Harmonizing greenhouse gas reporting requirements to reduce burden
Enbridge Inc. is North America's premier energy infrastructure company with strategic business platforms that include an extensive network of crude oil, liquids and natural gas pipelines, regulated natural gas distribution utilities and renewable power generation. The Company safely delivers an average of 2.9 million barrels of crude oil each day through its Mainline and Express Pipeline; and we transport 25% of the crude oil produced in North America. The Company's regulated utility, Enbridge Gas serves approximately 3.7 million retail customers in Ontario and Quebec. Enbridge also has interests in more than 1,700 MW of net renewable generating capacity in North America and Europe.
Enbridge supports the government’s intent to reduce unnecessary costs and reduce regulatory burden and is pleased to provide our comments on harmonizing greenhouse gas (GHG) reporting requirements. Our comments are focused on the following areas:
- Aligning the facility definition with the federal OBPS definition
- Aligning the reporting requirements with those of the federal OBPS
- Aligning ON.350 requirements with those of the federal methane regulation requirements
1. Aligning definition of facility with federal definition
Enbridge is supportive of aligning provincial and federal definitions, however, the definition of facility proposed presents problems for Enbridge Gas Inc (EGI). The definition of metering station, which is used to differentiate between the transmission system and distribution system would result in some distribution stations being categorized as transmission due to the proposed pressure threshold. EGI suggests that the MECP align with the federal Output-Based Pricing System (OBPS) definition of facility, by proposing the following, which utilizes the MECP ON.350 definition of Natural Gas Distribution and no longer utilizes the proposed metering station definition (yellow highlighting indicates proposed changes):
(1) Any one of the following constitutes a facility:
2. The portion of a natural gas pipeline system within Ontario that is used to transmit processed natural gas ... of which the pipelines and associated installations or equipment – including compressor stations, storage installations and compressors – are operated in an integrated way, but excludes pipelines, installations or equipment that are used in natural gas distribution.
3. The portion of a natural gas pipeline system within Ontario that is used in ... natural gas distribution.
“Natural gas distribution” means all natural gas equipment downstream of gate station inlet valves where pressure reduction and/or measuring occurs for eventual delivery of natural gas to consumers. Some natural gas distribution systems receive gas from gas batteries rather than from transmission pipelines and typically transport odourized natural gas.
Under the above definition, transmission, storage and LNG facilities would be captured under the Ontario Emissions Performance Standard (EPS).
4. Aligning with federal quantification methods
ECCC Greenhouse Gas Quantification Requirement References
Under the definitions section of the “Guideline for Quantification, Reporting and Verification of GHG Emissions” (Guideline), the definition of “Canada’s Greenhouse Gas Quantification Requirements” (GHGQR) should specify which version of the document is being referenced, as opposed to simply including ‘as amended from time to time’. This is key, as the proposed changes to the Guideline specifically reference sections and equations in the GHGQR which are susceptible to renumbering upon ECCC’s release of new versions of the document. As an example, the federal OBPS regulation specifically refers to the 2017 version of the GHGQR, in which the equation to calculate the annual mass of CO2 emissions from combusted gaseous fuels is Equation 2-10, whereas in the 2018 version of the GHGQR this same equation is Equation 2-8.
Currently, the proposed changes to the Guideline require flaring emissions related to natural gas transmission and distribution to be quantified twice, under both ON.20 and ON.350.
Under the current Guideline (July 2019 version), the Operation of Equipment Related to Natural Gas (ON.350) requires flaring emissions to be calculated according to ON.353(7). This methodology is aligned with the flaring methodology under WCI.350. Under OBPS, Natural Gas Transmission facilities are required to calculate emissions due to flaring using WCI.350 (specifically WCI.353(d)), not the methodology referenced in the GHGQR. Therefore, the current version of the Ontario Guideline (July 2019 version), is aligned with the federal OBPS with regards to the flaring calculation methodology.
Proposed changes to the Guideline include adding flaring to ON.20, with specific reference to the GHGQR flaring methodology. This proposed change does not result in alignment with the federal OBPS, and rather than reducing reporting burden, it increases the burden by requiring reporters to change their existing calculation methods. Furthermore, the GHGQR flaring methodology requires the use of flow meters and weekly measurements of carbon content or HHV. EGI does not have flow meters installed on all flares and weekly analysis of the flare gas composition is not available. Due to the timing of the proposed changes to the guideline, compliance with this proposed methodology is not possible.
Enbridge proposes that MECP maintain the current calculation methodology for flaring (ON.353 (7)), for natural gas transmission and distribution. As such, MECP needs to provide clarity in ON.20, that the flaring methodology proposed to be added to ON.20 does not apply to facilities that report flaring under ON.350.
While Enbridge recognizes that, due to the EPS, flaring emissions will be required to be verified, Enbridge agrees with the MECP’s decision to continue to consider vented and fugitive emissions as reportable only. We suggest that the MECP provide wording in the regulation to indicate that natural gas transmission flaring emissions will be verified to the methods under ON.353 (7) but that there is no requirement to verify other emissions quantified under the Operation of Equipment Related to Natural Gas (ON.350).
In order to be consistent with the federal OBPS, Enbridge proposes that the on-site transportation definition be updated to exclude those vehicles and other machinery that are fueled using fuels on which the carbon levy has been paid. Additionally, please include further wording that clarifies that licensed road vehicles are excluded from on-site transportation.
At EGI’s natural gas transmission facilities, mobile equipment such as maintenance vehicles may be fueled using a diesel tank. These tanks are not separately metered and there is no way to determine at this time how much fuel is used by vehicles that remain on-site and those that go off-site. The fuel for the tank is purchased through a third party and no exemption certificate is applied.
EGI proposes the following definition (yellow highlighting indicates proposed changes):
“On-site Transportation emissions” means releases from machinery used for the transport or movement of substances, materials, equipment or products that are used in the production process at an integrated facility, and that are fueled using fuel to which an exemption certificate referred to in subparagraph 36(2)(b)(v) of the Act applies. This includes releases from vehicles without public road licences.”
EGI asks that the MECP confirm that O.Reg. 390/18 continues to include the provision to use alternative methods to quantify emissions that do not exceed the lesser of 20,000 tonnes and 3 per cent of the facility emissions (O.Reg. 390/18, Section 5(6)). We suggest that MECP include wording in the regulation or guideline that specifies the deminimus threshold can be used to comply with the reporting requirements under the EPS in order to provide a small amount of additional flexibility to reporting companies.
As mentioned in the EGI comments on the Ontario EPS, submitted March 21, 2019, more clarity is required as to whether the Electricity Generation Sector emissions performance standard applies to a natural gas transmission facility that generates electricity. It is not clear if natural gas transmission facilities, which do not generate electricity as their primary activity, are required to meet the electricity EPS.
Under the federal OBPS, facilities that generate electricity, but not as their primary activity, have the option of not quantifying production due to electricity generation (these facilities are not required to quantify the electricity generation, but are still required to include the associated emissions within the total annual facility emissions calculated under OBPS), as per 31(1)(b)(i) of the OBPS Regulations.
EGI supports the approach taken under the federal OBPS, as we do not meter our electricity generation as none of the electricity is sold or used off-site. As such, EGI proposes that Section ON.22(l), which requires a facility to report the annual quantities of gross electricity generated on-site, sold off-site, lost on-site and purchased, be removed from the reporting requirements or limited to those facilities that choose to quantify their electricity generation production (If a company meters their electricity generation it would be beneficial to report electricity generation production in order to benefit from the electricity generation EPS). As previously stated, electricity generation is not the primary activity at natural gas transmission facilities and as such, electricity generation is not metered. Therefore, the required reporting changes proposed under this section of the guideline are not possible for EGI. Additionally, as previously indicated, these items are not required to be reported under the federal OBPS (reporting under electricity generation is optional).
Furthermore, EGI proposes that the MECP maintains the current definition of Electricity Generation (as defined in O.Reg. 390/18, Schedule 2), which excludes the operation of stationary emergency generators with a nameplate generating capacity of less than 10 MW.
Enbridge proposes that ON.22(g)(3) be removed from the proposed changes to the Guideline as it requires annual measured temperature and pressure to be reported. This does not align with current practices of natural gas transmission facilities or the reporting requirements under the GHGQR, which require volumes to be corrected to 15oC and 101.325 kPa.
Quantification of Production
EGI proposes that the details of the quantification of production be made available as soon as possible in order that facilities which are subject to the EPS have adequate time to ensure measured parameters are available to calculate production values according to the requirements of the regulation and to provide comments to the MECP.
Further, EGI suggests that MECP align as closely as possible with the production calculation methods under the OBPS as industry provided extensive consultation and input. Additionally, aligning with the OBPS will reduce the burden on EPS facilities to implement further reporting changes. Where possible, it is also recommended that provisions for use of engineering estimates are allowed where measurement instrumentation is not yet available.
5. Ability for director to require a revised GHG report and verification
EGI is notionally supportive of the proposed changes as noted below:
• The Reporting Regulation includes circumstances under which a facility is required to submit a revised GHG report to the director. We are proposing the following circumstances under which the director may request a revised GHG report from a covered facility:
o The director feels that the Accredited Verification Body (AVB) that has verified the GHG report has a potential threat to the AVB’s impartiality.
o Based on the emissions, production and other data submitted by the facility and verified by the AVB, the director has come to a different calculation of the Total Annual Emissions Limit (TAEL) or the verification amount in the GHG report.
• The revised GHG report, verified by an AVB with no conflict of interest, will be required to be submitted to the director within 90 days of receiving the director’s request being sent.
6. General Comments
GHG Emissions Performance Standards and Methodology for the Determination of the Total Annual Emissions Limit (Methodology)
The MECP needs to be cognizant of the fact that Table E in the Methodology will need to be updated regularly, due to facilities being created, bought and/or sold. Table E identifies specific facilities, not facility types, by GHG ID. Beginning with the 2019 reporting year, the GHG IDs for both legacy Union Gas (GHGID 1150) and legacy Enbridge Gas Distribution (GHGID 1038) will no longer be relevant. It is our understanding that the new amalgamated company (EGI) will be assigned a new facility GHG ID, and is therefore not included in Table E.
Operation of Equipment Related to Natural Gas (ON.350)
Please see the attached marked up copy of ON.350, in which Enbridge has proposed some changes in order to provide more clarity. Additionally, some edits have been made in order to better align ON.350 methods with the requirements of the federal Methane Regulation. These changes include, but are not limited to, allowing for the use of continuous monitoring devices as a measurement method for compressor seals/rod packing in order to align with the federal Methane Regulation and reduce the measurement burden.
General Edits to the Proposed Guideline
Upon review of the proposed Guideline, there appear to be some typos in ON.20 (Fuel Combustion and Flaring). Please see below:
Section ON.22(c) should read as follows:
Any person that is not subject to subsection (b) above shall report the total annual quantity, expressed in tonnes (t), of CO2, CH4 and N2O emissions, by ……
Section ON.22(d) should read as follows:
Any person subject to this SQM shall report the methods used to quantify each greenhouse gas under subsections (b) and (c) of this section, by fuel type and source.
Section ON.22(f) should read as follows:
Any person subject to this SQM shall, for each fuel used under subsections (b) and (c) report the…
Section ON.22(g) should read as follows:
Any person subject to this SQM shall, for each fuel used under subsections (b) and (c), report the annual measured…
Section ON.20(h) should read as follows:
Any person subject to this SQM shall, for each fuel used under subsections (b) and (c), report the…
Section ON.20(j) should read as follows:
Any person subject to this SQM shall, for steam used to quantify emissions under subsections (b) and (c) above, report the…
Section ON.20(l) should read as follows:
Any person subject to this SQM who is not subject to subsection (k) above shall report the annual quantities of…
It is anticipated that Enbridge may have further comments once the details of the proposed amendments to the GHG Reporting Regulation are drafted. Enbridge would be pleased to provide further review of the draft Regulation and Guideline prior to the documents being published. If you have any questions or require additional information please do not hesitate to contact Brad Lattanzi, Government Affairs Strategist (firstname.lastname@example.org).
Submitted December 20, 2019 3:44 PM