Many industry leaders and policy decision-makers clamour for a "Canadian energy strategy," but the Harper Government speaks of making Canada a "Clean Energy Superpower." Russ Kuykendall suggests nine policy measures that could position Canada to be a clean energy superpower, and how that could benefit producers, consumers, GHG emissions-reduction efforts, and Canadians:
Canada's energy endowment brings new meaning to the expression "an embarrassment of riches." Depending on how it's calculated, actual, current demand on Canada's recoverable oil reserves supply stands at 75 years to 125 years or more. Canada's recoverable natural gas reserves—both conventional and "shale" gas—now stand from 175 years to 250 years at current, actual demand levels. And Canada's recoverable thermal coal reserves—used for generating electricity—stand at enough to meet current demand for 400 to 1000 years.
Canada's National Energy Board estimates that from January to June, 2012, various Canadian electricity suppliers exported on the order of 27,000 GW.h's of electricity.1 Of this electricity, approximately 58% is hydro-electric generation, about 15% is nuclear-generated, and about another 2% to 3% is generated from alternative sources, including wind and solar. The remainder is from thermal generation, powered by burning either thermal coal or natural gas. As such, some 73% to 76% of Canada's electricity generation is classed as "non- or low-emitting."
To put that in perspective, the United Kingdom is struggling to get their electricity generation to 30% non- or low-emitting. Worldwide, approximately 40% of electricity generation is from thermal coal, 20% to 25% from natural gas, 20% from "hydro," less than 15% from nuclear generation, and, perhaps, 5% from "renewable," including wind, solar, geothermal, and tidal. That is, non- or low-emitting generation amounts to, perhaps, 40% of all electricity generated globally.2 The growth in demand for electricity will not abate in developed countries, let alone those economies in transition from developing to industrialized economies. At present, only thermal generation appears to be an affordable means to meeting that prospective demand. Affordability aside, thermal generation may be the only option with the proven capacity to meet that demand.
The biggest part of Canada's energy resource, both by sheer volume and value of exports, is still, by far, hydrocarbons—crude oil, natural gas, and thermal coal. In 2008, the value of exports of oil and gas, mainly from Alberta, surpassed exports from the automobile-manufacturing sector, centred in southwestern Ontario—historically, Canada's most valuable export sector. As the price of oil was depressed during the recession of late 2008 and early 2009, the sheer volume of crude oil exports rose significantly, especially to the U.S., while the overall value of those exports fell.
In 2011, almost $100 billion of Canada's merchandise exports valued at more than $447 billion was from the oil and gas sector, or more than 22% of all exports (calculated using "Trade Data Online," Industry Canada). By comparison, just over 10%, or goods valued at $46.5 billion, was exported by the automobile manufacturing sector.
Canada is the largest foreign supplier of oil and natural gas to the U.S. market, with proven reserves of crude oil third only to Saudi Arabia and Venezuela. Further, 97% of all "non-sovereign," proven, recoverable reserves of crude oil are in Canada.3
But it's not all good news for the "oil patch." The global and, especially, the North American supply of natural gas has hugely increased its recoverable reserves, due in large part to the development of "fracking" technology. This is bringing on-stream some very large shale gas plays, including the Montney play and the Horn River basin of northeastern British Columbia, to say nothing of the potential in Quebec, as well as New York, Pennsylvania, and elsewhere. The continuing expansion of recoverable reserves continues to exert downward pressure on the price of natural gas, pushing it below $3.00 per MMBTU (10,000 million British thermal units) in August (NYMEX), albeit in the middle of summer in the northern hemisphere.4
Crude oil may not be immune to this downward pressure. Much as "fracking" could exponentially expand natural gas supply, so could recent discoveries of conventional oil in the Bakken formation (spanning North Dakota, Montana, Saskatchewan, and Manitoba), and the application of fracking to "shale oil" reserves. Further, the recoverable reserves in Alberta's oil sands could increase from slightly north of 170 billion barrels to as much as 315 billion barrels, as technology improves. Within the next five to ten years, world market prices for a barrel of oil could be pushed below $50. More localized market pricing on oil could be pushed well below that.
So, Canada quo vadis? Which way forward for Canada? Is it as Alberta's Premier Redford suggests: a Canadian energy strategy? Or is it more along the lines suggested by Prime Minister Harper: positioning Canada as a clean energy superpower?
I want to suggest some key policy challenges going forward, and an analysis of what is meant by "Canadian energy strategy." I intend to show how Government could position Canada's energy resource base to the greater advantage of Canadians, Canadian producers, and of consumers of Canadian energy abroad.5
1. Synthetic crude from the oil sands could be a big part of the solution to the problem of reducing GHG emissions globally, particularly GHG emissions where the largest "share" of GHGs are emitted: transportation.
The objections to the production of oil from bitumen in the Alberta oil sands have focused variously on its footprint on the boreal forest, consumption of potable water, and on the life cycle greenhouse gas emissions (GHGs) from production, transmission, refining, and consumption of synthetic crude from the oil sands. But I want to focus on the last: GHG emissions.
When oil sands bitumen is refined into gasoline, its lifecycle GHGs are comparable to the lifecycle GHGs from the refining of California, Venezuela, and Saudi Arabia heavy oil.6 But when synthetic crude from oil sands bitumen is used optimally—as a feedstock to be refined into ultra-low-sulfur diesel (ULSD), its lifecycle GHGs are considerably lower than California, Venezuela, and Saudi Arabia heavy oil.
The very process of extracting and upgrading bitumen into synthetic crude removes the sulfur from it. When used optimally as ULSD feedstock, the lifecycle GHG emissions from oil sands synthetic crude are comparable to those of light crude refined into gasoline. However, the lifecycle GHG emissions from synthetic crude are lower than those from light crude when each is used as feedstock for producing ULSD.
At least two diesel refineries in the U.S. Deep South are taking delivery of, and running at full capacity on, synthetic crude from the Alberta oil sands to refine it into ULSD for sale and export to the European Union market, where more than 60% of the running stock of automobiles is fuelled with ULSD. To ban oil sands synthetic crude as a feedstock for ULSD would tend to raise lifecycle GHG emissions globally, including the EU. Conversely, shifting Canadian—let alone U.S. and Asian—automobile running stocks to ULSD fuelled vehicles would take a big bite out of GHG emissions from transportation—the largest segment of GHG emissions. (More, later, on how natural gas could also address transportation, GHG emissions).
2. Marketing oil sands synthetic crude as the best feedstock for ULSD production and, therefore, as a key part of the solution to reducing global GHG emissions could position and price it as a premium product, and offer the basis for a generation or more of Canadian prosperity.
The economic potential benefits to the Canadian economy from developing oil sands production capacity doesn't run to the billions of dollars, but to the hundreds of billions of dollars! And that is before the resource is extracted. Production of oil sands synthetic crude has been underway for more than forty years, and less than 7 billion barrels has been extracted from the currently recoverable reserves of more than 170 billion, and from the potential reserves of more than 315 billion barrels. Far from perpetuating the Gibeonite curse, making Canada fit only for hewers of wood and drawers of water, industrial construction to develop oil sands capacity requires a highly trained and educated work force of engineers, project managers, and skilled trades (many from Atlantic Canada), steel and machinery and equipment from central Canada, business services from across Canada, and financial investment from capital in Canada and offshore. If this is "Dutch disease," let's have more of it!
As already mentioned, the huge expansion of natural gas supply exerts downward pressure on natural gas pricing. As such, that downward pressure offers an incentive to convert return-to-base fleets to natural gas. Expanding the natural gas market to return-to-base vehicles would increase demand. Return-to-base vehicles include city transit and school busses, postal and courier trucks, local delivery trucks, tow trucks, taxis, forklifts and other similar equipment, airport service vehicles, servicing trucks, and farm vehicles and equipment. Return-to-base fleets often already have refuelling stations at the base, so use of natural gas would not entail construction of natural gas fuelling infrastructure, but converting on-site refuelling stations to natural gas.
4. "Build pipelines now," should be our motto. Time is of the essence in building pipelines for transmission of synthetic crude and shale gas to position Canada to compete on world markets from a position of strength.
The expansion of natural gas supply and the downward pressure on pricing is such that the financial viability and, therefore, the future construction of the Alaska and Mackenzie valley natural gas pipelines is severely in doubt. Pipeline construction is about making oil and gas supplies accessible to markets, and whether or not the pricing of those products makes sense of building the pipeline. It's not enough to have a product. One must get that product to potential customers for purchase, and that requires infrastructure—in this case, pipelines.Given downward pressure on natural gas pricing and the potential for expansion of supply and, therefore, potential downward pressure on oil pricing, pipelines from Canadian production to market should be built sooner, rather than later. Delay risks making building the pipelines no longer financially viable. But the sooner pipelines are built, the better positioned Canadian producers will be for global markets for oil, including synthetic crude, and natural gas, including liquefied natural gas (LNG). Pipelines are important, too, in expanding the markets accessible to Canadian producers who tend to extend favourable pricing to our nearest customers in the U.S. market as they lack the ability to make products accessible to customers outside the U.S. Expanding pipeline capacity to Canadian ports will make customers in other markets accessible to Canadian producers. Part 3 of the Budget Implementation Act, 2012, (Bill C-38) went far toward eliminating the duplication of efforts on environmental assessments of projects, including pipelines, by federal and provincial governments. Environmental assessments will still be required to meet a certain standard. But instead of requiring two environmental assessments per project, one will be deemed sufficient, whether administered provincially or federally. This will shorten project timelines, reduce project costs, and get the pipelines built while constructing them makes good, financial sense. Finally, if Canadian governments extend public funding or tax concessions to pipeline projects, they may want to consider taking equity stakes in exchange. This would bring a return on investment (ROI) to public treasuries and recover taxpayer dollars otherwise granted or foregone. As an added benefit, governments would be in a better position to insist that the first round of pipeline project investors, including aboriginals, be protected from predatory actions in respect of pipeline project completion and marketing.
5. Canadian governments, federal and provincial, must reform the policy problems attached to "transfer pricing" and natural resources "rents" (including royalty structures) with reference to oil and gas production and exports.
As more and more sovereign petroleum companies, as well as multinational petroleum companies, invest in Canadian production, Canadian governments should address "transfer pricing" and "natural resources rents."
"Transfer pricing" is the price a Canada-based producer owned by a sovereign or multinational oil and gas company will charge to the destination company, also owned by that sovereign or multinational. In order to reduce its tax bill from Canadian, federal or provincial governments, the Canada-based producer will give the destination company a very favourable price. This is the "transfer price." Overall, the sovereign or multinational enjoys increased profits by shifting taxation of profits to its most favourable tax jurisdiction.
Canadian governments should require a transfer price that is reflective of the world or regional "going" price for that product on the day it is transferred from the Canada-based company to another entity owned either by the sovereign or multinational. As such, the Canada-based producer owned by a sovereign or multinational will be put on a level playing field without an unfair advantage over Canadian companies held in Canada. Also, Canadian governments will not unnecessarily forego revenues to public treasuries.
Although Alberta's royalty structure on oil and gas extraction once served as a benchmark for governments in other jurisdictions who wanted both to encourage investment and development of oil and gas and to collect royalty revenues for public treasuries, the Alberta model may have seen its day, as demonstrated by the controversies on this while Ed Stelmach was Alberta's premier.
Balancing costs associated with exploration and development before an investor begins to realize ROI is a key challenge. Instead of pursuing a royalty structure, the Government of Norway imposes a special income tax rate on resource companies to take into account their profiting from a limited, natural resource—what is, in fact, a "capital" resource. This approach also takes account of exploration and development costs by focusing "natural resources rents" on ROI. The governments of the UK and Australia (as of July 1, 2012) are following Norway's example, likewise moving away from a royalty structure:
Norway's petroleum tax system approximates a rent-based tax. Though based on its company income tax system, it utilises (sic) an uplift on expenditure to exempt the normal return and reimburses the tax value of exploration expenditure for companies in a loss position. Norway imposes a total tax rate on petroleum rents of 78 per cent, consisting of a 50 per cent rent-based tax rate and company income tax rate of 28 per cent, with no deduction at the company tax level for the rent-based tax paid (Australian Government).7
Canadian, federal and provincial governments may want to do something similar, using the Norwegian model as a benchmark, as with the Australian government, but in line with Canadian corporate income tax rates, and in accord with Section 92A of the Constitution Act, 1867.
Finally, reforming transfer pricing could make more synthetic crude supply accessible to independent, Canadian refineries, by removing the tax disincentive for producers to sell their product in Canada.
6. Canadian governments, federal and provincial, should channel a portion of natural resources rents into sovereign wealth funds, in order to secure Canadian prosperity for generations to come, and to fund the physical infrastructure necessary to support steady, Canadian population growth.
Sovereign wealth funds are not unknown in Canada. The Quebec government has long invested its taxpayers' Quebec pension contributions through a sovereign wealth fund. The Canada Pension Plan is funded similarly by a federal, sovereign wealth fund, now the largest in Canada. In 1976, the Alberta Government created the Alberta Heritage Savings Trust Fund, initially by channelling 30% of resource royalties into it.The rationale for a natural resources sovereign wealth fund is similar to the rationale for natural resources rents. Natural resources are finite, capital resources. When they're gone, they're gone. Creating a sovereign wealth fund from the rents on natural resources allows this generation of Canadians to guarantee "cash flow" from these natural resources to future generations as well as this.
By signing onto agreements with the U.S. on the leaded gasoline conversion of the 1970s, Canada disadvantaged Canadian refineries on exporting their products to the U.S. As a result, Canadian refineries may sell only partially finished gasoline to customers in the U.S. market. This is part of the reason that it is difficult to increase refinery capacity or to renew Canada's oil refineries for gasoline production. That, in turn, is part of the explanation for the limited supply of gasoline that keeps pricing higher than it might otherwise be.
This does not apply, however, to ULSD where Canada holds an advantage as the source of the best feedstock. If Canada were to reopen its leaded gasoline agreements, it could make itself susceptible to a U.S. attempt to gain advantage with respect to production and marketing of ULSD. So Canadian policy-makers must think very carefully about this one.
With respect to wind or solar-generated electricity, the laws of physics are such that when the wind doesn't blow or the sun doesn't shine, electricity is not generated by wind turbines or photovoltaic arrays. Near Pincher Creek, Alberta, are large fields of wind turbines with large electricity generation potential, built with large funding incentives from the Alberta Government. When the wind blows, generation increases the supply such that the price of electricity troughs. When the wind stops, generation stops, and the price of electricity generated elsewhere spikes.
This problem could be solved with storage capacity, but another problem attaches, and that is the sheer cost of infrastructure, including surface rights to land, necessary for wind generation. Those places where the land is cheap and the wind blows reliably are well distant from markets which, in turn, would require construction of significant transmission infrastructure as well as storage capacity.
Unlike wind or solar, thermal generation using coal or natural gas can be located relatively near electricity demand, relatively cheaply. Technology is available, now, to make natural gas generation low-emitting and commercially viable. The challenges for thermal generation from coal are greater, but may not be insurmountable in making it, too, low-emitting.
Tidal generation would be more reliable than wind or solar, but the costs associated with building generation capacity are large. Waste generation holds only limited generation potential relative the huge demand for electricity.
However, for at least a portion of the Canadian electricity market, one "renewable" holds out real promise to make a large dent in meeting demand. Initial costs in building generation capacity are expensive but could be offset by the low costs once generation capacity is in place. Further, we have an example of at least one foreign jurisdiction8 that supplies all its needs with this technology: geothermal electricity generation.
Canada's Rocky Mountain trench holds out some of the greatest geothermal electricity generation potential in the world. In Alberta, along the Rocky Mountain trench, what can double as geothermal test holes have been drilled, some 450,000 of them, for oil and gas exploration and extraction. Data for each of these have been collected and recorded and could serve as the groundwork for the development of a geothermal electricity generation business. If it were to lift its moratorium on test holes, British Columbia, too, could benefit from the development of geothermal electricity generation capacity.
Through its Department of Natural Resources, the Government of Canada is funding a geothermal electricity generation pilot project in Fort Liard, Northwest Territories, that is scheduled to come on-stream by mid-2013.9 As it becomes operational, this project will have the capacity to generate 1MWe, replacing the diesel generation of electricity on which Fort Liard is currently dependent. Further, the project holds out the second-stage possibility of "district heating"—that is, supplying home and commercial heating to customers as a by-product of the geothermal electricity generation.
9. Create one accelerated capital cost allowance (ACCA) with a one-year, straight-line depreciation provision, modelled after the now-expired Class 27, Schedule II, of the Income Tax Regulations, to incentivize capital equipment investments that would achieve a minimum, established threshold of GHG reductions/mitigation, and eliminate all other Schedule II classes intended to incentivize mitigation of GHG emissions.
Why Class 27 as a benchmark? Class 27 was in effect from the 1970s through the 1990s to give plant owners incentives to install equipment or change processes to reduce pollution (not including what is now understood as GHG emissions). Class 27 did not prescribe the machinery or technologies eligible. It did prescribe, however, the outcome required in order for the ACCA to come into effect. Class 27 was so successful that it was phased out in 1999, after all the plants eligible for the benefit had been upgraded. The Government of Canada should consider a "Class 27-like," Schedule II ACCA regulation to give incentives to reduce and mitigate GHG emissions, without prescribing technologies or fuels.
Such an ACCA would be "fuel blind," potentially applying to renewables and hydrocarbons alike, without playing favourites. If someone figured out a way to make wind or solar or tidal generation financially viable, and could show its ability to reduce GHG emissions reaching an established threshold, it would be eligible. If a technology were invented and developed with the ability to reduce GHG emissions up to that same threshold while using thermal coal as a fuel, it, too, would qualify. Employing combined-cycle natural gas generation on a macro scale for a large, consumer market or on a micro scale for a single, commercial operation could be eligible. Geothermal electricity generation or heating could be eligible. So could converting return-to-base fleets to natural gas, or consumers' switching from gasoline to highly efficient ULSD vehicles. Whatever the technology, machinery, or fuel, that would be left to the ingenuity and creativity of Canadians, without picking winners and losers apart from GHG emissions reduction or mitigation.
The federal Department of Finance might well want to do the analysis necessary to determine for decision-makers whether or not there would be any net cost to the federal treasury from such an ACCA. Instituting such an ACCA while eliminating others, combined with the sales taxes on the additional capital expenditures for such technology and equipment, could well turn out to be revenue neutral.
"National Energy Strategy" versus "Clean Energy Superpower"
Finally, what do various proponents mean by a "national energy strategy" or a "Canadian energy strategy?" For some, it means tying the hands of hydrocarbon energy companies, or making renewables instantly price-competitive with hydrocarbons by imposing an onerous "carbon tax" and by offering generous subsidies to renewables. For others, it may mean funding transfers, tax concessions, and passing on the cost of renewable subsidies to Canadian consumers and taxpayers across Canada, or only in certain jurisdictions. It could mean securing predictable, domestic and foreign policy environments for those in the business of producing hydrocarbon energy. For still others, it could mean reducing inter-provincial trade barriers to energy transmission. And for a few—well outside Alberta—it could mean reviving the late Mr. Trudeau's "National Energy Program" with its "made in Canada" oil pricing for Canada's domestic industrial base and its revenue windfall to the federal treasury.
But this last possibility may well be the most important when it comes to the politics of a "national" or a "Canadian energy strategy." For several who hold key decision-making roles and who must be party to any discussion of a Canadian energy strategy, anything that sounds even remotely like "National Energy Program" is anathema. They can well remember how the NEP brought oil exploration and extraction in Canada to a virtual screeching halt.
In Grande Prairie, Alberta, where I grew up, for example, the industrial parks—composed of acres and acres of land accommodating dozens, if not hundreds, of oil patch businesses—turned into ghost towns of abandoned steel and concrete block offices and service bays, virtually overnight. The halt devastated those supplying the oil patch, hotels putting up mobile oil patch workers and restaurants feeding them, developers and general contractors and sub-contractors' building neighbourhoods and housing, the skilled trades, retailers, and, even, farmers who took second jobs and students who found summer jobs in the oil patch. The town shut down.
Few families were unaffected, at least indirectly. As the effects were made worse by the global recession of 1981 and 1982, the social consequences for marriages and families came home to roost. So, as far as it concerns those who felt the effects of the National Energy Program in Alberta, neither a "national energy strategy" nor a "Canadian energy strategy," call it what you will, is likely, at least not for the time being. You say, "Canadian energy strategy." They hear, "National Energy Program," irrespective of the particulars.
As to positioning or branding Canada as a "clean energy superpower," that holds possibilities, along the nine policy lines I have described above. And, it might well serve the purposes of at least some who clamour for a Canadian energy strategy.
1 "Electricity Exports and Imports: Monthly Statistics for June 2012." Calgary: National Energy Board, 2012 (Found at: http://www.neb.gc.ca/clf-nsi/rnrgynfmtn/sttstc/lctrctyxprtmprt/2012/lctrctyxprtmprt2012_06-eng.pdf, August 2012).
2 If Germany and Switzerland follow their plans to phase out nuclear generation and Japan continues to hold back on its nuclear generation, pressure can only mount to make up the difference elsewhere.
3 About 80% of proven, recoverable oil reserves is "sovereign oil." Nearly all of the remaining 20%â€“ non-sovereign, proven, recoverable oil reserves â€“ are in Canada.
4 As yet, the downward pressure from expanding supply excludes the potential for recovering natural gas from "gas hydrates" off the Newfoundland and Labrador shores and on up into the Hudson Strait between northern Quebec and Baffin Island.
5 Irrespective of where we are positioned on the debates over hydrocarbons as an energy source, we would do well to hold our respective positions with a measure of epistemological humility. That is, no matter what position we may hold on hydrocarbons, we cannot hold that position with absolute certainty. Reasons? Good ones, even? Yes. Absolute certainty? No. In order to hold positions reasonably, we must entertain the possibility the position could be wrong, at least in part. Secondly, irrespective of how we position on hydrocarbons and the environment, we should pursue good management â€“ good stewardship. That stewardship should attach to Canada's landscapes, water and air, to our energy resources, to the wealth generation capacity of the Canadian economy, and to the financial resources of Canada's public treasuries.
6 Tiffany Groode, Rob Barnett, and Samantha Gross, From Well to Wheels: Life-Cycle Greenhouse Gas Emissions of Various Sources of Crude Oil. Cambridge Energy Research Associates (CERA), October 2, 2009. Found at: https://client.cera.com/aspx/cda/client/report/report.aspx?KID=11&CID=1064, January, 2010. The CERA study claimed GHG emissions from Alberta oil sands bitumen oil are about 10% higher than the average of well-to-wheels, GHG emissions from all heavy oil produced globally. On average, GHG emissions from oil production are 20% of the total. For oil sands heavy crude, the production GHG emissions are about 25% of the life-cycle total.
7 Found at: http://www.deewr.gov.au/Department/Documents/Files/10_Fact_sheet_Resource_Profit_Tax_Final.pdf, August 2012.
9 Found at: http://www.borealisgeopower.com/uploads/Ft._Liard_Geothermal_Project_.pdf, August 2012.