To understand the degree to which provincial policies could reduce coal’s share of Alberta’s power-generation mix, we modelled three scenarios, which we have called Continued Fossil Reliance, Clean Power Transition, and Clean Power Transformation. We will discuss each of these, along with their results and impacts. For a discussion of our approach to effective capacity, price modelling, and greenhouse gas projection, please refer to the Appendix.
SCENARIO 1: CONTINUED FOSSIL RELIANCE
Our Continued Fossil Reliance scenario assumes a business-as-usual approach to power demand and production in Alberta. We have based it on two publicly available forecasts of electricity demand and generation supply—those of the Independent Power Producers Society of Alberta (the trade association representing the province’s power generators) and the Alberta Electric System Operator (the organization that operates Alberta’s electricity grid).
This scenario sees annual electricity demand growing by around 53 per cent by 2033 and This scenario sees annual electricity demand growing by around 53 per cent by 2033 and sees the province continuing to rely on coal (20 per cent) and natural gas (64 per cent) to supply the majority of its electricity needs. As Figure 3 shows, in this scenario Alberta exchanges its current heavy reliance on coal for natural gas, a more price-volatile fossil fuel.
SCENARIO 2: CLEAN POWER TRANSITION
We rooted this model on the existing and committed generation capacity developed through the gap analysis above, with one notable exception: we specified earlier decommission years for existing coal plants. We chose moderate near-term coal plant shutdown dates, avoiding immediate shutdowns and allowing for more-than-adequate timelines to permit and build replacement generation. This scenario lowers the permissible operating lifespan of coal units, from 47 years for the oldest, to 40 years for those most recently brought onto the grid. This 40-year minimum still allows developers to pay off the capital cost of their assets. In fact, industry proposed this timeframe for provincial and federal regulations of emissions in the past.
We selected energy efficiency targets for this scenario based on a recent Alberta Energy Efficiency Alliance analysis. The Alliance identified economically feasible demand-side energy efficiency upgrades that are currently economic in each of the province’s major electricity consumption sectors and estimated the total energy savings, which varied from sector to sector (Row and Mohareb, 2014). We incorporated the electricity-specific energy savings potential into our analysis. We stretched the implementation of these already-economic energy efficiency upgrades across the 20 years of analysis.
For other alternative and renewable generation sources, we chose capacity additions for ambitious but moderate growth, well within the resource potential in Alberta and within the growth rates seen in other jurisdictions that have brought a significant amount of renewable energy onto the grid. We considered population, energy system size, and appropriate siting (for example, rooftops). We balanced the proportions of renewable-energy sources added, factoring in existing capacity, projected growth, expected price impacts, and the need for firm supply.
Meanwhile, we allocated moderate growth for geothermal and storage—the latter is a basket of technologies and solutions that balance electricity supply and demand across intervals ranging from milliseconds to hours. Though neither of these currently exists in Alberta, they do in other North American jurisdictions, and it is unrealistic to assume neither will come into commercial feasibility over the next 20 years. Each is increasingly positioned to play a growing role in Alberta’s future energy mix.
We then refined installed capacities based on a number of parameters, including the need to meet minimum annual projected generation demand and system requirements for effective capacity, as established by AESO (see Appendix). We modelled a generation mix that included variable-output sources, such as wind power, with rapid-dispatch sources, such as peaking natural gas. We added some combined-cycle natural gas capacity to the gap analysis. We also added more peaking natural gas than under the Continued Fossil Reliance scenario—to complement intermittent renewables.
As Figure 4 shows, a much wider diversity of energy sources meets Alberta’s projected demand, reducing reliance on any single fuel source.
SCENARIO 3: CLEAN POWER TRANSFORMATION
As its name suggests, the Clean Power Transformation scenario represents a more ambitious change in Alberta’s electricity generation landscape. It relies on a mix of policies and approaches that would all but eliminate coal power generation from the Alberta grid by the year 2033 in favour of cleaner alternatives.
We used the same general methods as in previous scenarios to develop this scenario—including the same level of energy efficiency—but we employed more aggressive targets for alternative and renewable sources.
In this scenario, we assumed government will adopt policies to considerably accelerate clean energy deployment—while still keeping them well within resource potentials—and pro-rated them to match the growth seen or targeted in leading renewable-energy jurisdictions across similar time spans. By adding a larger share of renewable energy to the mix—including firm renewable power such as large hydro, biomass, geothermal, and storage—we reduced the need for both combined cycle and peaking on-demand natural gas plants, relative to the Transition scenario.
Alberta’s extensive northern hydroelectricity resource offers the largest known potential for firm energy supply with proven technology and could further displace emitting sources (Government of Alberta, 2013.) However, we moderated this development because of the difficulty of financing the very high capital costs of large hydro in the province.
For this scenario, we simulated a much more aggressive timeline of coal plant shutdowns. We started again with 47-year operating-lifetime limits on the oldest plants to moderate near-term shutdown rates, and reduced this to 37 years for the province’s third-newest facility.
Recognizing that shuttering a plant earlier than anticipated presents an economic burden, we targeted the province’s two newest coal units—federal regulations will allow them to operate beyond 2050—for biomass co-firing. Under this scenario, beginning in 2020 the operators of these two plants would gradually begin adding locally available biomass waste, derived from slash from logging operations, to their furnaces to displace coal. Our model adds biomass in 10 per cent increments until it generates half of the plant’s total output.
More analysis would prove useful, and we introduced co-firing to this scenario as one possible solution for addressing carbon pollution from the most recent coal unit investments. Still, our initial analysis of Alberta’s annual roadside logging slash indicated that meeting half of energy demand from the two coal units was possible from biomass waste generated within 250 km of the units. The phase in rate allows time to build four to seven facilities that will be needed to collect, process, and distribute the material and accounts for expected efficiency losses in co-firing with these higher proportions.
Government and industry have identified carbon capture and storage (CCS) as a GHG reduction solution. Though a pair of electricity CCS projects received more than $1 billion in Alberta and federal funding commitments in 2008, their developers have since shelved both projects. CCS could also accomplish the greenhouse gas reductions seen with biomass co-firing, should it prove itself as a cost-effective technology.
Under this Clean Power Transformation scenario, “pure” coal plants would not operate beyond 2031, leaving only the two newest plants with 50 per cent biomass co-firing. For comparison, under the Continued Fossil Reliance scenario and existing policy, this would not occur for another three decades.