Ontario’s new long-term power plan good, but demonstrates difficulty in planning

My Clean Break column takes a look at some of the new assumptions in Ontario’s latest 20-year electricity plan — assumptions that have changed dramatically since the previous plan was introduced (but never formally approved) three years ago. Electricity demand that we were supposed to reach before 2015 has now been delayed to beyond 2030. Now that’s quite the gap. More than that, the newer forecast takes into account the impact of electric-vehicle charging on the grid and the plethora of power-sucking gadgets populating our homes, while the previous forecast didn’t (at least not as much). Five years ago, Ontario was going to convert its Thunder Bay coal-fired power station to run on natural gas. Gas was cheap back when the decison was made, but the plan was cancelled a couple of years later after gas prices shot up to record highs. We took a $10 to $13 million cancellation penalty for that decision. Now, thanks to a bounty of shale gas, the option isn’t just back on the table, it’s going ahead. More than that, the government is now seriously looking at converting a number of other coal-fired units (at Nanticoke and Lambton) to natural gas.

The point: So much can change in just a few years it’s incredible. This is why the decision to plan for a new nuclear build I take with a grain of salt, as there are many alternative options that exist or will emerge. Importing hydroelectricity from Quebec or Newfoundland & Labrador is but one. I’m quite resigned to refurbishing, where appropriate, much of the nuclear fleet we have (sorry, Greenpeace), but I’m not as keen about building new reactors. Once built, they’re designed to last for 50 years or longer. So much can change in that 50 years that, as a ratepayer, I don’t want to be locked into one technology at the expense of others that may — and likely will — emerge. As I just showed, so much can change in just five years. I don’t want new nuclear crowding out better options.

Andy Frame, a former advisor to Ontario’s Ministry of Energy, wrote yesterday in a commentary that the new plan, while better than the last one, is still severely flawed. But his criticisms are mostly over the top. He says “this policy has resulted in the doubling of rates in Ontario to a level higher than in most U.S. states,” and that this has killed our industrial advantage. Historically there have always been U.S. states and Canadian provinces with lower — in some cases much lower — electricity rates. Have we seen a mass exodus of industry into Quebec, or Manitoba, or Wyoming? No, because electricity rates are one of many factors that are weighed by companies. Ontario is still very much competitive with many of the states that count, including Michigan and Pennsylvania, and we’re far cheaper than New York State, New Jersey and California. The claim that our industries are going to pick up and run is scaremongering, and other quite innovative programs are in place to help these Ontario industries cope with rising prices by becoming more efficient with their energy use, including the Industrial Accelerator Program and the Northern Pulp and Paper Electricity Transition Program. For too long unsustainably low electricity prices have been used to prop up our industry, which does nothing to make them more globally competitive/efficient.

And while it is true — and no surprise — that rates will keep going up over the next 20 years, critics too often look at this in isolation from trends in other states. Most U.S. states have renewable portfolio standards that require a certain amount of renewable energy in their mix. Like Ontario, they need to desperately upgrade infrastructure, and they’re making their grids smarter. Bottom line is that electricity prices will be going up in jurisdictions all across North America. Ontario is not unique here, and it’s unrealistic to keep measuring ourselves by pointing to Quebec, which has low-cost hydroelectric resources that are unique to its geography. Where is our industry going to move? To Europe, where rates are well above what we have here? Not likely. China? Well, if they’re moving to China it’s because of cheap labour and energy subsidies that violate WTO rules. We need to keep the situation in Ontario in perspective.

Andy Frame also writes:

Turning to supply, the decision to shut down coal generation for environmental reasons was made in haste, without considering alternatives or the problems that result from providing replacement power. In Europe, coal gasification has become a major source of supply. Called “cleaner coal,” it results in lower emissions — much less than what blows over Ontario from Ohio Valley coal plants. If coal plants were converted to cleaner coal, existing transformer stations and transmission lines could still be used.

This is a ridiculous comment. Yes, coal gasification exists in Europe, though I’m not sure I would agree it has become a “major” source of supply. But at the same time as Frame says it’s good to leverage our existing coal-plant assets, he talks about a technology — gasification — that can only be applied to new coal plants. New coal plants that use gasification are expensive and are only built if there is a plan to capture the CO2 and store it. Ontario doesn’t have the geography that can do CO2 sequestration economically, and so-called carbon capture and sequestration is hugely expensive and untested at large scale even for the most ideal locations. And yes, there are technologies — i.e. band-aid solutions — for retrofitting coal plants, but these also don’t come cheap, aren’t 100 per cent effective and don’t address the CO2 issue. Frame could be a climate skeptic who doesn’t care much about the CO2 issue, I don’t know, but if so that’s not the position of those who have an ounce of concern for climate change.

The bottom line is that Frame and other critics of the plan seem to think that electricity policy alone is what determines the survival of Ontario industry. It’s an important component, but the price on a bill doesn’t reflect other programs and initiatives in place to help alleviate the economic strain. Sure, looked at in isolation it may seem scary, and it’s easy to criticize something in isolation of other facts, but it’s not constructive to the debate.

The Ontario government’s plan isn’t perfect. I have my own concerns. I think we’re paying too much for large-scale solar, largely because solar prices have dropped dramatically since the FIT was introduced and this isn’t reflected in FIT prices. If I had my way, I would take the opportunity during the 2-year FIT rate review to dramatically cut the FIT price for multi-megawatt solar farms and eventually move to competitive bidding for these large projects. I would keep the rooftop FIT and microFIT but adjust the rates down accordingly, as the Germans are doing. I would also throw large wind projects — 50 MW or larger — back into a competitive bidding situation that, like Quebec, still has some local content requirements.

Beyond that, what else can be done? Everybody is claiming about how expensive the plan is, but what’s the alternative? Green energy is less than half of the projected cost increases, and the rest are a necessary part of modernizing the grid and realizing the potential of conservation and energy efficiency. Even building new coal plants would be more expensive. Keeping our existing coal plants open is not an option, in my view.

On a final note, a carbon tax should be viewed as a complement to this, not as an alternative as the Task Force on Competitiveness, Productivity and Economic Progress suggests in its recent review of the Ontario economy. I’ve got my problems with this report, largely because it fails to consider the many barriers that alternative technologies face to being adopted. The purpose of the FIT was to help level the playing field so newer, smaller developers, farmers, communities, homeowners, schools, etc… can participate in the province’s energy system. Its goal was to promote more distributed generation, diversity of supply, and of course renewable energy technologies that face an uphill battle in an industry dominated by nukes and fossil fuels. Simply throwing a carbon tax out there will help, but it won’t change that much, especially if the tax doesn’t amount to very much. Bottom line is I found their analysis flawed and their research weak.

The other problem, and Frame does this as well, is that it keeps using the average spot price for electricity as the comparison to new green energy generation. A more fair comparison is to the marginal cost of generation, because we know that whatever new form of generation we add to the grid — nuclear, natural gas, renewables — is going to be more expensive (far more) than the spot price.

Guest Post: Plenty of options for energy-efficiency retrofits in buildings, says Wakulat

Energy-efficiency incentives for industrial and commercial buildings come and go. Next up on the chopping block is the $60-million BOMA Toronto Conservation and Demand Management fund, which is designed to incent building owners and operators to undertake conservation projects on their properties. It will expire on December 31, 2010. Soon after the federal government’s ecoENERGY Retrofit Incentive for Buildings program, which targets small and medium-sized organizations, will end on March 31, 2011.

Ideally, energy retrofit projects will coincide with building maintenance or budget cycles, but the limited-time offer of incentive programs may restrict an organization’s ability to act on those incentives. That said, even with the expiration of incentive programs, a retrofit can still offer considerable savings and other benefits to a building owner/operator. Unfortunately, high up-front costs may prove to be a significant obstacle. So what’s the alternative? Another option is an energy-savings agreement (“ESA”), which offers energy-efficiency enthusiasts an opportunity to side-step the incentive question and proceed with a retrofit according to an organization’s own timeline.

A typical ESA outlines and addresses the design, construction, guarantee, and follow-up monitoring of energy-saving projects. It establishes a building’s baseline energy use, adjusted for weather and occupancy, for a fixed period of time pre-retrofit. A party other than the property owner (e.g. contractor, third-party financing company) will pay for the retrofit and earn its revenue when the building owner/operator remits energy savings realized against the baseline to the financing entity.

ESAs have been used with considerable success in the public sector in the guise of Energy Savings Performance Contracts (“ESPCs”). They are employed between a government agency and an energy service performance company (“ESCO”). The ESCO finances, installs and maintains new energy efficient equipment in the facilities at no up-front cost to the government. The ESCO is paid back from the energy savings of the contract.

According to Natural Resources Canada over 86 retrofit projects have been implemented using ESPCs, attracting $320 million in private sector investments and generating over $43 million in annual energy cost savings. The projects have been responsible for 15-20 percent in energy savings and helped to cut greenhouse-gas emissions by 285 kilotonnes. Similarly, the U.S. Department of Energy reports the implementation of over 550 ESPC projects worth $3.6 billion as of March 2010. They have resulted in savings of approximately $11 billion (U.S.) in energy costs.

There are generally two different contract options in the public sector that can be modified as needed for use in the private sector: the first-out performance contract and the shared savings performance contract. Under a first-out contract, the ESCO finances the projects and retains all the energy savings until the project is paid for or until the end of the contract, whichever occurs first. A contract may stipulate a maximum return on investment, thus triggering contract termination if the ESCO realizes its return prior to contract expiration. Should the ESCO fail to realize its return before the expiration date, the contract terminates as originally intended, and payments to the ESCO stop.

With a shared-savings contract, the ESCO and building owner/operator each receive an agreed-upon percentage of energy savings over the life of the contract. The catch here is that even though a building owner/operator may start to realize a financial benefit earlier than a first-out performance contract, this type of contract will run for a longer period of time. Otherwise, the two contracts are substantially similar.

In addition to scheduling freedom, an ESA benefits a building owner/operator by allowing it to (i) incur a limited up-front financial sacrifice; (ii) realize energy and maintenance cost savings post-ESA; (iii) reduce GHG emissions; (iv) demonstrate sustainable values to its stakeholders; and (v) increase property value and marketability of a building by updating or replacing old or obsolete equipment with newer, more efficient technologies that result in higher-quality systems, fewer breakdowns and reduced maintenance. Improved lighting, better air quality and more comfortable room temperatures could also reduce absenteeism and increase employee productivity.

As government intervention in the building retrofit market recedes or is modified, ESAs can help property managers deal with these changes by providing reliable benefits with minimized financial risk.

Robert J. Wakulat is an independent green energy and business lawyer residing in Toronto. Visit his blog at wakulat.blogspot.com for his views on various legal issues related to green energy.

Congrats to Nalcor, Nova Scotia for opening the tap on Lower Churchill

The tap could be opened wider, and that day will come, but it’s good to see Newfoundland and Labrador utility Nalcor striking a deal with Nova Scotia utility Emera to develop 824 megawatts of hydroelectric capacity at Muskrat Falls, part of the larger Lower Churchill initiative. The $6.2-bilion deal should see emission-free power start flowing by 2017 that will allow NF&L and Nova Scotia to significantly reduce their dependence on oil and coal for the production of electricity. Read coverage here and here.

According to the deal, Nalcor will get 40 per cent of the power, Emera 20 per cent, and the rest will be sold into other markets, mainly New England states. Hydro-rich Quebec, of course, wasn’t too happy with the announcement because it wants to dominate hydroelectric exports and has been actively trying to block any attempts by Nalcor to transmit power from Lower Churchil across Quebec into Ontario and other U.S. jurisdictions. There’s bad blood between Quebec and NF&L, going back to the raw deal NF&L got when it struck a deal with Quebec to develop Upper Churchill.

If Quebec is serious about battling climate change and reducing Canada’s emissions, as it says it is, then when is it going to start cooperating with other provinces toward reaching that goal? Certainly competition is good, and Ontario — as one example — would benefit by having access to more than one source of clean electricity outside of its own borders. There’s plenty of need for clean energy… certainly everyone can benefit by developing these valuable resources.

Of course, the battle with Quebec is likely to continue. Nalcor still wants to develop another 2,200 MW at Gull Island, and it would very much like to carry that power through Quebec and into Ontario and other U.S. markets. Certainly, Quebec needs to be compensated for this in some way, but so far the two provinces disagree on what constitutes fair and reasonable. We need to move beyond this bickering…

Sorry to nag, but about that geothermal power thing…

Well, I’m at it again, sounding like a broken record, maybe, but it’s a song I have to play. My latest Clean Break column asks why Canada, and particularly Alberta, is still paying no attention to the potential of its geothermal resources while, south of the border, stimulus money is seeing geothermal power projects sprouting up and thousands of jobs being created. No, I’m not saying that geothermal power plants are going to replace the oil patch, but there’s no reason why the skills and technologies in the oil patch can’t lead to a boom in geothermal development in Alberta, and help the province wean off coal in the process.

It’s interesting, I didn’t include this in my column, but when I asked Alison Thompson, chair of the Canadian Geothermal Association and vice-president of Magma Energy, why the major oil and gas companies are avoiding geothermal power, she answered in two words: “Skills shortage.” Because there is no government policy supporting geothermal in Canada, no roadmap, no awareness within the bureaucracy of its potential, and no price on carbon that would force companies to look at alternatives, there’s also no desire to take skilled workers from the oil patch — such as reservoir engineers — and throw them onto a geothermal project. Thompson, who used to work at both Nexen and Suncor and co-led a two-year oil industry research effort called GeoPowering in the Oil Sands, said the oil companies know geothermal is a proven technology. They just need the right nudge. “At a certain point somebody needs to rise above the excuses and just do it.”

Which brings me back to Prime Minister Stephen Harper’s ridiculous comment about how passage of the Climate Change Accountability Act would have hurt the economy and killed jobs. Geothermal power is a prime example of where skills in Alberta are transportable to a different sector that can help the province achieve emission reductions. There is so much potential for collaboration between the oil patch and geothermal developers yet so little interest in going down that path. It’s simply mindboggling.