The Canadian government’s "low carbon economy" strategy should mobilize private capital and not rely heavily on new investment that is, effectively, 100% public debt, or electricity rate-base financed. Unfortunately, this is the corner that both BC and Ontario policy strategies appear to be based on—even though they are different policy sets at first glance.

How do we mobilize private capital where the private sector is bearing investment risk, in lieu of the current situation in which the public and electricity rate-payers are being asked to bear 100% of investor risk, and at a risk premium that is many multiples of the private sector’s current cost of capital?

First, I think that all provinces should call on the government of Canada to regulate a new "Class 27"-style capital one-year depreciation rate for any investment in equipment replacement or additions in EXISTING buildings, power plants, manufacturing facilities and commercial vehicle fleets that will result in a minimum 20% reduction in GHG emissions—as long as the investment does not drive up any other pollutant discharges.

Here is look at the original Class 27 language as well as a strawdog draft of a new Class 27 that I think would work.

Capital Cost Allowance ("CCA") accelerated depreciation for tax purposes is always the federal government’s least-cost mechanism to spawn new private sector investment. This is a federal tax deferral, not a full reduction. So it only costs the federal government the time value of money if the new capital investment spawned by the regulation is incremental.  

Since there is very little new investment in existing Canadian plants at this recessionary time, almost all investment responding to the new CCA rate will be indisputably incremental.

Please note that if we assume that at the existing capital stock turnover rate, sources of 35 MM TCO2e will be retired before 2020, adopt Dr. Jaccard’s forecast of "Business as Usual" ("BaU") net GHG growth, and assume (for now) that we can implement policies and measures to ensure that new sources discharge only 50% of the GHGs that are in the BaU forecast, then:

Owners of buildings, plants and commercial transportation fleets that are in operation today and would still be in operation, on a BaU basis, in 2020 must deliver 3 out of every 4 TCO2e/year that Canada has to realize to achieve the federal government’s stated absolute national GHG target for 2020.

Almost all of the public resources that the governments of BC and Ontario have committed to GHG "reduction" to date are focused on the tax of ensuring that new energy and industrial sources, and new building construction, is less GHG-intensive than the BaU case. Very little of the new spending mobilized private capital to cut GHG emissions at existing sources that would normally continue to operate through 2020.  

This is what the new Class 27 should do.

Please note that most investments in existing facilities and fleets that increase energy efficiency and reduce GHG and air pollution emissions already attract one year depreciation rates (for tax purposes) in Europe, the UK and the US.  Putting the new Class 27 CCA regulation in place in Canada—before consideration of the credit banking provision that I have built into the strawdog—does no more than level the playing field for capital investment in Canada with the UK, US and Europe. I have included a depreciation tax credit banking (but not trading) provision in the strawdog regulation to:

• convert Canada into a slightly more attractive investment climate than the UK, Europe and the US, while

• signaling that currently unprofitable enterprises will only benefit from the tax credit if they figure out how to generate profits (and pay corporate income taxes) within 10 years of the original investment in new equipment to reduce emissions and

• to effectively allow transfers of the depreciation tax credit only to acquisitors of the sites at which the existing plants are located and only when the site buyers redevelop those sites to create green industrial jobs.

I don’t quite have the credit banking language in the strawdog right, yet. But a key element of final regulation wording should be to allow the bankable tax credit to be bankable and only transferable to investors who redevelop and generate incremental jobs in the communities at the highest economic risk due to GHG regulation.

Ontario’s Feed-in Tariff (TIF) does not do Hamilton (one of the top 30 Canadian economies at risk) any good if none of the new green power installations or continuing green power service jobs are not located in the Hamilton area.  

How Could a Province Lever Off a new Class 27 CCA regulation?

Assuming that the provinces can convince the feds to put a new Class 27-like CCA regulation in the next federal budget, the provinces can adopt another US tax measure to maximize the leverage potential of the CCA regulation.

For the past 30 years, or more, US federal tax laws have declared the interest income that bond-holders earn on state and municipal bonds issued to finance power generation capacity as well as ports and certain rail infrastructure, to be 100% income tax exempt.  This provision in US tax law ensures that private sector banks and investors are quick to supply low interest loans to private and public developers of the targeted infrastructure.

In exchange for Class 27, provinces should consider telling the feds that they will consider implementing the long-standing US-style interest income tax exemption, at the provincial levels, for bonds/loans to certified green technology infrastructure investments.

Remember, the goal here is to mobilize private capital—most importantly bank lending—at least short and long-term cost to the federal and provincial treasuries and to residential and industrial electricity rate-payers.

Perhaps the provinces might even go so far as ask the feds to mirror the proposed provincial interest income tax exemption in federal income tax law, in addition to promulgating a new Class 27 regulation.

In the US, Congress is obliged to establish an appropriation for every tax measure it approves, every year (unlike Canada, where we appropriate budget only for cash outlays). This establishes a fixed limit to governments’ exposures under the tax incentives. I also believe that the government of Canada and the provinces should consider establishing US-style annual "spending" limits for the above-recommended tax measures, to remove public revenue uncertainty from the proposal.

Note that the establishment of annual limits to tax credit commitments means that governments have to decide and disclose to the marketplace how they will manage the situation if/when demand for the tax credits exceeds the tax credit/interest income exemption budgets.

In most cases, the US Congress has ruled that tax credits will be made available on a ‘first come, first serve" basis, and I think that is the best approach for both of the above-recommended tax incentives.

Note, however, the alternative.  

In some cases, Congress has ruled that tax credits will be allocated pro-rated to demand.  For example, under the US Energy Security Act, large US producers of ethanol qualify for a production tax credit that is UP TO US$0.54/US gallon of ethanol produced, while small ethanol producers qualify for UP TO US$0.65/US gallon in production tax credits.  

In 2008, however, US ethanol production exceeded the Congressional forecast, so demand for production tax credits exceeded the appropriation for those tax credits.  Congress ruled that small US ethanol producers shall take the maximum US$0.65/US gallon tax credit and any remaining tax credit budget after that shall be appropriated to large producers pro-rated to their output.

This formula was established well in advance of the 2008 operating year, so this was no surprise to the industry.

The result was that in fiscal 2008, the US’s large ethanol producers realized only a US$0.45/US gallon production tax credit, not the legislated maximum US $0.54/US gallon. In fact, back in 2004, large US ethanol producers realized only US$0.20/US gallon in production tax credits.

In the 2005 Energy Security Act, the US Congress raised the large producers’ tax credit maximum from US$0.51 to US$0.54. But this was not the significant measure the US Congress introduced in 2005. The significant measure was an increase in appropriations for the ethanol production tax credit, which enabled the large producers to realize the full US$0.54/US gallon in 2006 and 2007 and US$0.45/US gallon (still over double their 2004 production tax credit realization) in 2008.

At the end of 2007, Congress amended the Energy Security Act to increase the level of the US biofuels mandate, but Congress did not substantially increase the forecast appropriations for the ethanol production tax credit. In other words, in 2007 Congress clearly signaled to the large US producers that it was time to start weaning themselves off of government subsidies.

I think the long-standing practice of pro-rating production tax credits (which I do not recommend in general) as in the ethanol example is very neat. This enables government to determine at what level of production the subsidies for each market participant should start to decline, and at what rate. As long as the strategy is well understood by industry from the outset, industry can manage this kind of uncertainty. This uncertainty motivates investors to be early adopters of the new technologies.

While I think that the federal new Class 27 budget should be allocated on a "first come, first serve" basis at the outset, I also think that the federal government might be well-advised to shift to tax credit rationing on a pro-rated basis (through a regulation amendment) after a number of years. Similarly, any budget allocation-constrained federal and provincial interest income exemption tax credits could also shift from "first come, first serve" to pro-rated to loan output shares, after a while.

This is a more rational and market-responsive way of phasing out a tax credit when market penetrations of the targeted investment start to become significant.

Now Let’s Talk About Ontario’s Feed-in Tariffs

I have repeatedly reported, previously, that FITs have been useful policy tools and renewable targets have been achieved at relatively low aggregate electricity price increases only if/when they have been implemented in the context of legally binding Renewable Energy Standards ("RES"). For this to work out, the RES has to be the primary driver of incremental green power demand and efficiency investments, not the price of the FIT. I have said that government must quickly implement four core regulations. A federal RES is one of those four.

I have also reported that Spain’s pre-2007 RES/FIT mix proved much more cost effective than Germany’s or any Scandinavian nation’s green power development strategies.  The keys to Spain’s success story include:

• the existence of a strong RES since 1985…15 years before Spain introduced its FIT, and

• Spain’s development and publication of a long-term transmission development map, which is continually updated based on increasing knowledge about the availability and cost of development of Spanish renewable resources.

• a FIT that fixes a green power premium to market rates for electricity, but does not fix absolute green power rates for 20 to 30 year terms.

Germany’s FIT actually provides incentives to the market to develop renewable power supplies where transmission access issues are greatest and costly to resolve. Germany’s FIT obliges the power utilities to build transmission infrastructure to meet the green power development demand. As a result, Germany and residential utility bills have realized unprecedented increases in transmission charges as a direct result of the FIT structure.

Spain has produced an intelligently developed map of current, planned and potential transmission and distribution infrastructure. Spanish green power projects bid to supply the utilities given the published transmission development plan. The pre-2007 Spanish FIT guarantees green power suppliers set premiums over market rates for long terms, but does not guarantee actual power prices for those terms.

Please note that in spite of this incremental uncertainty over the German FIT model, Spain had achieved greater green power market penetration by the end of 2007 than German, at less than 1/3 of the German incremental increase in transmission and aggregate power prices.

In 2007, Spanish leaders succumbed to market pressure to adopt a German-style FIT. In mid-2008, distressed with the manner in which this change affected Spanish electricity market, Spain retroactively and substantially reduced fixed prices in all power purchase agreements signed under the German-style FIT and reverted back to the pre-2007 Spanish FIT model.

The key difference between the models is in the balance sheets and credit worthiness of green power project developers. The German-style FIT attracts more cash-strapped green power applicants. The PPA-to-built-project ratio in Germany lags that for pre-2007 FIT Spain, significantly.

Also, the incidence of large corporate takeovers of cash-strapped small green power developers in German is significantly higher than it is in Spain. The Spanish green power market is dominated by private investors who have the capacity to share some long-term electricity price risk, while the German green power market is dominated by suppliers who have little to no risk-bearing capacity.

After implementing the tax measures I outline above, the Province might consider phasing in a FIT shift to the pre-2007 Spanish model over time.