Energy Probe

In regards to biofuels, I have gone on record for years that once we fully consider the impacts of ethanol—not just from corn, although corn ethanol is the worst of the ethanol options—it will become socially unacceptable to deal in ethanol at all. Biodiesel is a different story. 

Biodiesel from palm oil should be a "no". But biodiesel from recycled waste oils and virgin canola and soy is okay—the biodiesel does not displace the food value of canola and oil, it uses oil after it is separated from the protein in the beans, so the food value can still go to the food market. Part of the reason for this difference is that we know how to sustainably harvest canola and soy using minimum tillage and multiple crop rotation practices.

However, we still do not know how to harvest corn at commercial scale using minimum impact methods.

All things considered, you really want to skip the alternative "alcohols" or sugar-based fuels and stick with oil. There are many reasons, including the above. Another is that oil-based fuels can incorporate large recycled content, while you don’t put recycled content in alcohol-based fuels. Vegetable-based oils can be blended with mineral-based oils at any point in the supply chain. Not true for alcohol/sugar-based biofuels.

More importantly, the diesel engine and power train remains a better platform for plug-in electric hybrid technology development than the gasoline engine platform. So we should be thinking oil, clean diesel, and diesel engine platforms for innovation.

In the longer term, I think production of biodiesel from algae is likely to prove the big breakthrough—and I put that within 5 years, not 20. Algae-biodiesel reactors will be built at diesel-oriented oil refineries. The biodiesel reactor uses waste heat and CO2 from the diesel refinery in the algae-to-biodiesel production process, and the biodiesel is run through the refinery’s hydro cracker to ensure that it will perform in cold climates just like petroleum-based biodiesel. Then we can put 50% biodiesel blends in EXISTING TRUCKS, let alone new diesel electric hybrids—conventional gasoline combustion engines can tolerate no more than 7.7%, gross, ethanol.  

The best existing diesel-electric hybrid (made by Opel/Vauxhall) uses the diesel engine only to recharge the batteries—not for direct power—and has a range over 740 km and much lower GHGs than the newest prototype gasoline hybrid.

It makes NO sense to dedicate resources to develop gasoline additives. We should be thinking about how to shift the gasoline market to clean diesel and diesel electric hybrid engines and power train technology.

One key to getting there is to get the sulphur content in diesel fuels down to 10 parts per million from the existing regulated 15 parts per million. This makes inexpensive catalytic converters and fine particulate traps workable on diesel-powered vehicles, so that we get air pollution reductions at the same time we get GHG reductions at relatively low incremental fuel and vehicle costs.

The issue for cellulose-based ethanol is the diesel fuel that has to be consumed to move the cellulose feed stocks to processing plants. Another difference between biodiesel and ethanol is that biodiesel plants can be designed to hit economies of scale at relatively small plant sizes. So we can locate the plants close to the feedstock supplies. Ethanol production usually requires very high production volumes to hit economies of scale. So we have to ship biomass feed stocks large distances to the plants.  

Having said that, I think there might be one (only one) BC-based ethanol production technology that could hit good numbers with small- scale plants. Whether or not I am correct about the one BC example, small scale economies is what we have to be looking out for in all biomass-based fuel alternatives. It simply costs way too much (in $s and fuel) to ship waste wood, which is only 50% carbon at best, long distances to make transportation fuels.

Probably one of the largest problems is that some decision-makers still do not know the difference between ethanol (what I call "alcohol" or "sugar-based" fuels, to real scientists’ disdain) and biodiesel ("Oil"). I tried to encourage then-NR Minister Lunn to differentiate between the two some years ago. In that regard, I think I failed.

I recently entered into a dialogue with a Canadian business journalist about lessons Canada can learn from European energy and environmental market regulations.

My principal point is that while many Canadian academics and environmentalists misrepresent, often quite unintentionally, the impacts of post-1990 European energy tax and cap and trade measures, they appear to have missed the VERY important positive story of District Heating in Europe. I think this is largely because the lion’s share of European District Heating Infrastructure was fully developed by 1985 and has nothing to do with post-Rio/UNFCCC decision-making.  

One of the key resulting failures is that we are now planning to shut down and decommission coal-fired power plants that are rarely retired in Europe. In Europe, the same plants are worked through three phases rather than simply shut down. In phase one, they make only electricity. In phase two they co-generate steam (which, in Europe, is usually condensed into hot water to supply a District Heating network) as well as producing electricity. In phase three (after 45+ years of operation), they cut back their electricity production and continue to make steam to supply District Heating.

An aged coal-fired power generating unit might operate at an efficiency rate as low as 30%—meaning the energy value of its power output equates to 30% of the energy value of the fuel fed into the generating plant. Fossil and or biofuels are combusted to make steam, which is then pushed through turbines or other processes to make electricity.  

The average GHGs per MWh of electricity output is usually in the 1.1 to 1.3 TCO2e/MWh net output range. But the aged boilers often make steam/hot at 85% efficiency.  

On average, 10,000 pounds of steam converts to hot water that displaces about 1 MWh-equivalent of electricity or natural gas demand. When we take away the step of converting the steam into electricity, and directly use the steam or condensed steam to supply district heating, the GHGs per MWh of useful heating value delivered to customers can range anywhere between 0.4 and 0.8 GHGs per displaced MWh-equivalent of electricity or natural gas demand.  

Using aged boilers to supply heat into the district heating network can be a very cost-effective transition in a GHG reduction strategy. The key is the distance of the boilers from the homes, commercial offices and industry that can use the steam/hot water.

Denmark has been able to develop hot water recovery, transmission and recycling systems at a retail cost to Danish consumers in the CAD$0.06/ to CAD$0.10/displaced MWh retail price range. This is significantly less than the CAD$0.46/MWh average price for electricity that is currently charged Danish households.

The Danes have found that they can pay off capital and operating costs in a network that carries hot water as far as 55 kilometers from steam/heat sources to retail customers.  Steam is more efficient than hot water over short distances; hot water is more efficient than steam over longer distances.

Note that the Danish District Heating network was almost fully developed by 1985, when Danish retail (taxes included) power prices were still below CAD$0.12/MWh.

The reporter was on his way to Copenhagen and decided, as a result of our conversations, to set up meetings with Danish administrators and operators of the Danish District Heating network, which currently supplies hot water and displaces 60% of the nation’s previous electricity and natural gas demand to heat space and hot water.

I use the UNFCCC GHG data for sector and national GHG estimates. Download the CRF reports for the countries you are interested in to get the best GHG stats for power sector.  Download the CRF zip file here. 

To see direct GHGs from electricity production, as well as upstream fossil fuel mining and refining emissions, expand the .xls file for the year(s) you are interested in and go to Table1.A(a)s1.  This is where you get the best electricity sector, coal mining and petroleum product refining GHG statistics.

To see nation-specific GHG emission factors for well-head/mine-mouth and processing GHGs for liquid and gaseous fuels, not including crude extraction or finished fuel transport emissions but including heavy oil upgrading GHGs (which are blended into the refining stats), look at Table1.A(a)s2 and Table1.A(b). 

So far, you have looked at energy consumption GHGs only and have not yet seen crude fuel extraction GHG estimates. Section 1.AA.2.F in Table1.A(a)s2 gives you the upstream fugitive GHG factor for each of the fossil fuels. Then Table1.A(b) gives you an estimate of the combined extraction through processing/refining (including fugitive) GHG factors for domestically produced fossil fuels. The GHG factors in Table 1.A(b) usually differ from one nation to the next. But it is going to be rare that the upstream GHG factor for imports is actually the same as it is for domestic production. 

The Table A(b) GHG factor is usually a pretty good estimate of the upstream emissions factor for the domestic production for the country you are looking at, and not appropriately applied to imports. But it is currently the case that both the Canadian and US CRF reports use a common North American GHG factor for natural gas. This factor, therefore, understates the upstream GHGs associated with Canadian natural gas consumption while it overstates the US upstream GHG factor. So if you use the CRF factor to estimate the full fuel cycle GHGs for Canadian electricity produced from natural gas, you will end up with an underestimate.  For most analyses, however, this factor will serve you well enough.
 
For a little snapshot of the differences between Canadian and US natural gas CO2 (not GHG) factors, go here. Select "Indicators", "CO2 emissions" then (1) CO2 from the consumption of natural gas and (2) CO2 from the flaring of natural gas. Then select "Natural Gas", then (1) consumption and (2) production.

They divide consumption emissions by consumption volumes, and flaring emissions by production volumes. You will see that this dataset puts the Canadian CO2 emission rate per unit of dry gas consumed at 1.5% higher than the US rate, and Canadian CO2 emissions from flaring per unit of dry natural gas produced at 122% the CO2 flaring discharge rate for US domestic gas production. This partially reflects the fact that Canadian natural gas reserves in the west have higher sulfur contents than typical US gas reserves, hence the higher flaring CO2 rate. And this US EIA dataset does not attempt to account for fugitive losses other than from flaring.

Beyond  the limited information you can find at the UNFCCC National Reports website, no one’s estimates are very good for developing nations.

But in the UNFCCC CRF reports, the estimates for electricity consumption (in Tjs) covers all electricity consumption in some national reports, and only fossil-and biomass-fuelled electricity consumption in others (no nuclear or hydro). So while this is the best place to get good electricity sector GHG estimates, you can’t rely on the CRF reports for total electricity demand or production part of the equation.

The best estimates of total electricity output, consumption, imports and exports, by fuel of origin and including renewables, hydro and nuclear, are here, under "Electricity" and "Renewables". Use the gross heat content tables in these sections to convert GWh and Quadrillion BTUs to Tj or whatever common energy output reporting format you wish to use.

The production, consumption and trade estimates at this US EIA website are simply reprinted International Energy Agency (IEA) data and easier to access and use than the IEA data. But the GHG data at the US EIA site is unreliable (CO2 only for some nations, more or all GHGs for others). The easiest way to put pretty good GHG/MWh-equivalent numbers is to put the GHG estimates from the UNFCCC CRF reports together with the electricity production, consumption and/or trade data from the US EIA website.

You may or may not want to see what it would mean to adjust national GHG liabilities to reflect electricity trade, as the US proposed climate change legislation dictates. Note that the US climate change bills oblige states to book GHGs arising from electricity demand in the state of final consumption, not the state in which generation occurs. This US-dictated GHG reporting procedure potentially delivers huge trade advantages to the US at the expense of Canadian clean electricity exports. We have not yet properly discussed this issue in Canada, at least as far as I know.

The US EIA version of the electricity trade data does not tell you electricity country of origin or destination for exports. If you need to get more into the implications of booking power generation attributes to the importing state/national GHG inventory, and want to assign net GHGs arising from electricity trade to the importing nation, you might want to buy some data directly from the IEA, here. The free data (last year reported 2008) does not tell you enough.. But the IEA emissions reports cover only CO2 and not all GHGs, so while you can use the IEA electricity production trade numbers with confidence, you still want to use the UNFCCC CRF GHG estimates where they are available. 

I find the IEA data too expensive. So for Europe, I use Eurostat production, import and export data (which is consistent with IEA and OECD data), which you can find here, go to "Energy Statistics – quantities (nrg_quant)"  under "Database". Here you can find electricity imports and exports by country of origin and destination for European nations’ electricity consumption.  Again, use the UNFCC GHG data to establish national sector GHG baselines, do not the mixed up CO2/GHG data in the Eurostat database for GHG/MWh baseline national estimates..

For Canada/US electricity trade, you can rely on the National Energy Board electricity trade reports, here. Here you can see trade between provinces and states.  If you want o figure out what GHG factor to assign to trade broken down by province and state:

• for provincial electricity sector GHG factors go to Environment Canada’s national GHG inventory, go here for 2006 and earlier numbers, email request for most recent—2007—report and go down the Table of Contents to click on ANNEX 9: Electricity Intensity Tables).

• for or US electricity sector GHG factors  by state, go here, and do an "all programs" state level emission search under the "unit level emissions" option.

There are still some significant problems with the Environment Canada estimates, but these are still the best official estimates you will get for now. The US numbers are much more reliable.  This fact alone is a significant source of tariff risk for Canada/US electricity trade.

If you do not care about imports and exports by country/state of origin, destination, another good source with a different production breakdown is the set of production import and export estimates from the free IEA tables here(go here, click on excel or archives after "electricity" under "Related Surveys". )

For the most up-to-date comparable data on national energy and environmental taxes and policies, including current energy and environmental tax rates and total government revenues, go to the OECD Economic Instruments database, here.

But remember that it is rarely the case that tax increases are fully passed through as retail price increases on each fuel that government might target with taxes. For example, fuel suppliers might respond to an increase in taxes on gasoline with a reduction in the wholesale price of gasoline and a commensurate increase in the wholesale price of (tax exempt) propane or ethanol. To see clearly how rarely point of production or consumption taxes/tax increases translate into equivalent retail (tax included) prices/price increases, go back to the Eurostat website, here, click on "database", then "environment and energy", then "energy", then "energy statistics – prices" then compare prices with and without all taxes, with and without VAT. And compare rates for residential customers to industrial customers.

Note that energy vendors will shift cap and trade compliance cost burdens in the same way they have always manipulated wholesale fuel prices to move around carbon tax burdens. Ultimately, integrated energy companies will lay off the lion’s share of any new Canadian tax or cap and trade regulation compliance costs on domestic "captive" customers (where there is no risk of customer flight), who will pay a disproportionate share of either cost burden (relative to "footloose" industrial customers and export markets.,  This is the primary reason I opposed carbon/CO2 taxes as a climate change mitigation measure and favour product standards (with credit trading and banking over quota-based cap and trade.