Energy Probe

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.

Many supporters in the reduction of greenhouse gases say that the most effective way to do so would be to NOT license further capacity without retiring existing capacity. Nor should capacity to support fossil fuel-based transport be expanded. One way to keep cars off the road is to stop building roads—forcing consumers and businesses to make do with existing infrastructure of that sort and facilitate shift to other modes

I don’t agree with this idea, as it gives massive market power to incumbent oil companies and entities that own real estate on existing rights of way—enabling them to erect new barriers to new market entrants and new technologies that they do not own. But I agree with your general concerns. I think there is a better way to address them.

We never talked about the policy recommendations that I made to Nova Scotia—recommendations that provincial cabinet accepted. I recommended that their first step has to be to introduce a new more stringent facility-level GHG reporting regulations and a legally-binding Renewable Energy Standard (RES). RES enabling legislation was made law in NS a couple of years ago, while the regulation establishing a short term RES standard passed about a year ago.

The NS RES permits the utility to surrender only Renewable Energy Certificates (RECs) that originate in renewable power projects that are located in NS. Then, new source performance standards for key GHG sectors that ensures that any new GHG -emitting plant is state of the art.  No offsets are allowed to provide relief from the new source performance standard. This new source performance standard for electricity became law in NS about 6 months ago.

55% of NS’s GHG emissions come from the electricity sector, so in that region it was important that we get the electricity sector regulations right first. In fact, electricity sector GHGs are larger and have grown faster in Alberta than oil & gas sector, a fact that seems to go missing in the hype. In the meantime, Alberta has approved construction of two significantly less-than-state-of-the-art coal-fired power plants since 2000. Big mistake.

The RES in Nova Scotia is an effective coal-fired power plant early shut down order, which both the utility and government agree. Neither the population or demand for electricity are growing in the province, so the requirement to add enough new renewable power to ensure that 13% of power sales are renewable by 2013 means that some older coal plants become redundant. Once we reached agreement on that fact with the utility, we were able to pass a GHG regulation that limits electricity sector-wide GHGs, as opposed to individual facility GHGs, absolutely, for power plants. 

Legislation putting the absolute sector-wide GHG limit in place became law about 6 months ago in NS. This does not add to the burden that existed once the RES became law, but removes any risk that those old coal plants will not get shut down.

The reason it was essential to put the electricity sector GHG regulation in place is that without it, it was not clear that the electricity regulator would allow the utility to accelerate the write off of existing coal-fired assets in their rate-setting process in the absence of the absolute GHG emission cap. While there will be continuing debate/disputes between the utility and the electricity market regulator about what the real value of the assets is for purpose of capitalizing the asset write-downs, but that is the kind of question that provincial electricity sector regulators are accustomed to fighting over.

The key message, so far, is that it was much easier to negotiate an aggressive absolute sector-wide GHG cap in place for the electricity sector: (1) AFTER we put the aggressive RES in place and (2) as long as we were not allocating quota to individual facilities. The NS power sector rules include credit banking and limited borrowing, but there is no quota allocation. Our strategy was always to work to this outcome.

In other words, when NS was developing the RES renewable mandate we were always asking ourselves BOTH: (1) is it physically doable in the time frame we are giving them and (2) is it tough enough to get us at least a couple of early coal plant shut downs? We did achieve the second objective and we will see if we achieved the first.

Phase 2 of my recommendations—which NS is developing into regulations at this time—is to include expansion of the Renewable Energy Standard to cover all fuel distributors, not just electricity distributors. So let’s say the electricity distributors will have to surrender RECs, to cover, say, 15% of their power sales in 2015. It is very important to ensure that the RES uses sales, not generation, as the denominator in the standard. This obliges the electricity distribution companies to account for the GHGs associated with power imports, insuring against the import of high-GHG power as a local regulation compliance strategy.

The new NS regulations in development will also require NS distributors of petroleum products and natural gas to report their quarterly sales in petajoules (Pjs), convert Pjs to MWh-equivalents (1 Pj = 277.78 MWh) and then the fossil fuel-based distributors will be obliged to surrender RECs covering the same % of total sales that will be the standard for the power sector in 2015 and 2020.

I strongly believe that this approach to regulation makes renewable energy development a core business activity for fossil fuel-oriented companies, which is our primary objective.  It increases competition for RECs in regions where one or a handful of entities dominate the power sector. 

I don’t think this approach to regulation will alienate Alberta industry. Just look at the Alberta large emitter regulation results. Alberta large emitters are already covering at least 40% of their Alberta "GHG offset" obligations by surrendering GHG offset credits from their wholly-owned wind power projects. There are many, many reasons why governments will seriously regret issuing GHG offset credits to zero-emission power projects. These projects should be credited under an RES. The feds should not make the mistake of issuing Offset Credits to zero-emission power projects, but should cover all of electricity and fuel sectors with a federal RES and issue only RECs to zero-emission projects.

The federal standard should issue RECs to entities that manufacture biofuels in Canada. The federal RES should also issue RECs to NEW nuclear and all new hydro generation capacity. It should issue RECs to cogeneration, geothermal and geoexchange projects where every MWh-equivalent of electricity steam or hot water that is delivered to a third party directly from the source or through a district heating system gets a REC. It should also issue RECs to power generators who sequester CO2 in geological formations. Most importantly, the federal RES should issue RECs to existing building owners who invest in upgrades and reduce ALL ENERGY demand.

The key questions we are working through at this time include:

• What should the GHG sequestered to REC conversion rate be?

• How do we certify that certain transmission investments are essential to opening   up renewable resource markets for purposes of determining that transmission investments qualify for RECs. If the transmission operator gets RECs for any renewable power deliveries, the renewable power source of that supply would not get RECs. But putting this transmission option on the table enables, say, Nova Scotia to reward private sector investors in transmission capacity if/when that capacity creates NS access to PQ hydro resources. When NS issues RECs to transmission operators deemed essential to access imported renewable power and PQ only issues RECs to PG power projects that sell electricity to PQ consumers, there is no double-counting but a potentially good institutional incentive for transmission investment.

Obviously, the key is to start the work by developing a credible population growth and energy demand forecast. Given that forecast, the RES mandates for 2020 should reasonably be forecast to get us a 20% absolute GHG reduction, economy-wide, by 2020.  To focus the RES on new renewable development, we need to incorporate 2 classes of RECs under the RES: (1) one class for existing renewable projects, (2) once class for new renewable projects.  We need to do this to ensure that the regulation will generate the total new renewable capacity (and/or building efficiency-related reductions in demand) while leveling the playing field for existing and new renewable project owners. The 1997 Texas Renewable Portfolio Standard does this well and can be our administrative model for this purpose.

Because the RES makes new markets for investors, but does not directly assign new obligations to existing GHG=emitting plants, there should be no successful compensation claims under NAFTA Part 11. By comparison, if we actually implement a facility-level quota allocation that has any hope of generating an absolute 20% GHG reduction by 2020, that will generate US investor compensation claims that NAFTA panels will likely have to uphold.

A federal RES should incorporate the broadest possible definition of "renewable" without compromising the GHG objective. So nuclear should be "renewable" from a federal perspective. The federal standard should allow every province to implement its own RES through a delegated authority. Any province can regulate a definition of "renewable" that is more restricted than the federal definition, but provincial regulations cannot expand the federal definition of renewable. The federal legislation should  allow for/assume inter-provincial trading in RECs, but not remove provinces’ rights to erect barriers to inter-provincial trading. 

In other words, any province can write an RES that is quite different from the federal RES as long as: (1) regulated energy distributors surrender only federal RECs under the provincial regulations and (2) each province surrenders the RECs they collected to the feds to achieve compliance with the federal standard as required given energy sales in their regions.

This federal approach positions provinces to discriminate against certain RECs by technology and province of origin. Discriminating against RECs will increase provincial compliance costs. But it also increases the odds that local increases in power prices will generate local new jobs. The difficult task of weighing these trade-offs should rest with the lower levels of government, and the federal RES should allow provinces great flexibility in this regard. 

This may sound a little complicated, but it is actually much easier to do than implementing a Canadian quota-based supply management regime will prove to be.  100% of Canada’s trading partners have Renewable Electricity and Renewable Fuels mandates in law.

Japan’s "Total Primary Energy Standard" or "TPES", which applies to all energy, was first introduced in 1971. 

Spain’s was introduced in 1985. 

The European Renewable Energy and Fuels directives date back to 1999/2000, years ahead of the EU CO2 ETS. 

31 US states have legally-binding Renewable Portfolio Standards, Connecticut’s dating back to 1991 and 25 of the 31 having been implemented prior to 1997. Every US "cap and trade" bill outlines federal Renewable electricity and fuels standards in the first titles of the bill. That is because no prudent regulator would ever introduce a GHG quota allocation without first putting these critical product standards in place.

And when these critical product standards are properly designed, they drive the emission reduction agenda. The quota allocation only shifts wealth, given the existence of the product standards. Canada cannot possibly implement a GHG management strategy that can be integrated with the US without putting these key product standards in place first—just as the US, EU and Japan have done.

Having said that, I am recommending that we establish Canadian policy leadership by doing something different.  I am recommending that we cover all energy distributors with one common "Renewable Energy Standard" creating more competition for RECs. This is much more efficient and national goal-oriented than having one standard for electricity and one for fuels. This also gives the marketplace maximum flexibility to be creative in their responses to the mandate.

The other difference between my recommendation is that believe we must treat investments in conservation and sustainable demand reduction ("negawatt-hours") the same way we treat investments in new zero-emission energy supply. It gets RECs.

Canada’s energy product standards can be linked to the official national GHG inventory (or provincial GHG inventories), with a provision in law that the renewable targets will be ratcheted up at specific times if/when our official national GHG inventory and forecast suggests that this is necessary to ensure we meet our 2020 GHG emission objective.

But because we will be trading RECs, not GHG quota, this new market is very cheap to administer. The feds certify and register RES projects (including building upgrades.)   The project owners report Canadian and export sales quarterly. The government issues RECs to registered project operators’ reflecting their verified sales. The Canadian distributors of electricity, natural gas and petroleum products compete to buy RECs from the renewable project operators. The energy distributors surrender RECs, once a year, to cover their renewable content mandates.
After putting more stringent GHG reporting rules in place—so that we can build a more credible and verifiable national GHG estimate and forecast, the private sector can handle the uncertainty arising from the notice that REC targets will be adjusted to reflect changes in the official national GHG forecast.

The BC government’s Pacific Carbon Trust (PCT) pays private entities $25/TCO2e for greenhouse gas "credits" that are acquired to offset provincial government GHG emissions.

But neither the PCT nor Offsetters’ contracts oblige the venders of the "credits" to book balancing emission "debits" to their corporate GHG inventories on completion of a transfer. So when BC or the government of Canada finally regulates industrial GHG emissions, the PCT will continue to book reductions that have been realized at LaFarge to offset BC operations emissions, and LaFarge will also be booking those credits to it’s corporate GHG inventory. Or the PCT has to stop booking those credits that the taxpayer paid for, and Lafarge realizes the full return on the project that the taxpayers financed.

PCT/Offsetters contracts would only be sound if every time a corporate entity transfers a 1 TCO2e GHG "credit"–which reports to represent a 1 TCO2e reduction in a GHG inventory–to a buyer, that supplying corporate entity has to add 1 TCO2e to its reportable corporate GHG inventory.  Because LaFarge has no contractual obligation to add 1 TCO2e to its legally reportable GHG inventory when it transfers real title to 1 TCO2e worth of credits to Offsetters and then PCT,  PCT has either paid: (1) $25 for 1/2 TCO2e in reductions = $50/T, or (2) $25 for nothing (LaFarge retains the right to include the full reduction in its corporate GHG inventory report).

You can track Canadian large emitters’ corporate GHG inventory reports, which they are obliged to final annually (but with a 2-year lag) under existing federal law, here.

Because PCT/Offsetters does not include the discipline of double entry book-keeping in their contracting standards, the emerging carbon market is identical to the credit default swap market. A house that books only credits and no debits or contingent liabilities is a house that falls down. For this reason, there is little in the way of quality differential between the credits that PCT is buying and those that are trading over the Chicago Climate Exchange at this time.

I think this is worth talking about. If PCT introduces the discipline of double entry book-keeping into BC’s carbon market sooner rather than later, BC could be building the only real carbon market in the world. If we do not incorporate double entry book-keeping in these activities, we will just be one of the early and biggest losers in the next fake global derivative market.