Winner of the 2019 NEERLS Law School Essay Contest Gowling WLG - David Estrin Prize

  • June 24, 2019

Environmental Liability?: The Current State of Alberta’s Oil and Gas Well and Oil Sands Mining Liability Regimes

Riley Weyman, Schulich School of Law at Dalhousie University


A recent investigative report revealed that the Alberta Energy Regulator (“AER”) has estimated “worst case scenario” financial liabilities for the province’s oil & gas sector at $260 billion.[1] To account for these immense liabilities, the AER holds only $1.6 billion in collected security through its financial security schemes.[2] The gap between the oil & gas sector’s estimated financial liabilities and the limited amount of financial security held by the AER questions the efficacy of the province’s liability regimes. This paper will provide an overview of financial liabilities in Alberta’s oil and gas liability regimes and discuss the requirements for reclaiming lands disturbed by oil and gas projects. It will then outline the current financial security schemes for oil and gas wells and oil sands mining projects before identifying their shortcomings and providing examples of successful models from other jurisdictions. This will be followed by an analysis of how aspects of these successful models can be applied to the Alberta context.

Financial Liabilities

Financial liabilities in the oil & gas sector are calculated by determining the sum of the costs to suspend, abandon, remediate and reclaim the lands disturbed by a project.[3] This calculation is based on approved closure and remediation plans submitted by the operator.[4] Some of the costs include dismantling infrastructure, removing all by-products, contouring landforms and all planning, reporting and monitoring costs associated with the process.[5] These liabilities can vary significantly depending on the nature and size of a project, with reclamation costs for oil sands mining projects typically dwarfing those of oil and gas wells.[6] A company is relieved of these liabilities as they progress through the reclamation process that ends with the granting of a reclamation certificate by the AER.[7]

It is important to distinguish these financial liabilities from an operator’s liability for surface reclamation issues after a reclamation certificate is issued. For oil and gas wells, there is a 25-year liability period after a reclamation certificate is issued where the operator remains liable for surface reclamation issues.[8] After this period has elapsed, the liability is transferred to the government.[9] Operators are, however, liable in perpetuity for contaminations on their well-sites even after the issuance of a reclamation certificate.[10] During this liability period, reclamation certificates can be cancelled if the AER determines an application for a reclamation certificate was inaccurate, the site may be contaminated or the site no longer meets the reclamation standards.[11] These cancellations are generally the result of an operator failing a random or risk based audit by the AER.[12] A cancellation may also be the result of an investigation following a complaint, but the AER does not specifically define this process or publish data on these investigations.[13]

Oil sands operators are under a different liability regulation. If they held an approval for the site for which the reclamation certificate was issued, their liability is transferred to the government upon issuance of the certificate.[14] Like well operators, they are still liable in perpetuity for any contamination they cause on the land.[15] Syncrude remains the only operator to receive a reclamation certificate for land disturbed by oil sands mining.[16] They were issued a certificate for 104 hectares of land known as “Gateway Hill” in 2008.[17]

What is Reclamation?

The extent of an operator’s financial liabilities is largely based on the estimated costs for reclaiming the lands they have disturbed.[18] These estimated costs can vary significantly depending on the definition of reclamation that is adopted and the standards used in issuing a reclamation certificate.[19] The duty to reclaim land is set out in section 137 of Alberta’s Environmental Protection and Enhancement Act (“EPEA”).[20] It requires all operators to conserve and reclaim specified land and mandates the issuance of a reclamation certificate.[21] The Conservation and Reclamation Regulations (“CRR”), issued under the EPEA, state the objective of conservation and reclamation as returning the specified land “to an equivalent land capability”.[22] Equivalent land capability is defined as ensuring “the ability of the land to support various land uses after conservation and reclamation is similar to the ability that existed prior to an activity being conducted on the land, but that the individual land uses will not necessarily be identical”.[23] This ambiguous regulatory standard leaves significant room for interpretation and has led to competing views of what is considered adequate reclamation.[24]

The AER is tasked with issuing reclamation certificates and as such, ultimately has the final say on how to interpret equivalent land capability. They have issued several documents providing guidance on relevant criteria that should be considered in the certification process. Some of them highlight stakeholder concerns that the AER applies an industry friendly interpretation that neglects certain important stakeholder values as will be explored below.

Reclamation in the Oil Sands

The Land Capability Classification for Forest Ecosystems (“LCCS”) offers an example in the oil sands context.[25] The LCCS was a guidance document prepared by the Cumulative Environmental Management Association (“CEMA”) to help the Alberta government determine land capability in the oil sands region.[26] It created 5 classes of land capability based on the land’s ability to support productive forest uses.[27] Basing equivalent land capability largely on land’s ability to support productive forest uses significantly over-values the industrial worth of merchantable timber and de-values the productivity and importance of wetland and lowland eco-systems.[28] It takes a predominantly commercial view of capability and tends to ignore the significance of the pre-disturbance conditions, both ecologically and from Indigenous stakeholder and rights-holder perspectives.[29]

The LCCS was supplemented by the Criteria and Indicators Framework for Oil Sands Mine Reclamation Certification (“the Framework”) in 2013.[30] It was meant to be a “preliminary step” in defining the requirements for issuing a reclamation certificate in the oil sands region.[31] The updated 2014 version of the Framework is considered to be incomplete and requiring additional development before it can be fully implemented.[32] Unfortunately, as of 2016, CEMA, who developed the Framework for the Alberta government, has suspended all operations until further notice due to a lack of funding.[33] This leaves the Framework in a state of flux, as there has been no update or additional guidance on its application since 2014.

The Framework did begin to address the importance of taking into consideration the views of Indigenous stakeholders and rights-holders. The Framework was drafted by a CEMA working group that included representation from Aboriginal groups and stakeholders.[34] The Framework has a series of criteria and indicators that are supposed to help determine whether a particular objective is being achieved.[35] Several of the indicators and criteria for determining whether “reclaimed landscapes support an equivalent land capability appropriate to the approved end land use” include reference to traditional and spiritual uses of land.[36] One such indicator is whether “traditional plant communities have been established in mine reclaimed wetlands”.[37] This indicator was adopted to take into account the important role wetlands and specific wetland plants play in a traditional way of life.[38] This is an important addition to reclamation guidance as wetlands were an ecosystem that was de-valued under the LCCS.[39] However, as this framework was never fully completed or implemented, it is difficult to determine whether or not these considerations are given the weight they deserve.

Current reports indicate that some Indigenous groups and First Nations rights-holders are still unhappy with the status of wetland reclamation in certain oil sands projects.[40] When consulted by the AER for a June 2018 review of Syncrude’s Aurora North Tailings Management Plan, the Fort McKay First Nation and Athabasca Chipewyan First Nation both reported discontent with Syncrude’s elimination of wetlands and proposed changes to the final landscape of their mine site.[41] Many Indigenous stakeholders and rights-holders were also critical of Syncrude’s lack of input from Indigenous communities in their planning and research.[42] The Mikisew Cree First Nation, Fort McMurray Métis Local 1935 and the Fort McKay Métis Community Association all took issue with Syncrude and the AER basing their reclamation certification on indicators and criteria that were not acceptable to Indigenous communities.[43] This shows either a lack of implementation or divergence from the Indigenous consultation recommended by the Framework.

This discontent comes at a time when the government of Alberta and industry are supposed to be taking a more co-management based approach to oil sands development. The Lower Athabasca Regional Plan 2012-2022 (“LARP”) identifies the importance of upholding the constitutionally protected rights of Indigenous peoples in the oil sands context.[44] It recognizes the Crown’s duty to consult when Indigenous rights, including the rights to hunt, fish and trap for food, are adversely affected.[45] It proposes that government and industry must move beyond the duty to consult and towards a greater balancing of Indigenous and government/industry interests.[46] However, six First Nations in the oil sands region filed applications for a review of the LARP stating that the government of Alberta failed to effectively integrate their interests into the LARP.[47] The review panel, in their 256 page report, urged the Alberta government to follow through with their obligations in the LARP and suggested the creation of a Traditional Land Use Management Framework that would recognize a more co-management focused approach to land management.[48]

The Alberta Government has also tried to push towards a co-management focused approach by signing several agreements with Indigenous communities in the oil sands. In 2016, Premier Rachel Notley signed a protocol agreement with Treaty 8 First Nations leaders in northern Alberta.[49] The agreement establishes six working groups, including one dedicated to development and the environment, and states one of its key goals as better resource revenue sharing for First Nations communities.[50] The agreement is geared at establishing more collaboration and co-operation between First Nations, industry and the Alberta government.[51]

In January 2016, a renewed collaboration agreement was signed by the Alberta government and Fort McKay First Nation Chief Jim Boucher.[52] The collaboration agreement was meant to ensure a 10km zone around Moose Lake, a zone identified as having significant importance to the Fort McKay First Nation and one of the last areas of undisturbed land in the area, was protected from encroaching oil sands developments.[53] In April 2016, Jim Boucher and the Fort McKay First Nation filed a statement of claim against the government, stating that the government has failed to uphold their agreement after allowing an operator to apply to develop oil sands on the edge of Moose Lake.[54] The lawsuit sparked increased collaboration between the groups and they co-lead the drafting of a 45-page report featuring recommendations on how best to manage the land around Moose Lake.[55] The Alberta government released a draft of the newly completed management plan in February 2018 and requested feedback from the public.[56] The new management plan will be integrated into the LARP and depending on its success may be a better model for managing reclamation and development in the oil sands while also recognizing and protecting Indigenous groups’ Treaty rights and traditional land uses.[57] It could be a step towards implementing the LARP Review Panel’s recommendation for a Traditional Land Use Management Framework.

Reclamation for Oil and Gas Wells

Reclamation for oil and gas wells differs from oil sands reclamation and the certification process follows different guidelines. There are many overlapping considerations in both reclamation contexts, but the oil sands guidance often engages more stakeholder consultation due to the increased size and intensity of the projects.[58] The government of Alberta issued separate guidance documents for well reclamation certification on native grasslands, forested lands, cultivated lands and peatlands.[59] Unfortunately, none of them include specific reference to Indigenous stakeholder engagement or Indigenous rights.[60] The land specific guidance documents were created by a working group of “representative stakeholders” that did not include any listed representatives from Indigenous communities or First Nations.[61] The only reference to Indigenous rights or stakeholders in the well reclamation certification guidance is in the updated application submission requirements, where it says that private land includes Métis settlements and reclamation on a Métis settlement requires the operator to maintain records of any contact with landowners, occupants and interest holders.[62]

Despite a lack of specific reference to Indigenous rights or stakeholder engagement, stakeholders and more specifically, landowners are involved to some extent in the well reclamation certification process. Once the AER receives an operator’s application for a reclamation certificate and they deem it meets their validation and assessment rules, they post a notice of application on their website.[63] However, they leave it to the operator to provide a copy of the application package, notify the landowner and any interest holders or occupants and retain proof of delivery.[64] Once the application is posted to the AER website, there is a 30-day period for persons who believe they are adversely affected by the application to file a statement of concern with the AER.[65] If no statement of concern is filed, a reclamation certificates is issued automatically.[66] If a statement of concern is filed, an additional review is conducted in an effort to address the concern.[67] After the AER has made a decision on an application for certification, they provide notice of the decision to the registered landowner and anyone they consider to have been directly or adversely affected by the well site while it was operating.[68] “Eligible persons” are allowed to appeal certain decisions made by the AER if they meet specific criteria under the Responsible Energy Development Act (“REDA”) and the Responsible Energy Development Act General Regulation (“REDA Regulation”).[69]

The most active engagement with landowners is if an operator proposes to change the land use of a well site from its pre-disturbance condition. The reclamation certification guidance documents on native grasslands, forested lands, cultivated lands and peatlands all require the agreement of a landowner or land manager before the change of land use can be approved.[70] If a change of land use is proposed, the landowner or land manager must be involved in the discussion of how the land use will be changed. They must also sign a written agreement consenting to the change.[71]

Landowners and occupants are also consulted if an operator proposes to bury non-oilfield waste or leave facilities in place on a well site.[72] Similar to the provisions for changes in land use, an operator is required to receive written consent from landowners and occupants before any non-oilfield waste can be buried on a well site.[73] A landowner or manager also has veto power over whether any facilities or features will be left on a well site.[74] If they do not agree with having a feature left on their property, full removal and reclamation is mandatory.[75] Landowners or managers can only consent to leaving features or facilities that are accepted by Alberta Environment and Parks (“AEP”) as improvements to landowner use.[76]

The limited stakeholder engagement and lack of recognition of Indigenous consultation in the reclamation certification guidance for oil and gas well sites represent a missed opportunity. The Reclamation Criteria Advisory Group (“RCAG”) that created the guidance documents claim to have brought together representative stakeholders.[77] Unfortunately, by not including Indigenous viewpoints, the RCAG ignore traditional land use values and potentially violate constitutionally protected Treaty rights. These cultural values and rights need to be taken into account when assessing the full value of reclamation costs and an operator’s resulting financial liabilities. The Alberta government indicated intent to implement protocol agreements with Indigenous groups covered by Treaties 6 and 7, that cover the central and southern Alberta.[78] Hopefully this type of protocol would lead to increased co-management of oil and gas development and well reclamation that impact Indigenous groups’ ability to exercise their constitutionally protected rights to hunt, fish and trap on their traditional lands.

Types of Financial Security

There are several different types of financial security or “financial assurance” that a regulator can employ to safeguard against an operator’s default on their financial liabilities. These types of financial assurance can be divided into five categories: hard financial assurance from operators, soft financial assurance from operators, third-party assurance, sector level assurance and public assurance.[79] These categories all try to find a delicate balance between the policy goals of deterrence, compensation and economic activity.[80] A liability regime can be composed of multiple types of financial assurance, as tiered solutions can be an effective way to meet the regulator’s desired policy goals.[81]

Financial security schemes for oil and gas activity in Alberta are regulated and overseen by the AER.[82] The AER has authority to collect financial security from operators under section 135(1) of the EPEA.[83] The AER has typically developed financial security schemes that favour economic development at the cost of deterrence and compensation.[84] This conscious weighing of policy goals helps to explain the massive shortfall they are currently facing between their estimated financial liabilities and calculated financial securities. Similar to their guidance on reclamation certification, the AER and the Alberta government have separate financial security schemes for oil and gas well and oil sands mining projects.

Alberta’s Financial Security Scheme for Oil Sands Mining Projects

The AER’s Mine Financial Security Program (“MFSP”) governs financial security for oil sands mining projects.[85] The MFSP also governs financial security for coal mines, but does not cover in-situ oil sands sites.[86] Financial security for in situ oil sands sites is still regulated by the AER, but falls under their oil and gas well liability regime, which will be addressed later in this paper.[87] The MFSP collects financial security from operators and can use the security to pay for suspension, abandonment, remediation or reclamation costs when an operator is unable or unwilling to do so.[88] The MFSP includes four distinct financial assurance programs: the Base Security Deposit, the Asset Factor Safety Deposit, the Outstanding Reclamation Deposit and the Operating Life Deposit.

The Base Security Deposit (“BSD”) is mandatory for all new mines and was applied to mines with existing EPEA approvals when it was introduced in 2011.[89] It requires all newly approved oil sands mines to provide a BSD of $30 million for an oil sands mine and $60 million for an oil sands mine with an upgrader.[90] Mines that held EPEA approvals prior to MFSP implementation had the amount of financial security they paid to the government under the previous program converted into their BSD. These previously held securities often amounted to significantly higher base security than the current table amounts. For example, the Suncor Base Mine had over $359 million in government held security converted to their BSD, an amount significantly higher than the $60 million for a newly approved mine with an upgrader.[91] The goal of the BSD is to secure the AER with enough funds to safely suspend a mine’s operations after an operator defaults, until a new operator takes over or the site is closed.[92]

The Asset Factor Safety Deposit (“AFSD”) is meant to act as a way of differentiating mining projects based on their financial risks.[93] The goal of the AFSD is to ensure that a mine has sufficient assets to attract a new operator to take over a mine’s operations and eventual reclamation if the current operator defaults.[94] An operator is required to make an AFSD when the value of their MFSP assets is below three times the value of their MFSP liabilities.[95] This ratio of MFSP assets to MFSP liabilities is referred to as the asset safety factor (“ASF”) and has a threshold value of 3.0.[96] If the ASF falls below 3.0, the deposit an operator would be required to pay would be the amount required to return the ASF to 3.0, while accounting for current BSD and Operating Life Deposits.[97]

The Outstanding Reclamation Deposit is intended to act as an incentive for the proactive management of a mine’s reclamation liabilities.[98] It attempts to keep operators in line with the reclamation schedule set out in their approved mine reclamation plan. This reclamation schedule shows the total number of hectares of land an operator proposes to permanently reclaim each year.[99] If an operator does not meet their proposed total of permanently reclaimed land in any given year, they are supposed to pay a deposit of $75,000 per hectare that was scheduled, but not permanently reclaimed.[100]

The Operating Life Deposit is meant to be a way for the AER to collect more financial security from an operator as a mine reaches the end of its productive life.[101] Once a mine has 15 years or less of reserves, they are obligated to annually pay 10% of their total outstanding MFSP liabilities until the AER has security representing the entire cost of their MFSP liabilities.[102] Following this timeframe, the AER would hold financial assurance for the full cost of MFSP liabilities 5 years before the end of its productive life.[103] This system was designed to increase financial assurance when a mine becomes less valuable and more susceptible to default on their financial liabilities.[104]

The $939 million held in oils sand project security deposits under the MFSP are typically provided in forms of third-party or hard financial assurance.[105] Currently, the form of security most often used is a letter of credit.[106] Letters of credit are a form of third-party assurance provided by banks.[107] They function similar to bonds by having operators pay regular premiums to the bank in exchange for the bank paying out the assured sum if the security needs to be accessed.[108] Cash deposits and qualifying environmental trusts are forms of hard assurance that operators are also allowed to provide as security.[109] They are special financial assurance vehicles that provide cash in exchange for special tax benefits.[110] The $939 million held under the MFSP for oil sands project reclamation only represents BSD deposits, as the AER has not yet collected assurance under the other three deposit programs.[111]

Weaknesses of the MFSP

One of the key weaknesses of the MFSP in relation to oil sands projects is the low stringency in the timing of collecting financial assurance. The $939 million currently held under the MFSP for oil sands projects represents only 3.4% of the $27.4 billion in calculated oil sands liabilities.[112] Under the current scheme, the amount held in security has declined since 2014, while the amount of calculated liability has risen by over $6 billion.[113] This is in sharp contrast to financial assurance posted by coal mine operators who are also subject to the MFSP. With the drop in the coal prices, recognizing the high financial risk of their projects, all coal mine operators opted to provide full financial assurance to cover the reclamation costs of their mines.[114] This decision was based on the uncertainty of the future of coal mining in Alberta after the government announced plans to move away from a dependence on coal power by 2030 and the AER announced plans to increase auditing of coal mines.[115] Increasing the number of audits the AER conducts on oil sands operations could help to provide pressure for a move towards posting full financial assurance. However, without the government announcing plans to move away from oil within the near future, a voluntary move to full financial security in the oil sands would seem much less likely. Whether or not oil sands operators opt to post full financial security, leaving over 95% of oil sands liabilities unsecured for the bulk of their operating life leaves the public unnecessarily vulnerable to increasingly high social costs.[116]

A second weakness of the MFSP is the limited effectiveness of its financial risk differentiation mechanism. The AFSD is supposed to ensure that financially riskier operators post additional security to reflect their added risk of defaulting on their liabilities.[117] Under its current form, the AFSD has each operator self-report their resource assets, reclamation liabilities and the amount of security they are to post for each deposit.[118] This information is reported in a brief annual report that is certified by the operator’s chief executive or chief financial officer.[119] The calculations are not confirmed by a third-party nor are operators required to submit supporting documentation.[120] Not only is there no third-party audit of an operator’s self-reported figures, but the internal auditing by the AER has been insufficient. In 2015, only five higher level audits had been conducted by the AER since the MFSP was introduced in 2011.[121]

The self-reported calculations in an operator’s annual report also tend to overvalue a mine’s resource assets. During their 2015 audit of the MFSP, the Auditor General of Alberta determined that treating proven and probable reserves as equal risks overvaluing a mine’s assets.[122] This is because probable reserves only have a 50% chance of ever being realized.[123] Equating them with proven reserves that have a 90% chance of commercial extraction does not account for the significant risk that these resources will never be realized; therefore, it tends to inflate a mine’s assets.[124] The asset calculations also do not factor in a discount rate for the possibility of future oil market fluctuations or regulatory and technological change.[125] Given the relatively longer lifespan of an oil sands mine, not accounting for these factors can lead to serious distortions.[126] This is especially concerning given the potential for stranded assets as a result of climate change initiatives. With the divestiture from fossil fuels, there is an increasing chance that oil reserves and other fossil fuels will remain in the ground in an effort to cut emissions and meet global temperature targets.[127] A 2015 study showed that in order to reach the temperature targets set out in the Paris Agreement, one third of the world’s oil reserves should remain undeveloped.[128] With the value of oil sands assets contingent on the extraction of proven and probable reserves, this could significantly weaken the reported financial strength of oil sands operators.

Self-reported oil sands reclamation liability costs are also largely based on unproven technology. Likely, the largest reclamation liability in oil sands mining projects, on both physical and economic scales, is reclaiming tailings ponds.[129] Tailings ponds hold the liquid tailings that contain bitumen and other toxic particles that could not be recovered during the extraction process.[130] Before the water can be released back into the natural environment, it must be treated and fully remediated to remove all contaminants.[131] Unfortunately, there is currently no effective long-term solution to dealing with these liquid tailings.[132] The current method is to produce end pit lakes by a process called water capping.[133] This method shows promise, but relies largely on unproven technologies, as no end pit lake has been successfully reclaimed outside of lab experiments.[134] Operators that plan on relying on this water capping technology are obligated to develop alternative options for reclaiming tailings ponds in case water capping proves ineffective. However, the risk of technological failure and costs of implementing alternative methods are not factored into current liability calculations, further questioning their accuracy.[135]

The MFSP also lacks transparency in regards to disclosing operators’ individual asset and liability calculations. The AER lists “public access to information regarding the liabilities, financial security and reclamation progress of each approval holder” as a key consideration in their current guide to the MFSP.[136] The AER releases the formulas operators use to calculate their MFSP assets and liabilities, but refuses to disclose operators’ actual asset and liability valuations, as they deem this information confidential and not accessible to the public.[137] The Alberta Wilderness Association takes issue with this lack of transparency, as the vast majority of oil sands mining projects are on public lands and these liability numbers are calculated using third party unit costs, not confidential internal costs using proprietary technology.[138] Oil sands mining operators are also known to collaborate on reclamation initiatives and pride themselves on their technology transfers within the industry, casting further doubt on the AER’s reasoning for withholding the information.[139]

Best Practices for Financial Assurance in the Mining Sector

The shortcomings of the MFSP raise the question of how successful financial assurance schemes in the mining sector are set up in other jurisdictions. In July 2018, Canada’s Ecofiscal Commission (“Ecofiscal”) released a report recommending financial assurance as a way to responsibly manage environmental risk.[140] It uses the mining sector as a case study and provides an excellent comparative analysis of several provinces’ and territories’ financial assurance schemes.[141] Through this comparison, some industry best practices can be identified.

Quebec and the Yukon require mine operators to provide full financial assurance up front.[142] This is the gold standard in terms of environmental protection, as it provides strong deterrence from accumulating risky environmental liabilities and provides excellent compensation if an operator were to default.[143] Unfortunately, this type of stringent approach can have a negative impact on economic activity and act as an entry barrier for smaller market actors.[144] Quebec was able to counteract the negative effects this approach can have on economic activity by improving the coherence of their entire mining regulatory scheme through changes to their Mining Act.[145] The Yukon’s scheme was implemented recently and has not been rigorously tested so its impact on economic activity is hard to quantify at this time.[146] The benefits highlight the importance of introducing financial assurance early in a mine’s life. Increasing the amount of financial assurance held against an operator’s liabilities early in a mine’s life is the best way to ensure society does not pay the cost of the mining industry’s environmental liabilities.

Ontario’s financial assurance program for the mining sector takes a slightly less stringent approach depending on an operator’s financial strength. They have a two-tier system that allows operators that pass an independent financial assessment to self-assure against part or all of their reclamation liabilities.[147] Operators that do not meet this test are required to provide full-upfront financial assurance before they begin their project.[148] To be approved for the less stringent tier, an operator must receive a sufficient credit rating from two of only three approved agencies. This system takes a much stricter approach to financial risk differentiation that can act as a significant incentive for operators to maintain sufficient financial strength while providing strong compensation from financially riskier firms. By applying third-party credit evaluations, it appears to provide more effective financial risk differentiation than the self-reported asset safety factor calculations employed under the MFSP.

Since the overhaul of Quebec’s Mining Act in 2013, they have made all mine closure plans (including an operator’s estimated liabilities) and financial security amounts accessible to the public.[149] This choice was made in an effort to increase transparency and enforcement.[150] Making these plans and estimates available to the public can be an effective way of holding operators accountable and ensuring the accuracy of their estimates.

How to Improve the MFSP

Some of these best practices from other jurisdictions could be worked into the MFSP to address some of the program’s shortcomings. Ecofiscal’s comparative analysis shows that with the proper safeguards and regulatory scheme, full-upfront financial assurance, as seen in Quebec, can be effectively implemented. A transition to full-upfront financial assurance is the goal that Alberta should work towards.[151] Most industry proponents might argue that due to the magnitude of calculated oil sands liability costs, operators cannot afford such a transition while remaining profitable. As in-situ oil sands operations fall under a separate financial assurance scheme, the oil sands mining landscape is composed mostly of large energy companies with significant resources.[152] Increasing the stringency and immediacy of financial assurance collection for these mines should not come at the cost of a significant drop in economic activity. The Alberta Wildlife Association reported that Teck Resources has the capacity to post full financial assurance for their proposed Frontier Mine if needed; cash flow reports from existing mine operators including Suncor, Canadian Natural Resources Limited and Imperial Oil suggest the same.[153] If the AER does not want to take the steps necessary to require full financial assurance for oil sands liabilities now, they should develop a plan to increase the amount of financial assurance held incrementally over the next decade, with the goal of fully assured oil sands liabilities by the end of that timeframe. Maintaining the status quo and only assuring a mine as it nears the end of its life depends significantly on the strength of increasingly unstable oil prices and shifts too much of the risk from industry to society.

If the AER chooses to phase in full-upfront financial assurance over an extended timeframe, they should, in the interim, adopt a more effective mechanism to differentiate financial risk. A successful model for this type of financial risk differentiation would be Ontario’s two-tiered system. Having registered third-parties perform an independent corporate finance test to determine an operator’s financial strength would be more accurate and effective than the current self-assessed asset safety factor method. This type of system would allow operators that pass the independent finance test to provide a lower amount of assurance and collect full-upfront assurance from the financially riskier operators that fail.

In order for this type of system to be successful, improvements need to be made to the way assets and liabilities are calculated, reported and monitored. This necessitates differentiating between proven and probable reserves and factoring in an appropriate discount rate to account for the risk that probable reserves are significantly less likely to be extracted.[154] Liability calculations also need to account for the possibility that water-capping won’t be a successful way to reclaim tailings ponds and factor in a discount for technological risk and uncertainty.[155] The AER will also need to improve their monitoring and auditing of operators’ self-reported valuations.[156] Making mine closure plans and liabilities accessible to the public will allow the public to act as an important check on operators, but the AER needs to increase the number of high level audits they conduct to ensure operators are accurately reporting their liabilities and following through on their reclamation plans.

The MFSP should include assurance against the possibility of a catastrophic event or mining disaster, such as a large tailings pond spill.[157] Currently, none of the five provinces and territories profiled by Ecofiscal in their case study have assurance against mining disasters built into their liability regime.[158] This represents a large additional risk to the public, who could be on the hook for remediation and reclamation costs if an operator is unable or unwilling to pay for the clean-up.[159] The absence of mining disaster assurance for oil sands mines is especially troublesome, as some of the most expensive mining disasters have been related to tailings spills.[160] With the sheer volume of liquid tailings held in the oil sands region, disaster assurance would be a good way to mitigate against some of the potential social costs of a spill. This assurance could either come through hard assurance paid by each operator or the risk could be pooled and costs shared through a form of sector-level or third-party assurance.[161] Requiring oil sands operators to maintain a certain level of disaster insurance could be a good option, as it could create a new marketable insurance mechanism and comes at a lower cost to each individual operator.

Alberta’s Financial Security Scheme for Oil and Gas Wells

Alberta currently collects financial assurance for oil and gas wells through two main mechanisms. The regime is overseen by the AER and is composed primarily of the orphan well levy and a liability management rating system.[162] There are three different programs under the liability management rating system, but they all use a liability management rating to assess the financial strength of different operations.[163] The three programs are the Licensee Liability Rating Program (“LLR”), the Large Facility Liability Management Program and the Oil Waste Liability Program.[164] This analysis will focus predominantly on the LLR and the orphan well levy, as they are the most directly relevant to oil and gas wells.

The orphan well levy is a type of sector-level financial assurance that pools financial risk. It is an annual fee set by the AER and paid out by all well operators.[165] Individual operators pay an amount commensurate with their percentage of the industry’s total deemed liabilities.[166] The annual fees are kept in the Orphan Fund that is administered by the Orphan Well Association (“OWA”).[167] The levy is meant to cover the costs of suspending, plugging and reclaiming wells that are “orphaned” after an operator goes bankrupt and cannot pay for their liabilities themselves.[168] The OWA is given the discretion to determine how they use the funds and prioritize which wells should be reclaimed in any given year.[169]

The LLR is the program used by the AER to require financially riskier well operators to post additional financial assurance. It works similar to the MFSP’s AFSD by having each operator calculate their deemed assets and liabilities and requiring those with asset to liability ratios below a set threshold to provide additional financial assurance to make up the difference.[170] The liability management ratio threshold is set at 1.0, meaning that as long as an operator had enough deemed assets to cover their deemed liabilities, they would not need to post any additional security.[171] The AER recently raised the threshold to 2.0 for firms wanting to acquire new wells in an effort to prevent financially weaker firms from amassing more liabilities.[172] Operators’ liability management ratios are assessed monthly as well as whenever an operator files an application requesting to transfer a well license.[173]

Weaknesses of Alberta’s Oil and Gas Well Financial Security Scheme

Alberta’s oil and gas well liability regime is not fulfilling its purpose of ensuring the public does not bear the costs of reclaiming oil and gas wells without putting undue risk on the Orphan Fund.[174] The OWA has seen their inventory of orphaned wells meteorically rise from 74 in the 2012/2013 fiscal year to over 3700 in late 2017.[175] This increase in orphan wells necessitated the OWA accepting a $235 million loan from the Alberta government to top up the Orphan Fund in order to manage their larger inventory.[176] Some of the major shortfalls of the regime in its current form are: a lack of up-front financial assurance, potentially inflated asset and deflated liability calculations and no set time limit for how long a well can remain suspended. Until the Supreme Court of Canada released their decision in Orphan Well Association v Grant Thornton Limited (“Redwater SCC”) at the end of January 2019, end-of-life obligations becoming subordinate to claims from secured creditors in bankruptcy proceedings was also a major shortfall.[177]

The oil and gas well liability regime currently does not require any up-front financial assurance. The regime requires an annual payment into the Orphan Fund through the orphan well levy, but does not require any up-front security to assure an operator’s projected liabilities.[178] Similarly, no assurance is collected under the LLR program until an operator’s liability management ratio falls below the threshold.[179] This has resulted in only $200 million being held in security for calculated oil and gas well and in-situ liability costs of $30.1 billion.[180]

The calculations used to determine an operator’s deemed assets and liabilities tend to produce inaccurate valuations of an operator’s financial strength. An operator’s deemed assets are calculated through a formula that multiplies their reported production volumes from the past 12 months by a three-year industry average netback, and then by three.[181] Including this industry average netback in the calculation can inflate the assets of operators with higher extraction costs or lower production by assuming that all wells are equally profitable.[182] This abstracts an operator from the context of their individual operation and can significantly distort an operator’s financial health.[183]

An operator’s deemed liabilities are also based on industry averages for the costs associated with reclaiming a well site.[184] Their liabilities are calculated by taking the industry average cost to suspend, abandon, remediate and reclaim a well in the region their well is situated.[185] This also removes a significant amount of context for each individual well and operator. While not posing as much of an issue for financially stronger operators, this can mask the vulnerability of weaker operators with above average reclamation costs. The calculation also does not account for any liabilities beyond the average cost of suspending, abandoning, remediating and reclaiming a well site.[186] This can be a significant problem for operators that carry large external debts or pending law suits unrelated to their environmental liabilities.[187]

One of the biggest problems with the regime is that there are no set timelines regulating how long an operator can leave a well suspended before it must be reclaimed. In order to understand this issue, it is important to understand the live cycle of a well. Figure 1, below, outlines the different stages of a well’s life up until it is reclaimed and a reclamation certificate is awarded.[188]

Figure 1: Simplified Life Cycle and Taxonomy of Alberta Wells

In 2017, Alberta had approximately 450,000 wells.[189] Of those 450,000, approximately 150,000 wells are stuck in a limbo where they are no longer producing, but have not been successfully plugged and reclaimed.[190] Without strict timelines, there is little incentive for operators to reclaim their well sites, as it is often cheaper and easier for them to pay their lease premiums than it is to fund full reclamation. Industry proponents often claim they leave their wells dormant so that they can re-open them in the future without having to dig a new well. However, less than 0.2% of wells that have been taken out of production for 10 years or more are ever reactivated.[191] In its current state, Alberta’s oil and gas well liability regime offers very little deterrence for operators that choose to leave their wells in an extended state of inactivity.

This is an especially important issue when wells are on private or Indigenous lands. In Alberta, most private landowners do not own the subsurface rights to their land and do not have a veto over development of subsurface resources on their land.[192] Operators must approach landowners and attempt to negotiate a private surface agreement.[193] However, if the landowner does not consent, a licensed operator can seek a right of entry from the Surface Rights Board and continue with the development after paying the landowner fair compensation.[194] When operators leave their wells inactive for extended periods of time, it comes with the opportunity cost of preventing the landowner’s productive use of that land.[195] Similar to the oil sands context, this can potentially infringe Indigenous groups’ constitutionally protected rights to hunt, fish and trap on their traditional lands and their Treaty rights.[196] This can cause additional tensions when a landowner or Indigenous group was already opposed to the development from the project’s outset.

Until recently, there were questions over whether end-of-life obligations for oil and gas wells were subordinate to claims from secured creditors in bankruptcy proceedings.[197] This uncertainty was the result of the Court of Queen’s Bench of Alberta and the Alberta Court of Appeal’s decisions in the Redwater case (“Redwater ABQB”; “Redwater ABCA”).[198] The Redwater ABQB decision, which was upheld by the Alberta Court of Appeal, overruled a longstanding precedent set in PanAmericana de Bienes y Servicios S.A. v Northern Badger Oil & Gas Ltd. (“Northern Badger”). Northern Badger established that oil and gas well end-of-life obligations lie outside the bankruptcy scheme, and are afforded an effective super priority to be paid out before any level of creditor.[199] The Redwater ABQB decision led to a rash of bankruptcies where financially weak firms entered the bankruptcy process to shed their significant environmental liabilities.[200] Since the initial Redwater ABQB decision came down, approximately 1800 wells and sites licensed by the AER have been disclaimed, and the OWA inventory has increased from approximately 1200 to over 3700.[201] For Alberta’s liability regime to function properly, the AER must have access to an operator’s positive assets before they are distributed to other creditors through the bankruptcy process.[202] The Supreme Court of Canada overturned the Redwater ABCA decision on appeal.[203] In a split decision, the Majority adopted language from Northern Badger finding that the AER’s regulatory regime operates outside of the bankruptcy scheme, with end-of life liabilities constituting a public duty and not a debt owed to the regulator.[204]

This decision has been championed as a win for both the environment and for holding industry responsible for cleaning up after themselves.[205] However, the true impacts of the Redwater SCC decision have yet to be felt. With limited economic incentive to trigger bankruptcy proceedings, secured creditors might simply walk away from their loans and leave bankrupt operators in a state of limbo, instead of funding insolvency proceedings to recoup their security.[206] This could result in more orphaned wells when the entirety of a bankrupt’s estate is eventually turned over to the AER and Orphan Well Association.[207] This highlights the other issue, timing. Without incentives for secured creditors to trigger bankruptcy proceedings, and no imposed time-lines for abandoning suspended wells, wells will likely continue to sit idle. Some Alberta landowners say that the outcome of the Redwater decision does not really matter.[208] Without reform to the underlying regime, wells may continue to sit idle, furthering existing concerns over impacts on landowner crops and the environment.[209] While the Redwater SCC decision will ensure operators fulfill their end-of-life obligations before paying out secured creditors, its impact on Alberta’s orphan well crisis is still uncertain.[210]

Best Practices for Financial Assurance for Oil and Gas Wells

Examining oil and gas well liability regimes from other jurisdictions can help to identify some industry best practices for efficiently and effectively financially assuring wells. British Columbia and Saskatchewan are facing similar inactive well problems and do not provide examples of effective schemes.[211] Some American states seem to have implemented effective regimes that may be able to offer some guidance for Alberta and the rest of western Canada.

In the US, posting financial assurance at the time a well is drilled is common practice.[212] In a 2016 report on US oil and gas well policy compiled by American research institute, Resources for the Future (“RFF”), all 22 states profiled mandated some form of financial assurance or bonding before a well is drilled.[213] The form of financial assurance accepted varies significantly from state to state, with some accepting only hard assurance and others accepting softer forms of security.[214] Texas and New Mexico offer leading examples for pre-drill bonding, only accepting hard assurance in the form of surety bonds, letters of credit and cash.[215] Similar to oil sands mining, the gold-standard for financial assurance is full-upfront financial assurance. However, it can be difficult to accurately determine the full reclamation cost for a well. Texas sets the amount of financial assurance as a function of well depth, requiring operators to pay $2.00 per foot of projected well depth for each well.[216] New Mexico follows a similar scheme, requiring $1.00 per foot of projected well depth on top of a base fee of $5000 or $10 000 per well, depending on the well’s region.[217] Implementing upfront bonding requirements in Texas led to a reduction in environmental harms, violations and orphan wells left behind by firms.[218] Similarly, New Mexico’s financial assurance regime has led to a declining population trend for orphan wells.[219] Introducing upfront, hard financial assurance has shown to be an effective way of managing future oil and gas well liabilities.

Introducing timelines for abandonment of inactive and suspended wells is also an important feature of effective liability management schemes. All 22 states profiled in the RFF’s report have regulations on the duration of temporary abandonment of wells.[220] Temporary abandonment is the equivalent of suspending a well in Alberta, when the well is no longer producing but not fully abandoned or reclaimed.[221] The range of lengths for temporary abandonment in the RFF’s study ranged from 6 months in Texas and Colorado to 25 years in California.[222] New Mexico again offers an industry leading example as they take a strict approach not allowing operators to request extensions on the mandatory timelines.[223] They set strict timelines for the suspension, abandonment and reclamation of wells, requiring an operator to either return a well to beneficial use or abandon and reclaim it after it has been suspended for five years.[224] These timelines are widely used in the US and amount to an important safeguard against orphaning wells, while still allowing for the possibility of reactivating potentially productive wells.

How to Improve Alberta’s Oil and Gas Well Financial Security Scheme

Some of these best practices from other jurisdictions could be applied to improve Alberta’s oil and gas well financial security scheme. It is clear from looking at Texas and New Mexico’s liability schemes that posting financial assurance before a well is drilled can be an effective way to help reduce the number of wells being orphaned and provide more funds for reclaiming well sites that are orphaned.[225] Upfront assurance is an important deterrence mechanism and safeguard that Alberta should integrate into their liability regime. Alberta should strive to adopt full financial assurance for all new wells as a condition of the licensing process.[226] Over the next few years, they should also work towards collecting full-financial assurance from well operators for all existing wells.[227] In an increasingly decarbonising world, it is important that operators internalize the risks associated with oil and gas extraction and that these costs are not transferred to taxpayers and future generations.

If Alberta is not yet ready to move to a full financial assurance model, a partial bonding system like those used in Texas and New Mexico would be a satisfactory interim measure. The amount required per well under the partial bonding system could be tied to well-depth and differentiated by region.[228] Implementing a partial bonding requirement could also increase competition among bonding firms to offer the most attractive financial terms and create a new lending market.[229] Alberta could also differentiate the form of assurance or bonding depending on the size of the operator. Private firms offering surety bonds would likely charge smaller operators larger premiums as they present a higher risk of default.[230] To compensate for this barrier for smaller firms, Alberta could implement a government funded bonding scheme for smaller operators to subsidize the cost of premiums.[231] This would need to be coupled with increased assessment of a prospective operator’s financial strength to ensure this preferential rate is only available to financially resilient operators.

Alberta also needs to adopt a deterrence mechanism to prevent operators from leaving wells in a state of indefinite suspension.[232] Timelines for reactivating or abandoning and reclaiming suspended wells have been an effective way of reducing inactive wells in New Mexico and many other states profiled in the RFF’s report.[233] The timelines could be based on the New Mexico model with a five-year limit on suspended wells.[234] Before the five-year limit is reached, the operator would need to decide whether to abandon and reclaim the well, or return it to a beneficial use.[235] Reclamation would need to be completed within one year from the date the well was abandoned.[236] Unlike in New Mexico, Alberta could adopt an extension to this timeframe.[237] An operator could apply to the AER, requesting to leave their mine in a suspended state for an additional 5 years.[238] The extension could only be granted if the operator can prove to the AER that a well has future utility and that there are sufficient justifications for the extension.[239] This acknowledges that there may be legitimate reasons to extend the suspension of the well and to avoid the premature closure of wells that have a legitimate prospect of becoming financially productive in the future.[240] The extension would bring the maximum length a mine can be continuously suspended to 10 years, a point after which it has been shown to be very unlikely a well would ever be reactivated.[241]

An alternative to strict timelines on inactive and suspended wells would be for Alberta to implement mandatory insurance for all non-producing wells.[242] This is an industry favoured approach, as it delays the decommissioning of mines that have a legitimate expectation of being reactivated, but still acts as a disincentive to leaving wells inactive indefinitely.[243] Once a well becomes inactive, an operator would need to show they have insurance against the full cost of reclamation.[244] In the event an operator goes bankrupt and cannot pay for reclamation themselves, the insurance company would cover the cost.[245] In exchange, the operator pays monthly premiums for the coverage that also act as a disincentive from leaving a well in an inactive state without a reasonable expectation of reactivation.[246] In their 2017 Report on oil and gas well liabilities, the C.D. Howe Institute suggested that this type of mandatory post-production insurance would pair well with a partial bonding element to create an efficient liability scheme.[247] This option for mandatory insurance is likely to be less favourable among landowners and other stakeholders, as it could delay the return of a well-site to the landowner’s preferred use.[248]

It may also be difficult to implement if the costs associated with a transition to more stringent financial assurance lead to increased bankruptcies.[249] Increased bankruptcies may lead the insurance companies to raise premiums to compensate for the increased risk of payouts, or refuse to insure inactive wells altogether.[250] This would likely have a larger impact on smaller operators, as it could act as a prohibitive cost barrier from entering or staying in the industry. Similar to the partial bonding scheme, the Alberta government could consider funding an insurance scheme for smaller operators to subsidize insurance premiums. The financial viability and structure of such a program would need to be assessed before implementation to ensure that operators are not capable of abusing the program to escape their environmental liabilities.

It is important that any changes to Alberta’s oil and gas well liability regime are coupled with increased transparency.[251] The current system suffers from poorly calculated assets and liabilities and the recent investigative report referred to at the beginning of this paper questions whether the AER even knows the true extent of their current liabilities.[252] Any changes to Alberta’s oil and gas well liability regime need to come with more transparency from the AER at all stages of the regulatory process. They need to produce accurate calculations on liabilities held under the liability regime and make them publicly available.[253] They need to base the calculations off reliable estimates of reclamation costs, such as recent OWA figures, not self-reported industry costs. They also need to implement more stakeholder, rights-holder and public engagement in establishing their requirements for reclamation certification, ensuring there is a voice for landowners and Indigenous communities. They must follow through with their commitments to Indigenous groups and ensure they are respecting their constitutionally protected rights to hunt, trap and fish on their traditional lands.


Whether you use internal estimations or the recently leaked worst case scenario projections, Alberta’s oil & gas sector liabilities have reached an extent where they can no longer be ignored. Alberta’s liability management regimes do not employ the necessary safeguards to ensure industry pays to clean up after themselves. The Mine Financial Security Program does not require sufficient upfront financial assurance to compensate for the risk that oil sands mining operations pose to the public. It also relies on self-reported liability estimates, does not effectively differentiate financial risk and does not account for major technological and market uncertainties. The oil and gas well liability regime also suffers from a lack of upfront financial assurance. It relies on inaccurate estimates of financial strength and does not set reclamation timelines. Both regimes suffer from a lack of transparency and do not sufficiently engage stakeholders in the reclamation process.

The government of Alberta scheduled a review of their liability management programs in 2017.[254] They held a series of meetings and discussions with different stakeholder and industry groups and were expected to release a report by the end of 2017.[255] While no formal report has been released yet, the AER has acknowledged that the current system is flawed and needs to be changed.[256] Some of the changes Alberta could make include introducing more upfront financial assurance in both the MFSP and oil and gas well liability regime, as well as regulated timelines for abandoning and reclaiming suspended wells and accounting for technological and market risks in their liability calculations. This should be coupled with improved transparency and accountability to key stakeholders including landowners, Indigenous communities and the greater public. Implementing these changes would help to ensure the cost of developing Alberta’s oil and gas resources stays with the people that benefit most and does not fall to the public and future generations.


[1] Emma McIntosh et al, “What would it cost to clean up Alberta’s oilpatch? $260 billion, a top official warns” (November 2018), online: Toronto Star Newspapers Ltd. <> [McIntosh].

[2] Ibid. See Alberta Energy Regulator, Liability Management Programs Results Report (Calgary: AER, December 2018) at 1 (oil and gas well liabilities); Alberta Energy Regulator, Mine Financial Security Program – Security and Liability (Calgary: AER, September 2018) at 1 (oil sands mining liabilities).

[3] Alberta Energy Regulator, Guide to the Mine Financial Security Program (Calgary: AER, February 2017) at 14 [AER, MFSP Guide]; Alberta Energy Regulator, Directive 006 – Licensee Liability Rating (LLR) Program and License Transfer Process (Calgary: AER, February 2016) at 20 [AER, Directive 006].

[4] Ibid at 15.

[5] Ibid.

[6] Benjamin Dachis, Blake Shaffer & Vincent Thivierge, “All’s Well that Ends Well: Addressing End-of-Life Liabilities for Oil and Gas Wells” (September 2017) at 13, 15, online (pdf): CD Howe Institute <’s-well-ends-well-addressing-end-life-liabilities-oil-and-gas-wells> [Dachis, Shaffer & Thivierge].

[7] AER, MFSP Guide, supra note 3 at 29.

[8] Alta Reg 115/1993, s 15(2) [CRR] (s.15(2) of the Conservation and Reclamation Regulations clarifies that the liability period is no more than 5 years for wells that were issued a reclamation certificate on or before October 1, 2003). See generally Alberta Environment and Sustainable Resource Development, Update Report on Alberta Environment and Sustainable Resource Development’s Upstream Oil and Gas Reclamation Certificate Program, March 2015 update (Edmonton: AESRD, 31 March 2014) at 4 [AESRD, Update Report].

[9] AESRD, Update Report, ibid.

[10] Ibid.

[11] Alberta Energy Regulator, Specified Enactment Direction 002: Application Submission Requirements and Guidance for Reclamation Certificates for Well Sites and Associated Facilities (Calgary: AER, 24 July 2018) at 3 [AER, Wellsite Reclamation Certificate Guidance].

[12] Ibid (the AER states that these audits are separate from their complaints process).

[13] The AER does not provide much information regarding their complaints process apart from including a phone number for their Energy and Environmental 24-hour Response line on their website see “File a Complaint” (accessed 13 December 2018), online: Alberta Energy Regulator <>. Statements of concern are well documented and clearly explained on the AER website see “Statement of Concern” (accessed 13 December 2018), online: Alberta Energy Regulator <>. However, they are typically filed in response to applications (including reclamation certification) and not in response to post certification issues (ibid). A lack of information on complaints resulting in the cancelation of reclamation certificates is an issue the AER should address.

[14] CRR, supra note 8, s 15(1); Alberta Environment and Sustainable Resource Development, Criteria and Indicators Framework for Oil Sands Mine Reclamation Certification, July 2014 update (Fort McMurray: AESRD, July 2013) at 160 [AESRD, Oil Sands Indicators Framework].

[15] AESRD, Oil Sands Indicators Framework, Ibid at 159.

[16] Gordon Kent, “Mixed reviews for oilsands land reclamation track record”, Calgary Herald (29 September 2017), online: <>. As there has only been one reclamation certificate issued in the oil sands, there has been limited opportunity to bring claims in relation to these certificates.

[17] Deborah Jaremko, “Vegetation planting nearing completion at major Syncrude reclamation area”, JWN Energy (20 March 2018), online: <>.

[18] AER, MFSP Guide, supra note 3 at 14; AER, Directive 006, supra note 3 at 20.

[19] Pierre Gosselin et al, “The Royal Society of Canada Expert Panel Report: Environmental and Health Impacts of Canada’s Oil Sands Industry” (December 2010) at 157-195, online (pdf): The Royal Society of Canada <> [Gosselin et al].

[20] Environmental Protection and Enhancement Act, RSA 2000, c E-12, s 137 [EPEA].

[21] Ibid.

[22] CRR, supra note 8, s 2.

[23] Ibid, s 1(e).

[24] The competing interpretations of the standard come from regulators, industry, the public and Indigenous groups in Alberta see Gosselin et al, supra note 19 at 157. See generally Clayton Gouin “Managing uncertainty: An examination of adaptive management and progressive reclamation in Alberta’s mineable oil sands” MIES Thesis, Norwegian University of Life Sciences, 2017) [unpublished] (for oil sands context with emphasis on Indigenous groups).

[25] Gosselin et al, ibid at 158.

[26] Alberta Environment, Land Capability Classification System for Forest Ecosystems in the Oil Sands, 3rd Edition, by the Cumulative Environmental Management Association, vol 1, (Field Manual) (Edmonton: AE, 2006) at 1 [AE, LCCS].

[27] Ibid at 5.

[28] Gosselin et al, supra note 19 at 158.

[29] The LCCS is a 148-page guidance document and does not include any reference to Indigenous, First Nations or Aboriginal persons.

[30] AESRD, Oil Sands Indicators Framework, supra note  14 at ii.

[31] Ibid.

[32] Ibid.

[33] “Home Page” (1 April 2016), online: Cumulative Environmental Management Association <>.

[34] AESRD, Oil Sands Indicators Framework, supra note 14 at 18.

[35] Ibid at 147,

[36] Ibid.

[37] Ibid at 29, 102, 116, 117, 147.

[38] Ibid at 147.

[39] Gosselin et al, supra note 19 at 158.

[40] Alberta Energy Regulator, Decision 20180613A: Syncrude Canada Ltd; Application for Aurora North Tailings Management Plan (Calgary: AER, 13 June 2018) at 4- 5 [AER, Syncrude Tailings Plan].

[41] Ibid.

[42] Ibid.

[43] Ibid at 4.

[44] Government of Alberta, Lower Athabasca Regional Plan 2012-2022, ISBN No 978-1-4601-0538-2 (Edmonton, GOA, 2012) at 5 [GOA, LARP]. First Nations groups in the oil sands regions have rights protected under Treaties 6 and 8 as well as s 35 of the Constitution Act, 1982 see Government of Alberta, Review Panel Report 2015: Lower Athabasca Regional Plan, by LARP Review Panel (Edmonton, GOA, 2015) at 6 [GOA, LARP Review].

[45] GOA, LARP, ibid at 29.

[46] GOA, LARP Review, supra note 44 at 5.

[47] Ibid.

[48] AER, Syncrude Tailings Plan, supra note 40 at 6.

[49] Otiena Ellwand, “Alberta signs historic agreement with Treaty 8 First Nations”, Edmonton Sun (26 April 2016), online: <> [Ellwand]. 

[50] Ibid.

[51] Ibid.

[52] Government of Alberta, Announcement, “Draft Moose Lake Management Zone Plan released” (16 February 2018), online: Government of Alberta Announcements <> [GOA, “Moose Lake”]. 

[53] Ibid.

[54] Darcy Henton, “Fort McKay First Nation Sues Alberta over Energy Development”, Calgary Herald (26 April 2016), online: <>. For more examples of First Nations bringing claims against the Alberta government in relation to oil sands development see The Canadian Press, “Alberta oilsands facing aboriginal legal onslaught in 2014”, Canadian Broadcasting Corporation (2 January 2014), online: <>; The Canadian Press, “Athabasca Chipewyan file lawsuit against Shell’s Jackpine oil sands expansion”, Financial Post, 16 January 2014, online: < energy/athabasca-chipewyan-file-lawsuit-against-shells-jackpine-oil-sands-expansion>. 

[55] GOA, “Moose Lake”, supra note 52.

[56] Ibid.

[57] Ibid.

[58] Alberta Environment and Parks, Reclamation Criteria for Wellsites and Associated Facilities for Peatlands, March 2017 update (Edmonton: AEP, 15 April 2016) at i [AEP, Peatland Wellsite Reclamation].

[59] Alberta Environment and Sustainable Resource Development, 2010 Reclamation Criteria for Wellsites and Associated Facilities for Grasslands, July 2013 update (Edmonton: AESRD, 2010) [AESRD, Grassland Wellsite Reclamation]; Alberta Environment and Sustainable Resource Development, 2010 Reclamation Criteria for Wellsites and Associated Facilities for Forested Lands, July 2013 update (Edmonton: AESRD, 2010) [AESRD, Forested Lands Wellsite Reclamation]; Alberta Environment and Sustainable Resource Development, 2010 Reclamation Criteria for Wellsites and Associated Facilities for Cultivated Lands, July 2013 update (Edmonton: AESRD, 2010) [AESRD, Cultivated Lands Wellsite Reclamation]; AEP, Peatland Wellsite Reclamation, supra note 58.

[60] AESRD, Grassland Wellsite Reclamation, ibid; AESRD, Forested Lands Wellsite Reclamation; AESRD, Cultivated Lands Wellsite Reclamation, ibid; AEP, Peatland Wellsite Reclamation.

[61] AESRD, Forested Lands Wellsite Reclamation, supra note 59 at iii.

[62] AER, Wellsite Reclamation Certificate Guidance, supra note 11 at 3.

[63] Ibid.

[64] Ibid at 3, 11, 17.

[65] “Reclamation Process and Criteria for Oil and Gas Sites” (accessed 13 December 2018), online: Alberta Energy Regulator <> [AER, “Reclamation Process”].

[66] AER, Wellsite Reclamation Certificate Guidance, supra note 11 at 3.

[67] Ibid. Additional reviews are also conducted for more complex applications and applications that requested variances on the standard certification criteria see ibid.

[68] Ibid at 3.

[69] Ibid. See generally Responsible Energy Development Act, SA 2012, c R-17.3; Alta Reg 90/2013 (definitions for “eligible person” and “appealable decision” are found in s.36 of REDA and s.3.1 of the REDA Regulation. The definitions include decisions that were made without a hearing that would otherwise be appealable under the EPEA, Water Act and Public Lands Act).

[70] AESRD, Forested Lands Wellsite Reclamation, supra note 59 at 4; AEP, Peatlands Wellsite Reclamation, supra note 58 at 7; AESRD Grasslands Wellsite Reclamation, supra note 59 at 5, AESRD, Cultivated Lands Wellsite Reclamation, supra note 59 at 3-4.

[71] AESRD, Forested Lands Wellsite Reclamation, ibid; AEP, Peatlands Wellsite Reclamation, ibid; AESRD, Grasslands Wellsite Reclamation, ibid; AESRD, Cultivated Lands Wellsite Reclamation, ibid.

[72] AER, Wellsite Reclamation Certificate Guidance, supra note 11 at 23-25.

[73] Ibid at 23-24.

[74] Ibid at 24.

[75] Ibid.

[76] Landowners cannot consent to leaving contaminated or un-reclaimed land see ibid at 24-25.

[77] AESRD, Forested Lands Wellsite Reclamation, supra note 59 at iii.

[78] Ellwand, supra note 49.

[79] Canada’s Ecofiscal Commission, “Responsible Risk: How Putting a Price on Environmental Risk Makes Disasters Less Likely” (July 2018) at 21-30, online (pdf): Canada’s Ecofiscal Commission <> [Canada’s Ecofiscal Commission].

[80] Ibid at 21.

[81] Ibid at 52.

[82] “Liability Management Programs and Processes” (accessed 13 December 2018), online: Alberta Energy Regulator <> [AER, “Liability Management Programs”]. 

[83] EPEA, supra note 20, s 135(1).

[84] Canada’s Ecofiscal Commission, supra note 79 at 42; Alberta Energy Regulator, Liability Management: Situational Awareness, by Rob Wadsworth, Slideshow Presentation (Calgary: AER, 7 June 2018) at 11 [AER, Liability Management June 2018].

[85] AER, MFSP Guide, supra note 3 at 2.

[86] Ibid.

[87] AER, “Liability Management Programs”, supra note 82 (Large Facility Management Program).

[88] AER, MFSP Guide, supra note 3 at 19.

[89] Auditor General of Alberta, Report of the Auditor General of Alberta: Environment and Parks and the Alberta Energy Regulator – Systems to Ensure Sufficient Financial Security for Land Disturbances from Mining (Edmonton: AGA, 26 June 2015) at 27 [Auditor General of Alberta].  

[90] AER, MFSP Guide, supra note 3 at 20.

[91] Ibid at 21.

[92] Ibid at 20.

[93] Canada’s Ecofiscal Commission, supra note 79 at 59.

[94] Auditor General of Alberta, supra note 89 at 28.

[95] AER, MFSP Guide, supra note 3 at 21.

[96] Ibid.

[97] Ibid.

[98] Ibid at 25.

[99] Ibid.

[100] Ibid.

[101] Ibid at 22.

[102] Ibid.                                                    

[103] AER, MFSP Guide, supra note 3 at 22-23.

[104] Auditor General of Alberta, supra note 89 at 25.

[105] Alberta Energy Regulator, Annual Mine Financial Security Program Submissions: 2018 Submissions for 2017 Reporting Year (Calgary: AER, 2018) at 1 [AER, MFSP 2018 Submissions]; AER, MFSP Guide, supra note 3 at 30; Canada’s Ecofiscal Commission, supra note 79 at 21-23.

[106] AER, MFSP Guide, supra note 3 at 30.

[107] Canada’s Ecofiscal Commission, supra note 79 at 24.

[108] Ibid.

[109] AER, MFSP Guide, supra note 3 at 30.

[110] Canada’s Ecofiscal Commission, supra note 79 at 22.

[111] Ibid at 59.

[112] Carolyn Campbell, “Cleaning Up After Ourselves: Oil Sands Mine Liability Program Needs Major Reform”, Wild Lands Advocate 25:4 (1 December 2017) 14 at 15, online: <> [Campbell].

[113] AER, MFSP 2018 Submissions, supra note 105 at 9; Auditor General of Alberta, supra note 89 at 25.

[114] Auditor General of Alberta, ibid at 32.

[115] Tracy Johnson, “Alberta to audit coal mines to ensure there’s money for cleanup”, CBC News (28 July 2016), online: <>.

[116] Canada’s Ecofiscal Commission, supra note 79 at 9, 34, 38.

[117] Ibid at 42.

[118] Auditor General of Alberta, supra note 89 at 31.

[119] Ibid.

[120] Ibid.

[121] Ibid at 32.

[122] Ibid at 29.

[123] Ibid.

[124] Ibid.

[125] Ibid.

[126] Ibid.

[127] Sini Matikainen, “What are stranded assets?”, The London School of Economics and Political Science (23 January 2018), online: <>. Assets can be stranded by an increased shift to renewable energy, restrictive government regulations, changing demand or legal action (ibid). For an example of legal action enforcing reduced emissions that could lead to stranded assets see Arthur Neslen, “Dutch government ordered to cut carbon emissions in landmark ruling”, The Guardian (24 June 2015), online: <>.

[128] Ibid; Cristophe McGlade &Paul Ekins, “The geographical distribution of fossil fuels unused when limiting global warming to 2 °C” (2015) 517:7533 Nature 187.

[129] Kevin Orland, “Oilsands Ponds Full of 340 billion gallons of toxic sludge spur fears of environmental catastrophe”, Financial Post (16 January 2018), online: <>.

[130] Gosselin et al, supra note 19 at 111, 121; See also Government of Alberta, Lower Athabasca Region Tailings Management Framework for the Mineable Athabasca Oil Sands, online version (Edmonton: GOA, March 2015) at 11 [GOA, Lower Athabasca Tailings].

[131] GOA, Lower Athabasca Tailings, supra note 130 at 12; Syncrude Canada Ltd, “Syncrude Sustainability Report 2015 (2015) at 21, online (pdf): Syncrude Canada Ltd <> [Syncrude Canada Ltd].

[132] Gosselin et al, supra note 19 at 192.

[133] Ibid at 130.

[134] Ibid at 192.

[135] Canada’s Ecofiscal Commission, supra note 79 at 59.

[136] AER, MFSP Guide, supra note 3 at 45.

[137] Ibid; Campbell, supra note 112 at 16.

[138] Ibid.

[139] Ibid; Syncrude Canada Ltd, supra note 131 at 14. Most oil sands mining operators are members of the Canadian Oil Sands Innovation Alliance (“COSIA”). COSIA was developed by Canada’s largest oil sands operators as a platform to collaborate and innovate on issues relating to environmental management. See <> for more information or “COSIA Report 2017” for a specific example of COSIA’s collaborative efforts.

[140] Canada’s Ecofiscal Commission, supra note 79 at viii.

[141] Ibid at 31.

[142] Ibid at 42-43.

[143] Ibid at 43.

[144] Ibid.

[145] Ibid.

[146] Ibid at 42.

[147] Ibid at 60.

[148] Ibid.

[149] Ibid at 62.

[150] Ibid.

[151] Campbell, supra note 112 at 16.

[152] AER, MFSP 2018 Submissions, supra note 105 at 1 (the only operators currently providing BSD deposits are Canadian Natural Resources Limited, Imperial Oil, Syncrude, Total E&P and Suncor. Fort Hills Energy Corporation and Canadian Natural Upgrading Limited are subsidiaries of Suncor and Canadian Natural Resources Limited).

[153] Campbell, supra note 112 at 16.

[154] Auditor General of Alberta, supra note 89 at 29.

[155] Canada’s Ecofiscal Commission, supra note 79 at 59.

[156] Auditor General of Alberta, supra note 89 at 32.

[157] Canada’s Ecofiscal Commission, supra note 79 at 45.

[158] Ibid.

[159] Ibid.

[160] Ibid at 32.

[161] Ibid at 45.

[162] Dachis, Shaffer & Thivierge, supra note 6 at 9; Alberta Energy Regulator, Bulletin 2018-07: 2018/19 Orphan Fund Levy (Calgary: AER, 9 April 2018) at 1 [AER, Orphan Fund Levy].

[163] “Liability Management Rating and Reporting” (accessed 13 December 2018), online: Alberta Energy Regulator <> [AER, “Liability Management Rating”].

[164] Ibid.

[165] AER, Orphan Fund Levy, supra note 162 at 1.

[166] Ibid.

[167] “Orphan Well Association” (accessed 13 December 2018) online: Alberta Energy Regulator <> [AER, “Orphan Well Association”].

[168] Ibid.

[169] Ibid.

[170] AER, Directive 006, supra note 3 at 4.

[171] Ibid.

[172] Dachis, Shaffer & Thivierge, supra note 6 at 9.

[173]AER, Directive 006, supra note 3 at 4.

[174] Ibid at 2.

[175] Dachis, Shaffer & Thivierge, supra note 6 at 7; Jodi McNeill, “A liability iceberg in Alberta exposed by the Redwater case” (26 April 2018) online (blog): The Pembina Institute <> [McNeill, “Liability Iceberg”].

[176] McNeill, “Liability Iceberg”, ibid.

[177] Orphan Well Association v Grant Thornton Limited, 2019 SCC 5, [2019] 3 WWR 1 [Redwater SCC].

[178] AER, Directive 006, supra note 3 at 4-6.

[179] Ibid at 4.

[180] Alberta Energy Regulator, Liability Challenges, by Rob Wadsworth, Slideshow Presentation (Calgary: AER, 28 February 2018) at 13 [AER, Liability Challenges February 2018].

[181] AER, Directive 006, supra note 3 at 17.

[182] Barry Robinson, “The Inactive Well Compliance Program: Alberta’s latest attempt to bring the inactive well problem under control” (2010) at 5, online: Ecojustice <> [Robinson].

[183] Jodi McNeill & Nikki Way, “The catch-22 of the Redwater case” (2 May 2018) online (blog): The Pembina Institute <> [McNeill & Way].

[184] AER, Directive 006, supra note at 20.

[185] Ibid; Robinson, supra note 182 at 5.

[186] Ibid at 6.

[187] Ibid.

[188] Dachis, Shaffer & Thivierge, supra note 6 at 4.

[189] Ibid at 1.

[190] Ibid.

[191] Ecojustice & Pembina Institute, “A Proposal for Managing Upstream Oil and Gas Liability in Alberta” (30 June 2017) at 6 [unpublished] [Ecojustice & Pembina Institute] (this proposal was prepared by Ecojustice and the Pembina Institute and was submitted to the government of Alberta for their liability management review. The document is not publicly available online).

[192] Alberta Association of Municipal Districts and Counties, “AAMDC Submissions on Oil and Gas Liability Management” (June 2017) at 4 [unpublished] [AAMDC] (these submissions were prepared by the Alberta Association of Municipal Districts and Counties and were submitted to the government of Alberta for their liability management review. The document is not publicly available online).

[193] Duncan Kenyon et al, “Landowners’ Guide to Oil and Gas Development” 3rd edition (November 2016) at 83, 321, online (pdf): The Pembina Institute <> [Kenyon et al].

[194] Ibid; “Private Surface Agreements Registry” (accessed 13 December 2018) online: Alberta Energy Regulator <> [AER, “Private Surface Agreements].

[195] Dachis, Shaffer & Thivierge, supra 6 note at 5.

[196] For examples of Treaty claims in Alberta related to oil and gas development see Ermineskin Indian Band and Nation v Canada, 2009 SCC 9, [2009] 1 SCR 222 (Treaty 6, oil and gas royalties); Lameman v Alberta, 2013 ABCA 148, 553 AR 44 (Treaty 6, damages for resource development infringing rights to hunt, fish and trap on traditional lands).

[197] McNeill, “Liability Iceberg”, supra note 175.

[198] Grant Thornton Ltd. V Alberta Energy Regulator, 2016 ABQB, [2016] 11 WWR 716 [Redwater ABQB]; Orphan Well Association v Grant Thornton Limited, 2017 ABCA 124, [2017] 6 WWR 301 [Redwater ABCA].

[199] Panamericana de Bienes y Servicios SA v Northern Badger Oil & Gas Ltd, 1991 ABCA 181 at paras 36, 63, [1991] 5 WWR 577 [Northern Badger].

[200] Alberta Energy Regulator, Why we are fighting: AER president and CEO Jim Ellis, by Jim Ellis, Public Statement, (Calgary: AER, 15 February 2018) at 2 [AER, Why we are fighting].

[201] Ibid.

[202] Dachis, Shaffer & Thivierge, supra note 6 at 9.

[203] Redwater SCC, supra note 177.

[204] Ibid at paras 134 - 135.

[205] Tracy Johnson, “Supreme Court rules energy companies must clean up old wells – even in bankruptcy”, CBC News (31 January 2019), online: <>.

[206] Sean F Collins, Walker W MacLeod & Kimberly Howard, “Redwater – SCC Delivers the Final Word” (4 February 2019) online (blog): McCarthy Tétrault LLP <> [Collins, Walker & Howard]; Redwater SCC, supra note 177 at para 221.

[207] Collins, Walker & Howard, ibid; Redwater SCC, ibid at paras 221, 288.

[208] Tony Seskus, “Why farmers’ frustration with orphan wells doesn’t end with the Supreme Court ruling” (1 February 2019), online: <>.

[209] Ibid.

[210] Ibid.

[211] Jeff Lewis et al, “Hustle in the oil patch: inside a looming financial and environmental crisis”, The Globe and Mail (23 November 2018), online: <>. 

[212] Jacqueline Ho et al, “Plugging the Gaps in Inactive Well Policy” (May 2016) at 21, online (pdf): Resources for the Future <> [Ho et al].

[213] Ibid.

[214] Ibid at 22.

[215] Ibid.

[216] Texas Administrative Code, TAC tit 16 § (Texas Secretary of State 1999).

[217] New Mexico Administrative Code, NMAC tit 19 § 15.8.9 (New Mexico Commission of Public Records 2008).

[218] Dachis, Shaffer & Thivierge, supra note 6 at 24.

[219] AER, Liability Challenges February 2018, supra note 180 at 17.

[220] Ho et al, supra note 212 at 30.

[221] Ibid at 29.

[222] Ibid at 30.

[223] Ibid.

[224] Robinson, supra note 182 at 19-20.

[225] Dachis, Shaffer & Thivierge, supra note 6 at 24; AER, Liability Challenges February 2018, supra note 180 at 17.

[226] Environmental and Stakeholder organizations are pushing for full financial security for new wells. See Ecojustice & Pembina Institute, supra note 191 at 3; AAMDC, supra note 192 at 5.

[227] AAMDC, ibid at 4.

[228] Ho et al, supra note at 23.

[229] Dachis, Shaffer & Thivierge, supra note 6 at 17.

[230] Ibid.

[231] Ibid.

[232] Ibid at 18.

[233] Ho et al, supra note 212 at 30.

[234] Robinson, supra note 182 at 20.

[235] Ibid at 20.

[236] Ibid.

[237] Ho et al, supra note 212 at 30.

[238] Robinson, supra note 182 at 22.

[239] Ibid.

[240] Ibid.

[241] Ecojustice & Pembina, supra note 191 at 6; AER, Liability Management June 2018, supra note 84 at 6.

[242] Dachis, Shaffer & Thivierge, supra note 6 at 18.

[243] Ibid.

[244] Ibid at 18-19.

[245] Ibid.

[246] Ibid at 19.

[247] Ibid at 20.

[248] AAMDC, supra note 192 at 4.

[249] McNeil, “Liability Iceberg”, supra note 175.

[250] Craig Brown & Sara Seck, “Insurance Law Principles in an International Context: Compensating Losses Caused by Climate Change” (2013) 50:3 Alta L Rev 546.

[251] Jodi McNeill, “The Alberta government has a transparency problem it comes to oil and gas liabilities” (20 November 2018) online (blog): The Pembina Institute <> [McNeill, “Transparency Problem”].

[252] Ibid.

[253] Ibid.

[254] Government of Alberta, Announcement, “Review of old wells to protect Albertans, environment” (10 May 2017), online: Government of Alberta Announcements <> [GOA, “Review of old wells”]. 

[255] Ibid; Government of Alberta, Liability Management Review Engagement Questions Used for Discussions, (Edmonton: GOA, May 2017) (this document lists a series of discussion questions prepared by the government of Alberta for the liability management review stakeholder engagement sessions).

[256] AER, Liability Challenges February 2018, supra note 180 at 23.