The energy sector is one of the most complex and difficult areas of policy in the world today. Energy policy-makers and regulators face a three-cornered dilemma. The imperatives of each corner tend to defeat the others. The competing objectives are:
1. maintaining sufficient reliable energy supply
2. maintaining affordability and accessibility
3. mitigating climate change and other environmental degradations
The particular mix and interplay of these issues varies from region to region, but the overall dynamic is becoming universal. There is no “bliss point” where all of the imperatives can be reconciled: that is, it is essentially a puzzle without a definitive solution.
In the case of electricity, the cost of adding any new supply resources to address reliability, and particularly those which do not emit greenhouse gases (GHGs) to address environmental mitigation, is far greater than the cost of historically-available and developed resources, and undermines affordability. Looking at the problem from a different angle, increasing reliance on non-emitting generation resources undermines reliability of supply because they tend to be intermittent and their output is not matched to variations in load. This (and the higher unit cost of renewable generation) in turn drives up rates.
Low prices maintain affordability but high prices contribute to conservation and mitigation of greenhouse gas emissions. Rising prices not only undermine affordability as an objective in itself, but also erode the willingness of the public to endure pain for the sake of societal objectives: the so-called “social license” is a very precious resource and is easily squandered through high-cost policy options which do not maximize the corresponding societal return – like smart metering. In the long run, this is a significant obstacle to addressing the environmental imperatives.
Meanwhile, electricity generation in mature industrialized regions (like British Columbia) is facing its own tipping point as the “low hanging fruit” has already been developed. Our engineers of the 1950s and 1960s knew their business, and identified the best places to site large hydroelectric facilities. Each additional resource is not only less effective, but is higher-cost. Everything new that we add increases rates, with diminishing returns.
On the load side, it means that major new loads have disproportionate rate impacts for the rest of the customers, assuming that they pay the same price for energy as incumbent ratepayers. That is because the incremental cost of additional major supply is so much greater than the average cost of the pre-existing system, with its bedrock of low-cost heritage assets. Major new loads dilute the benefit of heritage assets among customers and increase the proportion of generation from high-priced sources. This presents challenging problems: will existing customers see their rates rise so that major new loads can be served under industrial tariffs that collect far less than the cost of the new supply? If not, will there be different rates between industrial customers on the basis of date of entry onto the system? (The latter solution is loaded with regulatory, logistical and political difficulties).
The best strategy would probably combine a recalibration of the industrial stepped rate to ration access to the benefit of heritage supply, and a major rewrite of the tariff rules for capital contributions by major new loads. There may also be a need for regional structures to firewall major new industrial loads from the rest of the customer base.
This problem is exacerbated by the desirability of shifting toward non-GHG emitting resources. These resources tend to be intermittent (seasonally, in relation to small hydro; hourly, in relation to wind) and further stress the system because of their need to be back-stopped by dispatchable resources – large hydro or hydrocarbon-based thermal. The seasonality of small hydro is particularly problematic in BC because it brings a surge of supply of electricity when we least need it – when the major hydroelectric reservoirs are also peaking.
The need to support GHG-benign renewables with natural gas-fired thermal plants is a typically circular problem in today’s energy sector: there are few if any solutions which do not carry their own contradictions and limitations. The irony of migrating to wind power in places like Europe as a strategy to reduce GHGs is that it entrenches the need for GHG-emitting thermal generation in the mix. You could call that the hidden carbon content of wind power: the more wind and solar they add in Germany, the more coal they burn to firm it up.
In systems like ours, with available large hydro to backstop renewables instead of using coal or gas, there is nevertheless a serious economic impact – a sort of “double-whammy”. Not only are the intermittent renewables a higher-cost/lower-quality resource, but they detract from the value of large hydroelectric resources which must increasingly be operated to mitigate the inherent deficiencies of renewables, rather than to optimize their own efficiency and value for utilities and ratepayers.
In North America, the entire equation is complexified enormously because of the recent developments of shale gas extraction techniques (“fracking”) which is producing a huge glut of anomalously low-priced natural gas – priced below its cost of production. This is a mixed blessing, not only because of environmental impacts, but also because of its profound distortion of energy markets and pricing, where one resource is plummeting in price at the same time as others are trending upward in the long term. Unless large quantities of natural gas can be liquefied and exported (globalizing natural gas as a commodity and therefore pushing up its domestic price), this distortion will continue to plague policy-makers and regulators, and defeat rational development of energy resources.
Ultra-low commodity prices for natural gas also mean a drastic reduction in the benefit the public obtains from the exploitation of this non-renewable resource in the form of royalty payments to government.
Spot electricity is mainly priced according to spot natural gas, and thermal electricity is being dumped onto the market at its variable cost of generation (i.e., fuel cost).
The overall scenario produces a resource cost-curve which tends to paralyse policy. We have three categories of energy supply.
First, our historic “heritage” hydroelectric generation resources, from the first-choice, largely-amortized facilities built decades ago, provide us with large amounts of both capacity and energy at very low cost.
Second, new domestic resources carry much, much higher energy unit costs and every addition drives up rates disproportionately, especially in the case of high-cost, relatively modest-scale renewables.
The third source of energy is the market. Market prices for electricity are absurdly low because of the glut of natural gas and a regional glut of thermal generation capacity, which combine to provide a glut of thermally-generated electricity. At the same time, we have a regional over-supply of intermittent renewable power, as jurisdictions independently strive for self-sufficiency and lower carbon emissions. All of this excess supply is further exacerbated by the impact of the recession which is damping industrial loads for both gas and electricity.
What this means is that any incremental generation resource drives up embedded historic rates, and at the same time far more costly than the market. Nobody in North America can make a profit in the marketplace from newly-developed electricity resources, with the exception of IPPs blessed with long-term fixed-price take-or-pay contracts with BC Hydro or other utilities – or clean renewables which (unlike our run-of-river hydro) qualify for premium prices in the California market.
Surplus energy has become a liability, not an asset. Far better to be a buyer than a seller in the emerging regional market.