Energy Probe

Oilsands operations have very different GHG profiles. The over-simple analysis that Berkeley’s Energy Group has done, to date, does not tell the whole story.  The analysis suggests (more or less accurately) that if we use oilsands feedstocks to make gasoline, the full fuel cycle GHGs are high relative to conventional sweet crude. 

The problem is that oilsands output is usually used as a "diesel" feedstock.  If we substitute oilsands-based diesel for gasoline in the single passenger vehicle fleet, GHGs are lower than if we continue to burn gasoline that is made most efficiently from conventional sweet crude. There are numerous technical options to enable us to further cut GHGs in oilsands production, while GHG/unit of conventional sweet crude production are going up worldwide and we have hit an efficiency plateau in that production stream. 

According to their own Carbon Disclosure Report, BPs European GHGs increased over 23% from 2005 through 2008, while their crude oil and gas production and refinery output fell. This is happening everywhere companies are drilling deeper and deeper for more and more sulphur-contaminated oil.

The oilsands upgraders with the highest GHG profiles are typically (but not always) upgraders at which 100% of the sulphur is stripped from the crude. It is more efficient to strip sulphur in the upgrading stage than in the refinery, which is your only option for conventional crude. 

Refineries designed to max out the diesel—as opposed to gasoline–production from oilsands sulphur-free feedstock discharge about 15% less GHGs than refineries that are designed to max out gasoline production from low sulphur crude. The Berkeley analysis takes the upstream GHGs for the sulphur-removed synthetic or upgraded crude and then models that crude being fed into a refinery that is designed to convert at least 35% of the barrel of crude feedstock into gasoline—which rarely happens in real life (you can’t really convert more than 10% of a barrel of heavy crude into gasoline without a whole bunch of additional processing that is energy intensive). 

And the Berkeley analysis also assumes that all of the oilsands feedstock going into these gasoline refineries still contains sulphur, double charging the oilsands fuel cycle for sulphur removal.

Then, at the tailpipe, diesel cars discharge 15% to 25% less GHGs per litre or mile than gasoline. The Berkeley researchers actually explicitly acknowledge, in the Technical Report posted at the LCFS website, that the least cost way for US fuel distributors to comply with the California LCFS is to start a shift in the single passenger vehicle fleet from gasoline to diesel. 

The LCFS has two separate standards, one for gasoline and one for diesel, with the express purpose of blocking the single passenger fleet fuel switch from gasoline to diesel shift. The sole objective of this strategy is to protect California refineries whose plants are more gasoline-oriented than others and US ethanol producers. 

The decision to create two separate standards instead of one single transportation fuel GHG standard in the LCFS is a trade and commercial policy decision, not an environmental policy decision.

Note that 100% of the transport sector GHG reductions realized in Europe since 1990 derive directly from the passenger vehicle fleet switch from gasoline to diesel. 50% of EU passenger vehicles are diesel-powered and 60% of new car sales are diesel. The Opel Astra diesel-electric hybrid model is quite wonderful.  But I think (I might be wrong) one condition of GM’s sale of Opel to Stronach is that he had to agree not to develop the Opel Astra in North America.

Also, I have little faith in ethanol and a lot more interest in the potential for algae-based biodiesel as a biofuel.  I like cellulosic ethanol, but can’t figure out how to get the costs of trucking wood waste large distances to feed big plants under control.

Even traditional canola and soya-based diesel is much more clearly sustainable than US ethanol. Biodiesel is easier because biodiesel economies of scale kick in at a much smaller plant size than ethanol economies of scale, so the feedstock transport costs are easier to manage. 

Also, there is the basic question of oils versus alcohols…and as far as I can see oils win.  The key thing with oils is that they are almost totally recyclable, while alcohols cannot be blended with recyclable content.  We know how to grow beans sustainably (without mining the carbon from the topsoil), but we do not yet know how to grow starches (feedstock for alcohol fuels) sustainably.

If I blend biodiesel into the diesel fuel I get another big tailpipe GHG reduction hit, before even talking about hybrids. Also, biodiesel can be blended into diesel at any point in the fuel distribution chain. We need way less new distribution infrastructure at ports, terminals, etc., for biodiesel than ethanol.

I am also much more enthusiastic about the long-term efficiency improvement potential of plug-in diesel electric hybrids than gasoline electric hybrid vehicles or 100% electric vehicles when considering the global (as opposed to Canadian) electricity supply options.

So when I think about continuing to import sweet crude and gasoline from Nigeria and Europe (burning fuel to run the ships) to blend with ethanol trucked in from the US, it all looks crazy to me.  I tend to think we want to regulate the heck out of the oilsands and at least consider what Canada looks like as a "clean diesel-electric nation"—or at least "not a gasoline nation.”

Nuclear

I am not ready to go pro-nuclear, but my brain tells my heart I should be more open to nuclear than I am at the moment. Waste management is a huge issue. But Canada already has the 4th largest stockpile of nuclear waste in the world, so we have to come up with a solution for that problem anyway. 

But when I look at nuclear technology options, I just do not see CANDU technology competing—even with better management at AECL. And the big global trend in nuclear at this time is very large reactors. I actually imagine a future in which small reactors—land-based systems that are much improved versions of the reactors that have been used for decades to run nuclear submarines, or newer/different technologies altogether. 

I have been watching the Toshiba project for Galena, Alaska for many years, however, and its progress appears snail pace slow.  And I don’t know how real the Hyperion technology is.

…and then there is the question of what we could achieve if we could apply small nuclear (not large nukes) to eliminate natural gas consumption in oilsands upgrading…

In summary, US cap and trade will oblige US producers AND IMPORTERS of petroleum products, liquids from coal, natural gas and biofuels to surrender US GHG allowances covering the US GHGs arising from the US end-use of those products. Then, there is a free allocation of US GHG allowances to US refineries and US natural gas distributors. The gas LDCs are obliged to sell their free allowances to raise cash to mitigate the impact of cap and trade on residential and commercial customer prices.

So, the day after the cap and trade law is in full effect, any US entity that imports Canadian crude or refined petroleum products, natural gas or biofuels will be forced to buy US GHG allowances to cover 100% of the US GHGs arising from the US consumption of those products.

Under the cap and trade proposals, there is no consideration of the question of whether or not our exports are less GHG intensive than US domestic production. The effective tariff on our exports is determined by the size of the free US GHG allowance allocation to US refineries. At this time, the big fight in the US is about how high that free allocation will be. I understand that Senator Boxer officially tabled numbers later last Friday night that are more generous to US refiners that the W-M bill, but I have not seen those numbers yet.

But the cap and trade bill taxes our energy exports for 100% of end use emissions, because there is no free US GHG allowance allocation to US importers. Upstream supply chain GHGs are irrelevant. It is the free allocation of allowances to US refineries, and that fact that foreign suppliers are not permitted to participate in the most important of the two US allowance auctions, that determines the (what will prove to be) high tariff on our exports.

Also note that the W-M bill exempts GHGs arising from the production of exported energy products from the US GHG cap (the Senate bill does not do that). If the final bill freely allocates any allowances to US refineries and exempts US GHGs from the US cap, then you will never see another dollar invested in resource value-adding capacity in Canada again. We become price-taking exporters of raw resources and price-taking importers of finished energy products. It is very important that Alberta gets on top of this.

The LCFS is bogus in its bias, but less threatening than the cap and trade bill in that US courts have to compel LCFS states to strike the standard if/when we provide data that is more realistic. US law leaves US courts no choice but to strike down environmental regulations that rely on biased emission estimates if better data/science is presented to the courts. Albertan producers should prepare for court challenges, but the LCFS challenges are winnable.

The combination of the facts that: (1) the US EPA maintains a long-standing position that Canadian facility-level emission reporting regulations are inadequate and, therefore, our national pollutant and GHG emission estimates are unreliable, (2) all cap and trade bills and draft LCFS regulations stipulate that an overly conservative GHG factor will be assigned to any imports from nations whose facility-level emission reporting regime does not compare to the US standard, and (3) all US cap and trade bills stipulate that there will be no cross-border trade in GHG allowances with a developed nation whose facility-level reporting standards are not US-comparable, means that Alberta’s top priority should be to see the feds put new more stringent facility-level emission reporting mandates in place ASAP.

Our pollution and GHG reporting regulations do not have to be identical to the US versions. In fact, the US laws are so intrusive and expensive to administer, we should see this as an opportunity to build a "comparable" (using a WTO definition, not necessarily a US Commerce Department definition of "comparable") source of competitive advantage for investors in Canada. 

But the element that has been part of US emission reporting rules since 1991 and which must be included in Canadian facility-level reporting rules is that the reporters have to declare their energy purchases, but fuel and combustion unit, to the regulator. The US has confidence in private sector emission reports because the private sector has also had to report all energy consumption by combustion technology type and combustion unit operating hours. So it is pretty easy to verify emission estimates given the other submitted data.

Canadian industry is going to HATE this emission reporting recommendation. But our final reporting rule should still be less intrusive and less costly to administer than existing US law for the same classes of operations. It is essential to block massive US trade barriers in development.

In a recent article, Dow Chemical spokesman Jonathan Moser said intensity targets are incompatible with a national cap-and-trade plan, particularly given the desire to make it compatible with a proposed regulatory system in the United States.

As I have pointed out many times before, every functional existing cap and trade regime with any track record in the world assigns at least two caps to any regulated source or distributor of regulated products: (1) an intensity cap and (2) an absolute cap, where the absolute cap is typically a little less stringent than the intensity cap multiplied by the average operating output/sales of the regulated plant/distributor.

It will always be true that growing industries are advantaged by an intensity cap without absolute limits. It is equally true that industries that are not planning to expand their national operating base are advantaged by absolute caps without intensity limits.

No clear-thinking regulator will do either. Any prudent regulator will assign both intensity and absolute emission limits to every regulated source or product.

Note that every electricity generation unit that is covered by the US SO2 cap and trade rule and every electricity and industrial source covered by the Los Angeles RECLAIM market rule, is governed by an air permit that includes both intensity and absolute NOx and SO2 limits.

No operator in either of those cap and trade markets can exceed either limit no matter how many NOx or SO2 allowances the operator might have in the bank. When/if you ask why this is true, you will find that the conditions that make it necessary to build these elements into the US SO2 and NOx markets also apply in the GHG2 context.

Please note that both ACES—the Waxman-Markey House bill—and the Kerry-Boxer Senate bill, oblige operators of Title VI and Title V facilities and any other operators of any source that discharges more than 25,000 TCO2e/year to apply for and comply with new  US GHG permits. This is step one in putting the multiple cap system in place.