Natural gas processing
Download September 26, 2018

Air emissions regulations and reporting requirements for the upstream oil and gas (UOG) industry in Western Canada: An update

Air emissions regulations and reporting requirements for the upstream oil and gas (UOG) industry in Western Canada are in constant evolution and it can be very difficult to keep up with the changes.

This article provides a high level overview of existing and upcoming regulatory/reporting air emissions requirements for UOG facilities in Western Canada.

Regulated Air Emission
Key Regulations
Latest Update
Major Changes
AER Directive 39 (AB)
OGC 07-03 (BC)
MER S-18 (SK)

AER: June 19, 2018

AER: New DEOS & Inventory List; Qualified Person requirements
SOR/2018-66 (Federal)
AER Directive 60 (AB)

Federal: April 2018
AB Draft: April 2018

First federal requirements come in force 2020; in voluntary period now. AB regulation in draft now, scheduled to be released late 2018.
GHGRP (Federal)
BC GHG Reg 249/2015 (BC)

Federal Draft: Sep 2018
AB: Jan 2018
BC: Jan 2016

Federal/AB: Reduction in reporting threshold from 50 kT CO2e/yr to 10 kT.
 AB: Carbon levy exemption for oil and gas in Effect until 2023

Pollutant Inventory (CACs, etc.)
NPRI (Federal)
Changes proposed for NPRI requirements starting 2018
Facilities meeting thresholds for any CAC must report all CACs; oil batteries exceeding certain thresholds must report VOC and benzene from tanks; bulk upload changes.
MSAPR (SOR/2016-151)
2016In effect 2017; Modern engines must have been registered July 1, 2017. All impacted engines must be registered by January 1, 2019.
Flare/Vented Volumes
AER Directive 60
OGC Guideline 5.1
SK Directives S-10 and S-20

AER: April 2018
OGC: May 2018
 MER: Nov 2015
More detail regarding flaring / incineration / venting Records
Emissions and Odours in Peace River Area
AER Directive 84
Sep 11, 2018
Reports submitted through OneStop

Specific details for each of the regulations in this table are provided below.


Key changes for the Alberta regulations include the following:

  • There are new DEOS Sheet and Inventory List templates.
  • There are new requirements for the person completing the DEOS and Inventory List ("qualified person") and the senior authority signing off on the inventory list ("person responsible").
  • The progressive introduction of emissions limits is complete and there is now one table which clarifies them.
  • There are many new clarifications regarding controls, including flares, incinerators, VRUs, condensers, and newly-identified controls which route still overhead vapours to the regenerator or a compressor engine.

BC and SK regulations have not been updated, but they may follow the AB regulations at a later time.

For more information, see


Due to its potent global warming potential, methane is getting significant focus both within the oil and gas industry and in other sectors. Here is the current state of regulation in Alberta and Canada (federally).

a. Alberta:

Alberta has stated a goal to reduce methane emissions from oil and gas operations by 45 percent from a 2012 baseline by 2025. Draft Regulations were issued (as part of Directive 60) in April 2018, and are currently being finalized, expected to be presented to government in late 2018. In short, there will be vent gas limits for:

  • Pneumatic devices
  • Compressor seals
  • Glycol Dehydrators
  • Fugitive Emissions

By June 1, 2019:

  • a Methane Reduction Retrofit Compliance Plan (MRRCP) must be completed, which must at a minimum contain the schedule to replace or retrofit existing equipment
  • a Fugitive Emissions Management Plan (FEMP) must be documented, as outlined in Appendix 12 of the Directive

b. Federal:

Canada will reduce methane emissions from oil and gas operations and will include that reduction in the promised national reduction of methane by 40-45 percent (below 2012 levels) by 2025. This will be regulated under the Canadian Environmental Protection Act (1999). Regulations have focused on the following emission sources:

  • Fugitive (leaks)
  • General facility production venting
  • Venting from pneumatic devices
  • Venting from compressors
  • Venting from well completions involving hydraulic fracturing

For more information, see

Greenhouse Gases (GHG) and Carbon Tax

For oil and gas, this usually means CO2, CH4, and N2O. These gases have had regulations in most jurisdictions for some time, however, regulations will be tightening and validation/verification will be more stringent going forward. Here is a breakdown by jurisdiction:

a. Alberta:

  • SGRR (Specified Gas Reporting Regulation, Alberta Environment and Parks) – If a facility emits over 10,000 tonnes CO2e per year (previously 50,000 tonnes CO2e/yr), they must report emissions.
  • The previous Specified Gas Reporting Regulation (SGER) has been replaced by a "Carbon Competitiveness" regulation in 2018, which applies to facilities that emit over 100,000 tonnes CO2e (in 2003); Benchmarks are set at 80% of production-weighted average emissions intensity. This can be accomplished by:
    • Improving Operations
    • Emissions Offsets (can purchase at $20/tonne in 2016; $30/tonne in 2017)
    • Emissions performance credits from a previous period
  • Carbon Tax: Starting January 1, 2017: $20/tonne CO2e in 2017; $30/tonne CO2e in 2018. (Equivalent to $1.011/GJ for 2017, $1.517/GJ for 2018+). Tax is charged on:
    • Fuel Imported into Alberta
    • Fuel sold within Alberta
    • Fuel flared or vented in Alberta
    • Natural Gas Produced / Consumed on site is exempt

b. British Columbia - Oil and Gas Commission (BCOGC):

  • Facilities (linear) emitting 10,000 tonnes or more CO2e/year must report emissions.
  • Facilities (linear) emitting 25,000 tonnes CO2e or more per year must have emission reports third party verified.
  • Emissions must be calculated using rules as laid out in the Western Climate Initiative (WCI).

c. Saskatchewan:

Waiting on Federal rules and regulations. Current focus is on Carbon Capture and storage and de-carbonizing the power system in Saskatchewan.

d. Federal:

  • ECCC GHGRP – Greenhouse Gas Reporting Program – since 2004
    • Mandatory reporting of total GHG for facilities emitting more than 10,000 tonnes/yr CO2e; voluntary program for smaller emitters.
    • Phase 1 of expansion 2017 – lowered reporting threshold to 10 kt CO2e
    • Certain sectors required to report additional information (including CCTS)
    • Will improve usability of reported data, better capture changes at facility level to better reflect abatement efforts by facilities.
    • Sep 4, 2018 – proposed expanded requirements for Phase 2:
      • Breakdown of emissions by industrial activity
      • Use of prescribed methods – overlap with WCI requirements – changes in fuel combustion and reporting criteria.
      • Report emissions for fuel combustion-flaring
      • Publication of 2018 reporting year requirements Dec 2018 (comments on draft due Oct 2, 2018).
  • Carbon Tax: - Minimum price on carbon. Currently set at $10/tonne CO2e starting in 2018. Negotiations with provinces ongoing.

National Pollutant Release Inventory (NPRI)

This is a federal program that requires reporting of many air, water and ground emissions. Reporting requirements can be significant for larger facilities, but smaller oil and gas facilities (<20,000 manhours per year) are only required to report combustion equipment emissions – Criteria Air Contaminants (CACs).

Some proposed changes applicable for UOG include:

  • All oil and gas facilities that currently meet the stationary combustion equipment release thresholds for any criteria air contaminant (CAC) will need to report all CAC emissions from all sources.
  • Also, oil batteries that meet certain production and oil type thresholds would need to report volatile organic compound (VOC) and benzene emissions from their storage tanks.
  • Finally, to facilitate the tracking of smaller facilities in the oil and gas extraction sector, improved guidance on the reporting of provincial regulator identification numbers would be provided.
  • Expansion of bulk uploading capability.


The highlights of the MSAPR are the regulation of:

  • NOx from large boilers (>10.5 GJ/h), heaters and stationary spark-ignition engines. Approximately 820 pre-existing boilers and heaters are subject to MSAPR, half in the oil sands sector.
  • The MSAPR applies to approximately 6,300 existing engines, with most in the upstream oil and gas sector.
  • A modern engine was manufactured after September 15, 2016, and applies to engines >75 kW (regular-use) and >100 kW (low-use). For existing engines the size threshold is 250 kW.
  • In future there will be further standards around: SO2, VOCs, NH3 and Particulate Matter

For more information, see

Flared and Vented Volumes

These volumes of gas have been regulated for a considerable amount of time, however, as they directly impact the amount of other emissions (see Sections 1 and 2 in particular), the volumes have specific regulation written about them, as follows:

a. Alberta: Directive 060 (Alberta Energy Regulator)

b. BC Oil and Gas Commission: Flaring and venting Reduction Guideline 5.1 (May 2018)

c. Saskatchewan: Directives S-10 and S-20


Directive 84

The key change here is that the monthly leak report, annual survey report and annual performance report must be submitted through AER’s OneStop submission tool.


How can we help?

We are working hard to keep up with the ever-changing regulatory landscape and ensure that our clients are compliant with all of these air emissions regulations.

Our goal is to

  • Simplify all aspects of your emissions reporting responsibilities
  • Ensure compliance with constantly changing air emissions regulations and reporting requirements
  • Leverage regulatory activities to find the best opportunities to reduce emissions, save money and optimize operations.

We have developed Applications focused on the air emissions reporting requirements of UOG operators in Western Canada, and work closely with you to achieve your reporting goals. We also work with trusted Partners to help with associated tasks, such as the development of inventories and fugitive emissions surveys.

Would like to improve your management of air emissions reporting?

See or contact us.

List of Acronyms

AER – Alberta Energy Regulator

AQMS – Air Quality Management System

BLIERs - Base Level Industrial Emission Requirements

CAC – Criteria Air Contaminant

CCIR – Carbon Competitiveness Incentive Regulation

CCTS – Carbon Capture

CO2e – Carbon Dioxide Equivalent

ECCC – Environment and Climate Change Canada

GHG – Greenhouse Gas

GWP – Global Warming Potential

LDAR – Leak Detection and Repair

MSAPR - Multi-Sector Air Pollutants Regulation

NPRI – National Pollutant Release Inventory Program

OGC – Oil and Gas Commission (BC)

OPBS - Output Based Pricing System

SGER – Specified Gas Emitters Regulation

By James Holoboff, M.Sc., P. Eng.

James has over 30 years of experience in process engineering and emissions management for the chemical and petroleum industries. He brings a strong background in the development and application of computer simulation models to Oil & Gas industry challenges. James worked for Hyprotech/Aspentech for almost 10 years in various capacities including Global Technical Support Manager and Business Development Manager for the Project Services Division. He then spent 5 years providing process engineering and simulation consulting to a number of operating companies and engineering firms. James has been a Managing Partner for Process Ecology for almost 20 years, during this time providing process engineering services, emissions reporting, project management, and software development support. James is a Chemical Engineering graduate from the University of Calgary and holds an MSc in Chemical Engineering from the same institution. In his spare time, when he’s not playing ice hockey or cycling, he is recovering from injuries incurred from those sports.



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