According to the WCI, five of its members (California, New Mexico, Quebec, Ontario and British Columbia) already have a system or are developing one and are responsible for around 70% of the carbon emissions in the region. The WCI is expecting to launch its regional scheme in January 2012, which would help reduce the costs involved in reducing carbon emissions as it would allow industrial emitters to buy and sell carbon allowances from other states, creating greater flexibility and increasing the potential number of emissions reduction projects. The aim is to reduce greenhouse gas emissions by 15 from 2005 levels by 2020. Under the new proposals, emitters will be able to surrender allowances at three year intervals, giving them additional flexibility as to when they reduce their emissions. It will also create an allowance reserve, if prices rise to unexpected levels.

However, it is by no means certain as to whether individual members will be capable of successfully passing cap and trade legislation. For example, AB 32, the Californian 2006 Global Warming Solutions Act is being delayed by a measure chiefly supported by two Texas oil companies, while Meg Whitman, the GOP’s gubernational candidate has said that if elected, she would delay the Act by a year.

In addition, Arizona, Utah, Washington, Oregon, Montana and Manitoba have decided to delay their participation, due to fears that cap and trade could lead to higher energy costs.  Only British Columbia, Ontario, Quebec, California and New Mexico are proceeding with plans to implement carbon trading by 2012. This is despite a recent economic analysis performed by the WCI that indicates that the scheme would “support robust economic growth and deliver net cost savings – even when the assumptions resulted in different carbon allowance prices.” The WCI estimates that the value of carbon allowances issued under its remit will be US$33/t by 2020.

According to Thomas Neff, a physicist and uranium-industry analyst at the Massachusetts Institute of Technology in Cambridge, China could purchase around 5000t this year – double its annual consumption – as it builds stockpiles for new reactors. “China’s demand is insatiable,” said Dave Dai, an analyst at the Daiwa Institute of Research in Hong Kong. “They will have to take almost whatever is available.”

The World Nuclear Association expects China’s uranium consumption to rise to 20,000tpa by 2020, equivalent to just under 40 per cent of last year’s 50,572t global output. The country envisages a power output of 85GW, nine times its current capacity, as it plans at least 60 new reactors by 2020. Loading a new reactor requires around 400t of uranium.

As a result of China’s nuclear new-build and reinforced by expansion plans mooted by India and recent utility interest, uranium prices are expected to rise – possibly by as much as 32 per cent over next year, climbing to an average US$55/lb as demand erodes supplies, according to Adam Schatzker, a Toronto-based RBC metals analyst.

If the deal goes ahead, Uranium One’s Honeymoon Well uranium project in South Australia will move into Russian government hands. According to the Globe and Mail newspaper: “The prospect of Kremlin control of the Canadian company left many investors worried that Uranium One would be pressured to serve Russian strategic interests that do not necessarily deliver the best returns…” and “alarmed industry observers worried that the Vancouver-based company might end up serving the Kremlin’s strategic interests.”

Rosatom is understood to control 40 per cent of the world’s uranium enrichment and builds reactors and fuel assemblies for 70 countries.

In a separate development, Rosatom and its Kazakh counterpart Kazatomprom agreed on the use of an existing uranium enrichment facility at Novouralsk in Russia rather than building a new enrichment facility. In addition, the two companies also signed a memorandum on forming a joint company to market and sell uranium.

IFandP recently had the pleasure of interviewing Ralph Rayner, Sector Director for Energy and Environment at international consultancy BMT Group Ltd on the current state of marine renewable energy, and the stumbling blocks that will need to be removed if it is to reach its full potential.

IFandP: In terms of years, how far behind is wave and tidal power generation compared to solar and wind power?

RR: If nothing were to change in terms of resources and encouragement, I’d say it was a decade behind. But we’re now seeing significant efforts to catch up with other renewables. The UK will soon have two full scale test sites running and there are encouraging signs of an improving investment and development environment.  If this is sustained then the gap will start to close.

IFandP: Which companies and approaches do you feel offer the most potential?

RR: It’s very much an open field and with so many options it’s difficult to pick winners. Answering this question will come down to rigorous testing over long periods to determine reliability. The majority of issues revolve around the problem of operating in such a hostile environment. It’s not like the offshore wind industry, where a significant part of the maturation cycle has already taken place. There could even be some technical showstoppers. For example, there is the problem of connection to the shore from devices such as tidal stream turbines which are located at sites which by their very nature are in places were you wouldn’t choose to run a cable. For some sites this will be very technically challenging.

IFandP: How is the Pelamis system progressing?

RR: It’s going pretty well in terms of engineering and technology. There are some significant issues as it nears commercial scale, but it’s come a long way. It needs long-term deployments to resolve the issues associated with maintenance. It’s only one of the technologies that are a long way down the development path. There’s always a hurdle between prototypes and achieving commercial scale, commonly referred to as the ‘valley of death’ as its hard to break through to the point where you can start realising economies of scale. This is an area where investment support mechanisms are needed.

The partnership agreement will see each party holding a 50 per cent stake in the project while Fission will continue as operator of Waterbury Lake, and as such, will be entitled to an administrative fee equivalent to 10 per cent of all expenditures as approved by the exploration and development plans.

For the summer 2010 exploration programme, a budget and work plan valued at around CAD2.07m have been put in place. Work, which includes a 4000m drill programme, is expected to start early July.

In related news, this morning has seen the start of the first round of talks between Japan and India with the aim of creating a similar bilateral civilian nuclear cooperation pact. Over the course of the two-day meeting, currently taking place at the Japanese Foreign Ministry, officials from both countries will be trashing out the details and compromises needed if India is to benefit from advanced Japanese expertise in the nuclear sector, without using it for military purposes or transferring the knowledge to another country. At the G20 summit, both countries’ prime ministers took the opportunity to reconfirm their intentions to cooperate in this field. However, there is substantial resistance to a deal from a section of the Japanese public, given India’s position as a non-signatory of the Nuclear Non-Proliferation Treaty and Japan’s unique status as the only nation to have experienced the horrors of nuclear warfare.

The Saskatchewan-based uranium producer signed two separate deals as part of a series of resource sector agreements signed between companies of the two nations alongside a visit to Ottawa by Chinese President Hu Jintao.  Cameco will supply around 23mlb of uranium concentrate by 2020 to a division of China National Nuclear Corp, the country’s no. 1 nuclear generator which has seven operating units and 10 additional ones under construction. The company also entered into a non-binding agreement with China Guangdong Nuclear Power Holding Co Ltd to negotiate long-term uranium purchase contracts and possibly jointly develop uranium resources.

“This is a very important region from any supplier’s perspective,” said Jerry Grandey, CEO of Cameco. The deal will help the company double its production to more than 40mlb annually by 2018.

Its new natural gas-fired plants will become the new clean power standard, which is expected to be firmed up by early 2011, according to a Reuters report. “Our regulation will be very clear,” Prentice said at a press conference. “When each coal-burning unit reaches the end of its economic life, it will have to meet the new standards or close down. No trading, no offsets, no credits.”

Canada has 51 coal-fired plants, which generate 19 per cent of its electricity and emit 13 per cent of its total greenhouse gases. By 2025, 33 such units will reach the end of their economic lives and will be required to shut down unless considerable investment are made to curtail their emissions.

The new power standard is expected to reduce emissions by 15Mt and is much stricter than current proposals made in the US, which Canada has traditionally taken as a reference point.

Capital Power Corp also contracted an option for an extra 375MW, comprised of 58 V90-1.8MW wind turbines for the 105MW Port Dover and Nanticoke Wind Project and 150 V90-1.8MW turbines for the proposed 270MW Kingsbridge II Project, both located in Ontario. The option is subject to the necessary provincial environmental and regulatory approvals.

“These turbine agreements with Vestas represent a significant milestone as the majority of the capital costs for the projects are now fixed, providing cost certainty and capitalizing on economies of scale,” said Capital Power President and CEO, Brian Vaasjo. “As we advance our contracted generation portfolio, we are looking to build on the success that Capital Power and Vestas have had on the Kingsbridge I wind farm, which has twice been Ontario’s best performing wind farm.”

Ontario Power Generation will add generating units at existing stations in Little Long, Kipling and Harmon as well as replacing a fourth generating station with a new three-station unit at Smoky Falls.

In total, the project will generate around 440MW of new hydropower, bringing the complex’s total capacity to 924MW when it is completed in 2015.