(February 15, 2011) Aldyen Donnelly argues that large industry in Canada has been supportive of carbon taxes over other forms of emissions regulations, since they could reasonably expect to receive the same exemptions that their European counterparts enjoy.
On Carbon Taxes
There are two considerations that have lead to large industry’s favouring a carbon tax over other measures.
First, in-Canada energy production emissions account for only 10% to 15% of Canadian energy and forest products emissions. Most of the Life Cycle Emissions occur closer to and at the point of final consumption of the products. Major companies who already export 70%+ of the resources they extract from Canadian lands assume–not unreasonably, that even their Canadian production emissions will ultimately be exempted from any carbon tax that might be implemented in Canada. So they are consciously lobbying for a tax measure from which they anticipate they will be fully exempt.
Why is this a reasonable assumption? Because every nation that has a carbon tax has already fully exempted electricity producers, petroleum refineries and “energy intensive businesses” from their carbon taxes and–in most cases–all other energy taxes. This is as true for Denmark and Sweden as for Germany and France. If you want, you can look up the environmental tax rates and exemptions for most (but not all) environmental tax measures in place in Europe on the OECD website (scroll down to Exemptions in Environmentally Related Taxes).
So step one is to get Canadian governments to agree to tax carbon consumption instead of regulate carbon discharges to the atmosphere. Step two is then to argue, reasonably, that Canada’s carbon tax regime has to treat large industry in a manner similar to the treatment it receives in Europe and elsewhere, otherwise investment in value-adding infrastructure will flee Canada. Please note, in passing, that the cap and trade regulation outlined in the US Waxman-Markey (passed 3rd reading in the House) and the Lieberman-Warner (did not pass 1st reading in the senate) bills also exempt US emissions arising from the production of energy that is exported from the US GHG cap. Also, 100% of GHG emissions from a US power generation unit are fully exempt from the US GHG cap if the generation unit sells only 15% or more of its output to a non-US-utility buyer (i.e. when a US coal plant exports 15% of its total output into Canada, then 100% of the GHGs associated with 100% of the power plant’s sales are exempt from the US GHG cap). This GHG exemption for power plants that export only a small portion of their total output is a simple repeat of the existing exemption the same plants get from the US SO2 emission cap that has been in law since 1995.
In other words, if our governments go with the carbon tax recommendations currently coming out of most Canadian industry, we will end up in a situation where:
- Significant taxes will apply to Canadian consumption of made-in-Canada energy, building products and food products, but
- Canadian energy, building product and food exports will be tax exempt.
Of course, the end result will be that:
- Less than 20% of Canadian large GHG sources will be covered by the Canadian carbon tax, so the carbon tax–at any rate–will have little impact on Canada’s GHG forecast, and
- The balance of trade between Canada and the US will quickly shift to favour US imports made-in-Canada resource products.
European energy tax exemptions for large industry now go way beyond the carbon tax
Very soon after financing corporate and personal income tax rate cuts (1990 – 1993) in Europe, each European nation then followed up with ad hoc exemptions or government-guaranteed below-cost electricity and gas supply agreements for “critically strategic” industries. For example, most European aluminum smelters receive electricity under 30 years fixed price agreements that cap the smelters’ power costs at around CAD$0.02/kWh, regardless what the costs of electricity production are.
By 1997/8 or so, a number of energy pricing/tax exemption-based trade disputes were filed with the European Commission, as each nation disapproved of its neighbour’s exemptions. Of course, the argument was that the ad hoc exemptions created unfair/subsidized advantage for some EU market participants.
EU member states finally resolved these disputes through the passage into law of the European Council Directive 2003/96/EC of 27 October 2003 restructuring the Community framework for the taxation of energy products and electricity (short version here ; full version here).
This law obliges member states to demonstrate that they collect a minimum level of “excise” taxes for each class of energy sold, where emission taxes, duties and levies are all included in the definition of “excise”, but VAT is outside this definition. The now very complicated current schedule for European minimum tax rates, by energy class, can be downloaded here.
The EU energy tax legislation leaves it to the member state to determine how they want to define the taxes they apply to energy sales (duties, levies excise, SO2, NOx, CO2, carbon, any other basis). But, in principal, total energy tax receipts have to equal or exceed the sum of minimum tax-covered product sales times the tax rate appearing in the attached schedule. The first is described under Articles 15 and 16 in the EU law, and the second is described under Article 17.
To calculate the nation’s total energy tax obligation, the member states subtract energy sold for the activities listed in Articles 15 and 16 from total domestic energy sales. Then they multiply the net sales estimate for each energy class by the legislated minimum tax rate and must demonstrate that total energy taxes actually collected equal or ecxeed the sum of the net sales x minimum tax rate for each energy type.
The energy consumption activities that are netted off the top to determine each state’s total energy tax target are, according to Article 15:
(a) taxable products used under fiscal control in the field of pilot projects for the technological development of more environmentally-friendly products or in relation to fuels from renewable resources;
– of solar, wind, wave, tidal or geothermal origin;
– of hydraulic origin produced in hydroelectric installations;
– generated from biomass or from products produced from biomass;
– generated from methane emitted by abandoned coalmines;
– generated from fuel cells;
(c) energy products and electricity used for combined heat and power generation;
(d) electricity produced from combined heat and power generation, provided that the combined generators are environmentally friendly. Member States may apply national definitions of “environmentally-friendly” (or high efficiency) cogeneration production until the Council, on the basis of a report and a proposal from the Commission, unanimously adopts a common definition;
(e) energy products and electricity used for the carriage of goods and passengers by rail, metro, tram and trolley bus;
(f) energy products supplied for use as fuel for navigation on inland waterways (including fishing) other than in private pleasure craft, and electricity produced on board a craft;
(g) natural gas in Member States in which the share of natural gas in final energy consumption was less than 15 % in 2000. The total or partial exemptions or reductions may apply for a maximum period of ten years after the entry into force of this Directive or until the national share of natural gas in final energy consumption reaches 25 %, whichever is the sooner. However, as soon as the national share of natural gas in final energy consumption reaches 20 %, the Member States concerned shall apply a strictly positive level of taxation, which shall increase on a yearly basis in order to reach at least the minimum rate at the end of the period referred to above. The United Kingdom of Great Britain and Northern Ireland may apply the total or partial exemptions or reductions for natural gas separately for Northern Ireland;
(h) electricity, natural gas, coal and solid fuels used by households and/or by organizations recognized as charitable by the Member State concerned. In the case of such charitable organizations, Member States may confine the exemption or reduction to use for the purpose of non-business activities. Where mixed use takes place, taxation shall apply in proportion to each type of use. If a use is insignificant, it may be treated as nil;
(i) natural gas and LPG used as propellants;
(j) motor fuels used in the field of the manufacture, development, testing and maintenance of aircraft and ships;
(k) motor fuels used for dredging operations in navigable waterways and in ports;
(l) products falling within CN code 2705 used for heating purposes.
And, according to Article 16:
2. Member States may also refund to the producer some or all of the amount of tax paid by the consumer on electricity produced from products specified in paragraph 1(b).
3. Member States may apply a level of taxation down to zero to energy products and electricity used for agricultural, horticultural or piscicultural works, and in forestry.
The law also stipulated that “the Council shall before 1 January 2008 examine if the possibility of applying a level of taxation down to zero shall be repealed.” The Council did review this provision in 2007/08 and decided not to repeal it.
So energy sales for the above-listed purchases are deducted from total sales for the purposes of determining each nation’s total energy tax revenue requirement under the EU law. But the sum of the products of the regulated tax rate multiplied by net sales for each energy type only creates a single national energy tax revenue requirement (the member states do not have to strictly comply with the revenue targets within each energy type).
Given that overall net energy tax revenue requirement, the EU law then permits nations to exempt some consumers from any/all energy taxes, as long as the revenues foregone due to these exemptions are made up with increases in the tax rate paid by other consumers or for other energy types. Article 17 tells you which classes of consumers can be given up to 100% exemptions from all energy taxes, as long as the state makes up the foregone revenues with tax increases elsewhere in the marketplace.
According to Article 17:
1…Member States may apply tax reductions on the consumption of energy products used for heating purposes or for the purposes of Article 8(2)(b) and (c) and on electricity in the following cases:
(a) in favour of energy-intensive business
An “energy-intensive business” shall mean a business entity, as referred to in Article 11, where either the purchases of energy products and electricity amount to at least 3,0 % of the production value or the national energy tax payable amounts to at least 0,5 % of the added value. Within this definition, Member States may apply more restrictive concepts, including sales value, process and sector definitions.
Just to put this energy tax exemption threshold–3% of production value–in context, the cost of energy accounts for over 5% of production value for most hotels in the western world.
What is the Net Impact of the EU energy taxation directive, and its allowed exemptions, on European power prices? You can look up tax-included power rates by customer class at the Eurostat website. There, you can download the following breakdown of average tax-included power rates by consumer class. (Please note that in September, 2009, just after the period reported below, UK electricity market regulators approved a 33%–on shot–increase in residential power rates while they held rates for large industrial customers at a 0-increase.)
Note the large differential between the rates/kWh charged the smallest and the largest industrial consumers in the carbon-taxing markets in the table below. An “NR” in the table means that the dominance of special government-guaranteed low, long-term fixed electricity rates in that part of the marketplace makes it impossible to provide a relevant estimate of class-average power rates. But actual rates in “NR” categories will be substantially lower than the lowest rate appearing to the right of an “NR” category.
The data in the following table should cause Canadian consumers and regulators to ask at least a couple of key questions:
- Most EU member states still burn coal to generate 50% or more of the electricity they produce, the notable exceptions being nuclear dominated France and Sweden and natural gas-dominated Austria. (Please note that while little coal is burned to make electricity within Swedish boundaries, Sweden’s traditional national electric utility–Vattenfall– is the single largest builder of new coal-fired power generation capacity in northern Germany at this time, as well as the largest owner of Danish coal-fired generation units (where coal-fired generation still accounts for over 50% of Danish power output). If Canada/the Provinces elect to implement European-style carbon management policies in Canada, how can we expect to generate different outcomes than those that have been achieved in Europe? in other words, Danish households still get 50% of their power supply from rather aged coal-fired power plants, even though residential power rates have trebled to more than CAD$0.43/kWh? Apparently, such an outcome is acceptable to the Suzuki Foundation, the Pembina Institute and Canada’s laregest industries. Do you think such an outcome will be defined as “success” by Canadian residential tax and rate-payers?
- Look at the large differentials between residential and large industrial electricity rates that Sweden, Finland, Germany, Norway, Spain, Ireland and Italy have developed in their attempts to stem industrial job losses, which losses are direct private sector responses to high energy price policies. How do you think Canadian ratepayers will feel if/when Ontario industrial power rates fall (current Swedish, Finnish and Norwegian rates for the largest industrial customers are actually lower than the tax-included rates paid in Ontario by large industry today) as residential rates skyrocket–as per the Swedish, Belgian, Norwegian, Spanish, Irish and Italian experience)? Do we prefer the Danish experience, which is a 30% decline in goods producing employment? In Europe, 100% of the power rate increases required to finance the “carbon tax”-based power market restructuring plan have been born by small residential consumers in all income-to-carbon tax-shifting nations. Is that okay with Canadians?
Obviously, it is clear to me why such an outcome might be okay with the CEOs of large Canadian industrials, at least over the relatively short term. But the European outcomes (GHG increases since 1994) cannot prove acceptable to Canadian CEOs over the medium term, which will require government to re-enter the market with regulation to realize Canada’s physical target of an absolute 17% reduction in nation-wide GHGs from 2005 levels by 2020.
California’s approved GHG cap and trade regulation–consistent with the House-passed Waxman-Markey bill–heavily discriminates against BC/Canadian power and natural gas exports to the US. Documentation at both the WCI and state of California websites clearly, clearly indicate that:
- One single GHG charge will be applied to each kWh of electricity exported from BC into the state, and BC exporters will not be permitted to differentiate exports by source. (The California argument is that BC’s GHG accounting system allows for double counting of benefits and this deficiency precludes the state from any alternative to assigning a single GHG factor to all BC exports. California’s view that BC’s existing and proposed power sector environmental attributes tracking system is deficient is accurate.)
- The GHG charge that will apply to all BC exports is the sum of all GHG associated with production in and imports that move through the Bonneville Power Authority transmission lines divided by total electricity throughput over those lines.
- Recently, US regulators determined that the GHG rate applicable to BC exports can range between 0.125 and 0.325 TCO2e/MWh of power exported, depending on (1) whether the final default is meant to reflect system average (0.125) or marginal supply (0.325) GHG rates, and (2) whether it is a high or low water year. While this range for GHG factors is lower than the 0.4069 default standard that the State of California had previously applied to electricity imports from BC, it is still some 5 to 16 times the default rate BC Hydro and the BC CAS staff use in their dialogue with BC emitters and taxpayers.
- Under the California regulation, all importers of natural gas have to go to the market to buy California GHG quota covering the CA consumer emissions arising from the in-state consumption of the gas imported from BC. There will be a free allocation of CA allowances to in-state gas producers/distributors to cover at least 90% of the GHGs arising from the in-state consumption of gas originating in the state. There is also a free allocation of CA allowances to CA oil refineries and CA power generators. But there is no free CA allowance allocation to importers of Canadian electricity or natural gas. So BC exporters will have to pay CA gas producers, oil refineries and power generators for allowances required to cover 100% of the BC electricity GHG factor plus 100% of the GHGs arising from the CA consumption of gas originating in BC/Canada, even if/when the life cycle emissions associated with CA in-state gas, electricity and petroleum production are higher than the emissions associated with the Canadian product sales.
In other words, it is simply untrue that the proposed US (or South Korean or Japanese) cap and trade rules were ever going to deliver a premium to Canadian exports.
This approach to US cap and trade–a highly US trade protectionist strategy–is entirely consistent with the design of US cap and trade for the leaded gasoline, CFC, and HCFC22 phaseouts and the US Acid Rain program SO2 allowance market rules. Predicting that US cap and trade was ever going to be fair to Canadian clean energy exporters, or have environmental integrity, is predicting that the US’s future GHG cap and trade regime will operate entirely differently than every historical US cap and trade regime has operated.
US federal and state policy makers are forecasting that Canadian exporters (not just of energy, but also of aluminum, iron & steel, forest products, glass, fertilizers and other chemicals) will continue to increase our product exports to the US and wear at least 70% of the cost of acquiring US quota from US emitters out of our export margins. They are basing this forecast of our future behaviour on the basis of how our exporters reacted the last 6 times the US hit us hard with discriminatory cap and trade regulations in the past.
Please note that Canada’s final CFC and HCFC22 regulations are prime examples of:
- Environment Canada regulations that attempt to fit into the US cap and trade strategy, which regulations
- Handed US manufacturers the full competitive advantage intended by the US cap and trade strategists.
Given that Canada responded with Canadian regulations that handed the US policy makers their strategic objective on a platter, in the past, and that current Environment Canada and Foreign Affairs staff appear to remain ignorant of the significant economic damage to the sectors covered by the historical Canadian regulatory responses to US cap and trade in the CFC and HCFC22 context, I find it difficult to be optimistic that our federal officials will find (or are even looking for) a Canadian regulatory strategy that will prove an effective defense against the unfair US/California cap and trade market rules.
I attach, again, a copy of my summary of the Leaded Gasoline Phase Out case study, which incorporates a real comparison of product (as opposed to point-of-production) environmental regulation, US cap and trade and EU-style cap and tax strategies. This case study shows you an approach to regulation (the original Canadian approach in the leaded gasoline context) that will prove a most efficient and effective regulatory model for Canadian GHG regulation. The key difference between the leaded gasoline experience and a preferred outcome in the GHG context is that in the go forward/GHG context we should be very clear that and how we will position the Canadian product (as opposed to production) standards as the foundation for major international and US court challenges of any manipulative and/or unfair US GHG quota allocation.
We utterly undermine the Canadian economy if:
- We fail to significantly upgrade Canadian facility-level emission and fuel use reporting standards, to make them closer to “US-comparable”. Including but not limited to in the context of the US Reformulated Gasoline Standard, the WTO has upheld US rules that unfairly discriminate against Canadian exports based on the argument that our emission reporting requirements are deficient. (And they are.)
- We fail to regulate GHGs and put Canada on a path to real reduction.
- We incorporate any form of quota allocation into Canada’s product standards for GHGs.
- We fail to allow for “joint compliance” and banking of over-compliance credits in Canada’s product standards, which provisions are easily incorporated without introducing any quota allocation. (See Canada’s leaded gasoline phase out history to see how.)
- We fail to challenge any US state and/or federal emission quota allocation scheme that artificially discriminates against Canadian exports.
- We fail to challenge any US legislated or regulated definition of “performance” that is based on % reductions from historical sectoral or economy-wide emission levels which procedure, by definition, assigns a higher sustainability rating to more GHG-intensive US energy products, aluminum, iron & steel, forest product and chemical outputs than it assigns to the mostly significantly less GHG intensive Canadian product exports.
The answer, therefore, is to regulate point-of-sale product (not point-of-production emission) standards for GHGs, following the leaded gasoline model. (It is more complicated for GHGs because we have to accommodate new market entrants fairly. If you want to get into that level of detail, write me back.) We can cover over 90% of Canada’s GHG inventory with fewer than 10 product standards (or maybe a dozen, depending on where we draw lines between products). That compares to dozens of emission estimation and cap-setting protocols that would be required to cover less than 30% of the national GHG inventory with point-of-production emission regulations. Canada’s product standards should apply to 100% of Canadian sales, domestic deliveries, plus exports.
Then, we should not stop where we did stop in the leaded gasoline case. With better facility-level emission reporting requirements and efficient product standards in place (it takes a little more dialogue to get product standards right…another conversation for another day), the minute the state of California promulgates its cap and trade regulation, or the US EPA promulgates comparable regulation, Canadian corporations (with the support of the government of Canada) must challenge the manipulative and unfair US GHG quota allocations in US courts. I am told that existing US federal laws prohibiting the states from erecting barriers to inter-state commerce will serve Canadian interests well in this context.
But then we have to o date, however, I have not run across evidence that any Canadian federal or provincial regulators/policy-makers recognize the basic challenges inherent in the GHG/climate change issue management file, and the risk appears high that we will respond to US cap and trade with Canadian CFC and HCFC22-equivalent product standards, which could lead to an economically devastating outcome for the nation.
The very difficult part is that the difference between the wording in a regulation that protects us, and has environmental integrity is–at face value–very, very small. And that is one reason why the risk is so high that we won’t get it right.