At the moment, the best method for reducing carbon emissions seems to be to electrify everything – but electricity must come from carbon-free sources in order to do that successfully. Natural gas is a step up from coal, though it is far from ideal. Wind and solar appear to be what everyone is focusing on, which is good, except that two important sources are often overlooked. One is carbon-free and non-renewable, with a whole host of issues that won’t be discussed here. The other is carbon-free, renewable, and supplies massive amounts of energy. Canada has already tapped into the latter immensely. Hydro power provides the majority of Canadians with their electricity due to Canada’s abundance of hydro resources. However, the areas within the country that lack these resources are currently scrambling to find ways to produce carbon-free power. The question must be asked: Why don’t we all share? Norway and Denmark share, and they’re two different countries. Why can’t Canadian provinces share with each other, within the same country? A Western Canadian electricity grid is not a new idea; it has been around for more than half a century. There are a lot of unresolved technical and political arguments that have prevented this grid from becoming a reality. But is it possible? The answer is simple, yet utterly complicated.
The First Claim: It is feasible to build an integrated western grid from a technical and market perspective
There have been numerous reasons that an integrated western grid has not been constructed, but technical limitations are not at the forefront of that list. Canadian provinces have more interties with American states than they do with each other, showing that it is the will that is lacking – not the way.
The biggest technical and market challenge is jealously guarded jurisdictions: Provinces are willing to share as long as there is enough capacity for their own jurisdiction – and they receive adequate compensation.
There is enough hydro power in western provinces (Manitoba and BC) to supply an integrated grid
The NEB forecasts an increase from 77 GW in 2014 to 87 GW in 2040 for hydroelectricity. This capacity expansion reflects a number of large hydro projects currently under construction, including sites that would be critical for supplying power to AB & SK such as Keeyask in Manitoba and projects in the planning and development stages such as Site C in B.C.
In this model, Hydro production increases from 381 TWh in 2014 to 452 TWh in 2040, but due to wind and natural gas expansion, total hydro generation percentage declines from 59 per cent in 2014 to 57% during this time period.
Alberta currently has 16,261 MW installed generation capacity, of which 6,267 MW comes from coal, 7,081 comes from natural gas, and the rest from renewables (hydro, wind, biomass). Saskatchewan currently has 4,437 MW generating capacity, of which 1,530 MW comes from coal and 1,771 MW comes from natural gas, and the rest from renewables (hydro & wind).
30% of power generated in AB must be from renewables by 2030. The remaining 70% can come from sources such as natural gas, but there is no mandated ratio beyond the minimal renewable input. This applies to generation only, not consumption, so new hydro products would have to be built within Alberta’s borders to account for a share of this generating load. Importing hydro would satisfy demand and lower overall generation in the province, which would in turn make it easier to reach the 30% renewables target by 2030. Coal is legislated to be phased out by this year but renewable capacity is a long way from being able to make up the desired generation percentage. The carbon levy that was introduced in 2017 should provide some incentive to move in this direction.
50% of electrical generation in SK must come from renewable sources by 2030, which is double the current share of 25%. About 44% of Saskatchewan's electricity comes from coal-fired generation. The province has no plans to phase it out but instead intends to retrofit existing units to include carbon capture and storage technology. While these all focus on generation rather than consumption, importing hydro could shape the resource ratio by allowing higher emitting facilities to retire. This would effectively drop the fossil fuel usage proportion which would in turn raise the renewable usage percentage.
Both BC and Manitoba receive over 92% of their electricity from hydro power, with more untapped potential available.
The NEB predicts that Alberta and Saskatchewan will have contribute to the change in electricity fuel source share as AB phases out coal and SK meets increasing demand with alternative sources of energy. B.C. and Manitoba are both expected to build new hydroelectric facilities and increase capacity, which is necessary for AB and SK to import significant power loads.
Manitoba and BC currently have a combined 17,638 MW capacity of developed hydro power. BC has more than double the capacity of Manitoba at 12,609 MW compared to 5,029 MW, but due to Manitoba’s lower population this amount accounts for over 97% of total electricity generation in the province compared to BC’s 92%.
Given that Alberta has a larger population than Saskatchewan it is fortunate that the capacity is distributed in this manner, with the most present and untapped potential available closer to more populated areas.
Alberta does have a significant amount of untapped hydro potential, but most of this would be unfeasible to develop due to distance and National Park impacts. The vast majority of untapped resources in Alberta are located in the far northern reaches of the province and, aside from dam impacts on the Peace or Slave rivers, some transmission lines would most likely have to run through Wood Buffalo National Park. The proposed site along the Slave River, a few kilometers south of the NWT border in the northeastern Alberta, is almost exactly 1000km from Calgary as the crow flies. In comparison, the proposed Peace River Site C dam is a little more than 700km from Calgary, and though the same concerns apply to affecting a river that enters the Wood Buffalo National Park, the proximity is much further and transmission lines will not have to pass through protected areas to reach consumers.
Saskatchewan, on the other hand, has very little untapped hydro capacity. It would be more efficient, from an economic and capacity standpoint, to import hydro from Manitoba rather than build several new dams with low MW potential. If a 1,000 MW hydroelectric facility were built in SK, which would use up more than a quarter of the total untapped potential, costs would likely be in excess of $1 billion, as a conservative estimate. That is simply not enough power considering costs for a much larger facility would be proportionately lower while providing more electricity, and cross-border services would have the possibility of being funded by the federal government, which should be more attractive to SK anyways.
Hydroelectricity is an ideal back-up for intermittent renewable energy
Hydro is still the best form of energy storage available. Dams can act as de facto storage facilities because of their ability to ramp up quickly and tail off accordingly, accompanied by a very reliable source. Pumped storage hydro (PSH) also currently accounts for 99% of total large-scale energy storage, though it is not in widespread application due to the nature of large-scale hydro’s reliability. Newer technologies are emerging, such as [lithium ion, fuel cells, etc. GREEN BOOK] but are still not as efficient or anywhere near as large-scale as pumped storage, and likely will not be competitive alternatives for quite some time. Existing hydro is limiting need for large-scale increased storage in the majority of Canada. The same could be true for Alberta and Saskatchewan as well. Hydro can ramp up quickly and can adjust to meet firm capacity on demand, which would make it a very reliable source to back-up increasing intermittent renewable energy, especially as Alberta moves from an energy-only market to an energy and capacity market.
It is feasible to build adequate transmission capacity between the western provinces
Capacity and interconnections among the four Western provinces are lacking. Alberta currently has two operating interties, one with B.C (rated capability of 1,000 MW for export and 1,200 MW for import) and the other with Saskatchewan (rated capability of 150 MW for both export and import). The actual operating capability of these interties is significantly less, however. Saskatchewan has several operating interties, including the 150 MW line with Alberta and three 230 kv (HOW MUCH MW?) and one small 115 kv (MW?). Unsure of current operating status of SK interties to MB.
New infrastructure is needed
A major deterrent to connecting provinces has been high upfront costs of this necessary infrastructure. If cost is no longer a concern - if external funding (i.e. Federal government) is available - the technical aspect of implementing it will be attainable. Existing interties with the United States, and examples elsewhere in the world (such as China) show the technical capabilities for building high voltage lines and transmitting electricity over long distances is more than sufficient. Due to the technical differences in operating electricity distribution systems in the provinces, new converter stations will have to be built to facilitate interprovincial sharing, which will cost money. The minimal amount of interties between provinces demonstrates that the limits for building the necessary infrastructure are, and always have been, cost and political barriers.
Expected technical benefits of integration
All regions connected by an integrated grid would have access to neighbouring production facilities. This allows for access to diversified resources to meet demand in case of an accident within any given territory. The result is increased reliability, decreased necessity for local capacity reserves, and an ideal backup system for further integrating small-scale renewable energy projects.
Increased demand diversity and supply security
A grid that encompasses a greater geographic region will provide a more diverse supply with peak demand periods that do not coincide. Also, a larger territory with more generating stations will face less risks that would hinder the grid, such as low rainfall or temporary dam impairment. This will provide greater supply security to all constituents served by the integrated grid.
Improved coordination of maintenance schedules
A more extensive production area will lead to a reduced overall impact on the system and greater flexibility in operating sites. All of these technical benefits allow for greater economic efficiency by reducing long-term overall investments and production costs.
The Second Claim: It is politically feasible to build an integrated western grid.
This has always been the greatest barrier because it requires provincial cooperation, resident support, and financial agreements. There has been a movement to do this every 10-15 years since the 1950s. Now, Alberta’s CLP and coal phase out should help make it easier than before. New generation facilities and converter stations will need to be built to connect provinces and comply with regulatory guidelines, but this can easily be done if there is enough political will – and funding.
It is possible to overcome regulatory & market hurdles for interprovincial connection
The federal sphere primarily has constitutional authority over international and interprovincial trade and commerce – this includes interties between provinces. However, there are many regulatory issues that need to be resolved before large-scale interprovincial electricity sharing becomes a reality.
At the provincial level project developers must obtain environmental approvals before the physical infrastructure can even begin being built. Each of the four Western provinces have established regulators, licensing authorities and Crown corporations to administer these, and other, approvals – and this is where the difficulties come into play. Alberta is the odd one out, with a fully competitive wholesale and retail electricity market, and is in the process of shifting to an energy and capacity market. British Columbia has a separation of electricity generation and transmission components, but both are wholly owned Crown corporations. Manitoba and Saskatchewan are both more rigid, vertically integrated monopoly utilities, but they do have some workable agreements already in place between them. Provinces have encouraged independent power development in the past, especially for renewables, but there is evidence that cooperation may be more beneficial for all.
Regulated monopolies (crown corps in BC, MB, SK) and a deregulated system (AB)
In the early 1990’s Alberta transitioned from a vertically integrated utilities monopoly (which the other three western provinces still consist of) to a system where customer choice and competition determine generation capacity and supply mix, electricity price and choice of retail electricity suppliers. This is a big part of why electricity is currently so inexpensive in the province.
There are three categories each of eligible buyers and sellers through the Alberta Power Pool, which is the official means to trade electricity. Sellers can be importers, marketers and independent power producers (IPPs). Buyers can be retailers, direct access customers and exporters. Importers are the ones that purchase electricity from BC through interties and sell to the Power Pool ( and they would presumably play a large role if integration brings large-scale power into AB from BC). Retailers own local distribution systems that sell to end-use consumers and direct access customers buy directly from the Power Pool.
In Alberta, new generation capacity is subject to market forces rather than rate regulation – this is what sets it apart from the other three western provinces. Electricity must be competitive. If imported power is not competitive it will not be used. Rather than a Crown corporation, the Alberta Interconnected Electric System (ABIES) is run by four major corporations: Enmax, ATCO, EPCOR, and Altalink, the latter owning more than half the provincial transmission system and serves over 85% of the population. Under the AB system, owners of transmission components own those components, but the entirety of the ABIES is regulated by the Alberta Electric Service Operator (AESO), which is a natural monopoly. All parties involved in procuring or providing electricity in Alberta must do so through the Power Pool. With this they have access to the grid but must pay non-discriminatory tariffs set forth by AESO. AESO is also responsible for managing and operating the Power Pool in a manner that promotes the fair, efficient and openly competitive exchange of electric energy in AB. This is, in essence, the regulatory system in Alberta, and it is shaped by market forces.
AESO must also contract with transmission facility owners in order to acquire transmission services and provide customers access to the ABIES – this is where a mutually beneficial AB-BC contract is imperative.
Demand growth in AB has led to private development of transmission lines, not just to connect to new generation to the grid, but also to provide merchant open access transmission service. The AB Energy and Utilities Board (EUB) – an independent, quasi-judicial agency of the Alberta government – ensures discovery, development and delivery of AB energy resources and utility services takes place in a manner that is fair, responsible and in the public interest. The EUB regulates transmission additions, among other things, so there is a need for approval here as well.
In British Columbia customers have enjoyed a long history of affordable, principally hydro-based power supplied by the Crown corporation BC Hydro.
The BC government segregated BC Hydro transmission assets by creating an additional Crown corporation, BC Transmission Corporation (BCTC). Its mandate is to independently plan, manage, operate and provide non-discriminatory access to BC Hydro transmission system.
PowerEx is the wholly owned power marketing subsidiary of BC Hyrdo responsible for all export negotiating. The BC Utilities Commission (BCUC) regulates electric utilities within the province and is charged with protecting public interest and public utilities, including virtually all/entire electricity market in BC. BCUC regulates BC Hydro, BCTC and PowerEx.
In Saskatchewan an Open Access Transmission Tariff (OATT) opens the electricity system to wholesale access. Northpoint Energy Solutions, a wholly owned subsidiary of SaskPower, the Crown Corporation utilities monopoly, was created to provide generation and load management services and to conduct energy trading. This is the branch that will need proper contracts with Manitoba to procure enough electricity to meet demand in an integrated grid.
SaskPower generates the vast majority of SK power, but additional power is procured from Manitoba to meet demand. The policy direction of SaskPower appears to be to primarily develop generation projects itself – but it has stated that it will continue to work with other generators to develop cost-effective power from elsewhere.
Manitoba Hydro, a Crown Corporation and the only utility provider in the province, owns and operates all MB generation, transmission and distribution. Because of this, designing contracts for interties between MB and SK will most likely be simpler than between BC and AB.
MB Hyrdo has implemented a non-discriminatory OATT which allows for third party use of transmission system as long as capacity is available. Electricity prices in Manitoba have consistently been among the lowest in Canada, thanks in large part to almost exclusive large-scale hydropower, which enhances the province’s position as a power exporter. Manitoba does not have a developed wholesale market for electricity.
Building an integrated power grid between the four western provinces must take into consideration all the different regulatory and market conditions listed above. Because homogeneity is lacking across the board, it will take a considerable amount of capital and political will to bring these markets together. It seems more feasible, given the regulatory differences, to link BC with AB and SK with MB, at least in the initial stages. This would make the most sense given the relative simplicity of aligning two markets in two separate instances, rather than linking four jurisdictions at once. However, there are still many benefits that could be realized from integration across the provinces, such as BC to SK or MB to AB. A memorandum of understanding signed between the two latter provinces in 2016 called for “a commitment to share information and develop co-operative measures related to energy conservations programs, renewable energy development and greenhouse-gas reduction policies,” while specifically emphasizing “the importance of improving integration of electrical grids in western Canada to open up economic opportunities, improve energy reliability and resiliency, and continue transition to a lower-carbon economy.” Regardless of the geographic extent to which integration reaches, it should be overseen nationally. Involvement from pan-Canadian and federal institutions, as well as implementation of the Agreement on internal trade, is critical for ensuring smooth regulatory approvals and increased electricity distribution across markets.
Pan-Canadian & Federal Agreements or Programs
• Agreement on internal trade - seeks to harmonize the treatment of energy-related goods and services. goal is to permit access to markets and a non-discriminatory treatment of energy goods and services (this agreement could offer a path to integration of electricity sectors)
• RECSI (Regional Electricity Cooperation and Strategic Infrastructure) – $2.5M available over two years to facilitate regional dialogues and studies to identify the electricity infrastructure projects with the most potential to achieve GHG emission reductions
• ecoERP (EcoENERGY for Renewable Power) – $1.39 billion available to support 104 projects that total 4,458 MW of low-impact renewable power – 1cent/kWh production incentive over 10 years; includes low-impact hydro, along with other renewables
The 2003 Clean Energy Transfer Initiative (CETI) between Manitoba and Ontario: Undeveloped hydroelectric resources in Manitoba were studied in terms of meeting Ontario’s needs in the CETI initiative of 2003. This initiative has been abandoned since that time due to a series of obstacles that arose: negotiations with First Nations for rights of way, uncertainty about financing from the federal government, uncertainty over the value of GHG emissions that would be avoided, the complexity of interprovincial relations and intraprovincial electoral dynamics. CETI can be viewed as a lesson for what went wrong in large-scale interprovincial electricity sharing – and how these obstacles can be overcome in the future.
It is possible to gain political support for using MB or BC hydro in Saskatchewan and Alberta.
There is explicit federal support for interties and regional grids, though local political support is mediocre at best.
According to the Government of Canada’s Pan-Canadian Framework on Clean Growth and Climate Change, particularly Section 3.1 New action 2 – Connecting clean power with places that need it:
This shows that the Pan-CDN Framework explicitly states an interconnected grid would be very beneficial – and shows that the will is there to get it done. The challenge lies in how to realistically go about building new and enhanced transmission lines.
It would be in the best national interest to integrate, but it is generally not viewed as being in the best interest of each individual province, where the jurisdiction lies. In order to gain more local support, federal influence (financially and politically) must be used to generate intra and interprovincial support. This can be used to frame integration as a national and global benefit while also showing how it will be in the best interest of individual provinces.
Western provinces will be able to say, “We are doing our fair share to reduce emissions, and we are acting in the best national interest” – because it will benefit each province individually. Technical benefits, such as increased reliability, and economic benefits, such as lower, more consistent prices, are available through an integrated western grid, but integration must be constructed properly to realize these benefits – that’s where the pan-CDN framework and federal financial involvement play a critical role.
Due to the historically provincial setup of electricity generation and distribution, many Western Canadians see their provincial utility as part of their culture. K Froschauer, in his Hydroelectric Development in Canada paper, goes so far as to argue some see the traditional utility market as part of their identity. This is based on a tendency for individuals to resent out of province electricity production, with some seeing it as being a ‘heritage.’ Aside from the perceived sense of attachment to electricity providers within provinces, local green energy projects, and the resulting jobs, are easy for provincial leaders to promote in pursuit of keeping campaign promises. But there are a few reasons why this kind of thinking could be altered. Providing a fully integrated grid, with distribution guarantees across all jurisdictions and federal funding, could shift thinking away from strong, individual provinces to a strong western system, provided no jurisdiction gets a perceived short end of the stick. If integration can be seen as beneficial to all, leaders and decision makers could champion the idea as benefiting their constituents – while also benefiting neighbours and the larger region as a whole. There is no reason to believe that people would be against a system that would benefit fellow Canadians – as long as there are no perceived local disadvantages from such a plan.
It makes economic sense
According to CESAR, levelized costs for hydro are the lowest next to coal, which is being phased out in Alberta and retrofitted in SK. High upfront infrastructure cost is unattractive, but if the necessary new developments (such as dams, transmission lines and converter stations) were paid for in large part by the Federal government, the cost of importing hydro could be the lowest available option.
Implementation of a National Infrastructure Bank will make Federal funding possible
In 2017 Finance Minister Bill Morneau announced the formal steps towards creating a Canada infrastructure bank to help fund major construction projects across the country. $35-billion was set to be committed, plus incentives to attract private investment at a ratio of $4 - $5 to $1 (private to federal). This will be used to roll out the $120-billion infrastructure plan announced back in March 2016’s budget, set to be used over a 10-year period. The plan was amended a $186-billion unfolding over 12 years, which would provide even more funding for necessary infrastructure projects. Should be priority because it will help meet national climate targets and was detailed in PCFCC.
Fair contracts are possible... in principle
It’s unlikely that AB would be gouged on price since Hydro power is so inexpensive; what is more likely to occur is that significant levels of imported hydro would drive AB market price down, making necessary investments inside AB less attractive. This would result in higher Capacity Auction and Renewable Electricity Program bids or insufficient build out, which in turn would cause issues with reserve margin/reliability unless proper power supply guarantee contracts were created. In order for Alberta’s AESO to “count on” Hydro imports from BC (in terms of firm capacity), BC Hydro, through PowerEX, would need to enter into a binding contract that essentially commits to providing AB power over BC customers – even if BC was facing a blackout situation. If that contractual arrangement were not set it would become a merchant line rather than a system reliability-based line, where BC power would need to compete with AB-based generation. AB-based generators are already upset about how existing BC imports are subsidized by the BC tax payer and are not competing on a level playing field, which is not a settled issue. SK and MB would need to reach a similar agreement.
Expected economic benefits of integration
Increased economic exchange
A large generating fleet makes it easier to use less costly technologies. That allows for easier access to resources situated in further regions, such as the out of province hydroelectricity that would serve as the backbone of an integrated western grid. Distant energy resources can be implemented at a lower cost than more expensive localized technologies in unfavourable areas, which leads to lower overall operating costs for the entire system.
Reduced investment in overall infrastructure
Pooling resources will lead to each province avoiding the costs of adding additional capacity individually; federal funding for grid infrastructure will make this even more significant.
Increased scale economies
A large integrated grid will allow for guaranteed access to a large market – correspondingly large generating stations can then be built, gaining economies of scale.
The Final Claim: It is possible to overcome the obstacles to integration
Based on all the technical, regulatory, political, and economic factors discussed above, three major obstacles are clearly identified as hindering an integration process:
1. The structure of political and electoral incentives at the provincial and federal levels;
2. The redistribution of the gains from a partial or complete integration; and
3. The lack of recognition of environmental benefits resulting from integration.
There is reason to believe, however, that it would now be possible to overcome these major obstacles due in large part to the Paris climate targets and provincial goals, such as the Alberta CLP.
If governments – both provincial and federal – are serious about reducing GHG in the long term, imported hydro should be pursued. Natural gas could be used as a transitional fuel while imported hydro comes online rather than replacing all coal-fired power plants in Alberta with NG facilities. The result would be up to 600 Mt less GHG emissions by 2060 in Alberta alone. Over this same time period hydro becomes the cheapest option – even cheaper than coal – due to the 100 year lifespan of average dams and no fuel input costs.
To manage that political challenge in the difficult context of Canadian federalism, decision-makers must be aware of and explicitly address the related issues, many of which will revolve around fairness norms, and will be as likely to involve non-material as material interests. Increasingly, distribution of environmental effects is also likely to be a factor. Most importantly, the federal government must play a consistent and supportive role.
The case for action is increasingly being made. But governments and their utilities are still hide-bound to their provincial boundaries. Federal investment is crucial or this does not happen.
The question is not if it's possible – it's “will it ever actually get done?”
 NEB (https://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2016/index-eng.html)
 Government of Alberta (gov.ab.ca)
 Pineau, P.O. (2012) Integrating electricity sectors in Canada: Good for the environment and for the economy
 Blakes, Overview of Electricity Regulation in Canada
 Fragmented Markets: Canadian Electricity Sectors’ Underperformance Pierre-Olivier Pineau (2013)
 Government of Alberta (https://www.alberta.ca/release.cfm?xID=390705C45ADB9-D76C-6E1B-9EC6271FFF650EF6)
 Pineau, P.O. (2012) Integrating electricity sectors in Canada: Good for the environment and for the economy
Government of Canada (https://www.canada.ca/en/services/environment/weather/climatechange/pan-canadian-framework/complementary-actions-reduce-emissions.html#3_1)
Froschauer, K., 1999. White Gold: Hydroelectric Development in Canada. UBC Press, Vancouver.
in BC Hydro generation, a “heritage” amount of electricity must be provided at an historical low cost to consumers (about 50 TWh). Beyond this, the cost of generation is not regulated and competitive contracts must be drawn up
 Pineau, P.O. (2012) Integrating electricity sectors in Canada: Good for the environment and for the economy