The Future of Electricity in Canada's Remote Communities

A massive geographic expansion of the Ontario power grid has begun, with the mobilization of work on the Pikangikum Distribution Line Project. The 117km distribution line, servicing the Pikangikum First Nation, is part of a much larger infrastructure effort to grid-connect Northern Ontario First Nations communities through the construction of 1800km of new and upgraded transmission lines.

This grid expansion aims to replace the diesel generation facilities in each of the communities, which are reported to be near the limits of their capacity, and have proven costly, unreliable, and downright unhealthy for the local residents. An analysis conducted by PricewaterhouseCoopers LLP (2015) indicates a substantial economic upside to the $1.15 billion project, of approximately $3.4 billion in avoided costs over a 40-year period beginning in 2021. In addition to the straightforward economic advantage is a host of other benefits, as the reliably delivered power acts as a catalyst for greater prosperity and economic self-determination for the communities.

Last Friday, Natural Resources Minister Jim Carr, announced $220 million towards initiatives to reduce the reliance on diesel fuel in Canada’s rural and remote communities. Since more grid expansions like the Wataynikaneyap Project could be considered for part of this initiative, ARI thought it would be interesting to compare the technical and economic parameters of this particular grid expansion against the 2018 capabilities and economics of microgrid technologies; solar + wind + storage.

To perform such a comparison, ARI has applied one of the most useful tools in our suite of analysis software; HOMER Energy Pro. HOMER is an ideal program for the rapid evaluation of microgrids, as it simplifies the evaluation and automates the optimization of the microgrid design. HOMER users are able to quickly define the desired system and control method, include economic parameters, and add operational constraints to the project (e.g. minimum amount of renewable capacity, minimum capacity shortfall, etc.). The results of the optimization are ranked based on the lowest Net Present Cost: the present value of all the costs of installing and operating the system over the project lifetime.

Lacking ideal temporal data, a design analysis was commenced using HOMER’s generic community load profile.  The community load profile was selected to represent the average electric loads of a representative community. The magnitude of the peak load and the annual energy consumption of a representative community were taken from reports from Hydro One Remote Communities Inc (HORCI).

With a load profile established, a microgrid can be evaluated by HOMER to establish the economics of various system configurations. A key decision is to determine what generation sources would potentially form such a microgrid. With a goal of reducing diesel consumption and enabling right-sized renewable generation, the following components for the microgrid were selected: a solar array (designed with Helioscope), an Enercon 2MW turbine, and a generic Lithium-Ion battery. Also included, but reduced in size by 40%, was the existing diesel generation capacity to act as an emergency backup power resource. The purpose of the HOMER simulations is to evaluate the strengths of the various generation sources, and suggest system sizing that can best achieve the stated goals. Apricity was interested to see when remote communities may be good candidates for microgrids as an alternative to traditional wires solutions. For each component the following key design parameters were identified:

  • CAPEX (including equipment AND development costs),

  • lifetime,

  • replacement CAPEX,

  • and ongoing OPEX

These were defined as key values using the most up to date 2018 information reported by Lazard’s LCOE and LCOS reports.

With all the system variables defined, HOMER was now set to proceed with calculation of the “optimal" system based on Net Present Cost of the microgrid components. The resulting optimal system was found to be:

Table 1: the required size of the microgrid components based on the design constraints provided to HOMER. Worth noting is the relatively poor performance of the solar and wind systems (even with large turbines), driven by high snow losses and a poor wind resource, which provides a conservative result for a generic Northern Community project.

Table 1: the required size of the microgrid components based on the design constraints provided to HOMER. Worth noting is the relatively poor performance of the solar and wind systems (even with large turbines), driven by high snow losses and a poor wind resource, which provides a conservative result for a generic Northern Community project.

It should be noted that the constraints placed on this optimization were educated guesses, and not necessarily in line with the strict energy requirements of any given remote community. Apricity Renewables can perform more detailed feasibility studies when working with specific communities to assess the opportunities and challenges of implementing microgrids.

When comparing microgrids against transmission projects, it is very important to have up-to-date information on renewable energy and storage pricing. We have found it is common for larger infrastructure planning reports to be relying on pricing information for renewable energy that is 3-5 years old. Using renewable energy pricing 3 years out-of-date can easily result in 30% or greater cost overestimates. Applying 2018 costs to these system component sizes, HOMER determined a Net Present Cost of ~$40 Million for the microgrid. HOMER is then capable of comparing this Net Present Cost against the cost of a proposed grid extension, which includes the construction and operating cost, the grid electricity rate, and length of the proposed grid extension. By determining the Net Present Cost of a grid extension per kilometer, a comparison could be made to find the ‘grid extension breakeven point’. In other words, how long can a community transmission line extension be before a microgrid solution might offer a more economically attractive solution? This comparison was partially inspired by reports of renewable energy and storage projects successfully replacing more traditional transmission upgrade projects. With HOMER we are able to evaluate the potential for microgrids to be viable alternatives to transmission infrastructure.

At this point, it would be unfair to ignore that the hypothesized microgrid would be built in a remote area which brings unique and costly shipping and logistical challenges. Since the economic values used in the optimization were taken from industry reports representing construction in more typical urban areas (e.g. Southern Ontario), the cost of a new Northern Ontario transmission corridor cannot be directly compared to the cost of a microgrid system that’s priced assuming simpler construction costs.

Table 2 below summarizes the sensitivity of the Grid Extension Breakeven Point to a range of Remote Project Cost multipliers. In effect, the multipliers act to increase the microgrid Net Present Cost, making a longer grid extension more viable:

Table 2: Optimal system Net Present Cost adjusted by a range of multipliers, to reflect the additional cost of construction logistics and operations in Northern Communities. Note: The Grid Extension breakeven point is calculated assuming 20 remote communities are serviced by the Grid Extension or alternatively each has a microgrid installed.

Table 2: Optimal system Net Present Cost adjusted by a range of multipliers, to reflect the additional cost of construction logistics and operations in Northern Communities. Note: The Grid Extension breakeven point is calculated assuming 20 remote communities are serviced by the Grid Extension or alternatively each has a microgrid installed.

A review of published figures, academic publications, and government reports suggests a 1.5 – 2.5x multiplier is a reasonable range of multiplier to consider.

Considering the ~1800km length of the Northern Ontario Transmission corridor, Table 2 shows us that a transmission line is the economically preferable option only when the costs to construct a microgrid are 2x the current industry costs of such a system.    

This is an interesting result! When the Wataynikaneyap Project first began in 2008, the cost of these technologies (particularly the battery storage) would have been prohibitively expensive. Rapid (and continuing) declines in technology cost have shifted the microgrid landscape quite substantially, and these systems have even become viable in remote areas with poorer renewable resources.  With continuing declines in the technology cost, a growing body of operational experience and confidence, and the federal governments recent announcement of support, expect microgrid systems to become competitive with grid expansion, from coast, to coast, to coast. 

DISCLAIMER: All data and information provided on this blog is for informational purposes only. Apricity Renewables has no involvement with Wataynikaneyap Power or the development of the Wataynikaneyap Project and presents this blog solely as a generic case study in microgrid economics and feasibility. Apricity Renewables Inc. makes no representations as to accuracy, completeness, currentness, suitability, or validity of any information on this blog and will not be liable for any errors, omissions, or delays in this information or any losses, injuries, or damages arising from its display or use. All information is provided on an as-is basis. Blogs posts do not necessarily reflect the views or opinions of Apricity Renewables Inc. and should not be construed as such.