NOx Emissions from Stationary Combustion Turbines MOECC vs. ECCC

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ORTECH reviewed the recent changes to the Stationary Combustion Turbine regulations and compared the differences between the Ontario Ministry of Environment and Climate Change ("MOECC") and Environment and Climate Change Canada ("ECCC").  We noted that some facilities might be compliant on a provincial level but not federally.  This posting will help to compare the two regulations. 

ECCC has updated its NOx emission requirements for new natural gas–fuelled stationary combustion turbines with the publication of Guidelines for the Reduction of Nitrogen Oxide Emissions from Natural Gas–fuelled Stationary Combustion Turbines in November 2017. The new Guidelines introduce a NOx emission limit that is up to 50% more stringent than emission limits set out in the National Emission Guidelines for Stationary Combustion Turbines published in 1992. The ECCC suggests various regulatory authorities use the Guidelines as a starting point for NOx from natural gas–fuelled stationary combustion turbines.

The current MOECC policy on emission requirements for new stationary combustion turbines is Guideline A-5 Atmospheric Emissions from Stationary Combustion Turbines published in March 1994. ORTECH compared the differences between the new ECCC guidelines and the current MOECC guidelines. We noted that due to the new, more stringent federal requirements, some facilities may be compliant on a provincial level but not federally. This posting will help to compare the two policies.

The MOECC policy (Guideline A-5 Atmospheric Emissions from Stationary Combustion Turbines) is located here and the ECCC policy (Guidelines for the Reduction of Nitrogen Oxide Emissions from Natural Gas–fuelled Stationary Combustion Turbines) is located here.


The following table presents a side by side comparison of the scope of both Guidelines, with differences highlighted.


NOx Emission Limits

The following table presents a side by side comparison of the NOx emission limits of both Guidelines.


Testing and Monitoring

The following table presents a side by side comparsion of the scope of the testing and monitoring requirements of both Guidelines, with differences highlighted.


In addition to the testing and monitoring requirements listed in the table above, the MOECC Guideline states that a verification of the average operating thermal efficiency of a Combustion Turbine should be conducted whenever there is source testing or in the case of units equipped with CEM devices initially and thereafter every 2 calendar years. The ECCC guideline has no requirement for verification of thermal efficiency.

If you have any questions about this post, please reach to Giulia Celli at

Ontario Cap and Trade Update

A decision has been made to proceed with amendments to the greenhouse gas cap and trade program, which include changes to the:

1.      Cap and Trade Program Regulation (O. Reg. 144/16)

2.      Methodology for Distribution of Ontario Emission Allowances Free of Charge

3.      Quantification, Reporting and Verification of Greenhouse Gas Emissions Regulation (O. Reg. 143/16)

Cannabis Industry and Odour Regulations

At this point, air quality and related permitting regulations in Ontario and the rest of Canada have not been well established for the Cannabis industry but that should not stop the industry from moving forward on anticipated air quality concerns such as odour issues.    Below is some information to consider as you prepare to permit a new cannabis facility which may also be relevant to existing facilities.

One potential path that  Ontario could take is found in  Regulation 1/17 of the Environmental Protection Act which allows many low risk facilities to register and operate under the Environmental Activity and Sector Registry (“EASR”) instead of the more traditional Environmental Compliance Approval (“ECA”) process.  The EASR process is intended to be a more simplified and timely permitting process.  Facilities which register under the EASR must prepare an Emission Summary and Dispersion Modelling (ESDM) Report as well as a Noise Report and an Odour Screening Report.

An Odour Screening Report requires determination of the primary North American Industry Classification System (“NAICS”) code for the facility.  For a Licensed Producer (“LP”), the applicable NAICS code is likely to be 325411 “Medicinal chemicals, uncompounded, manufacturing” or 424210 “Botanical drugs and herbs merchant wholesalers”.  The next step in the odour screening process is to calculate the setback distance from the source of odour emissions to the closest point of odour reception beyond the facility property. This distance is compared with minimum setback distances for specific NAICS codes.  Although the above NAICS codes relevant to cannabis production are not currently included in the screening process, it is possible that regulators will create such set back distances in the coming months.  The screening process defines many types of odour receptors but generally includes places where the public live, work, worship, visit or may otherwise be present. 

A Best Management Practices Plan (“BMPP”) is required if the Odour Screening Report shows that there is insufficient setback distance between an odour emission source and the closest point of odour reception.  A BMPP for odour may be required for facilities whose operations are defined by specific NAICS codes. For each source of odour emissions from a facility, including fugitive sources, the BMPP must identify potential reasons why the odour emissions may increase occasionally, odour control measures already existing at the facility and procedures to ensure that the control measures are properly maintained, operated and monitored. The BMPP also requires that additional measures to control odours are identified and a schedule is prepared for their implementation.

For facilities with specific NAICS codes and insufficient setback distances, an Odour Control Report may also be required.  This report must include a list of odour control measures or process changes which are used at similar facilities with the same NAICS code in Ontario or elsewhere, determine which of those measures are technically applicable to the applicants facility and, if necessary, explain why the list of measures or changes may not be applicable for reducing or eliminating odour emissions. 

The path that regulators will eventually take to address air quality and odour emissions from the cannabis industry is evolving.  In addition to municipalities managing these issues through zoning and bylaws tools, it is still to be seen if and to what extent environmental regulators will engage and whether existing permitting tools such as the EASR process will apply.  We do know that historically odours has been a source of complaints in many communities and it is important for cannabis producers to be viewed as a good corporate citizen.  Whether it is the federal, provincial or municipal government, odour concerns will be part of the permitting process. 

ORTECH has been involved in odour assessments for a broad range of industrial, agricultural and other facilities for over forty years and is experienced in the operation and performance of air pollution control equipment for many different NAICS code operations.   



Why determining Replacement Costs for your Renewable Energy facility is important?


As in your personal life with your home or car, your renewable energy facility typically needs to renew its insurance annually.  This might seem routine but the dynamic nature of costs associated with various renewable energy technologies should be considered.  This process is not just about getting the right coverage and affordable premiums but ensuring that should you have to make a claim, you have the correct coverage, limits and information at hand.  Factors to consider when determining the current replacement costs for your renewable energy facility are discussed below.

It is recommended that facility owners review the project as installed to determine the replacement cost based on current industry costs for components, labour, consider any changes in bylaws and debris removal/disposal. An estimate of the removal and disposal costs of the old facility is often overlooked and can run up to 25% of the replacement cost in remote places where transportation costs are much higher.

Some factors to consider the next time you renew insurance for your renewable energy facility:

  1. Is the replacement cost valid?  Do you regularly go to market to obtain more accurate information on the replacement costs as well as removal/disposal costs?  The solar and wind industry has seen a significant downward trend in construction costs while waste removal and disposal costs have been less predictable.  Replacement costs will affect insurance premiums and having current and accurate replacement costs may enhance your ability to collect full funds in the event of a claim and possibly avoid co-insurance penalties. Typically this is done formally every 3 years, similarly to the real estate industry.
  2. Following a loss, who owns the damaged equipment during the claims process?  This is an important question to answer.  The system owner may believe they maintain ownership but under the salvage clause within industry standard insurance policies it is the insurance carrier who has control if a claim is paid as they get the funds from the sale of any scrap equipment to recoup some of the losses incurred.   The insurance carrier may share the income associated with the sale of scrap equipment if the owner can do the work.  It is good to have a clear understanding of control over damaged equipment, before you arrange to dispose of it following a loss. Historically, insurers have seen little value in the scrap associated with solar installations as it tends to cost approximately 15% of the overall replacement cost to dispose of the system with not much salvaged.
  3. There are advantages to using an independent third party tp assess your replacement costs that is recognized by your insurer and broker.  Typical steps a vendor should use to conduct a thorough review of replacement costs include: 
  • Review of current installation, which may include a site visit,
  • Determine what comparable components would cost in the current market,
  • Estimate the level of effort for removal and the costs of disposal, and
  • Estimate the cost and timeframe for installing a new renewable energy facility.

In the end, getting a better handle on current replacement costs for your renewable energy facility might help reduce premiums at the time of renewal **Side note, check with your lender before reducing replacement costs to ensure compliance with lending agreements.  At the very least, in the event of a claim you will have a better understanding of costs supported by an independent assessment to support your position.  This forward planning will make your life easier should a disaster or other situation out of your control lead to an insurance claim. 

Time to Plan your Path to Compliance with MSAPR – Part 2: Engines

The Multi-Sector Air Pollutants Regulations (MSAPR) was registered by Environment and Climate Change Canada (ECCC) in June 2016 with the objective to achieve consistent Canada-wide performance standards for certain industrial facilities and equipment.   Stationary Spark Ignition Engines are one type of equipment targeted under the MSAPR, specifically Part 2.  MSAPR establishes a process for registering, monitoring, testing and reporting of oxides of nitrogen (NOx) emissions and provides NOx emission intensity limits (g NOx / kWh) which are phased in over time.

Part 2 applies to stationary spark ignition engines that meet the definition in MSAPR that are “pre-existing” (i.e. manufactured, owned or operated before September 2016), are at an “oil and gas facility” (other than an asphalt refinery) as defined, are > 250 kilowatt (kW) rated output capacity (break power) and that combust gaseous fossil fuel.  Part 2 also applies to stationary spark ignition engines that are “modern” (meaning they are not “pre-existing”), are at one (1) of thirteen (13) regulated facilities as defined, are > 75 kW (for an engine deemed “Regular” use) or > 100 kW (for an engine deemed “Low” use) and that combust gaseous fossil fuel.  

Engines that are operated at least one (1) hour per year are considered “Regular” use unless specifically deemed to be “Low” use.  One of the eligibility criteria for the election of an engine as "Low” use is if it is operated ≤ 1314 hrs in 3 year period (i.e. ≤ 5% of the time). 
Part 2 sets out nitrogen oxides (NOx) emission intensity limits (g NOx/kWh) as well as compliance testing, operation and maintenance and reporting requirements.

Impacted stationary spark ignition engines are to be registered by January 1, 2019.  For “pre-existing” and “Regular” use engines, the first phase NOx emission intensity limits apply January 1, 2021 and the second phase limits apply January 1, 2026.  There are no limits for “pre-existing” and “Low” use engines under MSAPR.  The responsible person (owner or operator) can choose a Flat Limit Approach or a Yearly Average Approach when assessing a fleet of “pre-existing” and “Regular” use engines.  The approach can impact the timing or whether mitigation measures are needed at all to meet future NOx emission intensity limits.

For “modern” and “Regular” or “Low” use engines, the NOx emission intensity limit of 2.7 g NOx/kWh applies starting July 1, 2017.  The Flat Limit Approach is the only option available for assessing a fleet of “modern” engines.  

At the time the future limits apply, compliance must be demonstrated by conducting an initial performance test and reporting with the frequency of ongoing performance tests or simplified emission checks impacted by the output capacity and type of engine (rich burn versus lean burn).

What are the Next Steps on the Path to Compliance?:

Now is the time to formulate a Compliance Plan for MSAPR Part 2.  A lower NOx emission intensity limit could apply as early as 2021 for “pre-existing” engines.   Projects to lower the NOx emission intensity can be capital intensive and time consuming so forward planning is highly recommended.  Suggested next steps in the development of a Compliance Plan should consider:

  • A detailed analysis of facilities to confirm pre-existing engines are indeed subject to MSAPR Part 2 as well as historical and expected future time of use as well as availability/suitability of site conditions for future performance testing;
  • A detailed analysis of timelines and mitigation or other measures required to ensure compliance including possible implications of choosing the Flat Limit Approach versus the Yearly Average Approach for your fleet of pre-existing engines;
  • Baseline emission testing.  Although not specifically required in advance of registration, there are distinct advantages to confirming the NOx emission intensity of pre-existing engines using actual testing as opposed to estimates especially if mitigation may be required to meet the future limits; and
  • An assessment of opportunities for synergies or efficiencies of the activities required in support of the MSAPR and other compliance activities such as those required in support of a provincial environmental permit.

For more information on ORTECH MSAPR service offerings, click here.

Is the time right for Solar?

“I do not believe the PRICE of Electricity, in Ontario, will stay the same or drop” 
If you agree with this statement read on.

6 FACTORS TO CONSIDER for Installing a solar system for your manufacturing plant or warehouse! Number 6 talks about FREE Money.


1.      The Price of Electricity will rise.

a.      Ontario’s electricity prices have increased by 71 percent from 2008 to 2016, far outpacing electricity price growth in other provinces, income, and inflation* Fraser Institute. The bigger concern is the price of electricity at the whim of the government, and under the current administration, we have seen the cost of electricity explode and be capped.  Politics rules the price of electricity from the grid, which means it is unpredictable.

b.      Another point to consider: in the next ten years, a significant amount of our nuclear generation is going to be shutdown or put offline for refurbished. This means a large amount of our energy load must be replaced.  That can have a significant impact on electricity costs for everybody.

2.      The Cost of Solar will continue to drop.  Adjusting for inflation, it cost $96 per watt for a solar module in the mid-1970s. Process improvements and a very large boost in production have brought that figure down to 68 cents per watt in February 2016, according to data from Bloomberg New Energy Finance. Palo Alto California signed a wholesale purchase agreement in 2016 that secured solar power for 3.7 cents per kilowatt-hour. Moreover, in sunny Dubai large-scale solar generated electricity sold in 2016 for just 2.99 cents per kilowatt-hour -- "competitive with any form of fossil-based electricity — and cheaper than most. *

However, since you are reading this from Ontario, here is some local knowledge. Note:Data from ORTECH’s due diligence engagements.

3.      The nexus between the price of electricity and cost of solar (“Grid Parity”) is almost here, without any incentives.   Grid parity occurs when an alternative energy source can generate power at a levelized cost of electricity (LCOE) that is less than or equal to the price of purchasing power from the electricity grid. The term is most commonly used when discussing renewable energy sources, notably solar power nd wind power. Grid parity depends upon whether you are calculating from the point of view of a utility or of a retail consumer. Reaching grid parity is considered to be the point at which an energy source becomes a contender for widespread development without subsidies or government support. It is widely believed that a wholesale shift in generation to these forms of energy will take place when they reach grid parity. Ontario is not at Grid Party for solar, yet, but its will be in the next couple of years.  If you continue reading, #6 makes it a real possibility.

4.      The Ontario government has mandated that electrical providers, Local Distribution Companies (“LDC”) allow their customers to offset their electricity use by generating renewable energy.  This Ontario regulation has been around since 2005, its just now that a conversation can be had with regards to real economic benefits. Cost reduction or avoidance is the primary purpose of this program.

5.      A lesser benefit from the financial aspect is the reputational boost. By using renewable energy to generate electricity without a contract, your firm will be seen by your investors, clients, employees and neighbours in a positive light.  Other reasons include the following:

  • Little to no global warming emissions,
  • Improved public health and environmental quality,
  • A vast and inexhaustible energy supply,
  • Jobs and other economic benefits,
  • Stable energy prices, and
  • A more reliable and resilient energy system.

Lastly…..FREE MONEY!

6.      The Canadian Manufacturer and Exporters Association (“CME”) has a Smart Green program (“SGP”) providing incentives at many steps through this process. There is up to $500,000 in incentive funds available for manufacturing facilities to bolster the return on investment (“ROI”).

So, what is the Solution? Answer:  Solar Net Metering:

Net metering is a billing mechanism that pays solar energy system owners for the electricity they add to the grid. In its simplest form, a net metering customer will generate their own solar electricity during the day, use what it needs to meet the requirements of the home (or other type of building), injects the rest into the electricity grid, and consumes from the grid when the solar is unavailable. The customer is then only billed for their net electricity use. If they generate more than they use in a month, they receive a credit to apply against next month’s bill. If the solar system generates less than the customer uses, they will see a charge on their bill.

How to get started?

First off, find a consultant that has experience with the Canadian Manufacturers and Exporter (“CME”) Smart Green Program (“SPG”).  This consultant should also be versed in Incentive Management and Solar consulting.   This is where you get to apply for up to $500,000 in incentive money.  You should be able to go through the entire process without any outlay of expense until you have to start building your solar facility.  There are many “Off-ramps” to allow you to stop the process.  Its very “risk-free” in its approach.  That should help with moving forward.

This section is designed to outline each step in the process, so it is clear and concise. Where there is an incentive available, your consultant should apply for and secure the incentive before any work is started.

The following section will outline the entire process.

1.     Incentive Management:  Use an experienced incentive management consultant to manage all the facets of the Smart Green program.  The upfront process will be to collect data on your operations and submit applications for funds at three different phases listed below.  It should be noted that at each stage,  the Client can choose to stop the process.  The graphic to the right provides a visual of the process.  As part of the intake process, the Client should be willing to provide:

  • Detailed Company Information,
  • Financial Information,
  • Building Information,
  • Utility Statements: 1-3 Years of Electricity and Gas bills,
  • Corporate Signing officer information.

2.     Incentive Application for Walk-through Assessment: Your consultant should facilitate applying for the incentive for this step with CME SGP process.

3.     Walk-through Assessment:  Once the incentive is approved, your consultant will conduct a walk-through assessment to determine the feasibility of installing a solar facility on your rooftop.  This assessment cost will be reimbursed by the Smart Green program.  The Walk-through will include:

  • Introduction,
  • Company Overview,
  • Baseline GHG Emissions Overview,
  • Walk-through Notes and Observations, and
  • Potential SMART Green Project (Solar Project).

4.     Incentive Application for Technical Assessment: Your consultant should facilitate applying for the incentive for this step with CME SGP process.

5.     Technical Assessment: Once the incentive is approved, your consultant should conduct the technical assessment.  This will provide you with the information to make your decision to move forward.  If you hire a competent consultant that you trust, it should be straightforward.  You should receive a technical assessment report containing the following items;

  • Facility and Process Background,
  • Facility Baseline GHG Emissions,
  • Process Baseline GHG Emissions, if needed,
  • Description of Energy Efficiency/GHG Reduction Measure (Solar Project),
  • Expected Post-Project GHG Emissions,
  • Capital Costs and Other Eligible Expenses,
  • Additional Benefits, and
  • Conclusion.

6.     Incentive Application for Capital Funding for Project. Your consultant applies for the Capital Funding incentive for this step with CME SPG process. The detailed assessment will include:

  • Introduction,
  • Facility and Process Background,
  • Facility Baseline GHG Emissions,
  • Process Baseline GHG Emissions, if needed,
  • Description of Energy Efficiency/GHG Reduction Measure (Solar Project),
  • Expected Post-Project GHG Emissions,
  • Capital Costs and Other Eligible Expenses,
  • Additional Benefits, and
  • Conclusion.


This is the point where you need to decide to spend money.


7.     Engineer, Procurement Construction process:  After the Capital Funding is approved, you should go to the market to find a vendor that can develop a comprehensive plan to implement the solar facility.  This will include all the engineering design, electrical connections applications, equipment procurement, installation and commission of facility and provide ongoing operations and maintenance of the facility.


Time to Plan your Path to Compliance with MSAPR – Part 1: Boilers and Heaters


The Multi-Sector Air Pollutants Regulations (MSAPR) was registered by Environment and Climate Change Canada (ECCC) in June 2016 with the objective to achieve consistent Canada-wide performance standards for certain industrial facilities and equipment.   Boilers and heaters are one type of equipment targeted under the MSAPR, specifically Part 1.  MSAPR establishes a process for registering, monitoring, testing and reporting of oxides of nitrogen (NOx) emissions and provides NOx emission intensity limits (g NOx / GJ) which are phased in over time.

Part 1 applies to boilers and heaters that meet the definition in MSAPR, are at regulated industrial sectors including oil and gas facilities, are > 10.5 gigajoules per hour (GJ/hr) of input capacity and that combust gaseous fossil fuel. This includes equipment that is pre-existing, transitional, or modern. Part 1 sets out nitrogen oxides (NOX) emission intensity limits (g NOx/GJ) as well as compliance testing, operation and maintenance and reporting requirements.

The requirements and timelines that apply to a boiler or heater depend on its commissioning date (pre-existing, transitional, or modern), its type of fuel (natural gas or alternative gaseous fossil fuel), capacity, and for pre-existing equipment, one (1) of three (3) classes based on NOX emission intensity, specifically:

  • Class 40: ≤ 70 g NOx/GJ – no specific future NOx emission intensity limit will apply
  • Class 70: > 70 but ≤ 80 g NOx/GJ – generally a future limit of 26 g NOx/GJ will apply starting 2036*
  • Class 80: > 80 g NOx/GJ – generally a future limit of 26 g NOx/GJ will apply starting 2026*

Note: * certain actions including Major Modifications may trigger a speed-up, there is also the potential for some relief (i.e. slightly higher future limit) provided specific documentation is submitted

The boiler or heater classification can be determined by a number of options including but not limited to stack testing or an arbitrary election as Class 80.  The first compliance benchmark of Part 1 was to submit on-line a classification report for pre-existing boilers and heaters by June 17, 2017.  At the time the future limits apply, compliance must be demonstrated by conducting an initial stack test and reporting and ongoing annual compliance stack testing and reporting requirements may also apply.

Modern and transitional boilers and heaters are subjected to emission intensity limits of 16-40 g NOx/GJ depending on circumstance and equipment type. Modern and transitional equipment must have an initial stack test on or after the date on which it begins to combust gaseous fossil fuel and before the earlier of the passing of six (6) months or May 25 of the following year. Ongoing annual compliance stack testing requirements may also apply.

What are the Next Steps on the Path to Compliance?:

Now is the time to formulate a Compliance Plan for MSAPR Part 1.  A lower NOx emission intensity limit could apply in 2026 or earlier if Major Modifications are planned.   Projects to lower the NOx emission intensity can be capital intensive and time consuming so forward planning is highly recommended.  Suggested next steps in the development of a Compliance Plan should consider:

  • A detailed analysis of facilities to confirm pre-existing boilers or heaters are indeed subject to MSAPR Part 1 as well as availability/suitability of site conditions for future stack testing;
  • A detailed analysis of timelines and mitigation or other measures required to ensure compliance including possible implications and actions required in the event of future Trigger Events such as changes in fuel or Major Modifications such as replacement of burners;
  • An assessment of opportunities for synergies or efficiencies of the activities required in support of the MSAPR and other compliance activities such as those required in support of a provincial environmental permit;  and   
  • Facilities which have chosen to arbitrarily elect pre-existing boilers or heaters as Class 80 have an opportunity to reclassify by conducting stack testing or by means of a Continuous Emission Monitoring (CEM) test before December 2022.  There are distinct advantages should this reclassification testing confirm a class lower than Class 80 (i.e. Class 70 would have 10 more years to meet the future limit and Class 40 has no specific limit).   Reclassification testing should be conducted sooner rather than waiting until 2022 as should the testing confirm that the boiler or heater is indeed Class 80, this would provide only approximately four (4) years (from 2022 to 2026) to implement a strategy to meet the future lower NOx emission intensity limit.

Look for the next ORTECH newsletter which will discuss MSAPR Part 2 – Spark Ignition Engines.         

For more information on ORTECH MSAPR service offerings, click here.
















What is the difference between an EASR and an ECA?


Your business must have an environmental approval from the Ministry of Environment and Climate Change (“MOECC”), if it releases pollutants into the air, land or water or stores, transports or disposes of waste. The aim of environmental approvals is to set rules for these activities in a way that helps protect the natural environment.  There are a number of approvals to assist you with your path to compliance.  Depending on the nature of your business activities, you will apply or register for one of the following:

  • Environmental Compliance Approval (ECA)
  • Environmental Activity and Sector Registry (EASR)
  • Renewable Energy Approval

The first two compliance tools result in the same outcome - an approval to discharge contaminants into the environment, which naturally leads us to the question:

What is the difference between an EASR and an ECA?

At a high level, an EASR is associated with virtually instantaneous approval and less ongoing annual requirements as compared to the traditional ECA.  But let’s back up and define each compliance path.  Environmental Compliance Approval (“ECA”) and Environmental Activity and Sector Registry (“EASR”), these hyperlinks will take you directly to the MOECC website specific to each path to compliance. Determining which compliance path is right for you is dependent on the complexity and uniqueness of the operation.  For more complicated operations, with higher potential for environmental impacts, an ECA is required and the EASR is used for more common activities or operations with less potential impact.  The following helps define these different levels of complexityoutlined in the regulations.


One of the fastest ways to determine your compliance path is to use the industry NAICS codes.  The default MOECC approach is that all activities and sectors go through the EASR process unless specifically excluded by the Regulation.  The following NAICS codes are specifically excluded from the EASR process:



EASR eligible activities

The MOECC has developed a process to determine those activities suitable for the EASR process; businesses meeting the eligibility requirements are required to register under the EASR process.  The EASR covers activities that are low risk to the environment and human health and use equipment and/or processes that are considered to be “standard” or have known environmental impacts.

Here is a link to the MOECC page with a summary of EASR eligible activities below:

  • automotive refinishing facilities
  • commercial printing facilities – lithographic, screen and digital
  • non-hazardous waste transportation systems (e.g. trucks and other motor vehicles, including vans and cars on public roads)
  • small ground-mounted solar facilities
  • facilities processing end-of-life vehicles
  • specific construction-related water-taking activities

What are the steps  for an ECA application?

  1. Evaluate the pros and cons of an ECA with Limited Operational Flexibility,
  2. Compile information required to complete the application,
  3. Schedule a consultant to complete a site visit; if required,
  4. Review your current Emission Summary and Dispersion Modelling (ESDM) Report, if available, and update to include any changes,
  5. Complete dispersion modelling and compare results to MOECC Point-of-Impingement Limits,
  6. Complete primary or secondary noise screening and coordinate an Acoustic Assessment Report (AAR), if required,
  7. Assemble the ECA application, including the ESDM Report, required MOECC forms and supporting information and pay the applicable fee.
  8. Regularly follow up with the MOECC to check the status of the application;
  9. Assist in answering any questions the MOECC review engineer may have; and
  10. Review the draft and final ECA.

How to apply for an ECA?

  1. Use the checklist for technical requirements for a complete ECA submission,
  2. Read the guide to applying for an ECA or hire an air quality consultant familiar with the process,
  3. Complete the ECA application form,
  4. Make sure you include copies of all required supporting documents, and
  5. Submit your application.

What are the steps for the EASR process?

  1. Assess all emissions from the facility.
  2. Assess all substances that have no MOECC limits and conduct a toxicology assessment, if needed.
  3. Assess noise and odour emissions.
  4. Develop and implement noise and odour mitigation control plans (i.e. odour control reports), if required.
  5. Develop maintenance and operational procedures as well as complaints and record management procedures.

How to apply for an EASR?

The applicant must register the activity on the MOECC website, here.  All the information from the ESDM report, odour and noise screenings, toxic substances review must be registered online. Your consultant can help you or you can call the MOECC directly for support.

If you have any questions, please contact ORTECH or visit our pages specific to each compliance path: EASR or ECA application .


    How Does Ontario's Cap and Trade System Affect my Business?

    In conjunction with the Canadian Independent Petroleum Marketers Association during their Canadian Fuel Marketing Conference , Ciara De Jong, Principal Consulting at ORTECH Consulting Inc will be conducting a one hour workshop on How Does Ontario's Cap and Trade System Affect my Business?

    ABSTRACT: Ontario’s first Auction under the Cap-and-Trade program is scheduled for March 22, 2017. The format of the auction has created a high degree of uncertainty amongst participants, not only related to the workings of the auction platform but also regarding the price and quantity to bid.   This workshop will provide a summary of what took place at the March Auction including lessons learned and key developments.  Were auction participants in a “buying mood” or do the results indicate a more of a “wait and see approach”?  Although not intended as auction advice, the workshop will also delve into what your business may consider in moving forward which such topics as reporting and Cap and Trade strategies.

    To register, please click here.

    Kontrol Energy Completes Acquisition of Ortech Consulting Inc.

    TORONTO, Feb. 10, 2017 /CNW/ - Kontrol Energy Corp. (CSE:KNR) (the "Company") announces that it has completed the acquisition of Ortech Consulting Inc. ("ORTECH"). ORTECH is a leading engineering consulting firm specializing in Green House Gas ("GHG") reporting, air quality testing, emission testing and renewable energy/power consulting.

    ORTECH has a 20-year successful operating history and has a stable client base, including some of Canada's largest integrated oil and gas companies. A material portion of ORTECH's annual revenue is from multi-year recurring contracts. For the last fiscal year ending March 31, 2016, ORTECH reported audited gross revenues of $5.3 Million and normalized EBITDA of $940,000.

    "ORTECH is a leader and recognized brand in the Ontario GHG reporting and power generation market," says Paul Ghezzi, CEO of Kontrol Energy. "We are excited about the closing of this acquisition and we look forward to expanding ORTECH's unique services and solutions across Canada. With the recently announced Canadian Federal Government carbon tax, large emitters of GHG will be required to better track and verify their emissions. The ORTECH acquisition provides the Company with a leadership position in a rapidly growing market. Further, the acquisition aligns strategically with our intention to create carbon reduction and monetization programs for our customers," continues Paul Ghezzi.

    The aggregate purchase price for the acquisition is $4.6 Million of which the Company has paid $4.6 Million in cash on closing. No common shares were issued as part of the acquisition. Ten (10%) of the purchase price will be held in escrow and be subject to any post-closing adjustments. In conjunction with the acquisition, the Company has closed on a $4 Million secured bridge loan with the Pinnacle Absolute Return Trust. The bridge loan has a term of 6 months and is secured by the assets of the Company and of ORTECH. It is anticipated that the bridge loan will be replaced by long-term senior secured debt financing over the next 6 months. Darvin Zurfluh, CEO of Pinnacle Absolute Return Trustee Corp., as Trustee of the Pinnacle Absolute Return Trust, says, "We are pleased to have completed a successful financing with Kontrol Energy Corp."

    Following the acquisition the Company anticipates consolidated annual revenues for 2017 will be in the range of $10 to $11 Million and annual EBITDA in the range of $1.3 to $1.5 Million.

    About Kontrol Energy Corp.

    Kontrol Energy Corp. (CSE:KNR) is a leader in energy efficiency solutions and technology. Through a disciplined mergers and acquisition strategy, combined with organic growth, Kontrol Energy Corp. provides market-based energy solutions to our customers designed to reduce their overall cost of energy while providing a corresponding reduction in Green House Gas (GHG) emissions.

    Additional information about Kontrol Energy Corp. can be found on its website at and by reviewing its profile on SEDAR at 

    Neither IIROC nor any stock exchange or other securities regulatory authority accepts responsibility for the adequacy or accuracy of this release.

    Caution Regarding Forward Looking Statements:

    Certain information included in this press release, including information relating to future payments of holdback amounts,  possible future acquisitions, anticipated consolidated revenue and anticipated annual EBITDA; the provision of solutions to customers to reduce overall energy costs and greenhouse gas emissions reductions, carbon reduction and monetization programs, growth strategy, the replacement of the secured bridge loan with long-term senior secured debt financing and other statements that express the expectations of management or estimates of future performance constitute "forward-looking statements". The forward-looking statements in this press release are presented for the purpose of providing information about management's current expectations and plans and such information may not be appropriate for other purposes. The forward-looking statements. Where the Company expresses or implies an expectation or belief as to future events or results, such expectation or belief are based on assumptions made in good faith and believed to have a reasonable basis. Such assumptions include, without limitation, that the ORTECH will be successfully integrated into the Company and that its revenues will be consistent with the Company's expectations, that suitable businesses and technologies for acquisition and/or investment will be available, that such acquisitions and or investment transactions will be concluded, that sufficient capital will be available to the Company, that technology will be as effective as anticipated, that organic growth will occur, that the Company will succeed in obtaining long-term senior secured debt financing, and others. However, forward-looking statements are subject to risks, uncertainties and other factors, which could cause actual results to differ materially from future results expressed, projected or implied by such forward-looking statements. Such risks include, but are not limited to, lack of acquisition and investment opportunities or that such opportunities may not be concluded on reasonable terms, or at all, that sufficient capital and financing cannot be obtained on reasonable terms, or at all, that technologies will not prove as effective as expected that customers and potential customers will not be as accepting of the Company's (including ORTECH's) product and service offering as expected, and government and regulatory factors impacting the energy conservation industry. Accordingly, undue reliance should not be placed on forward-looking statements and the forward-looking statements contained in this press release are expressly qualified in their entirety by this cautionary statement. The forward-looking statements contained herein are made as at the date hereof and the Company does not undertake any obligation to update publicly or revise any such forward-looking statements or any forward-looking statements contained in any other documents whether as a result of new information, future events or otherwise, except as required under applicable securities law.

    SOURCE Kontrol Energy Corp.

    For further information: Paul Ghezzi, CEO,; Kontrol Energy Corp., 5045 Orbitor Drive, Bldg. 9, Suite 401, Mississauga, ON L4W 4Y4, Tel: 905.766.0400, Toll free: 1.844.866.8123

    ORTECH Comments on Long-Term Energy Plan

    ORTECH Comments on Long-Term Energy Plan

    ORTECH Consulting Inc. (ORTECH), renewable energy, energy storage, greenhouse gas (GHG) and air emissions consulting, auditing and testing experts, would like to thank the Ministry for the opportunity to provide our view on the Long-Term Energy Plan (LTEP) and for providing substantive supporting documentation such as the Ontario Planning Outlook (OPO) to allow us to formulate a meaningful response.

    ORTECH commend the government as well as their agencies and their partners in industry in pursuing the goal of a supply of energy that is sustainable both environmentally and economically.  Energy is fundamental to all forms of activity today and many take for granted its reliability and convenience of access.  Energy is the fuel which drives not only our economic activities but also much of what we do in our everyday lives.  A LTEP in today’s changing world must be broad and far reaching, and touch on many different areas.

    The breadth of the LTEP is important for Ontario to continue driving down GHG emissions.  As clearly identified in the Fuels Technical Report (FTR), the GHG emissions associated with electricity have been falling for some time and are now a very small contributor to Ontario’s total GHG emissions.  Electrification of other energy uses such as heating and transportation will allow the use of decarbonized electricity to displace more GHG in these other energy use categories. This represents a new approach to energy planning as previous LTEPs have had a very dominant focus on electricity. Such an approach will require coordinated action from multiple Ministries and agencies.

    ORTECH comments on the LTEP are structured to follow the Discussion Guide and are provided in the order of the subject areas presented in that document.

    Distribution and Grid Modernization

    The global trend towards behind-the-meter generation will have substantial impacts on the utility sector.  With the continually falling cost of photovoltaic solar and the steadily increasing retail cost of electricity, the push to self-generation is constantly increasing.  ORTECH is encouraged to see that the Ministry is embracing these changes with proposed updates to the net metering regulation such as Single Entity Virtual Net Metering, removal of the 500 kW cap, and explicitly acknowledging the role of energy storage in net metering type applications.

    One concern with distributed generation is the phenomenon referred to as the “Utility Death Spiral”.  As rooftop solar reaches grid parity customers begin to switch towards self-generation.  This reduces the amount of energy delivered by the local distribution company (LDC) which is at least partially compensated on a per kWh delivered basis. Rates are often increased to make up for lost revenue, however higher rates only serve to further incentivize self-generation, resulting in a feedback loop or Utility Death Spiral.

    One possible way to avoid the Utility Death Spiral is by having the LDCs play a larger role in distributed generation.  LDC’s understand their customers and dealing with distributed electrical infrastructure is their core business.  They are ideally positioned to facilitate further uptake of distributed generation, increase the penetration rates of clean energy, and alleviate the need to bring power from distant centralized generators to the load centres where it is needed. Powerstream’s award winning Power House pilot program is an example of this and shows how utility-customer partnerships may work in the future.


    Microgrid solutions are not only for remote communities.  Microgrids can operate in parallel with the grid, providing the advantages of resiliency and robust infrastructure.  Combining microgrids with district energy or community energy resources can create strong nodes where energy can be supplied even in extreme circumstances. Many applications demand very high reliability of energy supply resulting in mission critical equipment with high costs for low utilization.  A microgrid approach to these applications can enable those systems to provide other benefits allowing for better use of existing equipment.

    Microgrids can also be used to provide alternate benefits such as improved power quality, load shifting and peak shaving, amongst others.  Using microgrids in this way can provide more reliability than traditional fossil fired back-up generators as microgrid systems will essentially be continuously tested.

    Energy Storage

    Achieving Balance stated that the government was to include energy storage technologies in its procurement process starting with 50 MW and assessing engagement on an ongoing basis.  This was to include: “commissioning an independent study to establish the value of energy storage’s many applications throughout the system; examining the opportunities for net metering and conservation policies to support energy storage; and providing opportunities for storage to be included in large renewable procurements.”

    At the end of 2016, it appears that energy storage procurement started and ended with 50 MW.  The Large Renewable Procurement (LRP) was to have “mechanisms to encourage innovative technologies and approaches, including considering proposals that integrate energy storage with renewable energy generation for upcoming procurement cycles”.  While an on-peak/off-peak pricing mechanism was included in LRP 1, it did little to encourage energy storage integration.  The benefit and capability of energy storage to smooth variable generation as well as provide additional reliability was not valued by the LRP 1 RFP.  The sole mechanism for incorporating energy storage was for power shifting.  However, this one application discounted the benefits provided by energy storage.  As an explanation, the LRP 1 RFP determined the “effective capacity value” of various generation technologies which represented “the amount of capacity that can be counted on at the time of system peak”.  Adding energy storage to a variable generator for the purposes of power shifting would significantly increase this value, but the RFP scoring rubric did not allocate any benefit for this.

    ORTECH would like to commend the Ministry on moving forward with the first 50 MW of procurement.  This program put Ontario at the forefront of the emerging industry of grid scale energy storage and marked the province as a global leader in the space.  However, a lack of additional support for energy storage will pose the risk of being surpassed by other jurisdictions.

    Innovation and Economic Growth

    Start-stop procurements can be quite disruptive to industry.  Gearing up for major RFPs followed by long periods of no activity hinders private sector planning and exacerbates the boom-bust cycle.  The Feed in Tariff (FIT) program is a good example of how programs can operate more smoothly with similar sized procurements that are repeated over short time frames. However, even with FIT procurement, program windows are announced one at a time resulting in considerable uncertainty as to future market opportunities.  Smaller procurements that are repeated more frequently will smooth out the roller-coaster type activity level in the Ontario industry, and greater certainty in future procurements and activity will help the industry develop the right level of capabilities to address needs.

    Climate change is a global concern.  Clear and effective long term programs will allow Ontario industry to refine the expertise to address these challenges providing a basis to assist other jurisdictions reduce their environmental footprint, and to benefit from these export opportunities.  However, a healthy domestic market that supports renewable energy and energy storage industries is required.

    It is generally acknowledged that environmental permitting is slowing down the development of projects.  This year’s Burden Reduction Act introduces the possibility of streamlining the permitting process.  However, it’s not yet clear if this will have appreciable benefit for energy projects. 

    Clean Energy Supply

    The OPO identified potential scenarios where electrical demand is increased.  These are related to electrification and a shift away from fossil fuel usage in transportation and heating.  It is important that additional electricity generated to meet these needs is clean energy otherwise no GHG benefit would realized from electrification.  For example, if higher electrical demand is mostly met by natural gas fired generators, the benefit of displacing natural gas fired heating with electrical heating is diminished.

    Since the Green Energy and Economy Act of 2009 came into effect, Ontario has aggressively pursued renewable energy development resulting in substantial amounts of renewable generation capacity being installed. This domestic demand for wind, solar and other forms of renewable generation allowed a strong industry to develop in the province. With advances in generating technologies and a strong local industry that is ready to deliver projects, Ontario is in a position to build wind and solar projects at competitive rates.

    The LRP 1 (in 2015) procured wind energy for a capacity weighted average of $86 per MWh and solar for $157 per MWh.  These rates are competitive with other generation technologies, with wind being one of the lowest cost forms of generation in the province and solar rapidly closing the gap.  This is supported by the OPO Data Tables which list current technology characteristics and show the range of levelized unit costs of electricity for wind and solar to be cost competitive with all other forms of generation. It should also consider that wind and solar are still experiencing significant cost declines as the technology matures and the industry increases in scale. While Conservation First remains the strongest economic performer in the province, Ontario’s supply of clean energy will be most efficiently procured from wind and solar.


    ORTECH recognizes the importance of the LTEP to the Province of Ontario and thanks the Ministry for the opportunity to provide comments.  ORTECH comments are summarized in pint form below:

    • Have the LDCs play a larger role in distributed generation
    • Combine microgrids with district energy or community energy resources
    • Assess the full value and expand the support for energy storage to ensure Ontario remains at the forefront of this evolving technology
    • Expand clear and consistent procurement programs (e.g. FIT) to ensure market certainty which will lead to the development of the right level of capabilities to address needs
    • Further streamline the environmental permitting process
    • Wind and solar are becoming increasingly more cost competitive and thus represent an opportunity for expanded development while addressing further reductions GHG emissions from the overall energy supply system  

    A strong domestic clean energy industry will allow for GHG reductions beyond our borders through clean energy trade.  Ontario is already a net exporter of electricity and the jurisdictions where our clean electricity is being sold include regions that still rely heavily on coal-fired power plants. While the GHG emissions associated with the electricity used in province is already very low, additional low carbon electricity still has the potential to reduce GHG emissions on a global scale.


    Is Net Metering with Solar PV the RIGHT choice for your company in Ontario?

    Written by Michael Tingle and Ka-Ming Lin

    The answer depends on your view of the trend in future electricity pricing.  If you feel the price of electricity is going to drop or stay the same, this may not be for you.  However, if the price of electricity for Commercial and Industrial (“C&I”) users will continue to rise in the next 5-15 years, net metering with solar photovoltaic (PV) may be of interest.

    Ontario Electricity Prices vs Cost of Solar PV

    This graphic depicts the historic, and forecasted price of electricity versus the install price for a solar PV facility. Although there are many variables, this serves as a reasonable guide.

    Other assumptions considered in the preparation of this graphic are:

    Price of solar based on a typical < 100 kW Feed-in-Tarrif (FIT) rooftop facility,
    Price of solar (forecast) is based on a 4% annual reduction in costs,
    Electricity prices are the time of use (TOU) rates based on 50% on-peak, 30% mid-peak and 20% off-peak plus typical local distribution company (LDC) delivery charges,
    The delivery charge benefit would only apply to load displaced, you do not get delivery charges back on energy returned to the system under net metering, and
    The electricity price (forecast) is based on the Bank of Canada’s target 2% rate of inflation.

    What is Net Metering with Solar PV?  Net metering allows an electricity user to install a solar PV facility onsite (or close to it) to generate electricity which can be used with any access delivered to the grid with compensation in the form of a credit on a future electricity bill.   Net metering has been an option since 2015 and is governed under an Ontario Regulation (O. Reg. 541/05: Net Metering).  However, only more recently has the price of electricity and the cost of installing a solar PV facility made net metering with solar PV more worthy of consideration.

    As shown in the graphic above, even if you were to install the solar PV facility today, the price of solar exceeds current electricity prices.  However, looking forward not too far in the future, price parity and beyond are possible. Some key business drivers you should consider when evaluating whether Net Metering with solar PV makes sense now (2017), instead of waiting until 2020 are described below.

    1. Cost Certainty of Electricity: Electricity prices are expected to rise in the short and long term.  When you factor in all the components of your electricity bill, the type of power user you are (time of use, class A/B) and global adjustment, you might want to lock in the price of electricity in the future. A Net Metering solution with solar PV can help you do that.
    2. Time Sensitivity:  Your Local Distribution Company (“LDC”) has a limit on the percentage of net metering solutions with PV they can manage on their distribution network.  Once they hit that level, you will not be able to participate in the net metering program although you could still be a “Behind the Meter” generator.  When it comes to net metering “the early bird has the best chance of getting the worm”. 
    3. Speed to Operation:  This solution has advantages over other renewable energy procurement processes as there is no environmental permitting unless you decide to go for a ground mount solar PV facility for which there is a simplified permitting process. Securing the connection with the LDC is likely to be the main hurdle.
    4. Greenhouse Gas (GHG) Emissions: If you generate emissions, as a course of operating your company or plant, net metering with solar PV will allow you to reduce or offset your emissions. This solution will enable you to retain your emission reduction credits. (currently emitters above 25MT only)
    5. Saving Money:  The benefit of net metering is that when you are not using electricity at your plant, you are allowed to inject power back into the grid and receive a credit on your next bill. Currently, you can bank this credit for 11 months which can help balance cash flow.
    6. Reputation: In addition to future cost saving, there are marketing and promotional advantages to be realized. Maybe your owners, board of directors or shareholders have given you a mandate to “GO GREEN”.  Generating your own electricity using renewable energy such as solar PV fits the bill. 

    Whats Next?  Making a decision on net metering with solar PV requires a level of analysis. You will need to understand how you pay for electricity and review monthly bills (1 or more years of history) to determine your peak demand and load profile. This in combination with an assessment of which of the above drivers are most important to you should assist in the decision making process.  The solar industry

    in Ontario is flush with capable and knowledge firms and individuals, reach out to them for assistance and advice to determine whether net metering with solar PV may be right for you now.

    For more information on ORTECH's Net Metering with Solar PV, click here.

    5 Tips to get your Solar Facility financed

    You have received your Power Purchase Agreement, Feed-in Tariff contract offer or RFP Win; now you are thinking “I need to get my project debt financed!”  

    Enclosed is a list of Best Practices to make this process as easy as possible.  The example below is based on either a ground mount or rooftop solar Facility that is not constructed.   However, this process can be used for constructed projects or Wind Power, Waterpower, Renewable Natural Gas or Energy Storage projects with some modifications.

    Also note, there will be regional requirements that are not listed in this guide, so check with your debt provider for any additional material that is required.

    Getting Started:

    Tip #1: Agreeing to use the debt providers IE can simplify the process

    Debt providers will have their preferred technical due diligence service providers often referred to as Independent Engineer (I.E.). Some developers may indicate that they have their own favourite .  However, the IE needs to be truly independent.  

    Tip #2: Get all your documents in order

    The first phase of technical risk management services conducted by the I.E. typically includes the provision of essential documents for review (see below for list). The requested documentation will be dictated by the status of the Facility under consideration (e.g. early development, pre-construction, post-commissioning, etc.). To complete the review efficiently and to minimize scope creep, the I.E. will typically start the review once all documentation is provided.

    Tip #3:  Missing documentation is a major red flag and will cost time and money to complete the review.  Do it right the first time.

    It is common that the initial batch of documentation provided is not complete.  This means the I.E. will need to review the preliminary batch for completeness only (i.e. not a technical review at this stage) and notify the developer of key documents that are missing if any. It is important to note that initiating the formal technical review while documentation is missing or deemed insufficient will ultimately be reflected in the draft I.E. report.  

    Tip #4: Save costs by providing all the documentation up front, at one time.

    Following the document review, the I.E. will issue a draft examination of documents report providing analysis and commentary on the reasonableness, accuracy and completeness of the documentation and identify the main risk factors and possible impact, if any, on the ability of the Facility to generate the expected level of energy/revenue.  That last part is key to any debt provider. The review must indicate an ability to service the debt.  

    Tip #5:  Use up-to-date documentation because the site visit will end badly if you don’t!

    Following document review, a site visit should be performed. The site visit will involve physical inspection of critical components for consistency with the provided documentation and confirmation of overall Facility design and compliance with the major Contract parameters including:

    • facility type (i.e. rooftop or non-rooftop solar) and physical location,
    • nameplate capacity including approval of DC overbuild and record of inverter production, if visibly accessible,
    • main equipment components (panel, inverter and racking suppliers),
    • connection point location, and
    • review of power production or data log information, if available, for the purpose of performing a high-level check of the Facility’s ability to achieve maximum capacity.

    What documentation is required to get financing for your Solar Facility?

    Debt financing is usually the last thing developers think about, but you need to be prepared. That preparation should be in the form of well-organized, complete Documentation. 

    Here is a list of Documents you should have handy to make this process as easy as possible.  The example below is based on either a ground mount or rooftop solar Facility that is not constructed.   However, this process can be used for constructed projects or Wind Power, Waterpower, Renewable Natural Gas or Energy Storage projects with some modifications.
    Also note, there will be regional requirements that are not listed in this guide, so check with your debt provider for any additional material that is required.

    What Documentation do you need to prepare?   
    Essential documentation that will be reviewed for accuracy, completeness and technical suitability as applicable and available before the site visit, may include the following:

    Previous due diligence report, if applicable.
    This can save time and provide the debt provider with a sense of comfort if another I.E.  previously reviewed the Facility.  If you have a previous report available, provide it.

    Power Purchase Agreement / Feed-in Tariff (“FIT”) documentation: Includes: contract, contract assignment and term buyback documentation, if applicable.
    This provides important confirmation that the Facility is “real” and viable.

    Key project design documentation:  Includes: as-built, signed/stamped electrical single line diagrams (“SLD”), main equipment specifications (panels, inverters, racking) including capacity, efficiency, warranty, the status of warranty assignment (if applicable) and facility layout drawings.  The design documentation is important and should meet industry standards. This documentation will be compared with observations made during the site visit, if there are differences, explanations will be required and documented.

    EPC warranty and commissioning report: Includes: Warranty contracts and reports from the EPC signing off of the project including performance testing reports.
    Understanding warranty is important from a debt provider hold back point of view, and the commissioning report will provide valuable information to the I.E. as to the ability of the Facility to perform over time.

    Grid Connection documentation:  Includes: A metering plan (if applicable), LDC connection cost agreement and status of assignment, if applicable. Jurisdictions will not allow a Facility to connect to the grid without following a process. This documentation will help to mitigate risk in the eyes of the debt provider f that the distribution company has signed off on the Facility.

    Environmental permitting and documentation: Includes: Permitting approval documents from the local government agency. Environmental permitting is important. Facilities cannot begin construction until the required permits or approvals are in place. The debt provider is also interested in the conditions of the permits and whether the ongoing costs to meet these conditions are adequately considered when assessing the ability of the Facility to service the debt.

    Land status documentation: Includes: confirmation that a lease agreement is in place for suitable duration, building permit or Certificate of Completion. The debt provider wants to understand any risks associated with the lease agreements like length of term or that zoning will not allow for buildings that can cause shading to be built.

    Energy output information: Includes:  calculations and /or Solar Resource Assessment
    This is very important. If you provide a poor quality resource report that is not consistent with industry standard, the I.E. will likely raise this as a red-flag and/or may require the analysis be redone costing additional time and money.

    Financial Model: Includes: breakdown of main capital cost items (panels, inverters, racking, roof upgrades, other) and operating cost items (O&M contract, monitoring, lease, roof repairs, insurance, administration, other) and debt service calculation, if available.
    This will be reviewed in depth so ensure the assumptions and costs can be validated

    Constructability assessment documentation:
    The I.E. will look for any issues that might cause unusual challenges during the construction of the Facility (e.g. geotechnical study.)

    Notice to Proceed (“NTP”) related documents:
    For construction financing, this confirms the Facility has been approval to begin construction.  This is very important document when shopping for debt financing.

    Commercial Operation Date (“COD”) related documents:
    This confirms that the project has been signed off. This document can be called a number of things in different markets.

    Operation and maintenance (“O&M”) documentation:
    The I.E. will want to understand the plan, cost and approach. The debt provider will want to see how these costs, including key component replacement, are accounted through the entire lifecycle of the Facility.

    In Summary, spend the time to get your documentation together.  Provide the I.E. with a complete package of documentation and provide access to your Facility.  You do not want to give the I.E. or the debt provider a reason to question your Facility, if there are issues, work collaboratively with the I.E. to resolve them.


    Ontario Cap and Trade Update

    Yesterday, the Ontario Ministry of Environment and Climate Change posted its regulatory proposal to amend the Cap and Trade Program Regulation (O.Reg. 144/16), in order to include offsets provisions that will be developed to allow for high quality offset credits with integrity, transparency and financial value within Ontario’s cap and trade program. The deadline for feedback to this proposal is December 30th, 2016.
    Per the EBR posting found here, Offset Credits are a compliance instrument contemplated under the current cap and trade regulation. Facilities and sectors not subject to the cap and trade regulation that are able to reduce greenhouse gases in accordance with the proposed requirements and associated protocols will be eligible to seek to have offset credits created and issued. Offset Credits may be used by capped facilities to meet up to 8% of a compliance obligation.
    Ontario awarded a contract to the Climate Action Reserve to adapt 13 existing offset protocols (the rules specific to various project types such as forest management and fertilizer use) for use in Ontario and Quebec under the cap and trade program. Three protocols will be in place by early 2017 with the remainder by 2017-18.

    The regulatory proposal provides an overview of the criteria, process and administrative requirements for the registration of offset initiatives and the creation and issuance of offset credits that can be used to meet a compliance obligation.

    The offsets regulatory proposal outlines the policy for a number of program elements, including:

    • Offsets Initiative Registry
    • Start Dates
    • Crediting Periods
    • Reporting Requirements
    • Verification Requirements
    • Offset Credit Creation Criteria
    • Buffer Account
    • Offset Credit Issuance
    • Project Reversals

    The EBR posting for this regulatory proposal also notes that while cap and trade will encourage reductions, there may also be opportunities to reduce greenhouse gases beyond the cap and trade program and the offset credits that form part of that program.

    The government is leading by example and has committed to government operations being carbon neutral by 2018. As part of this commitment, the government will engage with relevant stakeholders on the development of a separate class of quality, branded, voluntary reduction instruments for use by government and the private sector. All of these voluntary reduction instruments will come from Ontario-based projects ensuring that the social and economic benefits accrue to the citizens of Ontario. Voluntary reduction instruments would be unique and could occur anywhere within the province including rural areas and in Northern Ontario.

    The Ministry proposes to form a working group to provide advice and help identify the best means to foster voluntary reductions and removals of greenhouse gases. There will be a policy posting in 2017 that will expand on the Government’s approach to encouraging the creation of voluntary reduction instruments, which will be separate from cap and trade and distinct from the offset credits and other compliance instruments created for cap and trade.

    If you have any questions on this, click here for ORTECH's Cap and Trade Readiness services.

    Risk Mitigation: Successful Transition of the Power Plant

    Many power generating facilities lack training of new personnel, up-to-date procedures, and true preventative and predictive maintenance protocols. Several companies may be unprepared to answer the question of what will happen when their seasoned veterans walk out the door and hand the reigns over to a new, less-experienced operator. Plant managers and owners understand their personnel will retire soon, but fail to realize knowledge will also leave with those employees. A majority of utility companies and generating facilities have neither prioritized the transferal of knowledge and skills to the new generation nor updated their plants to digital platforms.

    The Problem of an Aging Workforce

    One third of all baby boomers have hit retirement age. Consequently, the power market is due for a large generational shift. This will result in loss of invaluable industry knowledge. According to the Department of Labor, 50 percent of the utility workforce will be retired within 10 years with almost 45 percent of the non-nuclear generation technicians currently above 53 years of age. A survey conducted by the Center for Energy Workforce Development states: “The non-nuclear generation workforce, specifically Operators and Technicians, show the largest number of employees still eligible to retire...The results clearly reflect a need to put more emphasis on skilled technician and engineering positions.” Not only who is going to replace veteran baby boomer but also how do you gain their technological expertise? Will younger staff be able to retain their knowledge through word of mouth and continue to build on it? According to a report from PWC, “The growing number of retirement-eligible employees, rising turnover costs and the generational shift in utility personnel are driving a loss of productivity in the power sector. Traditional ‘word-of-mouth,’ on-the-job training of utility workers is not sustainable. More than ever before, work processes and procedures should be documented and continuously improved.” Power-Eng says “Establishing a program for transferring knowledge is an essential element for dealing with “brain drain.” Veteran utility workers tend to pass valuable institutional knowledge orally, rather than documenting and updating the information systematically. This intellectual capital is often lost when the worker retires because there is no formal program to capture their know-how.” This conversation must include a plan for replacement as well as transferal of technological expertise.

    A Reliable Fix

    One way to answer these tough questions is to utilize third party technical services companies, who provide operations and maintenance help. These companies develop site specific training videos, operating procedures, which helps reduce human error, improve operator knowledge and improve facility performance and could reduce insurance costs. For preventative and predictive maintenance, a computerized maintenance management system (CMMS) can reduce unscheduled breakdowns of equipment, increase plant reliability and reduce maintenance costs. Another area a third party technical service company can help with is the creation of Smart Piping and Instrumentation Drawings (P&ID’s), which may allow facilities to be a digitally based plant. The P&ID’s are a powerful way to represent the flow, layout, controls of a system as well as maintain a sortable and searchable database of all the systems contained therein. The drawings and database contain the pipe diameter, line number, valves, instruments, controls and respective tags. If other information is found on existing drawings such as type of material, insulation thickness, equipment capacity etc., then this is typically incorporated into the drawings and database. This database is helpful to plant personnel since they can record service dates, look up manufacturer’s parts and replacement parts and can input the location within the building.


    Through simple, third party initiatives your plant can have fully trained personnel, up to date procedures, preventative and predictive maintenance management systems. By implementing just a few of these options, power plants can successfully be brought into the digital age and retain the skilled knowledge that is leaving while also improving reliability and safety.


    How are you migrating your experienced knowledge to a digital format and the younger generation?