TY - JOUR AU1 - Ingelson,, Allan AB - Abstract In the USA and Canada where most of global shale oil and gas development has occurred, due to concerns about climate change the national governments have adopted new regulations to further significantly reduce national methane emissions from the upstream oil and gas industry. The 2016 US Environmental Protection Agency emissions standards and 2018 Canadian methane regulations build on decades old oil and gas conservation schemes to further reduce the volume of methane that is released from facility equipment leaks and venting. In Canada, venting methane at new oil and gas well sites is now prohibited. Operators are required to capture and use a much larger volume of natural gas than in the past. A negotiated settlement of the first US emissions reduction enforcement action was reached in April 2018. The facility operator agreed to pay a civil penalty of US $610,000 and spend a minimum of $2 million to install new technology at its facilities to further reduce methane emissions. The creative settlement agreement contains a comprehensive set of conditions to provide for a reduction in upstream industry emissions. 1. INTRODUCTION Methane (CH4) a significant component of natural gas is emitted from upstream oil and gas industry operations around the world.1 For decades emissions have been restricted by some oil producing governments under oil and gas conservation legislation and regulations to maximize long-term oil and gas production and to reduce the volume of wasted natural gas that is released into the atmosphere from upstream operations and the associated facilities. Methane a potent greenhouse gas (GHG) has a global warming potential more than 70 times carbon dioxide during a 20-year period.2 In light of increased public concerns in the USA and Canada about climate change, the national governments made commitments in December 2015 under the Paris Agreement, to reduce national GHG emissions.3 At the same time shale oil and gas development is increasing in the USA and Canada. As more shale oil and gas wells are drilled and completed, and methane is released from the associated facilities, emissions will increase unless existing regulations are revised or new regulations are adopted that require a significant reduction in the volume of natural gas that is released into the atmosphere from equipment leaks and venting. To address the issue of increasing methane emissions from the upstream oil and gas sector in the USA, the Environmental Protection Agency (EPA) in 2016 adopted new equipment performance standards to further significantly reduce methane emissions from upstream operations and facilities.4 Two years after the US adopted its methane reduction standards in April 2018, pursuant to section 332(1) of the Canadian Environmental Protection Act,5 the Minister of Environment and Climate Change tabled new ‘Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector’) (methane regulations), in Part II of the Canada Gazette.6 These regulations apply to emissions from the following types of upstream facilities: buildings, other structures and stationary equipment located on a single site, on contiguous or adjacent sites or on sites that form a network in which a central processing site is connected by gathering pipelines with one or more well sites – for the purpose of The extraction of hydrocarbons from an underground geological deposit or reservoir; The primary processing of those hydrocarbons; or The transportation of hydrocarbons—including their storage for transportation purposes—other than for local distribution. Facilities include gathering pipelines, transmission pipelines, natural gas gathering and boosting stations, natural gas transmission compressor stations and natural gas processing plants.7 In addition to reducing the volume of wasted natural gas that is emitted from existing upstream oil and gas facilities, another reason that the federal governments have adopted more stringent emissions reduction regulations, is the potential for an increase in emissions from more shale oil and gas development. Recently, technology has been refined that allows regulators to better detect and monitor methane releases from shale oil and gas wells and the associated facilities to accurately measure the volume of methane emissions from upstream oil and gas facilities. Employing satellite data, atmospheric methane emission trends in North America have been analysed and compared before and after shale oil and gas development, and it has been observed that emissions have increased significantly in areas that have experienced shale oil and gas development.8 According to one study by Howarth et al, hydraulic fracturing of shale oil and gas wells can result in the release of 40–60 per cent more methane into the atmosphere than from conventional oil and gas wells, and more than 8–12 per cent of methane from shale gas development escapes via equipment leaks and venting.9 In light of increased shale oil and gas development and production in the USA10 and the larger volume of associated methane emissions from upstream operations, the Obama administration responded to public concerns about the potential impacts from global warming by directing the EPA to complete a public consultation process on a proposed set of ‘cost-effective’ rules to curb harmful emissions from the oil and gas industry while allowing for continued, responsible growth in national oil and gas production. Pursuant to the Clean Air Act,11 the EPA, in 2012 released the first methane emissions rule applicable to hydraulic fracturing operations. Three years after the initial rule, the EPA proposed a second rule to extend its methane emissions initiative to additional upstream sources including natural gas facilities. After completing an extensive consultation process in which more than 900,000 comments were received, the EPA in 2016 released ‘New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants for the Oil and Gas Sector’ to further limit the volume of emissions from new, reconstructed and modified oil and gas sources.12 These standards are designed to reduce US national methane emissions to 40–45 per cent below 2012 levels by 2025.13 After the EPA adopted its national methane emissions reduction standards,14 another federal regulator the Bureau of Land Management (BLM) that manages upstream oil and gas development on more than 245 million acres of onshore federal lands that represent approximately 1/3 of the mineral estate in the USA,15 adopted a new ‘Methane and Waste Prevention Rule’ to update its oil and gas conservation requirements to further reduce methane emissions from oil and gas operations on lands under its administration.16 In addition to the federal emissions reduction actions, a few of the oil and gas producing state governments including Colorado, Pennsylvania and California have taken action to further reduce the volume of emissions from upstream operations on state lands under their administration,17 beyond what has been required under decades old state oil and gas conservation regulations.18 In 2018, after negotiations between a facility operator and regulators, the first US emissions reduction enforcement action was settled, under which the corporate defendant must pay a civil penalty of US $610,000 dollars and $2 million to upgrade technology at its facilities to further reduce methane emissions.19 The USA is Canada’s largest trading partner and the major export market for its oil and natural gas. Paralleling earlier US regulatory actions taken by the Obama administration in 2012 and 2016, to further reduce methane emissions from the Canadian upstream oil and gas industry, the federal government decided to align its national methane emissions reduction policy with the USA. On 10 March 2016, then EPA Administrator Gina McCarthy, alluded to joint US and Canadian actions to further reduce methane emissions from North American oil and gas producers to achieve the commitments made by both governments in December 2015 under the Paris Agreement: Today as part of the Obama Administration’s ongoing commitment to act on climate, President Barack Obama and Canadian Prime Minister Justin Trudeau committed to new actions to reduce methane pollution from the oil and natural gas sector, the world’s largest industrial source of methane. These actions build on the historic agreement that nearly 200 nations made in Paris last December to combat climate change and ensure a more stable environment for future generations.20 Three months after the EPA Administrator’s comments, on 29 June 2016, Prime Minister Justin Trudeau announced that Canada would reduce methane emissions from the Canadian oil and gas industry by an equivalent percentage, to 40–45 per cent below 2012 levels by 2025, as part of the North American initiative on Climate, Energy and the Arctic.21 Notwithstanding previous actions taken by the Obama administration to reduce methane emissions from the upstream oil and gas industry, President Donald Trump on 28 March 2017, issued an Executive Order, requiring federal government agencies to review regulatory actions that ‘potentially burden the development or use of domestically produced energy resources and, as appropriate, suspend, revise, or rescind’ such rules.22 Acting on President Trump’s Executive Order, on 12 June 2017, the EPA proposed a 2-year stay of the 2016 methane emissions reduction requirements to allow for reconsideration of the requirement.23 On 1 March 2018, the EPA announced two changes to the 2016 emissions reduction requirements.24 In addition to the EPA reconsideration, the BLM decided to rescind the 2012 hydraulic fracturing rule, ‘to prevent the unnecessarily burdensome and unjustified administrative requirements and compliance costs’ associated with the rule and to avoid ‘encumbering oil and gas development on Federal and Indian lands’.25 The BLM estimated that rescinding the 2012 hydraulic fracturing rule will reduce well operator compliance costs by up to $9650/oil or gas well, totalling in the range of US $14–$34 million annually.26 In response to the BLM decisions to retreat from the methane emissions reduction requirements, lawsuits have been initiated by environmental groups and some state governments.27 The actions challenge the legality of the administrative decisions on the basis that they violate the US Administrative Procedure Act28 and other federal statutes, and the plaintiffs have requested that the courts vacate the suspension of the emissions reduction requirements. Due to the change in US federal policy regarding reducing GHG emissions and the ongoing litigation and the associated uncertainty about additional enforcement actions to further reduce national methane emissions, in light of the more certain direction of Canadian government policy and the law to satisfy its commitments under the Paris Agreement by further reducing upstream industry emissions, we will now focus on the Canadian methane regulations created to achieve the same objectives as the 2016 US emissions reduction standards. The 2018 Canadian regulations that are being phased-in, create uniform, national requirements to significantly further reduce methane emissions from upstream onshore and offshore operations. In light of the number of governments evaluating the potential for shale oil and gas development including Argentina, China, Australia, Libya, Algeria, Mexico, South Africa and the UK, that may be interested in further reducing their national methane emissions in response to climate change, counsel for governments, regulators and oil and gas developers may find the new Canadian regulations that require the capture and beneficial use of a larger volume of otherwise wasted methane from hydraulic fracturing operations and the associated facility equipment leaks and venting practices, to be a useful frame of reference in the development of new regulations elsewhere. 2. CANADA’S ACTIONS TO REDUCE UPSTREAM EMISSIONS In light of the national government’s commitments under the Paris Agreement,29 the federal government has facilitated the development of a Pan-Canadian Framework on Clean Growth and Climate Change, which is a national plan directed towards reducing the effects of climate change. First Ministers in Canada created provincial-national-territorial groups to consult with Indigenous peoples, the business sector, civil society, and the general public to discuss options and propose recommendations as to how to best respond to climate change.30 Following the consultation process, four pillars were identified under the plan to respond to reduce national GHG emissions: pricing carbon pollution; complementary climate actions such as implementing more stringent emission standards; adapt and build resilience to the effects of climate change; and investing in clean technology, innovation and jobs.31 The Canadian methane regulations fall under the second pillar of the Pan-Canadian Plan, that provide for more stringent emission standards like those adopted in the USA in 2016.32 The 2018 Canadian regulations and 2016 US EPA emissions standards are both designed to protect the health of residents by reducing methane emissions and the associated volatile organic compounds (VOCs) to improve air quality. In regard to the VOCs associated with methane emissions, negative health effects attributed to these compounds include ‘premature mortality for adults; heart attacks, cardiovascular morbidity, respiratory morbidity, asthma attacks and acute and chronic bronchitis’.33 The objective of the Canadian regulations is to ‘reduce the immediate or long-term harmful effects of methane emissions by improving air quality’.34 Environment and Climate Change Canada (ECCC), the federal government department responsible for administering the regulations continues to monitor the level of national methane emissions from the upstream oil and gas industry and has noted an increase in the volume of national emissions.35 Before tabling the regulations the Canadian federal government evaluated the economic costs and benefits of the proposed regulations in its regulatory impact analysis process,36 just as the US federal government had done before the EPA released its 2016 emissions reduction standards.37 Consistent with the Canadian Treasury Board Secretariat’s Cost–Benefit Analysis Guide, the impacts were estimated by using a baseline scenario without the regulations, and comparing that case to the scenario in which the regulations have come into effect. The Canadian government estimates that from 2018 to 2035, the cost to the upstream oil and gas operators to repair and replace equipment in facilities to further reduce emissions will total $3.9 billion over an 18-year period.38 However, as the new regulations will prompt facility operators to capture and use an increased volume of otherwise wasted natural gas in facilities for heating or electricity generation, that the government estimates to be worth $1 billion, the net cost to facility operators of upgrading and/or replacing equipment will actually be $2.9 billion.39 Canadian government economic forecasts were developed by employing an Energy, Emissions and Economy model that incorporates emissions projections reported in Canada’s Greenhouse Gas Emissions Reference Case.40 As in the USA under its 2016 methane emissions reduction rules, some of the provisions in the new Canadian regulations will be phased-in and come into force on 1 January 2020 and others in 2023.41 These provisions will allow upstream facility operators to plan and budget for equipment upgrades and/or the purchase of new equipment. ECCC estimates that by 2025, the methane regulations will result in an emissions reduction equivalent to 232 million tonnes of CO2.42 Constitutional frameworks to regulate emissions in the federal states In both Canada and the USA, the national and regional (provincial or state) governments have the constitutional authority to regulate oil and gas development and limit the release of methane emissions. With two governments in each country regulating methane emissions, the federal character of the legal systems adds complexity to further restricting the volume of methane emissions beyond what would be the case in unitary states. As the new Canadian federal regulations build on existing provincial oil and gas conservation (OGC) regimes that have restricted the volume of methane emissions for decades to a more limited extent, an understanding of the interplay between the federal and provincial systems is essential to appreciate the role that both governments can play in further reducing upstream emissions. The Constitution Act 1867, formerly referred to as the British North America Act (CA),43 provides for a division of legislative powers between the federal and provincial governments under which both governments have the authority to regulate oil and gas exploration, development and production on their respective lands, and have done so for decades. Section 109 of the CA, 44 provides provincial governments with a proprietary interest in provincial lands and the minerals contained therein and the authority to regulate oil and gas development on those lands and the associated emissions. Section 92(5) provides provincial governments with the exclusive authority to legislate for the management and sale of public lands within each province which includes hydrocarbons, and section 92A(1) of the CA, provides provincial governments with the authority to regulate oil and gas exploration and production.45 The CA46 also provides the federal government with the authority to regulate oil and gas development and production on federal lands, where a much smaller volume of hydrocarbons have been produced than on provincial lands.47 Pursuant to section 91(24) of the Constitution Act 1867,48 the federal government enacted the Indian Oil and Gas Act,49 to regulate oil and gas development on Indian reserve lands which are under the jurisdiction of the national government and the government created a special agency called Indian Oil and Gas Canada that for decades has restricted methane emissions under an oil and gas conservation (OGC) scheme from operations on these lands.50 In addition section 91(7) of the CA,51 provides the federal government with the authority to limit emissions from upstream operations on military lands. One situation in which there is joint federal and provincial regulation of upstream emissions is offshore oil and gas operations in Atlantic Canada, provided for under section 91(12) of the CA, where the federal National Energy Board52 jointly with the governments of Newfoundland and Nova Scotia, limits emissions pursuant to an OGC scheme under the Canada Oil and Gas Operations Act.53 Limiting emissions to protect the environment, public health and safety The constitution also provides both the federal and provincial governments with the legislative authority to restrict the level of emissions to protect the environment, air quality and the health of residents. In light of increased public awareness and concerns about global warming and climate change, the federal government adopted new regulations in 2018 to significantly further reduce the volume of national emissions beyond the levels restricted under provincial oil and gas conservation regimes. The federal government has restricted emissions to protect the environment and air quality, initially in the 1980s under the Clean Air Act,54 and now under the successor legislation, the Canadian Environmental Protection Act.55 In his 2009 analysis of the constitutional authority of the Canadian government to limit national GHG emissions, Professor Peter Hogg argues that the federal criminal law and the broad based peace, order, and good government power are the main ones that can be relied on by the federal government to restrict emissions.56 He states, ‘There is no doubt that mandatory reduction in greenhouse gas emissions would be upheld as an exercise of the criminal law power of Parliament’,57 and cites R v Hydro-Quebec, as a leading Supreme Court of Canada precedent to support this opinion.58 The federal government may also rely in some cases on its jurisdiction over inter-provincial and international matters to further limit methane emissions to protect the environment and air quality.59 In light of the potential national and international environmental impacts from methane emissions, Canada’s highest court decision in R v Crown Zellerbach Canada Ltd,60 can also be cited to support the authority of the federal government to further restrict the volume of methane emissions beyond the level currently allowed under existing provincial OGC schemes, to respond to climate change as part of its environmental protection and health and safety protection powers. Provincial governments also have the authority to restrict the volume of methane emissions to protect the environment under sections 92(5) and 92(13) of the CA.61 For example the provincial government of the largest oil and gas producing province Alberta, restricts the volume of methane emissions from the upstream oil and gas sector under its Environmental Protection and Enhancement Act62 and Climate Change and Emissions Management Act.63 As in Alberta the Government of British Columbia that regulates much of the current shale oil and gas development limits methane emissions under the BC Environmental Management Act64 and its Greenhouse Gas Reduction Targets Act.65 On 2 October 2018, Prime Minister Trudeau and British Columbia (BC), Premier John Horgan announced approval of a $40 billion liquefied natural gas export project facility in BC, to supply the Asian market. Increasing shale oil and gas development will create additional emissions from an expanding industry.66 In conjunction with its environmental protection authority, the BC government recently commissioned a health risk assessment of the impacts from shale gas operations on the health of residents in the northeastern part of the province where most of the development is proceeding.67 In summary, the volume of methane emitted from upstream operations is regulated by both federal and provincial governments for several policy reasons—oil and gas conservation, responding to climate change (environmental protection) and protecting public health and safety. The environmental and public safety concerns have prompted the more stringent methane emissions standards in both the USA and Canada to further reduce upstream emissions.68 The largest volume of emissions in Canada is from upstream operations on provincial lands, where regional governments have restricted the volume of emissions for decades under OGC legislation and regulations. The Canadian federal government also employs OGC laws to limit the much smaller volume of methane emissions from oil and gas operations on lands under federal jurisdiction. 3. EXISTING PROVINCIAL OGC REGIMES THAT LIMIT EMISSIONS The 2018 federal regulations were not created in a vacuum. To appreciate the interplay between existing provincial systems and why the federal government has adopted more stringent emissions standards, we will now examine the weaknesses of the provincial OGC systems to be addressed in the new federal regulations. For decades governments in the USA and Canada, have restricted the level of natural gas/methane released into the atmosphere under OGC legislation and regulations that predate environmental protection acts and regulations created in response to climate change. The state, provincial and federal OGC systems were designed to encourage investment in oil and gas development and minimize operating costs for operators.69 As most of the Canadian onshore oil and gas development has occurred on provincial lands in the western Canadian provinces of Alberta, British Columbia and Saskatchewan, provincial regulators have more experience than federal regulators in restricting the volume of emissions and more comprehensive provincial frameworks exist that provide a foundation for the federal government to further reduce emissions. Alberta the first province to experience major oil and gas development and production and one that continues to produce most of the Canadian hydrocarbons and associated emissions from the upstream industry today, was the first provincial government to create OGC legislation used to limit methane emissions.70 With the best technology available in the 1930s, the provincial Oil and Gas Conservation Board, starting limiting the volume of wasted natural gas escaping into the atmosphere under the Alberta Oil and Gas Conservation Act.71 The focus of the provincial OGC regulatory system, as with other OGC regimes is to maximize long-term hydrocarbon production and the associated industry and government revenues.72 As oil and gas development emerged in the neighbouring oil producing provinces of Saskatchewan and British Columbia, the other governments modelled their OGC policies, legislation and regulations after Alberta’s model in 1953,73 and 1954.74 As a result, the largest oil and gas producing provinces have similar OGC legal frameworks that limit the volume of methane emissions to a level that is less than what the national government now requires. As the revenues from oil and gas development are more important to the provincial economies than the federal economy, provincial oil and gas regulators have been reluctant to adopt more stringent emissions requirements that would force operators to incur the additional costs of equipment upgrades or replacement to further reduce emissions from equipment leaks, as the additional costs could burden their industries and make them less competitive with other competing jurisdictions, an economic concern that prompted President Trump to issue the 2017 Executive Order, that we considered earlier in this article.75 Two major sources of upstream methane emissions are equipment leaks and venting. According to ECCC, oil and gas facility equipment leaks account for 34 per cent of upstream emissions,76 and 23 per cent from venting.77 Venting, a common practice in Canada and other oil producing nations is a process through which natural gas is intentionally released directly into the atmosphere. As natural gas is used to control pressurized equipment including pumps in multiple upstream operations and facilities, methane is released from equipment in processing facilities through vents. Venting methane from larger facilities is discouraged but not prohibited in the provincial OGC systems, due to economic and the emergency safety considerations to prevent natural gas explosions. Equipment leaks Provincial oil and gas regulators encourage reduction of methane emissions by recommending that operators detect and repair facility equipment leaks.78 In 2013, the Alberta government adopted a new act called the Responsible Energy Development Act (REDA)79 to better regulate the industry and created a new oil and gas regulator called the Alberta Energy Regulator (AER). The AER employs the Environmental Protection and Enhancement Act,80 Oil and Gas Conservation Act,81 Oil and Gas Conservation Rules,82 and directives 060,83 01784 and 084,85 that contain detailed technical information used to limit the volume of methane emissions. Under REDA, the AER administers and enforces Energy Resource Enactments which include acts, regulations and directives.86 Similar guidelines are employed in British Columbia87 to limit emissions from increasing shale oil and gas development. Provincial regulatory systems rely heavily on voluntary industry guidelines developed by the Canadian Association of Petroleum Producers (CAPP), a national oil industry association that represents most of Canadian oil companies.88 Based on decades of industry operating experience, the CAPP guidelines provide valuable technical information on where the most common sources of methane leaks are in upstream facilities; they recommend early equipment leak detection and repairs; and how to economically manage emissions by focusing on larger leaks.89 CAPP recommends screening for methane leaks in concentrations of 10,000 ppm or higher to determine which repairs merit attention.90 The industry guidelines recommend that operators prioritize the most common types of equipment leaks for regular and more frequent screenings as part of directed leak inspection and maintenance programmes.91 As some types of equipment are subject to higher vibration levels, industry guidelines suggest that equipment components most likely to leak methane should be monitored and inspected more frequently.92 The provincial regulations do not prescribe specific timelines for repairs and do not prescribe time deadlines by which inspections are to be carried out to verify that equipment leaks have been repaired. With regard to reducing the volume of methane that is intentionally vented, conserving methane and utilizing it in facilities for beneficial purposes such as heating or electricity generation rather than venting and wasting the gas is recommended in provincial OGC schemes, but not required. In summary, OGC systems were not designed to reduce the volume of emissions from equipment leaks and venting, as now required by the Canadian government to satisfy its GHG emissions reduction commitments under the Paris Agreement.93 Provincial regulators rely heavily on voluntary industry guidelines and practices for the frequency of equipment inspections, extent of repairs, and venting practices. The federal government has concluded the less stringent provincial methane emissions standards result in a higher volume of emissions than is necessary from facility equipment leaks and venting. The holes in provincial OGC schemes are now being plugged under the new federal regulations.94 4. THE 2018 FEDERAL METHANE REGULATIONS The regulations create uniform national standards to further significantly reduce methane emissions from both onshore and offshore Canadian oil and gas operations.95 Two major emission sources from upstream facilities to be significantly reduced under the new federal regulations are from facility equipment leaks and venting. The new regulations prohibit venting from a third source, hydraulic fracturing and the associated operations at newly completed oil and gas wells. Equipment leaks The term ‘fugitive emissions’, in section 2 of the regulations, refers to gas leaks from equipment defined as ‘the emission of hydrocarbon gas from an upstream oil and gas facility in an unintentional manner’.96 The regulations focus on reducing emissions from the largest sources which are the upstream oil and gas facilities that receive more than 60,000 standard m3 of hydrocarbon gas during a 12 -month period.97 Focusing on a smaller number of sources reflects a high leverage approach, as it reduces the amount of enforcement resources required by the regulator to enforce the regulations as there are far fewer facilities to inspect and monitor. As discussed earlier in this article, one weakness of provincial OGC systems is the lack of concrete provisions to compel leak prevention and detection programmes and timely repair of equipment leaks that can further reduce emissions. The federal regulations address this problem by mandating completion of leak detection and repair programmes as follows:98 Operators of a facility must establish and carry out at the facility a regulatory leak detection and repair program (LDAR) that satisfies sections 30–33; or an alternative leak detection and repair program referred to in subsection 35(1) that results in at most the same quantity of those fugitive emissions as would result from a regulatory program referred to in the paragraph above. A second significant weakness in provincial systems is the failure to require timely equipment leak repairs. To remedy this deficiency, the federal regulations provide that in most cases leaks must be repaired within 30 days of being detected as follows: A leak from an equipment component that is detected, whether as a result of an inspection or otherwise, must be repaired if the repair can be carried out while the equipment component is operating, within 30 days after the day on which it was detected. In any other case, the equipment component must be repaired within the period before the end of the next planned shutdown unless that period is extended under section 33.99 In light of the stipulated time period in the federal regulations, more timely repairs of equipment leaks should be completed in most cases and emissions further reduced. The prescribed 30 day leak repair period in the Canadian regulations corresponds to the same time period specified in the US BLM methane Waste Prevention and Resource Conservation rule.100 As in the USA, there is an exception to the 30 day time limit to complete equipment repairs in all situations. The exception allows the Canadian regulator to review, and in special cases approve, a time extension when equipment repairs will require a natural gas facility shut down and a corresponding disruption in energy security. The prior US experience has revealed that shutting down facilities in some cases will disrupt a secure supply of natural gas and threaten energy security. Supply disruptions during cold Canadian winters could cause serious health and safety problems in the future as natural gas is used in many provinces for heating homes and buildings. Therefore it is not surprising the federal government has followed the US lead and incorporated the exception to the repair time limit in the new regulations.101 A 3rd weakness in the provincial regulatory systems that we have discussed is the failure to require periodic inspections within a prescribed time period, to verify that equipment repairs have been completed to prevent additional methane from leaking into the atmosphere. The federal regulations address this deficiency as follows: Equipment components at an upstream oil and gas facility must be inspected on or before the later of May 1, 2020 and the day that occurs 60 days after the day on which production of the facility first began; and at least 3 times/year and at least 60 days after a previous inspection.102 Mandating a minimum of three annual inspections in the federal regulations and enforcing the emissions limits should prompt operators to place increased emphasis on leak detection and repair programmes. As we will learn later in this article, a surprise inspection in the Markwest case led to the enforcement action and a negotiated settlement in April 2018, that resulted in substantial financial costs to the upstream facility operator in the 1st US prosecution for exceeding the prescribed methane emissions levels.103 In addition to requiring periodic inspections the Canadian regulations specify the types of technologies that will be employed by the federal regulator during inspections to measure the level of emissions such as infrared cameras, sniffers, drones and satellite systems, to avoid disputes with operators about which technologies will be used to measure the level of emissions when evaluating whether the operator’s emissions have exceeded the level permitted under the federal regulations. In summary, the federal regulations clearly convey to upstream facility operators the emphasis that ECCC is placing on preventing, detecting and repairing equipment leaks in a timely manner to further reduce emissions. The fact that time periods are specified in the regulations by which operators must complete facility equipment repairs and that a minimum of three annual inspections must be carried out, should prompt facility operators to pay closer attention to the level of emissions from equipment leaks. I submit that when these provisions are enforced they will result in a decreased volume of emissions from a source that is clearly foreseeable and preventable. In addition to the general provisions in the regulations covering equipment leaks, there are other provisions tailored to reduce emissions from specific types of equipment. Leaks from pneumatic devices A variety of automated instruments called pneumatic devices are used throughout the upstream industry employ natural gas to pump liquids and for other purposes. These devices account for 20 per cent of the emissions from upstream operations.104 As with other types of equipment, the regulations prescribe operating efficiency standards for pneumatic controllers and pumps to reduce the volume of methane that leaks into the atmosphere.105 Operators will be required to replace certain types of high-bleed pneumatic controllers that release a larger volume of emissions than low bleed or no-bleed controllers. As with the other types of equipment, the repairs and/or equipment replacements must be completed within the time period specified in the regulations. As discussed earlier in this article, to provide facility operators with reasonable notice to allow operators to budget for new equipment purchases to replace existing equipment, the provisions applicable to pneumatic devices are scheduled to come into force in 2023.106 Emissions from a 3rd type of equipment called compressors account for 9 per cent of Canada’s upstream methane emissions.107 These are mechanical devices employed to increase the pressure in pipelines to move natural gas from production sites to consumers.108 As with the pneumatic devices that we just discussed, the regulations require the repair or replacement of compressor parts and in some cases the entire compressor to further reduce the volume of emissions from this type of equipment. Venting As noted previously, the other major source of methane emissions is from venting. The new federal regulations require a 95 per cent reduction in the volume of methane that is currently vented from oil and gas facilities.109 To achieve this goal, section 26 of the regulations creates an annual venting limit at upstream oil and gas facilities that receive no more than 15,000 m3 of hydrocarbon gas annually. One exception to the maximum emission limit in the regulations that provides flexibility to facility operators, is in an emergency at a gas processing facility, when the operator may be allowed to vent methane for safety reasons to prevent an explosion.110 In routine (non-emergency situations) as an alternative to venting gas, the regulations require operators to capture and use at a minimum 95 per cent of the hydrocarbon gas.111 The regulations provide that the gas must be captured and used for beneficial purposes.112 Section 5 of the regulations requires that the gas conservation equipment used in facility be operated in such a manner that at a minimum 95 per cent of the gas is captured and conserved.113 Section 7 of the regulations stipulates one of the following 3 methods be used to capture and conserve the gas: used at the facility as fuel in combustion device that releases at most 5 per cent of the combusted hydrocarbon gas to the atmosphere as hydrocarbon gas; delivered; or injected into an underground geological deposit for a purpose other than to dispose of the waste.114 In regard to the first option indicated above, the regulations specify that no more than 5% of the gas can be released. Rather than venting gas into the atmosphere and wasting it, the regulations require operators to use the gas at processing facilities for beneficial purposes such as heating or electricity generation. The federal regulations incorporate by reference existing provincial equipment operating efficiency and gas destruction standards used to measure the volume of methane emissions that is to be destroyed rather than released into the atmosphere.115 Section 9 of the regulations provides: ‘Hydrocarbon gas destruction equipment that is used at an upstream oil and gas facility116 must satisfy the requirements related to the destruction of hydrocarbon gas set out in: sections 3.6 and 7 of Version 4.5 of the guideline entitled Flaring and Venting Reduction Guideline, published by the Oil and Gas Commission of British Columbia in June 2016, if the facility is located in British Columbia. section 3 of the directive entitled Directive S-20: Saskatchewan Upstream Flaring and Incineration Requirements, published by the Government of Saskatchewan on November 1, 2015, if the facility is located in Manitoba or Saskatchewan’. sections 3.6 and 7 of the directive entitled Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, published by the Alberta Energy Regulator on 22 March 2016, in any other case.117 The second option in section 7 of the regulations ‘delivered’ refers to piping the otherwise waste gas so that it can be sold and used for a beneficial purpose, the same approach that is recommended in provincial OGC regimes. A third option available to operators is injection of the gas into subsurface oil and gas reservoirs to remain in the ground and not to escape into the atmosphere. This widespread industry practice, referred to as ‘enhanced recovery’, has been approved by provincial, state and federal regulators for decades. The three above emissions’ reduction practices which are recommended in the provincial OGC systems that we have considered are now required practices under the federal regulations. Reducing emissions vented from compressors There are special provisions in the regulations that limit the volume of emissions to be vented from compressors.118 Beyond the general provisions in the regulations to reduce emissions from venting at facilities, as there are different types of compressors that emit different levels of emissions, the new regulations contain provisions that are tailored to different types of compressors. To reduce the volume of emissions from each type of compressor, there is a requirement in the regulations that industry operators complete annual measurements to ensure that the emission limits stipulated in the regulations are satisfied. Section 14(a) requires the measurement of gas flow volumes as the first step towards further reducing the volume of emissions. Section 16(3) requires that operators take initial and subsequent gas flow measurements during specific time periods as follows: The flow rate must be initially measured on January 1, 2021, if the compressor is installed at the facility before January 1, 2020, and the 365th day after the day on which the compressor was installed at the facility in any other case; and subsequently, the period that ends on the 365th day after the day on which a previous measurement was taken. Section 14 provides for optimal equipment performance which takes into account the different types of compressors used at different sites to minimize the volume of emissions released from different types of compressors.119 As with other types of equipment that we have considered, operators of compressors will be required to take action to use the gas or destroy it, to satisfy the applicable venting limits prescribed for the relevant type of compressor. Corrective action is required if the volume of emissions exceeds the limit prescribed for the compressor, which depends on the installation date, the type of compressor, and its rated brake power.120 Specific timelines of 30 days and 90 days to complete the required work on compressors are stipulated in the regulations for operators to further reduce methane emissions.121 Hydraulic fracturing and well completions—preventing an increase in emissions Hydraulic fracturing (HF) of oil and gas wells refers to the processes used to create cracks or fractures in subsurface reservoirs that allows oil and gas to facilitate economic oil or gas production.122 HF is being employed in shales throughout North America.123 For example, in the Montney shale in BC and Alberta which has the potential to produce 1.125 million barrels of oil and 449 trillion cubic feet of natural gas,124 and in the Bakken shale in the provinces of Saskatchewan and Manitoba and in North Dakota and Montana in the USA, HF is critical to economic shale oil and gas development.125 Throughout Canada, to prevent additional emissions from new oil and gas wells, section 11(2) of the federal regulations called ‘No Venting’, prohibits the venting of methane at all new well sites and requires the capture and use of natural gas for a beneficial purpose or combustion/destruction of the gas. The section specifically states: Hydrocarbon gas associated with flowback at a well that has been hydraulically fractured… must not be vented during flowback but must instead be captured and routed to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment”. The prohibition on venting gas from operations at new oil and gas wells will prevent an increase in methane emissions. The new federal regulations recognize that the existing provincial standards in BC and Alberta applicable to emissions associated with HF of new oil and gas wells are stringent enough to prevent emissions, thus allowing operators that comply with the provincial requirements not to also satisfy a second set of federal standards as well. Section 13 of the federal regulations called ‘Non-application – British Columbia and Alberta’ provides that: Sections 11 and 12 do not apply in respect of an upstream oil and gas facility that is located in British Columbia, if the facility is subject to the requirements with respect to well completion involving hydraulic fracturing that are set out in the guideline entitled Flaring and Venting Reduction Guideline, published by the Oil and Gas Commission of British Columbia in June 2016; and Alberta, if the facility is subject to the requirements with respect to well completions involving hydraulic fracturing that are set out in the directive entitled Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, published by the Alberta Energy Regulator on 22 March 2016. Therefore, section 13 of the federal methane regulations provides that operators that satisfy the current OGC requirements in the BC guideline126 and AER Directive 060,127 do not have to comply with the new federal emissions standards as well.128 However, in the case of other provinces such as Saskatchewan and Manitoba, where the federal government has concluded that the provincial regulations that limit emissions associated with HF operations and well completion are not of an equivalent rigor to the federal standards, operators must comply with the federal standards.129 The Canadian federal prohibition on venting at new shale oil and gas well sites parallels the Pennsylvania state no venting requirement.130 As a condition of state well permitting, natural gas must be captured and directed into a combustion device in Pennsylvania to prevent emissions from new oil and gas wells as in Canada.131 Following the lead of the Canadian federal government, the AER, like the state regulators in Colorado, Pennsylvania and California has adopted more stringent emission requirements and is phasing them in them in to further reduce the volume of methane released into the atmosphere.132 5. ENFORCEMENT In light of the more recent adoption of stricter federal methane emission regulations in Canada in 2018, there are no reported decisions yet regarding a Canadian enforcement action under the new federal regulations.133 However in the USA, the first enforcement action taken by federal and state regulators against a natural gas gathering, transportation and processing company for venting excess methane and VOC emissions, was settled in April 2018.134 A negotiated settlement Pursuant to section 113(b) of the Clean Air Act (CAA)135 and Pennsylvania Air Pollution Control Act,136 the US Department of Justice, EPA, and the Pennsylvania Department of Environmental Protection filed a complaint against MarkWest Liberty Midstream & Resources, LLC and Ohio Gathering Company (MarkWest) for contravening the ‘Prevention of Significant Deterioration’ provisions,137 and the ‘Non-Attainment New Source Review’ provisions,138 due to venting methane at a level that exceeded the prescribed volumes in two states, Pennsylvania and Ohio.139 In addition to being charged for releasing excess emissions from its facilities, the operator was charged for failing to secure the required permits and maintaining records for its stand-alone facilities and compressor stations. The defendant expressly denied any liability for contravening the emissions limits.140 Federal and state regulators sought injunctive relief and civil penalties.141 According to Christopher Rimkus, Managing Counsel for the corporate defendant, workers arrived at a pipeline site to carry out routine maintenance.142 Maintenance activities were performed daily, weekly or monthly to avoid the buildup of condensate in gas gathering and transmission pipelines. To prevent an explosion for safety reasons, natural gas was vented to reduce any pressure in the pipeline before the maintenance activities could proceed. Federal government agents arrived at the site for an inspection at approximately 8 a.m.; halted routine maintenance activities; began questioning the workers and collected samples. The agents finished the site inspection and made requests for the production of documents; however no additional action was taken by the federal agents at that time.143 The managing counsel has reported that after the execution of the federal search warrant it became clear to him that ‘the search warrant was based in large part on a number of misconceptions’. Specially, that operations ‘were not occurring in secret’ as they ‘are routinely scheduled’ and the activities in question ‘do not vent the volume of the entire pipeline segment to atmosphere – but a much smaller amount when inserting or retrieving a tool’.144 The managing counsel also notes that ‘Employees capture any natural gas liquids (NGLs) or other liquids that may be in the barrel in a storage vessel and do not release them to the ground. The public was categorically not at risk from the operations and no evidence has ever been presented to substantiate any claim to the contrary. Worker safety is protected during the operations as the studies conducted pre-search warrant attest to’.145 The enforcement action taken by federal and state regulators was framed as an Air Pollution Emergency Claim, under section 303 of the Clean Air Act.146 Counsel for the defendant reported that the basis for the search warrant and preliminary discussions with both the Department of Justice and the EPA focused on protecting industry workers and public health. He notes that ‘previous and subsequent scientific studies demonstrate there was no imminent and substantial danger to workers or public’,147 and the ‘EPA, states, and industry have traditionally been under the impression that emissions from the operations in question were de minimis’. After inspecting the site and reviewing its operations the corporate defendant ‘conservatively identified a small subset (less than 10%) of its sites where emissions might have been above Pennsylvania state de minimis permitting thresholds’. The managing counsel noted there was ‘No motivation or benefit for the company for not obtaining the appropriate permits as they are easy to obtain either for minor sources of emissions or under other criteria, and that operational design changes are easy and inexpensive to make so that the emissions fall below de minimis levels’.148 The operator had previously investigated and evaluated the development and testing of new technologies to sample and estimate the level of volatile organic compounds (VOCs) in emissions from its operations, and had previously undertaken design enhancements that substantially reduced VOCs, methane, and ethane emissions from its compressor stations and stand-alone facilities in Pennsylvania and Ohio.149 Notwithstanding a denial of liability, the defendant oil and gas operator ultimately settled the enforcement action.150 In the negotiated Consent Decree, both the defendant operator and governments acknowledged that ‘the settlement agreement was negotiated in good faith to avoid further litigation and that it is fair, reasonable, and in the public interest’.151 The settlement agreement provides for the payment of a civil penalty in the amount of US $610,000 and expenditures at a minimum cost to the operator of US $2 million.152 The operator must install air pollution control equipment at more than 300 facilities to further reduce emissions and improve air quality in Pennsylvania and Ohio.153 The EPA estimates that the new emissions controls will result in a reduction of 706 tons per year of VOCs, and a 91.5 per cent decrease in annual emissions throughout the company’s natural gas gathering system.154 In addition, the operator must install and operate ambient air monitoring stations near two compressor stations. The information collected from the monitoring stations about the nature and volume of emissions from the company’s operations must be shared with the general public. Furthermore, the operator must make available and share with other industry operators its innovative technologies developed to reduce emissions and allow other operators to use, on a royalty-free basis through licenses, these technologies to further reduce emissions.155 In addition, the operator must fund three supplemental community environmental improvement projects designed to reduce emissions from oil and gas facilities.156 The terms of the 104 page settlement agreement negotiated between the facility operator and the regulators are available for review and analysis.157 For reference and consideration in negotiations in future similar enforcement actions, the following terms of the agreement provide guidance as to the specific actions that must be taken by the facility operator to further reduce methane emissions from its operations that were agreed to in the negotiated Consent Decree in the first enforcement action reported in the USA: The agreement specifies the type of emissions reduction technology that must be used at compressor stations and the minimum efficiency (98 per cent) that must be achieved to destroy and reduce emissions158; The agreement specifies a date by which the operator must implement the specified emissions reduction program159; For the purpose of compliance with the agreement, the defendant company is obligated to calculate the mass of the VOC emissions160; In regard to ambient air quality monitoring of emissions from compressors, the defendant must install and operate for a minimum of 720 days, one meteorological station and two air sampling stations to sample and analyse the level of total VOCs and reduced sulphur compounds. The defendant must submit by 120 days from the effective date of the agreement an ambient air monitoring plan to the EPA for approval. The defendant must follow the approved monitoring plan and submit quarterly information reports and annual reports to the EPA161; In addition to the above actions required under the settlement agreement, three specific practices that are to be taken by the operator to protect workers from emissions include: Incorporating standard operating procedures into training materials that include protocols for response to alarms; Laminated job safety checklists for each site; Respiratory protection for changing filters at compressor stations.162 In regard to improving the containment of liquids at compressor stations and facilities, to prevent emissions at new facilities that are built, such facilities must have liquid containers with grounded steel receptacles that are covered at all times when not in use163; To minimize the risk that a corporate defendant will repeat the offence, the agreement also requires the following actions to be undertaken: To ensure the defendant’s managers, employees and contractors are aware of the enforcement action to reduce the potential for releasing excess emissions in the future, the defendant must provide a copy of the settlement agreement to all of its officers and managers to ensure that employees and contractors whose responsibilities may include compliance with the agreement are made aware of the terms of the agreement; and the defendant company must place an electronic version of the agreement in a section of its internal website related to environmental matters. The company is clearly responsible to ensure that all employees and contractors that perform any future work carry out that work in compliance with the terms of the agreement.164 The defendant in addition to paying the civil penalty must spend a minimum of US $2 million to implement the projects to reduce emissions under the creative sentence,165 and the projects must not be ones that the defendant was planning or intending to build, carry out or implement other than for the purpose of settling the enforcement action166; The financial requirements under the agreement to discourage the operator from releasing excess emissions again and to prevent the company from benefiting financially by transferring the facilities and the associated costs to another business entity include the following: The financial penalty is not tax deductible167; The settlement agreement prohibits the defendant from using the required reduction in methane emissions under the settlement agreement for the financially beneficial purpose of clean development emissions reductions that include emissions offsets and obtaining, trading or selling any emission reduction credits168; Interest is payable on the financial penalty on any amount that is past due at a rate specified in the agreement169; In regard to the sale or transfer of its facilities, the agreement provides that the obligations are binding on the successors or assignees of the company,170 and that the company must provide written notification to a successor or assignee and the government(s) of the existence of the agreement before the closing of the sale or transfer of the relevant facilities171; The defendant must condition any sale or transfer of ownership or operation ‘of any of the Covered Facilities upon the execution by the Third Party’ of a modification to the agreement to make the terms and conditions of the agreement ‘related to the ownership or operation of the transferred Covered Facilities applicable to the Third Party’.172 In addition to minimizing the risk that the facility operator will repeat the offence, to reduce the potential for other industry operators to commit a similar offence in the future, the comprehensive agreement requires the corporate defendant to communicate the lessons learned from the enforcement action with other industry operators as follows: Share with other industry operators the lessons learned from the enforcement action by posting information on its website; and offering educational presentations that include hosting four demonstrations or training sessions per year during a 3-year-period; In addition the agreement requires the facility operator to share on a royalty-free basis with other industry operators, the proven innovative technology that it developed to reduce emissions on an industry wide basis as follows: In regard to transferring the proven innovative emissions control technology that the defendant developed, it must provide on a royalty-free basis, licenses to other operators to use its proprietary design that is proven to decrease liquid accumulation and the associate volume of emissions. To promote the quick adoption and use of the innovative technology by other operators, the defendant must make available on a website that is publicly accessible no later than 6 months after the effective date of the agreement, a royalty-free license and information on the design of the technology. The defendant must make its technical staff available in person at every educational session, to demonstrate the installation and adoption of the VOC emissions reduction technology. The defendant must create comprehensive educational materials on the installation and maintenance of the technology to reduce emissions173; The above terms of the comprehensive settlement agreement negotiated between the facility operator and the regulators provide concrete examples of the actions that must be taken by the facility operator to further reduce emissions from its operations, consistent with the EPA 2016 emission reduction standards. 6. CONCLUSION For decades, OGC regulations in the USA and Canada have been employed by regulators to limit the volume of methane emissions from upstream operations. As in other oil and gas producing nations these regimes focus on maximizing long term oil and gas production and at the same time minimizing the waste of natural gas by employing cost effective measures to optimize government and industry resource revenues. In light of the commitments made under the Paris Agreement, the US and Canadian governments adopted more stringent national emissions reduction regulations in 2016 and 2018 respectively. Current litigation in the USA creates uncertainty about the extent to which methane emissions enforcement actions will be taken in the near future. However in Canada, new federal regulations that build on existing provincial OGC schemes, create uniform national emissions standards to further significantly reduce emissions from upstream oil and gas industry sources. The regulations require a substantial reduction in emissions from the largest upstream sources—facility equipment leaks and venting. The regulations mandate increased capture and beneficial use of otherwise wasted natural gas by requiring timely implementation of equipment leak detection and repair programmes, along with three annual facility inspections to confirm methane leaks have been repaired. Equipment that leaks methane must be upgraded or replaced within specified time periods to further reduce emissions from leaks. The regulations create monthly and annual facility venting limits at upstream facilities. As an alternative to venting methane, the regulations require that a higher volume of natural gas to be captured and used by upstream operators for beneficial purposes such as heating or generating electricity in facilities or destroying potential emissions. To prevent an increase in emissions from the expanding shale oil and gas industry in Canada, venting at new oil and gas well sites is now prohibited. A comprehensive settlement agreement negotiated between the facility operator and regulators in the first US methane emissions enforcement action provides concrete examples of conditions designed to further reducing upstream emissions from venting in the USA, consistent with the objectives of the EPA emissions reduction standards adopted in 2016. Footnotes 1 E. Allison and B. Mandler, ‘Methane Emissions in the Oil and Gas Industry’ (1 June 2018), online: American Geosciences Institute accessed 27 May 2019. 2 Environment and Climate Change Canada, ‘Proposed methane regulations – A significant step in addressing climate change in Canada’, (Ottawa: ECCC, June 2017), accessed 7 January 2019. 3 United Nations, Climate Change, entered into force 4 November 2016, accessed 27 May 2019. 4 US Environmental Protection Agency, ‘Actions and Notices about Oil and Natural Gas Pollution Standards’ accessed 18 December 2018; Memorandum, Docket for rulemaking, ‘Oil and Natural Gas Sector – New Source Performance Standards, National Emissions Standards for Hazardous Air Pollutants, and Control Techniques Guidelines’ (EPA-HQ-OAR-2010-0505), 17 October 2017, 7. 5 Canadian Environmental Protection Act, SC 1999, c 33. 6 Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), (2018) C Gaz II, 152:1; accessed 27 May 2019. 7 ibid. 8 Oliver Scheising and others, ‘Remote Sensing of Fugitive Methane Emissions from Oil and Gas Production in North America Tight Geologic Formations’ (2014) 2 (10) Earth’s Future 548. 9 Robert Howarth and others, ‘Natural Gas: Should Fracking Stop?’ (2011) 477 (7364) Nature 271; Robert Howarth and others, ‘Methane and the Greenhouse-Gas Footprint of Natural Gas from Shale Formations’ (2011) 106 (679) Climatic Change 679. 10 Don Smith and others, ‘Where “shale” We Go from Here: Opportunities and Challenges in Shale Plays Located Outside the USA’ (2017) 10 Journal of World Energy Law and Business 159. 11 Clean Air Act, 42 USC. 12 EPA, ‘EPA Releases First-Ever Standards to Cut Methane Emissions from the Oil and Gas Sector’, (12 May 2016) accessed 3 January 2019. 13 ibid. 14 EPA (n 12). 15 US Dept of Interior, Bureau of Land Management accessed 9 January 2019. 16 Bureau of Land Management, Waste Prevention and Resource Conservation Rule, 43 CFR, subpart 3179, accessed 10 January 2019. 17 Smith and others (n 10) 169. accessed 27 May 2019. 18 Blakely Murphy (ed), Conservation of Oil and Gas: A Legal History 1948 (American Bar Association 1949). 19 accessed 15 February 2019. 20 Gina McCarthy, ‘U.S. Environmental Protection Agency, EPA Taking Steps to Cut Emissions from Existing Oil and Gas Sources’ (10 March 2016), accessed 27 May 2019. 21 Drew Nelson, ‘The Power of Three: Mexico Aligns with U.S and Canada on Oil and Gas Methane Pollution’ Environmental Defense Fund: Energy Exchange (29 June 2016); Environment and Climate Change Canada, ‘Canada’s methane regulations for upstream oil and gas’ accessed 27 May 2019. 22 Exec Order No 13,783, 82 Fed Reg 16,093 (28 March 2017). 82 US Fed Reg at 61,925. 23 US Environmental Protection Agency, ‘Regulatory Actions: Notices about Oil and Natural Gas Air Pollution Standards, EPA Proposes to Stay Oil and Gas Standards for Two Years’ accessed 8 January 2019; changes to provisions that cover equipment leaks, pump and professional engineer certification requirements were considered. 24 ibid, ‘EPA Amends Narrow Portions of Fugitive Emissions Requirements in the 2016 New Source Performance Standards for the Oil and Natural Gas Industry’. 25 Hydraulic Fracturing on Federal and Indian Lands, Rescission of a 2015 Rule, 82 Fed Reg 61,924, 29 December 2017; codified at 43 CFR, pt 3160. 26 ibid 61,925. 27 Wyoming v Zinke, 871 F.3d 1133 (10 Cir 2017), Sierra Club v Zinke, No 3:18-cv-00524 (ND Cal., filed 24 January 2018), California v BLM, No 4:18-cv-00521 (ND Cal. filed 24 January 2018); California v BLM, No 3:17-cv-07186 (ND Cal. filed 19 December 2017). The Sierra Club, Environmental Defence Fund, and several other environmental groups filed a similar complaint on the same date. See Sierra Club v Zinke, No 3:17-cv-07187 (ND Cal. filed 19 December 2017). The states and environmental groups also filed separate motions seeking a preliminary injunction, requesting that the court preliminarily enjoin the 2017 delay rule and reinstate the 2016 venting and flaring rule. The motions for preliminary injunction were granted on 22 February 2018. 28 Pub L 79-404, 60 Stat 237. 29 (n 3). 30 Government of Canada, Environment and Climate Change Canada, Pan-Canadian Framework on Clean Growth and Climate Change: Canada’s Plan to Address Climate Change and Grow the Economy, (Gatineau, Quebec: Environment and Climate Change Canada, 2016). 31 ibid. 32 ECCC (n 30, 8). 33 EPA, ‘Overview of Final Amendment to Air Regulations for the Oil and Natural Gas Industry’ accessed 14 January 2019; see also ECCC (n 30) s 1. 34 ECCC (n 30) s 1. 35 Environment and Climate Change Canada, ‘Canada’s Emissions Trends 2014: chapter 2’ (Ottawa: ECCC, 2014), online: ECCC accessed 5 January 2019. 36 Environment and Climate Change Canada, Regulatory Impact Analysis Statement for Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), 151 (21) Can Gaz I, accessed 15 January 2019. 37 Environmental Protection Agency Regulatory Impact Analysis, Docket for Rule Making, ID No EPA-HQ-OAR-2010-0505-7630. 38 ECCC (n 30). 39 ibid. 40 ibid. 41 ibid ss 58(1)–(2). 42 Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (2018) 152(1) C Gaz II 62 (Regulatory Impact Analysis Statement) accessed 27 May 2019. 43 Constitution Act, 1867 (UK), 30 & 31 Vict, c 3, Part VI (Distribution of Legislative Powers), s 92(13) [Constitution Act, 1867]; Constitution Act, 1930 (Transfer of Natural Resources Agreement). 44 ibid. 45 ibid Schedule 1982 amendment. 46 ibid. 47 ibid ss 91(7), 91(10), 91(12), 91(24). 48 ECCC (n 30). 49 RSC 1985, c I-7. 50 accessed 18 January 2019. 51 ECCC (n 30). 52 National Energy Board, accessed 24 December 2018. 53 RSC 1985, c.-7. 54 RSC 1985, c. C-32; see R v Canada Metal Co [1983] 2 WWR 307. 55 SC 1999, c. 33. 56 Peter W Hogg, ‘Constitutional Authority over Greenhouse Gas Emissions’ (2009) 46(2) ALR, at 514. 57 ibid at 514. 58 [1997] 3 SCR 213. 59 ibid s 92(1) (c). 60 [1988] 1 SCR 401. 61 ECCC (n 30). 62 RSA 2000, c E-12. 63 SA 2003, c C-16.7. 64 SBC 2003, c 53. 65 SBC 2007, c 42. 66 Dan Healing, ‘Massive LNG project in B.C. Gets Shareholders’ Final Approval’ (Toronto Star, 2 October 2 2018) accessed 10 January 2019. 67 Government of British Columbia, ‘Oil and Gas Activities in Northeastern B.C. at Human Health Risk Assessment’, online: Government of British Columbia, 2017, . 68 COGCC Rules, accessed 1 March 2019. 69 Blakely (n 18). 70 Turner Valley Gas Conservation Act, SA 1932; Oil and Gas Conservation Act, RSA 2000, c O-6; Alta Reg 151/1971 and amendments up to and including 1/2016. 71 RSA 2000, c O-6. 72 An Act for the Conservation of Oil and Gas Resources of the Province of Alberta, SA 1938, c.1. 73 Oil and Gas Conservation Act, RSS 1953, c 327. 74 Petroleum and Natural Gas Act, 1954, c 31. 75 (n 23). 76 ibid. 77 (n 2). 78 Alberta Energy Regulator, ‘AER Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting’, (Edmonton: 27 September 2018). 79 SA 2012, c R-17.3 s 3. 80 Environmental Protection and Enhancement Act, RSA 2000, c E-12. 81 (n 69). 82 Oil and Gas Conservation Rules, Alta Reg 151/1971; 83 (n 77). 84 AER Directive 017: Measurement Requirements for Oil and Gas Operations accessed 30 December 2018. 85 AER Directive 084: Requirements for Hydrocarbon Emissions Controls and Gas Conservation in the Peace River Area, Sept. 11, 2018, accessed 30 December 2018. 86 ibid s 1(1)(i); Alberta Energy Regulator, ‘Acts, Regulations & Rules’, accessed 29 December 2018. 87 Flaring and Venting Reduction Guideline, Version 5.1, BC Oil and Gas Commission (May 2018) 55, accessed, 3 January 2019. 88 Canadian Association of Petroleum Producers, ‘Best Management Practice: Management of Fugitive Emissions at Upstream Oil and Gas Facilities”’(2007) 9. 89 ibid. 90 ibid. 91 ibid. 92 ibid. 93 ibid. 94 The Alberta Energy Regulator in 2018 and 2019 has revised directive 060 and created directives 084 and 017, and is currently in the process of better aligning the Alberta provincial emissions reduction requirements with the 2018 federal regulations. 95 (n 2, 8). 96 (n 6). 97 ibid. ss 26-45. 98 ibid, s 29. 99 ibid, s. 32. 100 (n 57) Fed. Reg. #2016-2767; 43 CFR, s. 3179.304; accessed 10 January 2019. 101 (n 6). 102 ibid, ss. 30(1)-(3). 103 Civil Action No. 2:18-cv-00520-LPL (US Dist Ct Western Penn). 104 (n 1). 105 ibid, s 37(1), 37(2), 39(1). 106 ibid. 107 ECCC (n 2). 108 Canadian Centre for Energy Information, “Our Petroleum Challenge”, JJ Kubik, ed. (8th ed), 2013; Upstream facilities are those connected to oil and gas drilling, exploration and production operations. 109 ECCC (n 6). 110 ibid. 111 ibid. 112 Examples of uses include heating facility buildings and generating electricity. 113 ECCC (n 6). 114 ibid. 115 (n 6) s 9. 116 (n 108). 117 (n 6) s 9. 118 (n 6) ss. 14(b), 16(3). 119 ibid, ss 18(2), (3). 120 ibid, s 14. 121 (n 8). 122 Canadian Centre for Energy Information, ‘Our Petroleum Challenge’, 8th ed at 140. 123 Smith and others (n 10). 124 Canada, National Energy Board, British Columbia Oil and Gas Commission, Alberta Energy Regulator & the British Columbia Ministry of Natural Gas Development, Energy Briefing Note: The Ultimate Potential for Unconventional Petroleum from the Montney Formation of British Columbia and Alberta (Calgary: NEB, 2013), accessed 15 January 2019. 125 (n 8). 126 (n 86). 127 (n 77). 128 (n 6) ss 11, 12. 129 (n 6). 130 Energy Information Administration, Today in Energy (2017), accessed 27 May 2019, Pennsylvania, Department of Environmental Protection, General Permit for Air Pollution Control in Natural Gas Compression and/or Processing Facilities (GP-5) (Charleston: Department of Environmental Protection 2013), accessed 27 May 2019. 131 1959, PL 2119, No 787, as amended. 132 ‘Requirements for Hydrocarbon Emission Control and Gas Conservation in the Peace River Area’ Directive 084, effective 27 September 2018; ‘Upstream Petroleum Industry Flaring, Incinerating and Venting’ Directive 060 (Revised, effective 1 January 2020); ‘Measurement Requirements for Oil and Gas Operations’ Directive 017 accessed 5 January 2019. 133 (n 6). 134 Civil Action No 2:18-cv-00520-LPL (US Dist Ct Western Penn), 42 USC ss 7501–15. 135 42 USC s 7413(b). 136 PL 2119, No 787, 1959, as amended. 137 42 USC ss 7490–92. 138 (n 134). 139 ibid. 140 ibid. 141 EPA, Consent Decree, accessed 27 May 2019. 142 Christopher Rimkus, ‘Launcher and Receiver Operational Enhancement: A Case Study’ Rocky Mountain States Section of the Air and Waste Management Association, 14 March 2018; accessed 16 February 2019. 143 ibid. 144 ibid. 145 ibid. 146 ibid. 147 ibid. 148 ibid. 149 ibid. 150 (n 141). 151 ibid. 152 ibid. 153 ibid. 154 ibid. 155 ibid. 156 ibid. 157 ibid. 158 ibid, para 13. 159 ibid, para 14. 160 ibid, para 11. 161 ibid, para 28. 162 ibid. 163 ibid, para 23. 164 ibid, para 8. 165 ibid, para 28. 166 ibid, para 29. 167 ibid, para 27. 168 ibid, para 47. 169 ibid, para 24. 170 ibid, para 3. 171 ibid, para 4. 172 ibid, para 5. 173 ibid, para 28. © The Author(s) 2019. Published by Oxford University Press on behalf of the AIPN. All rights reserved. This article is published and distributed under the terms of the Oxford University Press, Standard Journals Publication Model (https://academic.oup.com/journals/pages/open_access/funder_policies/chorus/standard_publication_model) TI - Plugging the holes—new Canadian and US regulations to reduce upstream methane emissions JF - Journal of World Energy Law and Business DO - 10.1093/jwelb/jwz014 DA - 2019-08-01 UR - https://www.deepdyve.com/lp/oxford-university-press/plugging-the-holes-new-canadian-and-us-regulations-to-reduce-upstream-0G45y0Lewh SP - 294 VL - 12 IS - 4 DP - DeepDyve ER -