and technology development requirements. Canada’s gain Whether India’s lofty goals are reached or not, the opportunities for Canadian businesses are manifold. For Canada, one of the world’s largest uranium producers, this opens up a vast new market for uranium export. As described earlier, CANDU technology is proven and accepted in India and the potential exists for selling goods (including reactors) and services allied to CANDU technology. This may assist the federal government in marketing its current auction of certain AECL assets. Safeguards Both sides claim that the Agreement applies only to civilian uses and contains adequate safeguards against nuclear technology proliferation. The Agreement will have to be ratified by the parliaments of both countries before it becomes a binding treaty. Other Benefits Even though the Agreement is limited to trade in nuclear resources and technology, the removal of a major foreign policy irritant between the two countries should enhance intergovernmental relationships and may well assist Canadian businesses in unrelated industries as they seek a foothold in the large and growing Indian market.
LDC Corner: Privacy by Design ("PbD"): The Gold Standard for smart grids On June 16, the Office of the Information and Privacy Commissioner of Ontario launched the publication, Privacy by Design: Achieving the Gold Standard in Data Protection for the smart grid (Grid Privacy). The report, a guidance document for electric utilities, suggests best practices for embedding privacy directly within smart grid systems at the design and operational stages. Privacy by Design (or PbD) is a concept developed by Commissioner Cavoukian which is premised on the notion that privacy cannot be assured solely on the basis of regulatory compliance. Rather, privacy needs to be an organization’s default mode of operation. To achieve this goal, privacy must be integrated into the design and operation of an organization’s systems, rather than added on as an after thought. This approach is reflected in 7 foundational principles which, if practised, would facilitate accomplishing the objectives of PbD. In Grid Privacy, these 7 principles have been adapted for application to smart grid development to create Best Practices for smart grid Privacy by Design: 1. Smart grid systems should feature privacy principles in their overall project governance framework and proactively embed privacy requirements into their designs, in order to prevent privacy-invasive events from occurring. 2. Smart grid systems must ensure that privacy is the default — the “no action required” mode of protecting one’s privacy — its presence is ensured. 3. Smart grid systems must make privacy a core functionality in the design and architecture of smart grid systems and practices — an essential design feature. 4. Smart grid systems must avoid any unnecessary trade-offs between privacy and the legitimate objectives of smart grid projects. 5. Smart grid systems must build in privacy end-to-end, throughout the entire life cycle of any personal information collected. 6. Smart grid systems must be visible and transparent to consumers — engaging in accountable business practices — to ensure that new smart grid systems operate according to stated objectives. 7. Smart grid systems must be designed with respect for consumer privacy, as a core foundational requirement. Commissioner Dr. Ann Cavoukian partnered with Hydro One and Toronto Hydro to develop Grid Privacy. The inclusion of two case scenarios directly relevant to distributor operations gives the document practical relevance. The first scenario contemplates the situation when a utility wishes to provide customer access to information. In this process, customer enrolment and customer authentication will be key features, each of which could have requirements that apply privacy constraints. The second scenario focuses on customer enablement with respect to demand-response programs, in-home displays, voluntary curtailment, advanced device management and so on. Grid Privacy provides specific examples of how to integrate PbD into the design and operation of the smart grid system that would facilitate both scenarios. Commissioner Cavoukian aptly notes that utilities have an interest in ensuring that consumer adoption of energy saving technologies enabled by smart grid systems is not hampered by fears relating to privacy. The 7 foundational principles of the PbD Gold Standard may prove to be another example of Ontario’s leadership position in smart grid development. Grid Privacy can be found at: http://www.ipc.on.ca/english/Resources/Discussion-Papers/Discussion-Papers-Summary/?id=967.
Upgrading Bitumen in Alberta: The Debate Intensifies Background Debate has intensified in 2010 over the future of upgrading bitumen in Alberta. In August 2009, the Alberta Department of Energy issued a Request for Proposals for the processing of Crown Royalty Bitumen. Later in 2009, Imperial Oil announced that bitumen produced from its Kearl Lake project would not be upgraded in Canada, but would instead be sent to the United States for refining. Suncor has also suggested that bitumen produced from its Firebag 3 project would be sent to the United States for further processing. At the Progressive Conservative Association of Alberta’s 2009 Annual General Meeting, members passed a resolution calling for, among other things, the Government of Alberta to stop the shipment of unrefined bitumen to other jurisdictions. Understanding Upgrading To appreciate the positions that have been and are being taken by various parties interested in the debate over the future of upgrading in Alberta, it is necessary to place in context the chemical / refining processes involved and then relate them to upgrader economics. At its most basic level, upgrading involves refining bitumen, which is a thick tar-like substance extracted from oil sands, by breaking down the complex molecules, and removing acid and sulphur content, to make synthetic crude oil (SCO), a much lighter oil that can be processed by refineries and distilled into naphtha, distillate, gasoil, and residential fuel oil, and further processed into refined petroleum products (RPP) such as gasoline, diesel, jet fuel and lubricants. Alternative Processes The process of upgrading generally falls into two categories: (1) carbon removal and (2) hydrogen addition. The most common form of carbon removal is referred to as “coking”, whereby heat and other catalysts are used to produce lighter oils and a solid carbon by-product; hydrogen addition, also known as “hydrocracking”, involves adding hydrogen which ultimately cracks or breaks the longer molecules that form bitumen into lighter oils. Each process has advantages and disadvantages. Coking is generally cheaper, but it ultimately yields less oil since approximately 15% of the original volume of bitumen produces coke, a charcoal-like solid, which is then burned as fuel or disposed of as waste. Hydrocracking is more expensive because it relies on the use of natural gas as a fuel-stock which must then be converted into hydrogen, but because there is effectively an addition to the bitumen, it yields more SCO than the original volume of bitumen. By using the process of hydrocracking, every 100 barrels of bitumen yields more than 100 barrels of SCO. Integrated versus Merchant Upgraders and the Economics of Upgrading Upgrading has historically been integrated with existing oil sands mining or in situ operations in Alberta, but there is nothing to suggest that an upgrader cannot "stand alone" and operate on a fee-for-service basis as a merchant upgrader, securing a supply of bitumen from oil sands producers and then returning the upgraded SCO to the oil sands producers for further refining. Whether SCO is produced from an integrated or a merchant upgrader, refineries set pricing for the SCO that they purchase based on the value of RPPs ultimately produced by the refinery and sold in the market. Decisions about whether an upgrader will be integrated with an existing project or operated as a merchant facility depend on project economics, and economics in the current market are extremely complex. For example, an upgrader coking facility in Alberta has typically cost billions of dollars to construct and, if recent history is any indication, is costing more than double what a similar facility costs on the Gulf of Mexico Coast. Capital costs of such facilities have tripled over the last 10 years. At the same time, one of the key economic drivers affecting upgrading is the “light-heavy differential” - the difference between the market price for a barrel of light crude and a barrel of heavy oil. Bitumen and heavy oil currently sell at a discount to light oil because heavy oil requires upgrading before it can be refined into higher value products like gasoline or diesel. Aside from the actual per barrel cost of upgrading, the light-heavy differential is influenced by the capacity of refineries to process bitumen. When refineries have excess capacity, the demand for bitumen and heavy oil, and their respective market prices, will rise and the price differential between light and heavy barrels will shrink. If, on the other hand, there is a shortage of refining capacity (because more light crude is available to refineries), the supply of bitumen in the market increases, the price of bitumen will drop, and the differential will widen. Upgraders are generally considered viable (economically) when the differential is wider than $20.00 per barrel and highly profitable when the differential approaches $30.00 per barrel. It is undoubtedly frustrating for both oil sands producers and upgraders that the differential price has ranged from a high $45.00 U.S. per barrel to a low of $3.00 U.S. per barrel and that the volatility of the differential price, as measured by the Montreal Exchange as the standard deviation of prices over a 30-day period, has ranged from a high of 516% to a low of 27%. In an attempt to overcome this market volatility in differential, the Montreal Exchange, by circular dated May 14, 2010, has indicated an intention to begin listing a futures contract for Canadian heavy oil, being the differential between the prices of Western Canada Select Heavy Crude Oil (WCS) and West Texas Intermediate Light Sweet Crude Oil (WTI). By way of benchmarking only, as of May 31, 2010, the light-heavy differential was hovering around $22.75 per barrel. Another factor influencing upgrader viability within a mining or in-situ production operation is the "netback", or the price received for bitumen less the cost of bitumen transportation, blending, and marketing, which the project developers expect to receive, and the extent to which this netback offsets the capital cost and otherwise removes risk from any decision to develop an upgrader. Given the exceedingly high cost of building a coking facility in the current economic environment, there would need to be a higher likelihood that the netbacks would be substantial before an upgrader project would proceed. The Debate Over Upgrading in Alberta The debate over upgrading in Alberta is divided between those who believe in an "Alberta Upgrading Advantage" - that bitumen must be upgraded in Alberta and those in the "Free Market" camp, who believe that market forces will properly dictate how and when upgraders will be built. Alberta Upgrading Advantage The Alberta Upgrading Advantage supports having Alberta’s bitumen and heavy oil upgraded locally, whether via merchant upgrading or integrated within projects, including such proposed projects as the Northwest Upgrader, Heartland Upgrader, Fort Hills Upgrader, or those proposed by Total E&P Canada or Statoil. This approach will assist in securing Alberta's long-term industrial future by enabling the Province to attract and keep skilled tradesmen and those trained and experienced in the operation and maintenance of upgraders. The National Post, in paraphrasing from the Book of Joshua, has described Alberta and Canada as "hewers of bitumen and drawers of crude", suggesting that Canada is supplying raw materials to the United States, where greater product value is ultimately created. The National Post argues that in the case of the oil sands, the shipment of bitumen to the United States could become the greatest loss of economic value for any country in world history. It has even been suggested that Canada risks being turned into an exploited “banana republic”, and should instead follow the lead of Venezuela and require that all new oil sands production be upgraded in the Province as of 2015. Another rather sophisticated argument advanced by those endorsing the Alberta Upgrading Advantage is that with the completion of the Keystone Pipeline and the Alberta Clipper Pipeline which are aimed at carrying significant volumes of bitumen to the United States, any attempts to later cut back shipments in the case of an emergency would put Alberta and Canada offside the provisions of Article 605, the proportionality clause, of the North American Free Trade Agreement. Some contend that this clause would prevent Alberta from reducing shipments of bitumen to the United States in the event of an energy crisis, unless a similar reduction was made to Canadian consumers. This, it is argued, would be unacceptable in the event of an energy crisis, when Alberta should otherwise be redirecting supplies of bitumen to satisfy domestic needs elsewhere in Canada. Free Market Arguments The Free Market proponents argue that it is folly to intervene in a market that is currently expressing no need for new upgrading facilities. The logic, as expressed by one commentator, suggests that any excess upgrading capacity must be filled first, and that expansion of existing facilities will occur second, since those expansions, such as the expansion of Shell’s Scotford Upgrader, are less costly than greenfield construction of new facilities. Only upon the fulfillment of the first two conditions does it make sense to pursue the construction of new upgraders. Currently, analysts are noting that there is excess refining capacity in North America. Reduced heavy oil supplies from Mexico and Venezuela have caused the light-heavy differential to shrink, resulting in producers getting a higher price for bitumen not upgraded into SCO. It has become more cost-efficient for producers to simply ship bitumen to existing refineries for processing rather than implementing their own integrated or merchant upgrading plans. The Free Market proponents simply refer to current economic reality:
The free market argument was succinctly stated by columnist Deborah Yedlin when she noted that "If Imperial Oil can’t make the [upgrading] numbers work in Alberta, who can?" Current Proposals Two of the most interesting initiatives supporting the Alberta Upgrading Advantage side of the debate are the Government of Alberta’s Bitumen Royalty in Kind, or BRIK, Program and a proposal calling on the Government of Alberta to require that bitumen be upgraded in Alberta and, if necessary, blocking the shipment of unrefined bitumen to destinations outside the Province. The Bitumen Royalty in Kind Program Under section 34(3)(a) of the Mines and Minerals Act (Alberta), royalties are deliverable in kind unless stated otherwise. The Alberta Department of Energy has stated its intention to take its bitumen royalty in kind and in July 2009 issued a Request for Proposals for the processing of Crown royalty bitumen. The proposal required proponents to either (a) purchase between 50,000 and 75,000 barrels of bitumen per day and irrevocably commit to upgrade those barrels in Alberta, or (b) offer to process Crown royalty bitumen and then elect to offer product selection and/or marketing services in addition to the processing services. By mid-May 2010, the Province had announced that negotiations were underway to build a new "bitumen refinery" as part of BRIK Program. While by no means a "done deal", North West Upgrading, in venture with Canada National Resources Limited ("CNRL"), proposed to build northeast of Edmonton and in three stages a 150,000 barrel per day refinery intending to go beyond upgrading (to SCO) to include higher value products such as diesel fuel. Upon completion, North West Upgrading would process 75,000 barrels per day of BRIK on behalf of the Province, and would have additional capacity to support CNRL or other bitumen producer upgrading initiatives as well. While by no means a full upgrading industry solution, the proponents of this strategy maintain that there would be considerable economic return associated with the project. Compulsory Upgrading in Alberta In the Fall of 2009, the Edmonton Whitemud constituency of the Progressive Conservative Association of Alberta passed a resolution calling on the Government of Alberta to embargo the shipment of unrefined bitumen to other jurisdictions and, if necessary, legislate that bitumen be upgraded in Alberta. This resolution, while not binding, was delivered to the Progressive Conservative caucus and is intended to influence government policy. The Future of Upgrading in Alberta While at first blush there does not appear to be any middle ground in the debate over whether bitumen must, or even should, be upgraded in Alberta, that may be an oversimplification of the issue. The continuing uncertainty concerning the "heavy – light differential" that would affect a producer's decision to proceed with upgrader development may well be circumscribed by the maturing of the heavy oil market and the trading of futures contracts. The currently less than robust economics surrounding Alberta upgrading will be influenced by (a) the BRIK Program, (b) additional merchant upgraders supporting technological innovation, (c) the development of additional pipelines to markets out of Alberta (and whether such pipelines make allowances for diluent such that diluted bitumen may be easily exported), and (d) the forecasted increase in oil sand production from approximately 1.2 million barrels per day to 2.3 million barrels per day by 2020. Only time will tell as to whether both strategies can co-exist. What is certain is that heated debate will continue in 2010 as Alberta oil sand development becomes increasingly viable and capital projects are resurrected.
Vermont Becomes First American State To Recognize Electricity From Large Scale Hydro Facilities As "Qualified Renewable Power" There are over 30 American states with Renewable Portfolio (or Electricity) Standards (RSP) designed to encourage the production of renewable power (wind, solar, etc.). While the targets and the definitions of “qualified renewable power” vary from state-to-state, one common denominator has been limiting the statutory definition of “qualified hydropower” only to electricity generated by smaller-scale hydro facilities. Two reasons have usually been cited by environmentalists to justify the disqualification of large scale hydropower. One is the environmental impact of new hydro dams. The second is that a growing supply of clean, reliable, low cost electricity from large scale hydro projects constitutes “unfair competition” that will discourage the development of less reliable, higher cost electricity from wind, solar and other renewable power sources. It has long been the position of the Government of Canada that discriminating between imported electricity based on the scale of the hydropower generation facility is a violation of NAFTA obligations, (there being no difference whatsoever in the actual imported product). However, such obligations generally lie with the national government, rather than at the sub-national (state, provincial or municipal) level. On June 4, 2010, outgoing Vermont Governor Douglas signed into law An Act Relating to Renewable Energy (H. 781) that, among other things, removed the prior 200 MW limit on the size of a hydroelectric facility considered “renewable”. In becoming the first American state to recognize large scale hydro-electricity as a qualified renewable energy resource, the Vermont government cleared the way for Vermont power authorities to sign an attractively-priced long-term power contract with Hydro-Quebec. Vermont’s decision to recognize hydroelectricity energy generation of any capacity as renewable energy adds a further complication in the already complex situation in Washington DC regarding a federal Renewable Portfolio Standard. Currently, the Kerry/Lieberman American Power Act proposes to maintain the status quo – i.e., no national RPS, with a continuation of the current patchwork of state standards. However, Senator Bingaman’s Energy Committee has already passed a bill with a national RPS that excludes large scale hydro. Meanwhile, Senator Graham and other pro-nuclear Senators have championed the idea of a national RPS that would expanding the definition of qualified renewable power to include at least “advanced coal” and nuclear power, if not large scale hydro. It therefore remains to be seen whether the current Kerry/Lieberman position (i) is a short-term tactic to attract support for their bill in the coming weeks through a subsequent amendment, or (ii) reflects their conclusion that the vastly different energy situations among the various states and regions means the matter is best left to the states as a matter of policy, not politics. The Vermont decision also complicates the future tactics and strategies of Canadian governments. While the enactment by Congress of a new national RPS that qualifies large-scale hydro would be the ideal result for Canada, Vermont’s move suggests that the next best result for Canada may now be the Kerry/Lieberman idea of no national standard, (rather than a new national standard that disqualifies large scale hydro). On the one hand, one (discriminatory) national standard would at least be easier to attack than a plethora of different state standards. On the other hand, forgoing a national RPS and leaving the issue at the state level would allow Canadian provinces to dialogue with their American state partners in the various bilateral entities that oversee the reliability of the cross-border bulk power system (such as the Northeast Power Coordinating Council or the Midwest Reliability Organization). The lesson of Vermont Bill H. 781 is clear. As the popular rhetoric of green energy continues to transform into the not-so-popular reality of rising hydro bills, a growing number of Americans will conclude that securing access to clean, reliable and low cost Canadian hydroelectricity is not such a bad idea after all.
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