Energy Probe

(Mar. 02, 2010) Dr. Jaccard said: “When the price of oil fell in the 1960s…”

Neither the nominal nor the inflation-adjusted price of oil changed much during the 1960s—at least compared to other decades. After a significant post-WW II hike, the inflation-adjusted price of oil fell during the 1950s and did not really change much until 1974, when the price went through the roof.

The oil prices started to dive again between 1987 and 1999, after which they sprang up but never reached the inflated-adjusted equivalent of 1980/81 price levels. We are not able to estimate the world price of crude with enough certainty to distinguish between a $20 and $19/bbl annualized price estimate in the official table below.  Statistically, those prices are the same.

What could matter is the rate of change in the price of oil relative to the rate of change in median household income. Households can maintain commodity consumption levels with little pain if their incomes are going up faster than commodity prices. This table shows that real oil prices did fall while real household incomes increased in the 1960s, but nothing like what happened in the 1980s and 1990s.

Dr. Jaccard said: “…in the 1960s we stopped building coal-fired power plants and started building oil-fired plants”

Ah…no.

This table shows that we built coal-fired power generation capacity consistently through the 1960s, 1970s and 1980s. We built over 3,000 MW of coal-fired power supply in the 1960s and more than double that capacity in the 1970s.

100% of the 6,957 MW of coal-fired generation capacity that came on stream in the 1970s was completed before the end of 1974.

It takes 5 to 7 years to get a fossil-fuelled power plant through the siting, permitting and construction process, which means that virtually all of that coal-fired generation capacity that was planned, approved and built over a period of relatively stable oil prices and just before oil prices drove through the roof.

Dr. Jaccard said: “…when the price of oil went up, we started building natural gas plants”

Ah…no…again.

As noted above, the price of oil increased, rather suddenly, in 1974, peaked in 1980 and crashed in 1987.  But as this table shows, Canadians built 71% of our oil-fired power generation capacity over the 1970s and 1980s, with the oil-fired generation construction boom really taking off in 1973—coincident with peaking oil prices.

We did build about 24% of our gas-fired power generation capacity in the 1970s, but: (1) we built three times more coal-fired and 1/3 more oil-fired generation than gas-fired capacity over that period and (2) while oil prices were high and gas prices were low in the 1980s, we built nearly no new gas-fired generation capacity. In fact, we built 46% of our gas-fired generation capacity since 2000, the period over which the price of gas has  increased continuously before finally hitting its peak in August 2008.

It might also be worth noting that since BC has had a carbon tax, demand for the taxed carbon-based fuels has increased in BC—in both absolute and per capita terms—at a faster rate than consumption for those fuels has increased in any other Canadian province or US state.

I believe that climate change and managing anthropogenic GHG emissions are key challenges that our generation must address. But I also believe that market regulation is the answer.

Dr. Jaccard’s recommended regulatory and policy recommendations are ineffective and inefficient, largely because they are made to fit a theoretical world and not the real one we live in. It is not sufficient for Dr. Jaccard to look up the facts and integrate them—although that is a first step—into his modelling. Most importantly, he needs to start asking and exploring one key question: why does the world not actually work as per his theory?  It is only through the exploration of the variance between his modelled world and the real one we live in that he can position himself to truly grasp how investment and consumption decisions are formed and to then develop policy and regulatory recommendations that have a chance at being effective and efficient.

Having said that, Dr. Jaccard is correct to site “density” as a priority objective, though my guess is that he and I would disagree about how to achieve that objective.

Aldyen Donnelly, March 02, 2010

Every time "cap and trade" has been introduced in the US (44 times since 1977 in air, water and wastewater markets):

• either covered sources or distributors of products that generate pollution or pollution precursors in product manufacturing or consumption process are compelled to cap and reduce discharges by biding regulations (which regulation may be in the form of at-source discharge limits and reduction schedules or point-of-sale product standards);

• 100% of the emission reductions achieved in historical cap and trade regimes have derived from compliance with these binding regulations;

• the binding regulations almost always provide for credit banking and trading among regulated sources or product distributors;

• then, an emission quota allocation, auction and trading rule are laid on top of the regulated markets.

I am not aware of a single historical example of the US implementing cap and trade without first putting the binding regulations in place. There is not a single historical example in which the emission quota allocation and trading rule has added incremental pressure on the market to reduce emissions beyond the target which will derive form compliance with the binding regulations.

Take the Acid Rain Program. It compels certain power generation units to apply for SO2 permits, which permits included binding SO2 discharge caps. It also obliges states to demonstrate that they are reducing the incidence of acid rain and are complying with increasingly stringent, binding, EPA-administered ambient SO2 and NOx (acid rain precursor) standards.  

So, for example, if the SO2 sources within a state are in compliance with the federally-permitted SO2 emission limits—which are defined in both SO2/MM BTU heat input terms and annual absolute emission terms— but not in compliance with federal ambient SO2 and NOx standards, the state has a legal obligation to impose tougher-than-federal SO2 and NOx discharge limits in state source permits to ensure compliance with the federal ambient air quality standards.

No SO2 or NOx source can exceed its permitted emission limits, no matter how many SO2 or NOx allowances the source owner might have in the bank.  

So it is the federal ambient air quality standards in combination with the state-administered operating permits that drive any aggregate SO2 or NOx reduction.  In theory, the SO2 and NOx allowance supply could decline faster than the sum of the emission limits in permits, but in real life that has never happened. EVER. In ANY US cap and trade-covered market.

How SO2 Quota Allocation Works in the US Acid Rain Program

In the SO2 market, the EPA freely allocates 98% of the SO2 allowance supply.  From 1995 through 1999, the EPA freely allocated 11.85 million TSO2 more allowances to the 110 oldest and highest emitting US coal-fired power plants than those plants had the physical capacity to discharge, assuming they were operating at 85% capacity all of the time.  

Starting in 2000, the free allocation of SO2 allowances to the oldest, dirtiest plants declined to 95% of their maximum physical capacity to discharge SO2. If the old plant owners elected to hoard their surplus free vintage 1995 through 1999 allowances, this allocation method meant the old plants could continue to operate, in aggregate, at 1995 levels through 2014.  

The Acid Rain regulation stipulates that starting in 2000, any utility that develops any new coal-fired power plant has to buy 100% of the US SO2 allowances needed to cover 100% of the plant’s emissions from either the US SO2 allowance auction (2% of annual supply) or the market.  

The 110 oldest plants discharge, on average, 3.75 lbs SO2/MM BTU heat input, while no one can build a new plant without physically complying with a maximum 0.5 lbs SO2/MMBTU heat input federal, permit-based emission limit. The 110 oldest plants qualify for their scheduled free SO2 allowance allocations for at least 35 years, even if the plant is shut down.

The Acid Rain regulation also stipulates that every merchant power plant in the US is exempt from the US SO2 cap and allowance allocation, where a "merchant plant" is any plant that sells 15% or more of its output to a non-utility US customer and/or without a regulated rate guarantee or to an export market. Note that the US merchant plants—i.e. any plant whose owners bear any rate risk for 15% or more of their output—are also 100% exempt from the US GHG cap and trade rule under both the Waxman-Markey and Kerry-Boxer GHG bills.

New US merchant plants have to comply with the federal New Source Performance Standard (same for all new plants; has not changed since 1977), and any more stringent limits that the state may have to impose for new sources to ensure compliance with federal ambient air quality standards, but new merchant plant owners have no obligation to acquire or surrender SO2 or GHG allowances.

If/when a utility-owned coal-fired power plant is sold and becomes a "merchant plant", it becomes exempt from the obligation to surrender SO2 allowances and its original owner no longer receives free SO2 allowances.

In other words, under the US Acid Rain program/SO2 cap and trade regulation:

• given a combination of federal ambient air quality standards and state permitting regimes that legally oblige power plant owners to cut SO2 emissions, which legal obligations are permit-based; and

• given that operating permits are not tradable; all the

• SO2 allowance and trading rule does is force the developers of newer cleaner plants to compensate the owners of the oldest dirtiest plants when they shut the old plants down.

Every US cap and trade system that has been initiated in the past—with one notable exception—has been a quota regime designed to compel new market entrants to compensate market incumbents when the market incumbents finally give up their highly profitable, old. operating permits with high emission limits. These permits with high emission limits are extremely valuable and in 47 of 50 US states if environmental regulation is introduced that directly or indirectly expropriates these previously established rights to discharge pollutants or pollution precursors, the regulator (federal or state) that causes that expropriation to happen must compensate the operators whose generous permits have been partially or wholly expropriated.  

All the US SO2 market rule does is relieve governments from the obligation to compensate old plant operators and transfers that compensation obligation to the general electricity rate base.

The assumption is that the new source developers’ cost of buying allowances from the old source owners will be spread over all rate-payers. Of course, the quota allocation and trading rule also delivers unprecedented market power to incumbent owners of the old plants.  

The Cap and Trade Rule Gives Incumbent High Emitters Unprecedented Market Power

While the original old plant owners will often "swap" SO2 allowances with third parties for short periods, they will rarely, if ever, free up their perpetually bankable allowances to allow new market entrants to build new, more efficient power plants. They hoard their SO2 allowances, ensuring that only entities that receive original SO2 allowance allocations will be able to build any new power plants in the US.  

I remain utterly astounded that a majority of US and Canadian academics continue to define this cap and trade system as efficient, fair or a successful form of emission control.

First, the SO2 quota allocation does not establish the emission reduction schedule—the basic federal ambient air quality regulations and state operating permits do. Second there is nothing efficient or "fair" (in a market sense) about the market power the free quota allocation confers on the original owners of the oldest dirtiest power plants.

Don’t Freely Allocate the Auction Quote: A Truly Misinformed Instruction

Please note that the mantra that "all permits should be auctioned" could not be more misinformed.

"Cap and trade" is a simple quota-based supply management and works, in emission markets, the same way it works in dairy, chicken or taxi markets. That is, 100% of any real, sustainable market value that attaches to the quota instrument is value that has to be expropriated from the physical production assets that are newly covered by the quota regime. If there is no devaluation of physical production assets, the real market value of the newly introduced quota certificates is, by definition, zero

Until President Obama came into power, most of Congress and the US administrative brand always understood that the quota allocation process has one, sole purpose: to deliver compensation to the property owners whose assets are devalued by the commitment to cut emissions, and to ensure that the required compensation does not have to originate in the federal Treasury.  

Whenever possible (the leaded gasoline, CFC and HCFC22 phase out) Congress has used the free allocation of quota under "cap and trade" to shift compensation burden to US entities that import regulated products, shifting this cost burden not only away from the federal Treasury, but also off the backs of US consumers.

If a US government actually complied with the dominant recommendations of the NGO and academic movements today and elected to auction 100% of the emission allowances/quota (as RGGI has done), then the regulating governments would/will have to directly compensate asset owners for any loss in market value of their assets that can be directly attributed to the new regulatory requirement that they acquire and surrender allowances. RGGI states thought they had avoided this compensation risk by creating such a large RGGI GHG allowance surplus (relative to the maximum physical capacity of the covered existing plants to discharge GHGs) that it could be argued in court that the Net Present Value of the perpetually bankable allowances that RGGI source owners hold is greater than the price they are paying for those allowances today.  

But, in fact, in 2008, a coalition of New York power producers filed suit against New York State, arguing that the state’s decision to auction 85% of their RGGI allowances disadvantaged them, relative to their competitors, and resulted in a devaluation of the market value of their assets. Having received multiple legal opinions suggesting that the state would lose the lawsuit, the sate settled in 2009 by freely allocating sufficient RGGI GHG allowances to the complainants to compensate them for their asset devaluation claim.

The Large Majority of US "Cap and Trade" Systems Have Not Survived and the US Acid Rain Program is Now Legless

Just under 50% of the US cap and trade regimes that have been launched in the US were disbanded within 5 years of completion of the pilot phase—where the pilot phase typically ran 2 to 3 years. Of the 35+ water and waste-water cap and trade systems that the US EPA has piloted since 1995, there have only been 3 arm’s length water quota trades in 3 separate markets over the first 7 years after the systems moved from pilot to full market regime. Most of the water cap and trade market systems have been shut down when it was apparent that the cap and trade system delivered destructive market power to incumbents, or when market manipulation was discovered.  

Unfortunately a number are now tied up in court. They are not simple to unwind. That is because allowances/quota becomes real property even if/when regulators build language into legislation to try to prevent that from happening.

Once a currency or quota certificate is traded like property, both US and Canadian courts find it is real property and legislators cannot pre-emptively successfully declare it is not real property.

This was tested in Canadian courts when the BC government claimed that tree farm licenses were not real property and TFL holders were not due compensation if/when implementation of the BC Forest Practices Act effectively reduced the annual allowable cut  (AAC) in their TFLs. The Supreme Court found against BC and ordered the BC government to compensate two major corporations for their AAC losses.

The US Acid Rain Program

The US Acid Rain Program established compensation for the owners of the US’s oldest, highest-emitting power plants by:

• freely allocating excessive SO2 quota to the old plant owners and

• guaranteeing those owners would receive their free SO2 allocations for at least 35 years (sometimes much more), even if/after they shut down the plants that originally attracted the free SO2 quota; and

• obliging every developer of any new US coal-fired plant to buy SO2 allowances/quota to cover 100% of their SO2 emissions, for the operating lives of the new plants, from the market.

If you want to see the long-term SO2 quota allocations for the US Acid Rain Program, go here. Click on "allowances" and then "Acid Rain Program", then "Owner/Operators".  (Alternatively, you can search by "facility".)  Select some owner/operators and then hit "Add Owner/Operators".  Now go to "Select Output" and then select "Allowance Detail Report".  Under "Update Column Selections", put ticks in the box for owner/operator.
Then hit "update column selections". Now go to "View Results" to download the report.

Scrolling through the report, you will see the scheduled volume and even serial numbers for the free SO2 allowance allocations, by original owner/operator, through 2039.  Remember, this is a firm, long-term SO2 quota allocation, because each owner operator continues to get their original-scheduled SO2 quota supply through 2039 whether or not they elect to shut down the actual plants that originally qualified them for the allocation in 1995. The SO2 quota allocations in these accounts only shift from one owner/operator to another if/when the original scheduled recipient sells this property right to someone else—which rarely happens.

US "Cap and Trade" Has Never Delivered Incremental Emission Reductions

Given an at-Source or product Standard regulation-based mandate to cut emissions, US "cap and trade" has always been a mechanism through which Congress shifts its legal obligation to compensate facility owners whose assets lose market value to target market participants. In the US Acid Rain Program, the obligation to compensate the old plant owners is shifted to the US electricity rate base.  

In the US leaded gasoline, CFC and HCFC22 phase-outs, 70% of the compensation liability was shifted to foreign suppliers of the regulated products to US markets (read: Canada), while 30% of the compensation costs were born by US consumers of the regulated products.

For a closer look at wellhead to refinery gate Greenhouse gas (GHG) emissions, take a look at these Life Cycle Emissions reports by the Alberta Energy Research Institute.

The Jacobs Consultancy was originally commissioned by the Alberta Energy Research Institute (AERI) to verify or disprove the full fuel cycle analysis for gasoline-from-oil sands feedstock that is used in the GREET model and the modified GREET model that the University of Berkeley team has used to inform the California Low Carbon Fuel Standard. The presentations at the website shows you Jacobs’ findings as well as a comparison of Jacobs findings to those of TIAX—the research on which the Berkley modified GREET full fuel cycle GHG estimates are based.

After that first round of research was published, I asked AERI why they had not also looked at the diesel fuel cycle.  After all, 78% of the full fuel cycle GHGs for gasoline occur at the tailpipe, and we all know that diesel tailpipe GHGs can be 10% to 15% lower (per ton mile of vehicle use) than tailpipe GHGs for gasoline-powered vehicles.  Based on some of my historical working experience, I also understood that refinery GHGs could be as much as 15% lower in a refinery that is designed to maximize diesel output, relative to a refinery that has a 35% gasoline fraction target slate.  

As a result, AERI asked Jacobs to look at the diesel full fuel cycle, but so far I have seen only preliminary conclusions from that analysis.  You might want to look at a new presentation, "Life Cycle Analysis and Technology to Decrease Green House Gas Emissions".

This new research suggests that the full fuel cycle GHGs associated with Canadian exports of heavy oil and refined products from oil sands feedstock is statistically zero.  In other words, the difference suggested in the slide deck is much smaller than the estimation error.  But let’s move on from there.

All of the analysis at this site still deals in average wellhead to refinery gate and transportation emission estimates. It shows that oil sands recovery and upgrading/refining emissions vary greatly depending on extraction process, whether or not the upgrader/refinery is co-generating heat and steam, and whether or not it uses coke to produce heat/steam. The upgrading/refinery emission estimates you see in this analysis are based on the consultants’ best estimates of refinery averages.

But there is one combined upgrader/refinery in Canada that is designed to maximize diesel output (or at least NOT designed to achieve a 35% gasoline fraction) from oil sands feedstock. It is the Scotford Upgrader/Refinery Complex, owned and operated by Shell International. This 25 year-old upgrader/refinery complex was subject to a major expansion starting in 2006.  

We do know the 2005 through 2008 GHGs for the Scotford and the rest of Shell’s operations in Alberta, but I don’t have an estimate of the upgrader’s and refinery’s throughputs at this time.  The upgrader has a rated processing capacity of 155,000 barrels per day (24,600 m-3/d), but has at times pumped out more than 200,000 bbl/d (32,000 m-3/d).  The refinery has a rated capacity of 100,000 bbls per day of synthetic crude feedstock.  

Actual Scotford throughput levels in 2006 and 2007 would not be representative years, due to the construction project and related plant downtime.  But based on old (pre-expansion) estimates of Scotford’s GHGs/MMBTU of product output ratio, I am guessing it should be lower than most other Canadian refineries and the GHG factors used in either the Jacobs or TIAX analysis.  

This is because: (1) the upgrader uses waste heat from the refinery, (2) the upgrader co-generates electricity and steam and (3) neither the upgrader nor the refinery use coke as a heating fuel. I think the Scotford numbers would suggest that the differential between the oil sands to diesel upgrader/refinery GHGs relative to GHGs from conventional crude-to-gasoline in a refinery that is targeting a 35% gasoline fraction—which differential appears to favour diesel-to-diesel over conventional oil-to-gasoline—is large enough to offset the higher extraction -to-upgrader GHGs for oil sands feedstock.

I also believe you will see that a wide range of opportunities exist to cut GHGs in the oil sands supply chain, while GHGs/MMBTU worth of conventional oil tend to increase as conventional oil reserves become depleted.  So the oil sands feedstock is also a superior platform for incremental GHG reductions in the liquid fuel supply chain.

Finally, a new diesel-focused upgrader/refinery is under construction in Alberta, being developed by Northwest Upgrading . The new upgrader/diesel refinery complex should be the "greenest" petroleum product refinery in the world.  It includes carbon capture where the flue gas stream will be injected to enhance oil recovery rates at a nearby semi-depleted conventional sweet crude reserve. This complex relies on gasification and does not have a coking unit.

Fuel Shifting and Tailpipe GHGs

I found the best way to get a picture of how important fuel shifting from gasoline to diesel has been in the EU27’s transport GHG emission profile is to look at the nations’ actual detailed GHG inventories as they appear in the CRF reports here.

Download the .zip file for any country you want to look at. Open the file for 2007, then go to Table 1.A(a) and look at, say, "Road Transportation". Then do the same for as many prior years as you deem necessary. Look at the difference over time.

I show you part of the tables for Denmark, comparing 1999 and 2007, below.  What this shows you is that fossil fuel consumption for road use increased 16.6% in Denmark from1999 through 2007, even though: (1) population grew only 3.2%, (2) cargo freight shipments fell 16.2% and (3) the tax-included price of diesel fuel increased 81% from 61.6 euros/1,000 litres to 111.3 euros/1,000 litres.

Since total cargo shipment (in tonne-miles) declined over the period, clearly 100% of the diesel fuel consumption increases reflect increases in passenger vehicle use and passenger vehicle fleet fuel-switching from gasoline to diesel. The dataset shows that Danish demand for transportation fuels actually grew over 42% between 1990 and 2007—even though population growth was under 6% and cargo freight shipments fell over this longer period.

With the gasoline and diesel consumption estimates from the UNFCCC, and the passenger and cargo freight estimates you can get from the US EIA and Eurostat, you can fairly easily calculate what the European transport sector GHG growth would have been in the absence of the passenger vehicle fleet  fuel switch from gasoline to diesel. And you could calculate what the US and Canadian transport sector GHG trends would have been had we experienced a comparable fuel switch, given our passenger and freight transport trends (our cargo freight shipments have increased, not decreased as in the Danish example).

As an aside, the fuel consumption and price data belie the mantra that simply "putting a price on carbon" will lead to reductions in fuel demand.  

If you  compare population density and ambient temperature (in heating degree days or HDDs) weighted transportation fuel consumption for the developed OECD nations, you will find that there is a very high correlation between per capita fuel demand and (1) population density and (2) average household income. While fuel demand is income elastic it appears quite price inelastic over other-than-very-short periods.

So my gasoline to plug-in electric-biodiesel hybrid passenger vehicle fuel shift—where biodiesel from algae reactors are added to petroleum refinery complexes and the biodiesel is run through the hydro cracker to ensure that it works well in cold weather—is a short to medium term transport sector GHG mitigation strategy. Achieving liveable and walkable nodes of high population densities in our cities, with nodes connected by electric rail, has to be a long-term priority objective.

Read the first part of “The oil sands should be shut down, right?”