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Below you will find general responses to enquiries that relate to green energy, generation connections and electricity distributor activities including conservation and demand management.
If you require more information or if your concern / issue is not reflected in the FAQ, please contact the Board at IndustryRelations@oeb.ca.
1. What are some of the key requirements associated with the connection process for larger generation facilities?
- Capacity must be available to support the proposed connection. The proposed in-service date must be within three years (five years for water power projects) from the date of application or in accordance with an executed Independent Electricity System Operator (IESO) contract.
- Proponents must be able to demonstrate site control over the land on which the generation facility will be located.
- Generators are to pay their impact assessment costs and provide the following information: the proposed point of common coupling with the distribution system; single line diagram of the proposed connection; a preliminary design of the proposed interface protection; and all necessary technical information required by the distributor to complete the Connection Impact Assessment.
2. What information are distributors required to make available to generators?
The distributor’s Generation Information Package should include feeder and substation technical capacity limits associated with the connection of generation (e.g., feeder design current carrying capacity and substation transformer reverse flow capability), as well as the other information specified in section 6.2.3 of the Distribution System Code. Distributors are also required by the Distribution System Code to make additional information available upon request as part of the connection process, such as the information required as part of the Initial Feasibility Assessment (see the next FAQ).
3. What is the distributor required to provide in the Initial Feasibility Assessment?
Upon request, distributors are to provide information about the amount of additional accumulated generation that can be accommodated on specific feeders and/or substations as well as other information about voltage level, fault level and feeder loading information at up to three proposed connection points.
4. What is in the standard form Connection Agreement for micro-embedded generation?
For micro-embedded generation, the standard form Connection Agreement (pdf) includes provisions dealing with technical requirements, liabilities, compensation and billing.
A deviation from the standard form of agreement is not permitted. See Policy Review of Micro-Embedded Generation Connection Issues (EB-2012-0246).
5. What is included in the standard form Connection Agreement for small and mid-sized embedded generation facilities?
For small and mid-sized embedded generation facilities, the standard form Connection Agreement (pdf) includes provisions that address matters such as customer facility standards; charges, settlement and billing; insurance; disconnection; and dispute resolution. A number of schedules must be completed by the parties. In completing these schedules, the parties may not include a provision that would be contrary to or inconsistent with the Distribution System Code or the remainder of the Connection Agreement. The Connection Agreement includes a specific section (Section 17: Amendments (pdf)) which indicates the types of amendments that parties are permitted to make. These include:
- Changes by mutual agreement that reflect changes to the Distribution System Code from time to time; and
- Changes by mutual agreement to schedules that were originally completed by the parties.
Any amendments beyond those permitted by the Connection Agreement require leave of the Board.
6. What, if any, modifications or additions can be made to the standard form generator Connection Agreements?
Sections 6.2.7 and 6.2.22 of the Distribution System Code state that connection agreements shall be in the form set out in Appendix E. There are two standard forms of Agreement included in Appendix E:
- The micro-embedded generation facility Connection Agreement.
- deviations from the standard form of agreement are not permitted.
- The form of Connection Agreement for a small embedded generation facility or a mid-sized embedded generation facility.
- deviations from the standard form of agreement are permitted only where the standard form specifically allows for additions or modifications (see the previous FAQ).
There is no standard form Connection Agreement for large (>10 MW) generation facilities.
7. What is the liability insurance coverage requirement for a generation facility connected to the distribution system?
For small and mid-sized generation facilities the insurance coverage requirements are stipulated in the standard form Connection Agreement included in Appendix E. Prior to execution of this Agreement, the Customer shall provide the Distributor with a valid certificate of insurance. The Customer shall provide the Distributor with prompt notice of any cancellation of the Customer's insurance by the insurer.
See Section 9 of the Agreement:
- if the Facility is a Small Embedded Generation Facility not less than $1,000,000 per occurrence and in the annual aggregate
- if the Facility is a Mid-sized Embedded Generation Facility not less than $2,000,000 per occurrence and in the annual aggregate
For micro-embedded generation facility the Connection Agreement has no requirements for liability insurance and is therefore not a condition to connect the facility to the distribution system.
8. Can the Distributor charge a micro embedded generator a connection fee?
If the connection of the micro-embedded generation facility will require a site assessment, then the distributor may collect a connection deposit for the preparation of the offer to connect. The connection deposit shall not be more than $500 per offer to connect [DSC 6.2.6B]
If the connection of the micro-embedded generation facility does not require a site assessment then the distributor cannot charge for the preparation of the offer to connect.
9. Is the connection deposit refundable?
There are four scenarios that relate to refunding of a connection deposit. [DSC 6.2.6B]
- If the Distributor does not provide an Offer to Connect; then the deposit is refunded
- If the Generator refuses the Offer to Connect; then the deposit is not refunded
- If the Generator withdrawals its application; then the deposit is not refunded
- If the amount of deposit is greater than the actual cost to connect; then the difference is refunded with interest applied
10. Can a generator choose how it is connected to the distribution system?
Retail embedded generators connecting at the same location as a load customer may choose their preferred method of connecting to a distribution system; either directly or indirectly. Regardless of the retail embedded generator’s choice of connection configuration, all retail embedded generators with a FIT or microFIT contract must have their own independent customer account with the distributor.
UPDATE: On April 9, 2010, the Independent Electricity System Operator (IESO) informed distributors that Measurement Canada will not recognize or support the in-series metering configuration as described in the IESO’s microFIT and FIT rules. As a consequence, on May 19, 2010, the Board instructed distributors to cease all in-series connections for microFIT and FIT projects. Going forward microFIT and FIT applicants must seek other options such as indirect parallel connections and direct connection.
On July 2, 2010 the IESO revised its microFIT (pdf) and FIT Rules and is no longer issuing contracts for projects connecting in-series
Please note that as a result of these developments Bulletin 200703 is being revised.
11. What happens when a generator connects behind the load customer meter, and the load customer does not maintain its connection with the distributor?
For indirect generation connections where a generator chooses to connect behind the load customer meter, the generator should be aware that they are dependent on the load customer maintaining its connection with the distributor.
Distributors should try to ensure that generators are aware of the potential consequences of choosing this way of connecting. This could be done in the distributor’s Generation Information Package, Conditions of Service or other opportunities for communication such as the Initial Feasibility Assessment meeting.
12. What are the connection requirements for generators who had capacity allocated before September 21, 2009?
Projects that had a capacity allocation must execute a connection cost agreement (if they had not already done so) and pay connection cost and capacity allocation deposits if they wish to retain their capacity allocation and proceed with their project.
13. If a generator receives a FIT contract from the IESO and subsequently applies to the distributor for connection of its generation facility but capacity is not available to accommodate the connection, how should this situation be resolved?
With the exception of micro-sized and capacity allocation exempt small embedded generation facilities, which are exempt from the capacity allocation process (see sections 184.108.40.206, 6.2.8 A and 6.2.8 B of the Distribution System Code), a distributor can only proceed to complete a Connection Impact Assessment for a proposed connection if capacity is available to accommodate the proposed connection (see section 220.127.116.11(b) of the Distribution System Code). In reviewing the availability of capacity to accommodate the connection, the distributor must:
- consider the feeder and/or substation technical capacity limits of its existing distribution system, any host distributor’s distribution system or the supply TS and transmission system; and
- include capacity additions included in any Board-approved plans to increase the capacity of one or more of the distributor’s distribution system, any host distributor’s distribution system or the supply TS and transmission system.
A generator that has a FIT contract but that cannot connect due to lack of available capacity should contact the IESO to understand the options available for the generation project.
14. If several microFIT projects apply for connection at the same location and the total amount of generation exceeds 10kW is a Connection Impact Assessment required?
The distributor should treat each application to connect separately. Micro-sized generation applicants do not require a Connection Impact Assessment as part of the connection process.
15. What rules apply to the processing of an application to connect where the capacity of an existing generation facility is being increased?
Under section 6.2.25a of the Distribution System Code, a generator that proposes to increase the output of an existing facility must submit a new application to connect. The rules that apply to the processing of these applications are determined based on the total rated capacity of the generation facility including the incremental addition. Accordingly, an application to connect an incremental addition of 10kW or less to an existing micro-generation facility would only be processed using the rules that apply to micro-generators if the total rated capacity after the incremental addition (i.e. the sum of the existing capacity and the incremental capacity) of the generation facility remains at 10 kW or less. This may mean, for example, that a facility that originally qualified as a “capacity allocation exempt small embedded generation facility” may no longer qualify as such for the purposes of processing an application to connect incremental capacity.
16. The Distribution System Code requires distributors to establish substation and feeder technical capacity limits relating to the connection of generation. Will there be a provincial standard with regard to establishing these limits?
Each distributor is responsible for establishing these limits for their own distribution system based on how the distribution system is planned and designed. Distributors may find it beneficial and efficient to work together in developing their approach to establishing these limits. The Board encourages a consistent approach where appropriate.
17. How should the distributor handle the MicroFIT and FIT generation projects that are already connected indirectly in series?
The Board is not providing specific direction at this time with respect to existing FIT or MicroFIT generation projects that are already connected in an in-series configuration. The IESO is continuing to work with Measurement Canada to find a solution to preserve existing in-series connections. The Board will provide further guidance as necessary on this matter if and when there are any future developments regarding this issue.
1. What is the definition of “capacity allocation exempt small embedded generation facility”?
Capacity allocation exempt small embedded generators are defined as generators that:
- Have a generation capacity of more than 10 kW and up to and including 250 kW, if connected to a line operating at less than 15 kV; or
- Have a capacity of more than 10 kW and up to and including 500 kW, if connected to a line operating at greater than or equal to 15 Kv
In determining the generator’s capacity, the total rated capacity of the facility including any incremental additions is used. This may mean that a facility that originally qualified as a “capacity allocation exempt small embedded generation facility” may no longer qualify as such for the purposes of processing an application to connect incremental capacity.
2. Is a capacity allocation exempt small embedded generation facility required to pay capacity allocation deposits?
Capacity allocation exempt small embedded generation facilities that are under contract with the IESO under the Feed-in Tariff (FIT) program are not required to pay capacity allocation or additional capacity allocation deposits. Although the IESO does not require these generators to pay application security, these generation proponents are required to pay completion and performance security to the IESO and are, therefore, exempt from the requirement to pay capacity allocation and additional capacity allocation deposits under the Distribution System Code (see section 6.2.18(d) of the Distribution System Code). Capacity allocation exempt small embedded generation facilities do, however, have to pay connection cost deposits to cover their connection costs.
3. Is a capacity allocation exempt small embedded generation facility required to obtain a Connection Impact Assessment from the distributor?
Yes. Capacity allocation exempt small embedded generation facilities are only exempt from the capacity allocation aspect of the connection process. As for all other “small” size generation facilities, distributors undertake a Connection Impact Assessment to determine the system impact of the proposed generation facility, so they can develop a detailed cost estimate and prepare the offer to connect.
4. When is capacity allocated?
Distributors will allocate capacity only after all Connection Impact Assessments (CIA)/technical reviews have been completed (distributor CIA; host distributor CIA; transmitter TS review).
5. When would a generator lose its allocated capacity?
A generator would have its allocated capacity removed under any one of the following conditions:
- If the generator does not pay any required deposits in the time allotted
- If there is a material change to the generation project that results in a material change to the Connection Impact Assessment
- If a connection cost agreement (CCA) is not executed within six months of receiving a capacity allocation
- If the proponent defaults on the terms and conditions of an executed CCA and does not correct the default in the time allotted
- If the distributor is informed by the IESO that the proponent has defaulted on an executed IESO contract
6. If there is no capacity available to connect a capacity allocation exempt (CAE) generation facility what is the distributor expected to do?
In cases where there is no capacity available for a CAE connection, the distributor shall notify the Board in writing and shall not take any further steps to connect the CAE generation facility without further direction from the Board in accordance with section 6.2.8(B) of the DSC.
1. In the case of forfeited deposits, where does the money go?
The Distribution System Code requires that certain generators pay a capacity allocation deposit and, in some cases, an additional capacity allocation deposit. These deposits are forfeited by the generator if the generation facility is not placed in service or if the capacity allocated to the generation project is removed for any reason.
The Board has indicated that any deposits that are forfeited would be held in a deferral account for disposition by the Board, and that the Board does not expect that distributors will retain forfeited deposits.
2. How is the connection cost deposit calculated under an alternative bid scenario?
Section 6.2.18 of the Distribution System Code requires that the applicant “pay a connection cost deposit equal to 100% of the total estimated allocated cost of connection” at the time the connection cost agreement is executed. The “allocated cost of connection” refers to costs that are the responsibility of the generator, and therefore does not include any costs associated with renewable enabling improvements. It also does not include expansion costs that are at or under the generator’s renewable energy expansion cost cap ($90,000 per MW of generation capacity). For expansion costs that are above the cap and therefore the responsibility of the generator, the connection cost deposit would be determined by excluding the cost of the contestable portion of work being done by the generation proponent.
3. When did the requirement for a deposit of 100% of estimated allocated cost of connection come into force?
This requirement came into force on September 21, 2009. In accordance with section 6.2.18 (a) of the DSC the connection cost agreement shall include a requirement that the applicant pay a connection cost deposit equal to 100% of the total estimated allocated cost of connection at the time the connection cost agreement is executed.
4. How is the connection cost for a microFIT generator facility determined?
With respect to the connection of an electricity generator (regardless of size) to the distributor’s distribution system, sections 3.1.5 and 3.1.6 of the DSC state that for non-residential customers, a distributor may define a basic connection by rate class and recover the cost of connection either as part of its revenue requirement, or through a basic connection charge to the customer and that all customer classes shall be subject to a variable connection charge to be calculated as the costs associated with the installation of connection assets above and beyond the basic connection. A distributor may recover this amount from a customer through a connection charge or equivalent payment. It is important to keep in mind that the level of these costs can vary considerably, not only from one distributor to another but also from one connection location to the next within a particular distributor for a variety of reasons, such as the type of wiring connection the microFIT Generator chooses (e.g. connect directly to the distributor’s distribution system or indirectly) and metering costs depending on the metering technology deployed by a particular distributor.
1. What are the cost responsibility rules based on?
The cost responsibility rules are based on the type of investment, as follows:
- Connection Assets (generator responsible)
- Expansions (generally, distributor responsible up to a cap/generator responsible above the cap)
- Renewable Enabling Improvements (distributor responsible)
The generator is also responsible for the cost of all assets owned by it.
These rules came into force on October 21, 2009 and apply to all applications to connect made on or after that date.
2. What is a connection asset?
It is the portion of the distribution system used to connect a customer to the existing main distribution system, and consists of the assets between the point of connection on a distributor’s main distribution system and the ownership demarcation point with that customer. Connection assets are expected to be dedicated facilities to connect a customer to the main distribution system and are not expected to be shared by other customers. The Board has clearly indicated that it expects distributors to expand or build out their distribution systems to reach connecting customers, and not the other way around. As such, the Board expects that distributors will not classify as connection assets lines designed to reach from the existing main distribution system to the customer’s location.
3. Who pays for the cost of the connection asset?
The generator is responsible for the cost of the connection asset.
4. Who is responsible for the cost of modifications or additions to the distributor’s main distribution system to accommodate a connecting renewable generator?
Cost responsibility depends on whether the investment is an “expansion” or a “renewable enabling improvement”.
An expansion of the main distribution system includes the following in relation to distributor-owned facilities:
- building a new line to serve the connecting customer;
- rebuilding a single-phase line to three-phase to serve the connecting customer;
- rebuilding an existing line with a larger size conductor to serve the connecting customer;
- rebuilding or overbuilding an existing line to provide an additional circuit to serve the connecting customer;
- converting a lower voltage line to operate at higher voltage;
- replacing a transformer to a larger MVA size;
- upgrading a voltage regulating transformer or station to a larger MVA size; and
- adding or upgrading capacitor banks to accommodate the connection of the connecting customer.
The distributor is responsible for the cost of an expansion up to the value of the generator’s renewable energy expansion cost cap (REECC) ($90,000 per MW of generation capacity). Costs above the REECC are the responsibility of the connecting generator. By way of exception, however, the distributor is responsible for the entire cost of an expansion if the expansion is in a Board-approved distribution system plan or is otherwise approved or mandated by the Board.
The distributor is responsible for the cost of a renewable enabling improvement, which is a modification or addition to the main distribution system that is made to enable the main distribution system to accommodate generation from renewable energy generation facilities. Section 3.3.2 of the Distribution System Code lists all renewable enabling improvements.
NOTE: The expansion and renewable enabling improvement cost responsibility treatments above apply only to work on the main distribution system of the distributor to which the generator is connecting. Similar work required on up-stream systems (host distributor and/or transmitter) and/or required between the point of connection on a distributor’s main distribution system and the ownership demarcation point with the generator is not subject to these cost responsibility rules. Rather, the costs associated with such work are passed through to the connecting generator.
1. How is settlement done for the Debt Retirement Charge in relation to distributed generation?
Collection, billing and settlement related to the Debt Retirement Charge is addressed primarily in regulations made under the Electricity Act, 1998 and administered by the Ministry of Finance.
2. What is the treatment of distribution system losses for generators?
There are four factors that determine the treatment of distribution system losses in general: ownership of a transformer; the delivery point for the electricity; the metering point; and whether a delivery or metering point is on the primary or secondary side of the transformer.
For generators connected to a distribution system the general rule is that no losses are applied. By way of exception, if the transformer is owned by the generator and the delivery point is on the primary side of the transformer while the meter is on the secondary side, a Board-approved 1% loss factor is applied. This rule, which is likely to apply only to relatively large generators as they are the most likely to own the transformer, addresses step-up losses through the transformer, and not losses associated with the flow of electric power from the generator to the distribution system per se.
3. Does the generation meter have to be a “smart meter”?
The generation meter must be sufficient to enable the distributor to be able to settle accounts with the generator, any associated load and, where applicable, the Independent Electricity System Operator. That meter may have the same attributes and functionality as a “smart meter”.
4. How are energy costs determined for a load account?
The energy (or competitive electricity “commodity”) costs for consumers are determined in accordance with the Board’s Standard Supply Service Code and applicable legislation. Under the Code, a consumer can be charged for these costs as follows (in each case, adjusted for losses):
- if the consumer is by law eligible for the Regulated Price Plan (“RPP”), has not entered into a contract with a retailer and has not opted out of the RPP, the consumer is charged the applicable RPP prices (in some service areas, this will be time-of-use or TOU prices whereas in other service areas, this will be tiered prices);
- if the consumer is by law ineligible for the RPP, has not entered into a contract with a retailer and has an interval meter or another “eligible time-of-use” meter, the consumer is charged the spot market price (the Hourly Ontario Energy Price or HOEP);
- if the consumer is by law ineligible for the RPP, has not entered into a contract with a retailer and does not have an interval meter or another “eligible time-of-use” meter, the consumer is charged the weighted average hourly spot market price; or
- if the consumer has entered into a contract with a retailer, the consumer is charged the contract price.
5. How are energy costs determined for a generator account?
A generator is charged for any energy that it uses in exactly the same way as a consumer (load account).
6. How are time-of-use (TOU) rates applied where a generator under a FIT contract is connected indirectly in series?
Settlement for the competitive electricity costs of a load that is associated with a FIT-contracted generation facility that is connected indirectly in series is done on a gross load basis. Currently, due to limitations in the meter data management/meter data repository (MDM/R), a distributor would need to supplement the MDM/R data with data from the bi-directional meters in order to settle these loads.
7. What service charges apply to generators?
Distributors are expected to recover all fixed costs in the monthly service charge. For generators that are required to have a separate account with the distributor (including RESOP-contracted generators other than those that are connected indirectly in series and including all FIT-contracted generators regardless of connection configuration), the applicable monthly service charge in most cases should be determined using the load customer class into which the generator falls based on its consumption. By way of exception, the Board has directed that all distributors establish a separate service classification for microFIT generators. A province-wide uniform fixed monthly service charge applicable to microFIT generator accounts has been set by the Board at $5.40.
This charge is meant to recover the ongoing incremental administration, billing and certain metering costs associated with the microFIT generator account. A copy of the Decision and Order and the associated Rate Order can be found on the OEB website.
8. Does the monthly charge for a microFIT generator rate class apply to connections made before March 17, 2010?
On March 17, 2010, the Board issued a set fixed monthly charge for microFIT generator rate class and also ordered that distributors make adjustments to the accounts of any microFIT generator customers established prior to the issuance of the Rate Order to reflect the difference between the approved fixed monthly charge of $5.25 and the interim rate that was established September 21, 2009.
9. Where a generation facility that is associated with a load is required to have a separate account with the distributor, and is owned by the load, can the accounts be consolidated into a single bill in which charges and credits are off-set?
Other than applicable conditions in a distributor’s rate order and associated requirements, the Board’s regulatory instruments do not generally preclude a customer from reaching an agreement with a distributor as to the off-setting of charges and credits in relation to multiple accounts. However, any such arrangements should be mutually agreed by the parties, and not unilaterally imposed by the distributor. In addition, some of the load customers associated with an embedded retail generator may be low-volume consumers to whom the mandatory bill presentment provisions of O. Reg. 275/04 (Information on Invoices to Low-Volume Consumers of Electricity) apply. It is the responsibility of each distributor to ensure that any billing arrangements that might be agreed with a low-volume consumer are not inconsistent with the requirements of O. Reg. 275/04.
The costs associated with any systems changes made to enable such billing arrangements may be subject to a prudence review by the Board as part of a proceeding to set the distributor’s rates.
10. Can a distributor pay a microFIT generator on a billing cycle that differs from the billing cycle that is applied to an associated load?
The Board's regulatory instruments do not mandate what a distributor’s billing cycle should be, and this is therefore a matter that is currently left to the discretion of the distributor. In most instances distributors would settle the generation account according to their existing billing schedule. If a distributor chooses to settle the generation account on a different billing cycle from the associated load account, the distributor should ensure that the customer(s) are fully aware of this fact. Lastly, if there are any costs associated with any system changes made to implement new billing cycle arrangements please note that this may be subject to a review by the Board as part of a proceeding to set the distributor's rates.
- IESO Rules
- Under section 5.2 (d) of the IESO microFIT Rules it states that Generation Payments will be made by the LDC according to the established meter reading and Settlement Periods of the LDC and in section 5.2 (e) it discusses the manner in which the financial settlement for microFIT is to be completed in accordance with the Retail Settlement Code, the Connection Agreement and the microFIT contract.
- Section 9.1 of the IESO FIT Rules provides a complete settlement overview.
11. Should a generation facility that is required to have a separate account with the distributor be billed for small amounts of energy used by inverters or other equipment required to run the generator?
12. If a microFIT customer is enrolled with an energy retailer, can they also enroll their generation facility in relation to the generation facility’s load?
There are no rules that would preclude this arrangement, if made available by a retailer.
13. How are settlements made with the Independent Electricity System Operator (IESO)?
These questions should be addressed to the IESO.
14. What types of generators fall under the classification of a microFIT Generator?
The microFIT generator classification applies to an electricity generation facility that is contracted under the IESO microFIT program and connected to the distributor's distribution system. The IESO's eligibility requirements for a microFIT program stipulate that generators have a nameplate capacity of 10 kW or less and use a renewable energy source.
1. Under what section of the Ontario Energy Board Act, 1998 or the CDM Code should eligible distributors file an application for a performance incentive?
Distributors should file their application in accordance with the CDM Code and should reference section 7.1.1 of the CDM Code.
2. Can a distributor apply for a performance incentive if it has achieved less than 80% of one or both of its CDM Targets?
No. Section 7.2.2 of the CDM Code states that a distributor is eligible for a performance incentive if it has achieved 80% of each of its energy savings and peak demand CDM Targets1.
(1) The OEB will allow rounding up of numbers that end in 0.5% or higher, such that the 80% threshold for a CDM Target will be considered to have been met for the purposes of the CDM Code if a distributor has achieved 79.5% to 79.9% of that CDM Target.
3. How should the performance incentive amount be calculated?
Section 7.2.3 of the CDM Code states that a performance incentive must be calculated in accordance with Appendix D of the CDM Code. A performance incentive calculator is available on the OEB's website to aid eligible distributors in calculating the performance incentive amount that they may apply for.
4. Do applications for a performance incentive need to be filed by a certain date?
A distributor can apply at any time after receiving the final evaluation results from the IESO. In the interests of closing off the previous CDM Framework in a timely manner, applications should be filed no later than April 30, 2016.
5. Are distributors required to have a third party review in relation to the final results for IESO (formerly OPA)-Contracted Province-Wide CDM Programs (Province-Wide Programs)?
Yes. Section 7.2.1 of the CDM Code states that a distributor must provide verified results at the time of its application for a performance incentive, and that the verification must have been completed by an independent third party selected from the IESO's2 third party vendor of record list. For the purposes of that section of the CDM Code, the OEB accepts the final results for Province-Wide Programs that have been verified by third party evaluators from the IESO's vendor of record list.
(2) The CDM Code refers to the OPA. These responsibilities now rest with the IESO.
6. Can a distributor dispute the final verified results for Province-Wide Programs before the OEB?
The OEB accepts the final verified results for Province-Wide Programs, as determined by the IESO, as final. Any disputes regarding the final results should be raised with the IESO.
7. If the OEB approves a distributor’s performance incentive application, how will the distributor receive payment from the IESO?
As part of the OEB’s decision on an application for a performance incentive, it will determine the appropriate amounts to be paid to the distributor by the IESO. The distributor must enter into an agreement with the IESO to enable performance incentive payments related to Province-Wide Programs to be made by the IESO. See the Minister of Energy’s letter of direction (pdf) to the IESO dated August 21, 2015.
8. What action will the OEB take against distributors who have not achieved 80% of their energy savings target?
The OEB has previously stated that it will review any instances where a distributor has not met 80% of its energy savings target on a case-by-case basis once the results for 2014 are finalized, and will determine next steps at that time. In accordance with the OEB’s August 26, 2015 letter (pdf), any distributor that has not met at least 80% of its energy savings target is expected to include in its 2014 Annual Report details of efforts they took during the 2011 to 2014 period to address any shortfall in results and to explain why those efforts were insufficient or unsuccessful.
9. Where can a distributor find a copy of the CDM Annual Report template?
The CDM Annual Report template (doc), developed by the joint IESO-LDC CDM Annual Report working group, is posted on the OEB’s website.
10. Should distributors include, in their 2014 Annual Report, information related to projected spending in 2015 and 2016 that relates to their 2011-2014 CDM Programs?
Section 2.2.4 of the CDM Code states that distributors are required to report on the activities undertaken by the distributor in the calendar year in order to achieve its CDM Targets. Section 2.2.5 outlines all of the elements that distributors should include in their Annual Report, including amounts related to spending on CDM Programs. The 2011-2014 CDM Framework term ended on December 31, 2014, and the 2014 Annual Reports will be the last ones filed under that Framework. Distributors should include all relevant information related to the achievement of their 2011-2014 CDM Targets in their 2014 Annual Report so that it is all documented in one place. Information about spending that is projected for 2015 and 2016 and that relates to 2011-2014 CDM Programs would provide the OEB with a more complete understanding of the efforts undertaken to achieve the 2011-2014 CDM Targets.
1. What is the connection process for a distributor-owned generation facility?
Board issued a Notice of Amendment to Codes involving the Distribution System Code and Affiliates Relationship Code for Electricity Distributors and Transmitters to reflect the ability of electricity distributors to own and operate certain renewable and other generation facilities as well as energy storage facilities.
1. How do I connect my generation facility to a transmission system?
Part of the process for connecting to a transmission system is set out by the Independent Electricity System Operator (IESO). Anyone planning to construct a new or modified connection to the IESO-controlled grid is required to apply to the IESO and complete the Connection Assessment and Approval process.
The Board’s Transmission System Code deals with the relationship between the connecting generator and the transmitter, including identifying who is responsible for providing connection facilities. As a general rule, generators are required to provide their own connection facilities to connect to the existing transmission system; that is, they have to plan, design, construct, own and maintain these facilities.
If the connection facility includes a transmission line that is longer than 2 km, leave to construct the connection facility must be obtained from the Board.
2. Can a transmitter develop new transmission connection facilities?
As a general rule, generators are required to provide their own connection facilities to connect to the existing transmission system. However, transmitters may develop, own and operate “enabler facilities”, which are new transmission connection facilities intended to connect multi-proponent clusters of renewable generation resources.
Each generator that connects to an enabler facility will be required make a pro-rata capital contribution towards the cost of the enabler facility, calculated as a share of the total cost equal to the generation facility’s capacity.
3. How are “enablers” identified?
A connection facility that is intended to connect a multi-proponent cluster of renewable generation resources may be treated as an enabler facility in any of the following circumstances:
if the connection facility is identified as an enabler facility and the associated cluster is identified as such in a Board-approved Integrated Power System Plan or in a Board-approved transmission system plan;
if the renewable resource cluster associated with the connection facility is the subject of a procurement directive issued by the Minister of Energy and Infrastructure to the IESO; or
if the IESO has provided the Board with written advice identifying the associated renewable resource cluster as one for which an enabler facility would be desirable, and the connection facility satisfies the screening criteria set out in the Transmission System Code