(Nov. 12, 2010) In real life, it is not possible to deliver energy cost savings to consumers who invest in efficiency if we mobilize a market-wide movement towards efficiency, unless we build a market construct that moves us increasingly away from high fixed cost solutions to a construct that favours, smaller scale, more locally appropriate, lower fixed cost/higher variable cost solutions.

The general pattern (that customers do not benefit from energy efficiency measures) illustrated by the BC demand and utility billing for natural gas by the residential sector is repeated across all provinces and sectors, but the rate of demand and price change can differ quite significantly across both regions and within customer classes. Generally, utilities have tended to load price increases on the residential rate base and to delay/try to minimize rate increases for the industrial rate base—except where provincial market regulators (e.g. Ontario) have attempted to introduce barriers to this approach.

The data shows that over the period 1996 through 2008, while BC residential customer demand for natural gas declined over 21% and 30%— per household and per 1000 square-meters of residential space respectively—the nominal pre-tax price the utilities charged the residential customers increased 62% (per household) and 85% (square meters of space basis).  Gas demand declined 26% per square meter of residential space, but only 17% per household.

Note that this is before we account for taxes on utility bills. Obviously, in provinces that have become more reliant on utility tax revenues over time (BC, due to the combination of the carbon tax and HST), utility bills have increased more than is indicated in the tables below.

This pattern is also apparent in European markets.

In Europe, whether we are talking about natural gas or electricity, the utilities have generally passed 10% of service delivery and tax increases on to the residential customer base. Today, the retail (tax included) utility rates for residential customers in Europe are typically 3 to 5 times the rate charged industrial customers. By comparison, in 2008 the rate charged the average BC residential natural gas customer was 1.7 times the rate/cubic meters or Gj for gas delivered to industrial customers.

What a closer look at the domestic and international data shows is that:

• the primary determinant of energy demand is household disposable income (which means, by definition, that any energy tax is highly regressive);
• the second determinant of energy demand (both stationary and mobile source demand) is population density;
• the third determinant of energy demand is weather (heating degree days or HDDs and cooling degree days CDDs);
• and, at least as far back as the available data does (1969 for most OECD nations), there is no discernible, sustainable correlation between energy price and demand.

What Does This Say for Energy Efficiency?

I still believe that investment in energy efficiency should be a top priority in any national energy strategy. But it is inappropriate to sell this concept to elected officials and consumers as free or nearly free. I perceive a rational analysis suggests that the medium-term market price of CO2 in North America should fall in the US$25 – US$50/TCO2e range given a goal of cutting North American GHGs by some 1 billion tCO2e/year.  This is what it would cost to expropriate (and compensate the owners of) and replace coal-fired power generation throughout North America and replace it with CCGT supply.

To estimate this price for CO2 I capitalize the retail electricity rate increase associated with this asset replacement strategy and add that to the capital costs of acquiring the assets and retiring long term debt secured by those assets, and amortize this total cost of expropriation/compensation over a 20 year operating life for the replacement electricity supply assets. I conservatively estimate that we would have to pay shareholders 1.4x current share value to acquire the power generation assets we propose to decommission.

Of course, a prudent and forward-thinking national energy strategy would not either retire all coal-fired generation capacity in North America or dictate that all of the replacement capacity should be CCGT technology. But I do think this hypothetical—but also doable—expropriation/compensation option does give us a good reference (not including speculation) on long term market value, in current dollars, for carbon. Such an analysis, in my view, should be central to any development and evaluation of a national energy strategy.

If my valuation of the expropriation/compensation replacement scenario is acceptable, then implementation of any set of policy and regulations that is estimated to have a retail energy price impact greater than the equivalent of US$25/TCO2e for displaced GHG emissions, then we should take that as a signal that the package of tax, energy and environmental policies/measures under consideration will:

• likely fail to achieve its stated CO2 reduction objectives; and/or
• prove to be more expensive to implement than the expert estimates.

And if we reasonably cost the price impact of a policy/regulatory package as greater than the equivalent of US$50/TCO2e displaced, we should label that draft strategy as inefficient—at least relative to the benchmark expropriation/compensation/replacement option.

I should note that “cap and trade”-type measures are pure and traditional quota-based supply management strategies. As in all other quota-based supply management regimes, when governments introduce a quota as a market management mechanism, 100% of the real value that attaches to quota (whether it is freely allocated or auctioned) is value that is expropriated from the production assets that are covered by the quota regime. For example, look at any Canadian dairy farmer’s balance sheet before and after Canada’s dairy quota regime was implemented.

For many reasons, any quota-based production or supply management regime introduces critical and substantive market inefficiencies. But this reality is rarely reflected in leading academic and private sector analysis of the quota allocation trading option for carbon markets (which markets include energy, building products and food).

I think that if/when we start to more rationally evaluate energy efficiency and real CO2 emission reduction options, investments in energy efficiency will still rank high (after investments that lead to increasingly densely populated neighbourhoods that might be connected to one another by rail) on the priority list. But energy efficiency investments will not—ever—pay for themselves in customer energy cost savings. That is, unless, we can explain how and why the future of utility pricing will play out very, very differently from the past.

Missing Tax Revenues

The above estimate of the market value of CO2 does not address the complications introduced by governments that elect to cut (or maintain low) income tax rates by generating new revenues from energy and carbon taxes. Depending on the state/province, Canadian government revenues that are vulnerable if/when the market substitutes non-carbon energy supply and efficiency for taxed fossil fuel demand run from US$10 to US$25 per potentially displaced TCO2e.

So, if/when we develop more efficient and less carbon-intensive economies, we do have to come to terms with the question: how will governments replace declining tax revenues.

BC’s 2010 budget gives us a clear illustration of the potential magnitude of the vulnerability of jurisdictions that have embraced “green tax shifting” as revenue-generating “environmental measures.” When you divide the BC budget’s carbon tax revenue forecast by the scheduled carbon tax rate, you will see that the BC government revenue forecast for 2011/12 and 1012/13 depend on:

• an historically unprecedented 3-year average increase in CO2 emissions in the existing BC CO2 tax base; and
• either a decision on the part of the government not to introduce BC “cap and trade” or
• a decision on the part of the province to renege on its commitment not to “double tax” industrial and utility sector CO2 emissions.

The existing BC CO2 emissions tax base total over 31 MM TCO2e, of which 16 to 18 MMTCO2e of the tax base originates at industrial and utility operations that would, in principal, be covered by the BC “cap and trade” regime. Introducing cap and trade in BC, therefore, blows a CAD$450 to CAD$620/year hole in the Province’s current public revenue plan. That does not count any reductions in not-carbon-weighted road fuel tax revenues that might also be realized over the period.

How much will provincial taxes on utility service sales have to go up to fill the hole in the BC budget resulting from the implementation of any strategy that reduces provincial demand for fossil fuels?  What implications does the reality of the BC budget and revenue forecast have for forward-thinking investors in clean energy and energy efficiency?

Building a Different Future

There are a number reasons that utility bills increase faster than consumers can cut demand. But the most important is that fact that our North American existing energy supply regime (this includes the transportation fuel supply system, not just the electricity and natural gas supply systems) is dominated by high fixed and low variable costs.  As long as we continue to adopt national energy policies that favour high fixed/low variable cost options over low fixed/high variable cost options for energy supply, we will likely fail to deliver any reasonable efficiency, CO2 reduction and/or energy price targets in the foreseeable future.

Therefore, a prudent national energy strategy will incorporate, as a primary (but not unique) objective, the gradual shift of our energy supply regime from large fixed cost solutions to smaller scale, more variable cost solutions.

Unfortunately, we do not appear to be there yet.

What does “big difference” mean in a practical context?

Less focus on supply solutions that need large new electricity system transmission capacity investment. More attention to the technologies that enable district heat. It is much cheaper to transmit hot water 55 kms. from a CHP steam host than to build incremental electricity transmission and distribution capacity where it does not exist to delivery the equivalent amount of energy in the form of electricity. Ironically, a national energy strategy with this orientation would not favour retirement of old coal plants that are currently generating electricity at 30% to 40% efficiency rates.  Depending on proximity to space heating customer bases, those old (written down) coal-fired power generation units can co-generate heat and achieve 80% to 90% operating efficiencies—assuming that 10,000 lbs of steam converts to enough hot water to displace 1MWh-equivalent of electricity or natural gas demand to heat building space and supply hot water.

This is one of many, many possible ideas. It is not my objective to impose energy supply strategies on Canadian stakeholders. It is my goal to try to get us all to look at the same data and develop a more realistic consensus of what real life looks like.

In real life, it is not possible to deliver energy cost savings to consumers who invest in efficiency if we mobilize (as I hope we do) a market-wide movement towards efficiency…unless we build a market construct that moves us increasingly away from high fixed cost solutions to a construct that favours, smaller scale, more locally appropriate, lower fixed cost/higher variable cost solutions.