Before I talk about the oil sands, I would like to describe how the UK and European "Cap and Trade" allocations have been subsidizing European oil-producer GHG increases by hitting residential electricity consumers with substantial rate increases

UK and European cap and trade quota allocations transparently over-allocate free EU CO2 allowances to all oil and gas producers, while under-allocating free allowances to electric utilities. This procedure obliges electric utilities to buy surplus allowances from oil and gas producers to achieve compliance with their obligations to surrender CO2 allowances covering 100% of their GHG emissions at the end of every operating year. 

I should note that an EU law that was unanimously passed (with the UK’s strong support) in 2003 also exempts any business (read: oil refiner) for whom fuel and power purchases represent 3% or more of operating costs from ALL ENERGY TAXES—including excises, duties, CO2, NOx, SO2 and VAT).

What is the end result? You can read it in the BP, Shell, Total and other European oil producers’ Carbon Disclosure Project (CDP) disclosures.

From BP’s most recent disclosure to the CDP, and BP’s most recent annual report, we see that:

• BP’s reported and regulated European GHGs per barrel of oil equivalent (BOE) production of European crude oil and natural gas has fallen substantially since 2005, from 469 BOE to 309 BOE.

• Oil’s share of total oil and gas production has increased over the period.

• BP’s reported and regulated GHGs per BOE grew from 0.076 TCO2e to 0.164 TCO2e from 2005 to 2008.

• EU nations’ free allocations of CO2 allowances to BP increased from 0.080 TCO2e to 0.162 TCO2e per BOE between 2005 and 2008 and increased again in 2009 over 2008.

• If BP maintains GHGs at 2007 actual levels from 2008 through 2012, BP will enter the 2013 post-Kyoto budget period with 963,478 surplus free CO2 allowances in the bank.

• Under EU ETS rules regulators will freely allocate almost 13 MM free CO2 allowances to BP, even if the production/output/sales volumes from BP’s European oil and gas production and refining operations continue to decline in the future at the rate they have declined over the past 5 years.

Analysis of comparable disclosures by Royal Dutch Shell, Total and other leading Europe-based integrated oil and gas companies show oil and gas production, emissions and allowance surplus trends that are roughly comparable to the BP trends illustrated in the table below.

What Even the US EPA and EIA’s official numbers say about Alberta Oilsands

While GHGs per barrel of oil extracted and upgraded from bitumen are about 15% higher, on average, than GHGs from conventional oil extraction, the GHGs/barrel from conventional oil production are going up, quite quickly, as the world relies on increasingly deep conventional crude oil reserves and the deeper we go the more energy it takes to get the oil out.  But GHGs per barrel of bitumen and heavy oil extracted and upgrades from the oilsands are declining, and have great potential for further decline (of course, I think forcing the operators to realize that potential on an accelerated schedule should be the focus of Canadian GHG oilsands regulations, not wiping oilsands development out.)

In some nations, GHGs per unit of extracted conventional oil are much higher than they are in Alberta’s oilsands. Most notably, the heavy oil produced in California (2/3 of all of the state’s onshore oil production) generates 15% higher GHGs/bbl than Alberta’s oilsands, on average. And GHGs/bbl of conventional oil produced in Nigeria, on which both the US and UK heavily relies for imports, are about 20% higher than Alberta’s oilsands.

Technically, if our governments were to (1) rule that any new Alberta oilsands output has to meet or beat the current "SAGD-Dilbit"(see definition below) wellhead to refinery gate GHG benchmark illustrated in the Jacobs Consultancy report for AERI and (2) substitute incremental Alberta oilsands heavy and synthetic crude exports to the US for US Nigerian imports and California’s heavy oil production: global GHGs associated with the US consumption of conventional gasoline derived from  450,000 bbls/year of new Alberta oilsands output could fall by some 2% to 3%.

If we were to ensure that all Alberta crude output is dedicated as a feedstock to refineries that are designed to maximize diesel/distillate—as opposed to gasoline—production as a fraction of total products, the global GHGs associated with this theoretical 450,000 bbls/year increase in oilsands exports to the US would fall even more. If the diesel produced from Alberta’s heavier feedstocks in diesel-oriented refineries was sold to consumers who retire gasoline-powered cars and replace them with 2009 and later-model diesel-powered cars, the global GHGs associated with that 450,000 bbl substitution could reach 25%, at a low cost relative to other transportation sector GHG reduction strategies.  If the diesel made from incremental Alberta heavy crude feedstocks is refined in plants designed to max out the diesel/distillate fraction, blended with 20% biodiesel before it is sold, the GHG reduction associated with that 450,000 bbl/year increase in Alberta oilsands crude and upgraded exports to the US could reach or exceed 40%.

To erect an artificial barrier to Alberta crude exports, largely with a view to protecting California heavy oil producers and California’s 20 gasoline-oriented refineries, all proposed US GHG regulations preclude the substitution of diesel for gasoline sales and do not permit market participants to take credit for the substantial and real GHG reductions that derive from that substitution.

Of course, the GHG reduction potential associated with the diesel-for-gasoline substitution is well-recognized in the UK and Europe.  Total transportation fuel consumption (in total gigajoules or "Gjs" of energy) actually grew faster in the EU25 than in Canada from 1990 through 2007. 100% of the transport sector GHG reductions logged by the UK and Europe since 1990 derive from the substitution of diesel for gasoline. At this time, 40% of on-road European passenger vehicles are diesel-powered and over 60% of new passenger vehicles sales are diesel-fuelled models—even in the UK.

Given these facts and those outlined below, the British Bank’s Alberta Oilsands protest is the height of hypocrisy..

Detailed Explanation and Data and Pictures you might find helpful: US Oil Production and Trade

From 2003 through 2008 the US imported an average of 330,000 barrels of oil from Nigeria and California heavy oil output averaged about 120,00 bbls/year of which US heavy oil imports from Canada’s oilsands reached 461,000 bbls in 2008.

A range of different extraction, upgrading and product export configurations can be and are implemented in Alberta’s oilsands. Global GHGs associated with US conventional and reformulated gasoline consumption would go down if we substituted the Alberta oilsands feedstock produced in the existing "SAGD-Dilbit" configuration, using existing technology and common practices (explained below) for Nigerian crude ("Bonny Light" in the table below) imports and California heavy oil ("CA-TEOR" in the table below).  The GHG reduction per barrel of gasoline produced would be small in the Nigerian crude substitution case, and as much as 10% if the Alberta exports are substituted for California heavy crude oil.

This means that if final US GHG and fuel regulations are designed to have environmental integrity (neither the California Low Carbon Fuel Standard nor the Binagaman-Specter or Waxman-Markey bills have environmental integrity), and if all incremental Alberta oilsands output achieved or beat the "SAGD Dilbit" configuration GHG emission benchmark, then there is the potential to increase Alberta oilsands exports to the US by up to 450,000 bbls/year with a net reduction in the global GHGs associated with those exports of 2% – 3%.

Of course, if Canadian regulators push Alberta oilsands producers to adopt known methods to further cut GHG discharges, the potential for global GHG reduction through the substitution of Alberta exports for Nigerian imports and California heavy oil is even greater.

Comparing Wellhead to Refinery Gate GHGs by Crude Feedstock, for Gasoline vs. Diesel

The above analysis is based on the assumption that all refineries are designed to convert 35% of each barrel of refinery feedstock, on average, into gasoline.  Making gasoline from Alberta feedstocks can add up to 20% to the GHGs/bbl of gasoline output, and all refineries designed to maximize gasoline output per barrel of crude input discharge, on average, 15% more GHGs per barrel of product output than refineries designed to maximize diesel output.

 If 100% of Alberta feedstocks were to be directed to refineries that are designed to maximize diesel output (this scenario is not analyzed in the Jacobs Consultancy report), the wellhead to refinery gate GHGs/Gj of diesel produced would be about 15% lower than the GHGs/Gj of gasoline produced in the SAGD-Dilbit configuration in the Jacobs estimates.  If Alberta oilsands feedstocks are dedicated to diesel production, therefore, life cycle GHGs (GHGs/Gj of marketable product) would compete with or improve on all of the gasoline GHG estimates appearing in the Jacobs estimates.

Therefore, the single most important message in the Jacobs analysis is that:

• Canadian regulators should see/incent the market to see Alberta heavy and synthetic oils as diesel feedstocks, and

• A low cost way for the US to reduce reliance on oil imports AND cut transportation sector GHGs is to implement policies that encourage the US and Canadian consumers to replace gasoline-powered passenger vehicles with ultra-low sulphur/biodiesel blended fuels that are made from Alberta heavy and synthetic crudes.

Comparing Refinery GHGs for Gasoline and Diesel Production

In the refinery, US average GHGs to produce diesel fuel are, on average and over all crude feedstocks, 9% lower than refinery GHGs associated with the production of conventional gasoline averaged over all US conventional and unconventional crude and synthetic crude feedstocks. But one of the reasons upstream Alberta bitumen and heavy oil is so GHG intensive is that many (not all) Alberta heavy oil producers remove all of the sulphur from the crude in the upgrading process. 

In the US, most of the conventional crude oil that arrives at a refinery gate still contains sulphur that has to be removed by the refiner.  This requirement to remove sulphur from conventional crudes at the refining stage is part of the reason that GHGs for refineries designed to max out gasoline production are higher than GHGs for refineries that are designed to max out diesel—and use Alberta feedstocks to do so.

Also, most refineris that target a 35% gasoline fraction averaged over all outputs have to subject all feedstocks to extra processing (such as "hydro-cracking", which consumes energy and generates GHGs) to achieve that high gasoline fraction from both the conventional and heavier-than-conventional feedstocks. 

The best light sweet crude feedstocks typically produce a 22% to 25% gasoline and Alberta heavy crudes produce only an 8% to 12% fraction without extra processing.  The extra processing converts diesel/distillate fractions into lighter gasoline fractions.

If North American fuel and climate change regulations recognize that full life cycle (including tailpipe, which are not included in the table above) GHGs for diesel are significantly lower than lifecycle GHGs for gasoline, then a low cost North American GHG reduction strategy involves the processing of Alberta heavy crude in refineries that are designed to maximize the ultra low diesel fraction—not the gasoline fraction—and to allow the North American gasoline market to slowly shift to ultra low sulphur diesel-biodiesel blended fuels.

Ironically, these facts are well recognized in the UK, where 60% of new passenger vehicle sales are diesel models. All European new diesel passenger vehicles are fitted with catalytic converters and fine particulate traps to massively cut diesel pollution.  These cheap tailpipe pollution control measures were not viable in North America before 2007, because they require ultra low sulphur diesel that was not generally available in North America before November 2007.