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       SEQ Table \* ARABIC    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       SEQ Table \* ARABIC    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.

Adjusting to the New Global Adjustment

The Global Adjustment (GA) was established by the Ontario government in 2005 to cover the cost of providing adequate generating capacity and conservation programs in Ontario. An annual pool typically in excess of $10 billion, the GA is set monthly to reflect the difference between hourly Ontario electricity price (HOEP) and financial obligations to generators. The obligations include regulated rates for Nukes and Hydro, payments to build and refurbish generating capacity, contracted rates paid to generators, and the cost of conservation programs. 

This $10+ billion-dollar annual pool is paid by Ontario electricity consumers, and is divvied up based on consumer categories. Class A consumers (5MW or greater demand) that have not opted-out of the Industrial Conservation Initiative (ICI), pay a GA charge based on their percentage contribution to the top five peak Ontario demand hours over the course of the year. The ICI provides an opportunity for Class A consumers to lower their cost of electricity, and acts as a market signal to reduce overall peak demand on the grid. Class B consumers (50kW-5MW) have typically paid GA through their regular billing cycle, and residential and small consumers have their GA charges embedded in the time-of-use (TOU) rates they pay. 

In an aim to further reduce peak demand and enable cost savings opportunities for consumers, changes have been made to the eligibility requirements of the ICI to allow for more consumers to participate in the initiative. Certain Class B industrial consumers with an average annual peak demand of 500kW or more, and any consumer with greater than 1MW average peak demand will be allowed to opt-in to the initiative, meaning GA charges will be removed from their consumption and assessed based on their peak contribution. Once opted in to the program, a participant can lower their monthly electricity bill by reducing consumption during potential grid peaks. Participants are welcome to employ any strategy they see fit to predict potential peaks and reduce their demand during these periods.

Strategies typically fall into two categories: reducing consumption by improving efficiency or ramping down on-site activity, and/or implementing behind the fence generation and storage systems to be used during potential grid peaks. Applying either or both strategies is an increasingly attractive option as GA costs continue to climb and the commodity price of electricity falls:

Figure 1: Change in commodity price of electricity and GA in Ontario (image produced by IESO)

Figure 1: Change in commodity price of electricity and GA in Ontario (image produced by IESO)

Enabling the on-site generation strategy are the great strides taken in lowering the cost and complexity of renewable generation and energy storage solutions. We’ve all seen the incredible cost decline in renewable generation over the last decade, and storage has begun its fall as well. According to the latest reports (Lazard LCOS 3.0), micro-grid sized lithium-ion storage systems have decreased 27% in cost of electricity and 101% in overall CAPEX in the last year alone.

This dramatic reduction in system cost is enabling more and more consumers to view participation in the ICI coupled with a technical solution as an attractive way to reduce their overall electricity bill without the need to interrupt business operations. With a clarified position laid-out by the Ontario government this year, some have argued the policy risk associated with investing in a technical solution has decreased (Osler).

Diminished policy risk does not setup an immediate home-run though; timely implementation of a solution should also be a concern. There is an element of Game Theory to be considered as part of a GA cost reduction play, since early adopters will be in a position to better predict peaks. Also, it should be noted that an early-adopters’ GA savings mean GA expense for a non-participant in the ICI. Those consumers late to the game will have to shoulder more of the fixed GA amount and can expect to encounter a peak-chasing effect that will increase the complexity of predicting peaks (the working assumption here is that enough consumers will have joined the ICI to have a material impact on when peaks occur). Becoming an expert peak-estimator could be incredibly important to ensuring that an investment in a technical solution is paid off in a timely fashion.

Multiple revenue streams from an installed technical solution can help alleviate the risk of a competitive ICI program. For example, a solar PV system can participate in the latest net-metering program. A battery system can take advantage of daily fluctuations in HOEP and perform energy arbitrage. And a combination of both technologies could help reduce GA charges, perform energy arbitrage, and provide net-metering!

What is fairly certain is that the pool of money that is the GA will exist for years to come. Even with a restructuring of the ICI (which would likely take several years to implement) the GA costs will have to be borne by consumers and allocated using a fair mechanism, be it through capacity (kw) or consumption (kWh). The multiple revenue streams of a behind the meter system and the ultimate reduction in consumption and capacity could be considered a way to hedge the risk of changing policy and increasing electricity costs.
 

DISCLAIMER: All data and information provided on this blog is for informational purposes only. 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.

Solar Eclipse: 2017 Edition

As solar nerds at heart, the Apricity Renewables team will be taking a moment of our time to view today’s solar eclipse!

Here in Ontario we won’t be lucky enough to witness the event in the “path of totality” but should see roughly 70% coverage at the peak, which will occur around 2:30PM in Eastern and Southern Ontario. If you find yourself unmoved by the partial eclipse seen in the province today, you will only have to wait until April 2024 when another total solar eclipse will follow a path stretching from Windsor to Montreal, and across the Maritimes. If you find yourself along today’s path, which runs from Oregon to South Carolina, you will be treated with a total eclipse as the moon transits between Earth’s surface and the sun. The point of totality on the surface will last for about 3 minutes (not as long as you would expect). In fact, NASA is planning to extend this time by chasing the point with high-speed aircraft, allowing for extended high-altitude research on the solar atmosphere.

The 2017 Solar Eclipse will impact solar energy generation across North America, with the California ISO region being significantly impacted. The California ISO anticipates a peak drop of 6GW during today's solar eclipse and is prepared to manage the temporary drop in solar production which will last roughly 3 hours. CAISO has leveraged data collected during a solar eclipse in Germany in 2015, a country where total nominal PV power installed is an incredible 41 GW!

In Ontario, IESO has provided a useful graph to illustrate the anticipated impact on demand as a result of reduced solar generation and also increased lighting loads:

Figure       SEQ Figure \* ARABIC
   1      - Estimated Demand increase on August 21 due to Solar Eclipse, compared against typical sunny demand day. Source:  Independent Electricity System Operator

Figure 1- Estimated Demand increase on August 21 due to Solar Eclipse, compared against typical sunny demand day. Source: Independent Electricity System Operator

While we are looking forward to witnessing this rare event, it is important to follow the safety guidelines  and recommended practices when viewing the solar eclipse. We have posted a few helpful links below to help our fellow solar nerds:

Eclipse Safety

Don't Let an Image of the Eclipse be your Phone's Last

 

PV Asset Performance in a Year of Record Rainfall

While flooding the shorelines of many lakes and rivers and keeping scores of people cooped up indoors, this uncharacteristically wet summer has also put a damper on the cash flows of solar asset owners across Ontario.  In what Environment Canada has dubbed the “Year of the Big Wet”, rain and clouds across the province have led to global horizontal irradiance (GHI) for the region tracking well below average, as seen in Figure 1. GHI is the strongest factor in the eventual energy output of a solar PV asset, and as such is directly correlated to revenue from a site. Solar PV asset owners that have relied on long-term weather averages alone to make revenue predictions have had a bumpy ride this year, but it’s so far smooth sailing for those that properly accounted for solar resource variability when planning and financing their projects.

Figure          SEQ
Figure \* ARABIC     1      : 25 year average of CWEEDS GHI values (with 1 standard deviation) for Ottawa, compared with Environment Canada measured GHI for 2016/2017

Figure 1: 25 year average of CWEEDS GHI values (with 1 standard deviation) for Ottawa, compared with Environment Canada measured GHI for 2016/2017

First, a primer on the use of exceedance probabilities in production modelling. An exceedance probability is the probability that an event will meet or exceed a given value. In the field of solar PV asset performance modeling, commonly referenced exceedance probabilities are P50 and P90. The values associated with these probabilities are the energy production levels that will be exceeded 50% and 90% of the time respectively. P50 and P90 analyses are typically performed on an annual basis. Think of a P50 as the amount of revenue a project will have made by the end of its lifetime.  Some years will be bad, some years will be great, but they will all average out eventually.  A P90 will help hedge the risk of bad years negatively impacting your operations.

             Figure 2 – P50 and P90 exceedance probabilities displayed on a normal distribution curve.

             Figure 2 – P50 and P90 exceedance probabilities displayed on a normal distribution curve.

The area to the right of the P90 value in Figure 2 represents 90% of the GHI values one would expect to observe in a given year.   

In the context of GHI, a P50 and a P90 value would be the GHI that would be exceeded 50% and 90% of the time.  A P90 value will always be lower than a P50 value.  While the concept between the two values is the same, their determinations require different approaches.

At the foundation of any solar PV asset production forecast, is a meteorological dataset.  P50 values for GHI are readily available as they are sourced from the most prevalent meteorological datasets, such as a Typical Meteorological Year (TMY). A TMY weather file uses decades worth of data to produce a representative single year’s worth of weather data, which is in essence a P50.  A P50 value is appropriate when predicting the energy output of a project over a sufficiently long timespan, where the year to year weather variability cancels out.

In situations requiring predictable cash flows, relying on a P50 alone is a risky proposition. For example, to adequately service debt, or to fund development of new assets. A P50 would overpredict revenue during low GHI periods, resulting in tighter operating margins. In locations where there is a large deviation from average GHI (think areas with frequent storms and high atmospheric moisture content) the production could be drastically different from the average. For these situations, a P90 analysis is the right tool for the job.

A P90 value is created by understanding the year-to-year variance in a collection of annual weather files. This usually requires access to several years worth of data, to ensure that an accurate variance and average are established. Once the variance of the dataset is known, a statistical analysis is performed yielding a P90 value.

The Canadian Weather Energy and Engineering Dataset (CWEEDS) is an example of a dataset used for P90 analyses. The dataset includes 492 Canadian locations with at least 10 years of data.

ARI has assessed the GHI data seen in Figure 1 to determine where the past year of solar irradiance in Ottawa sits relative to the P90 threshold, see Figure 3.

Figure 3 – Global Horizontal Irradiance for Ottawa. P90 value and August 2016-July 2017 average have been overlaid.

Figure 3 – Global Horizontal Irradiance for Ottawa. P90 value and August 2016-July 2017 average have been overlaid.

By noting that the 2016/2017 average GHI exceeds the P90 GHI we can determine that the low irradiance this summer is within the P90 variance of the CWEEDS data for Ottawa.  It is worth mentioning that this average falls below the P50 by 4.6%. This means that a revenue stream approximated with a P90 evaluation should be in good shape for the past year of operation. This longer view of the past year of operation helps give perspective on poor Q2 2017 GHI, which has been 13% below P50 for Ottawa and similar across the province. 

Performing a P90, or even a P95 evaluation, is frequently recommended and is often a requirement of take-out financers throughout the industry. Apricity Renewables has a strong foundation when it comes to translating weather variability into actionable and bankable information. Combined with a thorough understanding of other modelling variabilities, we aim to give asset owners a clearer picture of the financial viability of their systems over the entire project lifetime. Contact us here to find out how we can add a new level of confidence to your next solar project.

DISCLAIMER: All data and information provided on this blog is for informational purposes only. 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.

Ontario's Many Solar Noons

During our previous exploration of optimal array positioning for TOU markets, the ARI team was struck by another interesting element of solar integration into the Ontario electricity grid. The observation stemmed from the fact that our province spans nearly 1700km from east to west, and largely has the same time zone: solar noon in Eastern Ontario occurs nearly a clock-hour ahead of solar noon in Western Ontario.

With this significant temporal separation in solar noon, solar systems at opposite ends of the province will have a production offset throughout the day, as demonstrated by two identical but geographically separate systems modeled here:

Production of two identical systems on a clear sky day in separate locations (east of Ottawa, Thunder Bay)

Production of two identical systems on a clear sky day in separate locations (east of Ottawa, Thunder Bay)

This leads to an interesting advantage for large, Class A consumers in western Ontario who wish to avoid Global Adjustment (GA) charges through on-site generation with solar. Historical IESO data indicates that the Ontario demand peaks that drive the GA price usually occur in the late summer, around 5-6pm EST. The geographic production offset means that, at this time, an identical site in Thunder Bay would be producing as an Eastern Ontario site had been between 4-5pm. By no means is this the optimal time for production, but relative to each other a Western system would be producing nearly 170% more than the Eastern system. By the same logic, optimized systems with azimuths biased for afternoon production would fare better in Western locations.

The design and analysis surrounding a system built for reducing GA charges is not limited to this one factor. Many others considerations exist, chief among them is the probability of good levels of production coinciding with the small window of time that GA charges are incurred. A weather year such as the one the Eastern seaboard has had thus far in 2017 could give a system owner cause for worry. This is why ARI works with clients to evaluate production variability and the impacts this can have on system design, project financing, and the intended goals of the project. Watch for a future blog post on some of these considerations in the coming weeks.

DISCLAIMER: All data and information provided on this blog is for informational purposes only. 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.

 

 

Optimizing for Ontario: getting the most out of net-metered systems

As the price of solar PV modules continues to fall, fast and cost effective design optimization is becoming an increasingly critical tool for lowering overall system costs and maximizing project yields. Many of the latest modelling tools available to solar system designers allow for runs of parametric studies, which can quickly demonstrate the relative impact of changing system variables, such as panel tilt, row spacing, or array azimuth.

Design optimization of PV systems in Ontario will become ever more important as the FIT program winds down. Apricity expects the Ontario net-metering program to become an increasingly important platform that connects distributed PV systems to the grid. Gone will be the days of above retail price fixed-rate contracts that place no importance on when your power is generated. Under the present FIT program, designers have typically maximized yield by facing panels due south, and could care less about matching array output to building load or grid peak demand. But the success of a net-metered project is highly dependent on these factors! Matching production to periods of high personal consumption and/or market price of electricity is essential. As can be seen in the figure below, shifting the array azimuth westward can better align peak production with peak consumption:

A temporal comparison of power production from three PV arrays with different orientations (all 18 degree tilt), and a typical residential load profile (July).     

A temporal comparison of power production from three PV arrays with different orientations (all 18 degree tilt), and a typical residential load profile (July).

 

As margins will be tight on early net-metered projects, design optimization will play a critical role in helping designers push system performance to the limit. The advent of Time-of-Use (TOU) rate structures has demonstrated the power of design optimization. In the past few years we have begun to hear of designs in TOU jurisdictions deviate away from what used to be optimal array orientation: due south. Arrays have become slightly westward facing, aimed at capturing more afternoon sun and producing electricity when market demand (and retail price) for electricity is higher. Ontario has recently adopted a time-of use billing system as well. Will we also see Ontario designs begin to shift their array azimuths westward?

The answer to this question is, of course, an optimization problem. A modelling tool (such as NREL's SAM) is capable of evaluating multiple system designs in comparison to various TOU rate structures. In Ontario the TOU structure for residential and small business consumers is as follows:

Ontario TOU rate structure as laid out by the IESO

Ontario TOU rate structure as laid out by the IESO

 

Summer rates peak from 11am-5pm, and winter rates peak twice between 7am-11am and 5pm-7pm. The summer peak rate especially is seen to be out of sync with when solar noon occurs in July (1:23pm). Combine this fact with the knowledge that residential consumption peaks later in the day during the summer and one would expect a westward shift to benefit a net-metered project in Ontario, right? Well, the models indicate otherwise:

Annual Electricity Savings for a 8.5kW residential solar system at different azimuth angles. Note that this analysis assumes a home with a large enough load to avoid credit expiration.

Annual Electricity Savings for a 8.5kW residential solar system at different azimuth angles. Note that this analysis assumes a home with a large enough load to avoid credit expiration.

 

According to the quick parametric study, there is no incentive under the current Ontario TOU structure to orient arrays towards the west. In fact, even with the off-peak rate reduced by 30%, and the peak rate increased by 30%, there still is no advantage. With the current rate structure in Ontario it would appear the designers have no reason to center production later in the afternoon. It just doesn’t make financial sense!

Ongoing review and feedback of Ontario’s LTEP should consider how rate structures can support increased distributed generation that more effectively helps reduce peak demand. This discussion needs to also consider how grid peaks will shift as more distributed generation gets added, and as consumption patterns change due to increased market penetration of electric vehicles, the advent of the connected home, and the decarbonisation of home space heating.

This analysis demonstrates the power modelling tools have to correct what our intuition might get wrong. At Apricity, our expertise in advanced modelling tools allows us to create site specific models that address: the accuracy of solar resource data, uncertainties surrounding load profiles, and the impacts of snow losses in Canadian climates. Managing these factors requires the use of professional tools and site specific data. Apricity is committed and excited to combine our expertise with the most robust data sources possible to turn future solar projects from a ‘No’ to a ‘No-brainer’.

DISCLAIMER: All data and information provided on this blog is for informational purposes only. 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.

Investing in the past in an age of disruption

I've had a lot of questions from friends, family members, and colleagues not connected with the renewable energy industry on what I thought of the Ontario government's recent decision to effectively cancel the Large Renewable Procurement program that was underway until late September of this year.

I've put my thoughts down on paper, as a kick-off to the Apricity Renewables Inc. blog where our team will be posting content related to the renewable energy industry on a regular basis.

We hope this blog provides an interesting platform to share interesting technical insights, as well as to provide engaging commentary on market trends, policy, and new business models in the exciting and rapidly growing renewable energy industry.

Check out my post at the following link. 

-Nate Preston, M.ASc