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We inform industry about regulatory matters by offering formal education sessions, discussing the results of a field inspection with an operator, and working with companies to ensure that their applications meet our standards, to name a few ways. In addition to the guidance our directives and bulletins provide, this information helps companies meet our requirements and stay in compliance.

Here we share information for industry to learn more about certain AER requirements and what we expect for specific developments and activities.

Note/Disclaimer: The following information is provided for guidance and summary purposes only and is not an exhaustive description of AER requirements relating to a given topic or subject area. Operators and licensees must at all times comply with, and should consult, all applicable AER requirements before undertaking any activity.

Description Learning resources Applicable directives and regulations
Air Emissions & Monitoring
Read about Methane Reduction, Emissions Reports and Studies, Important Topics and Flaring and Venting related to energy development.

Updates to Directive 060 and Directive 017 were released in December 2018. Three web-based learning modules were developed to help operators comply with the changes. They are:

  1. Volumetric Reporting
  2. Measurement, Monitoring, and Reporting
  3. Methane Reduction Retrofit Compliance Plan

Air Emissions Modules
(August 2019)

Directive 060:
Upstream Petroleum Industry Flaring, Incinerating, and Venting

Directive 017:
Measurement Requirements for Oil and Gas Operations

Manual 011:
How to Submit Volumetric Data to the AER

Manual 015:
Estimating Methane Emissions


This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Coal Conservation Act

Coal Conservation Rules

Dam Safety

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Water (Ministerial) Regulation - Part 6 Dam and Canal Safety

Drilling Waste

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Directive 50:
Drilling Waste Management

This reference guide identifies the additional information required to submitting a drilling activity notification in DDS. Changes took effect on September 7, 2019.

Reference Guide for DDS Drilling Activity Notifications
(September 2019)

Manual 002:
Drilling Waste Inspections

Drilling, Well Servicing & Fracturing
Read about Coalbed Methane, Commingling, Drilling, Hydraulic Fracturing, Seismic Activity, and Well Testing related to energy development.

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Directive 008:
Surface Casing Depth Requirements

Directive 009:
Casing Cementing Minimum Requirements

Directive 010:
Minimum Casing Design Requirements

Directive 036:
Drilling Blowout Prevention Requirements and Procedures

Directive 059:
Well Drilling and Completion Data Filing Requirements

Directive 083:
Hydraulic Fracturing – Subsurface Integrity

Facility & Well Site (includes Sour Gas Plants & In Situ)
Read about In Situ Recovery, Sour Gas, and Sulphur Recovery related to energy development.

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Manual 001:
Facility and Well Site Inspections

Oil and Gas Conservation Act
Land & Wildlife

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Public Lands Act

Measurement & Data Quality Assurance

This presentation provides an overview of our Enhanced Production Audit Program (EPAP).

Production Audit Enhanced Production Audit Program
(June 2016)

Directive 007:
Volumetric and Infrastructure Requirements

Directive 017:
Measurement Requirements for Oil and Gas Operations

Directive 076:
Operator Declaration Regarding Measurement and Reporting Requirements

Manual 011:
How to Submit Volumetric Data to the AER
Oil Sands
Read about Oil Sands, Mining, and Oil Sands Development Requirements related to energy development.

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Oil Sands Conservation Act

Directive 073:
Requirements for Inspection and Compliance of Oil Sands Mining and Processing Plant Operations in the Oil Sands Mining Area

Directive 082:
Operating Criteria: Resource Recovery Requirements for Oil Sands Mine and Processing Plant Operations

Directive 085:
Fluid Tailings Management for Oil Sands Mining Projects

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Pipeline Act

Pipeline Rules

Directive 077:
Pipelines – Requirements and Reference Tools
Waste Management (includes storage)

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Directive 030:
Digital Data Submission of the Annual Oilfield Waste Disposition Report

Directive 047:
Waste Reporting Requirements for Oilfield Waste Management Facilities

Directive 050:
Drilling Waste Management

Directive 055:
Storage Requirements for the Upstream Petroleum Industry

Directive 058:
Oilfield Waste Management Requirements for the Upstream Petroleum Industry

Directive 075:
Oilfield Waste Liability (OWL) Program

The FAQ and the Oilfield Waste Form support the rules and requirements outlined in Directive 058.

Waste Form and Hydrovac Material FAQ
(May 2022)

Oilfield Waste Form
(March 2022)

This brochure helps waste generators characterize and classify oilfield waste. Waste Characterization for Oilfield Waste Generators
(April 2022)

Directive 058:
Oilfield Waste Management Requirements for the Upstream Petroleum Industry

Directive 047:
Waste Reporting Requirements for Oilfield Waste Management Facilities

Directive 030:
Digital Data Submission of the Annual Oilfield Waste Disposition Report

This brochure provides additional information for AER stakeholders to understand the AER Alberta Oilfield Waste Form. Alberta Oilfield Waste Form Brochure
(June 2022)

Directive 058:
Oilfield Waste Management Requirements for the Upstream Petroleum Industry

Water & Fisheries
Read about Water use and Watercourse Crossing Management related to energy development.

This is a list of all the possible inspection results operators could see on the Inspection Detail Report in DDS following a site inspection.

Inspection Items
(coming soon)

Water Act

Environmental Protection and Enhancement Act

Roadway Watercourse Crossing Remediation Directive

Information for operators to become involved in the inspection and remediation of watercourse crossings.

Information Package
(June 2019)

Description Learning resources Applicable directives and regulations
Compliance Assurance Program

This presentation describes our approach to compliance and enforcement, the Integrated Compliance Assurance Framework, and Manual 013: Compliance and Enforcement Program.

AER Compliance and Enforcement Program
(February 2016)

Integrated Compliance Assurance Framework

Manual 013:
Compliance and Enforcement Program

Read an overview of how we respond to incidents and emergencies related to energy development.

Description Learning resources Applicable directives and regulations
Emergency response overview

This presentation describes the AER’s expectations for emergency response.

Emergency Preparedness & Response

Directive 071:
Emergency Preparedness

Release reporting requirements

The presentation, FAQ, and brochure on release reporting requirements describe our expectations on release/spill containment, reporting, clean up, and disposal requirements. These documents clarify the reporting process, AER jurisdiction for various types of releases, different methods for clean-up/disposal, and commonly asked questions.

Release Reporting Requirements brochure (June 2018)

Release Reporting presentation
(December 2015)

Release Reporting FAQ
(April 2017)

Release Reporting Definitions
(June 2019)

Release Reporting Form
(July 2021)

Proactive Procedures to Prevent Spills brochure
(August 2013)


Directive 058:
Oilfield Waste Management Requirements

Directive 071:
Emergency Preparedness and Response Requirements

Oil and Gas Conservation Rules and Regulations

Description Learning resources
Digital Data Submission (DDS) system

This user guide helps industry use the DDS system to submit information to us via the Internet.

FIS Web User Guide

Unique Well Identifiers
The unique well identifier (UWI) is the standard well identification that was developed for the petroleum industry by the Geoscience Data Committee of the Canadian Petroleum Association and has been adopted by the oil and gas regulatory agencies of the four western provinces and federal areas. Unique Well Identifiers (UWI) description

More Opportunities for Industry to Learn

Our education programs and initiatives go beyond what is listed on this page. We offer many face-to-face sessions and presentations to companies throughout the year, such as

  • group operator awareness sessions,
  • presentations to individual companies, and
  • AER inspection training.

We announce upcoming information sessions and technical briefings on our Events page and through direct email communication with operators. To learn about other opportunities, please email @email.

Contact Us

If you have any comments or questions about this information, please contact our Customer Contact Centre.

LMF Program: Directive 088: Licensee Life-Cycle Management Questions and Answers

ABC - area-based closure
AER - Alberta Energy Regulator
BA - business associate
CSU - contaminated site upstream
DDS - Digital Data Submission
FIS - Field Surveillance Inspection System
LCA - licensee capability assessment
LLR - licensee liability rating
LMR - liability management rating
PNoA - public notice of application
RDT - regulator-directed transfer
SAGD - steam-assisted gravity drainage
SRP - Site Rehabilitation Program
WIP - working interest participant

General and Miscellaneous Q&As

Will you be providing a copy of this presentation and slides?
Yes, all information provided at this session will be available on our website and YouTube channel.

Where can I sign up for Alberta Energy Regulator (AER) updates?
You can sign up to receive notifications of AER website updates. The weekly web update email is distributed every Monday morning to inform subscribers about new or updated web content we posted the previous week, including announcements, bulletins, directives, or reports.

Will ongoing discussions be held with the investment community to ensure they are confident in the process and so capital inflows to Alberta do not dissipate?
We encourage transparency; however, the decision to share licensee capability assessment (LCA) information with third parties lies with the licensee. We are considering future engagement needs. Engagement opportunities will be posted to the AER events page.

Is there an example closure plan template?
We do not have a closure plan template.

Where can we find definitions for active and inactive wells?
Inactive wells are defined in Directive 013: Suspension Requirements for Well.

An active well is any well that is not inactive, abandoned, or reclaimed (reclamation certified or reclamation exempt). Licensees can view the status of individual wells in OneStop.

From a policy perspective, how will the AER measure success?
Our objective is the proactive reduction of liability. Performance measures are under development with the Government of Alberta.

When will the AER start taking special action for companies deemed at risk?
The licensee special action function, known as licensee management, is still under development. More information will be provided later in 2022. There is no set number of high risk or tier 2 or 3 parameters that will trigger action, it is about a company's overall risk identified through the holistic assessment.

Transfers Q&As

What is the timeline for a preapplication meeting?
Typically, we meet with applicants within two weeks of receiving a request for a preapplication meeting. You can find up-to-date AER application processing timelines on our website.

What will happen in a preapplication meeting? Will the AER share an applicant's likelihood of success of the transfer? Will the AER take the information presented during the meeting and use it for the application review?
We will discuss questions and how Directive 088: Licensee Life-Cycle Management is applied to a transfer application, but we will not be able to give specific input about the outcome. (We will not conduct a predetermination of the application or offer assurances verbally or in writing.) Also, any information presented at the preapplication meeting will not be automatically considered at the time of application review. However, companies may be asked to submit supporting documentation at the time of application.

Do transfer application processing timelines start on the date the licence transfer was submitted or the date that the 30-day public notice period expires?
Application and public notice of application (PNoA) timelines run concurrently, and both timelines start when the application is submitted. The PNoA days are calendar days, and application processing days are business days.

Why is there not a predetermination process available?
Licence transfers are submitted after an acquisition/divestiture has closed, and the threat of a licence transfer not being approved creates real risk of the assets remaining in limbo. Additionally, if the parties knew the required security deposit amount, it could be worked into the structure of the purchase and sale agreement.

The holistic licensee assessment conducted for each licence transfer application contains live or frequently updated data. A predetermination process cannot predict how the holistic licensee assessment will look at the time of application. Applicants can gain clarity on the application process through a preapplication meeting request emailed to @email.

The model used to determine the amount of security to collect to mitigate potential risks is provided in Manual 023: Licensee Life-Cycle Management.

Applicants are encouraged to consider licence transfer application timelines when drafting sale agreements. Our first duty under Directive 088 is to ensure licensees can meet their end‑of-life obligations. Companies need to evaluate the consequences of the transfer being denied, approved, or approved with conditions. Directive 088 and Manual 023 provide applicants with clarity on the most common factors used for evaluation; therefore, we will not offer predetermination.

Can either the transferor or transferee withdraw a transfer request?
Either applicant (transferor or transferee) can withdraw the application at any time before a decision has been made. If a decision has been made to collect security as a condition of approval and the application gets withdrawn before that transaction is finalized, the security deposit is not required. If it has already been paid, it will be returned.

Will alternative liabilities be considered instead of Directive 011 values during the preapplication and transfer process to represent more holistic abandonment, reclamation, and remediation costs? Can these more representative values be used to override closure liability after transfer?
We consider liabilities in Directive 011: Licensee Liability Rating (LLR) Program: Updated Industry Parameters and Liability Costs and Directive 001: Requirements for Site-Specific Liability Assessments. In addition, licensee-submitted closure spend data will eventually be incorporated into liability estimates once sufficient data is available, and other values may be incorporated as we evaluate the effectiveness of the program. We use the values in Directive 011 and site-specific values to determine liability estimates during the licence transfer application process. More detail on those values is found in Manual 023. Directive 011 is being scheduled for revision under the liability management framework. We do not offer a preapplication process under Directive 088 to see if those values will “get a transfer through.”

Is the AER considering allowing the assignment of dispositions with cancelled or outstanding obligations or expired dispositions in the future?
Assignments of dispositions are not regulated under Directive 088. The Public Lands Administration Regulation outlines the rules and requirements for public lands dispositions.

Where does the AER stand on transfers to an asset closure company?
We regulate licensees with a business associate (BA) code and eligibility under Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, regardless of their business model. If companies do not have eligibility under Directive 067, transfer applications cannot be submitted. “Asset closure” companies would need to meet the same requirements as “production” companies to gain eligibility under Directive 067. We will use the requirements in Directive 067 to determine if an applicant merits the privilege to operate in Alberta.

Can I submit a transfer application for a RecCert and RecExempt well licence only to transfer wells to purchasers to past white map deals?
This question is best answered in a preapplication meeting.

Can the AER deny a transfer if, after the transfer, the position of the transferor substantially worsens? Where does that leave the transferee?
Yes, we could decide to deny the application, approve, or approve with conditions (e.g., security) for either the transferor or the transferee. We will evaluate both parties' abilities to meet end-of-life obligations under the liability management framework.

What will happen to the old regulator-directed transfer (RDT) process when a transferee's liability management rating (LMR) is below 1?
The RDT will be treated no differently than other transfer applications in that LMR is no longer the factor that determines the outcome of the decision. RDTs will undergo a holistic licensee assessment as they have the same criteria applied to them as the rest of the transfer applications under Directive 088.

For nonroutine applications, will the AER contact the applicant to collect more information before deciding?
Yes, we will contact applicants when more information is needed. Not every nonroutine application will require more information.

Will the transferor be advised if the transfer becomes nonroutine?
No, transferors would not be notified. Applicants can look in the integrated application registry to determine the status of an application. Definitions and further clarity on nonroutine applications are in Manual 23.

Do all nonroutine applications go to a hearing? Are hearings only triggered if there are statements of concern (SOCs) filed? Do hearings only occur upon regulatory appeal?
Not all nonroutine applications result in a hearing. For more information, see statement of concern and the regulatory appeal process.

Will the AER let a company know what other considerations factor into a nonroutine decision?
When reviewing nonroutine applications, we first consider the holistic licensee assessment and then scrutinize specific factors as required. The factors we could possibly review are listed in Manual 023. If we decide to deny the transfer, we will provide both the transferee and transferor with a letter citing the reasons for our decision. If we decide to approve the transfer with conditions, we will provide whichever licensee is required to agree to the conditions with a letter citing the reasons for our decision. Applicants may file a regulatory appeal (regulatory appeal process) if they do not agree with the decision in whole or in part.

Will all transfer applications from companies with low financial distress and high magnitude of liability be considered nonroutine?
The decision to process an application as routine or nonroutine is our purview. However, Section 4.2 of Manual 023 outlines some factors that would trigger further scrutiny of the licensees and application.

Holistic Licensee Assessment and Licensee Capability Assessment Q&As

It's harder to understand our performance under the holistic approach. What's the benefit of this change?
We are shifting from a prescriptive approach to a risk- and performance-based approach. Rather than looking at only two parameters (deemed assets and liability), we now look at licensees holistically across the life cycle of an oil and gas development. Licensees are encouraged to understand their performance across all metrics. More information and clarity will be provided as it becomes available.

How will the holistic assessment be applied to new applications (i.e., wells, facilities, pipelines) and licence amendments?
Currently, the holistic assessment does not apply to new licence applications or licence amendments. However, in the future, new applications and amendments will be subject to holistic assessment. Directive 088 applies to all energy infrastructure and sites regulated under the Oil and Gas Conservation Act and Pipeline Act. We will comprehensively assess licensees to inform regulatory decisions regarding that licensee. As described in Directive 088 and Manual 023, this assessment uses a multifactor approach to assess licensees' capability for meeting their regulatory and liability obligations throughout the energy development life cycle (from project initiation to closure).

Furthermore, Directive 088 introduces the Licensee Management Program, which determines how licensees will be managed throughout the energy development life cycle. Under this program, results from the holistic licensee assessment will be used to identify licensees that may pose a risk in meeting their regulatory and liability obligations. Regulatory tools to mitigate risks may affect the review of other application types. The liability management framework intends to use the holistic licensee assessment for all decisions. However, in some cases, this may require updates to supporting directives (for example, Directive 056: Energy Development Applications and Schedules).

How long does a holistic assessment take? Will a new assessment be done for each transfer?
Every application will trigger a holistic assessment as the data in an LCA is live and can change frequently. The reviewer may note a recent transfer and take that information into consideration when assessing the current application. Application timelines have not changed and are posted on our website.

Is there a minimum quantity of licences in a transfer application that will trigger a holistic assessment?
No. All transfer applications will result in a holistic assessment of the transferor and transferee.

Is the LCA assessment being used by other teams at the AER when determining who will audit, etc.?
Currently, the LCA is only used by AER teams affected by Directive 088, including those tasked with security determination, administering the Inventory Reduction Program, and processing transfer applications. As the LCA evolves, it will be used by more AER teams.

How often will the LCA be updated in OneStop?
OneStop updates daily as our database is updated.

Will you be publishing information or bulletin on improvements to LCA?
We are looking at including notes in OneStop as updates are made. Additional information and clarification will be provided on the website as it becomes available.

How does a new licensee demonstrate adequacy for transfer approval? Are they more likely to have security requested by the AER?
The holistic assessment is intended to determine risk and is not a barrier to entry for new licensees. We would likely apply further scrutiny on newer licensees, given their lack of performance history. We would likely ask an applicant to demonstrate financing, and they could also expect a request for additional information. Security is the last line of defence for mitigating risk; it is not a foregone conclusion. More information is provided in Manual 23.

The magnitude of liability is a critical factor in determining risk. Is there a way for large producers to be considered low risk?
Although a company's size does affect the magnitude of liability, it's the holistic assessment that results in the overall risk assessment. The magnitude of liability is one of many factors considered.

By not providing company-specific details on how performance group parameters are generated, how are companies to duplicate or understand how the LCA is calculated?
Manual 23 provides some detail on the parameters and how they are calculated. Although we are considering additional details in the holistic assessment, we need to maintain flexibility in our LCA calculations. Please email @email for information on your specific situation.

How can a licensee improve their LCA score?
There are many ways to improve LCA scores; however, it depends on which parameter needs improving. For example, low financial scores can be improved by improving financial performance. Reduction of inactive inventory and completing closure will help improve closure parameters. Also, keep in mind which parameters are peer-ranked and understand that a licensee's tier in performance factors is relative to their peers. If peers perform better than a licensee, that licensee's ranking may be in a lower tier than expected.

Will more information be made available on calculations?
We are not publishing details on all calculations currently. Information on LCA parameters is provided in Manual 23.

Active observation wells associated with oil sands in situ development are categorized incorrectly as inactive. Does the AER have a timeline on when it will review this matter?
We will review this issue. There is nothing currently in the system to differentiate between active and inactive observation wells. We will consider this for future improvements.

Steam-assisted gravity drainage (SAGD) operations generally have several observation wells associated with active pads. These observation wells are included on the inactive well list but are exempt from Directive 013 requirements. How are these observation wells treated when calculating inactive well ratios as part of the LCA?
Observations wells are being treated as inactive for the calculation of the inactive well ratio parameter within the LCA. The activity of wells and facilities is determined based on the reporting of production and throughput. Because there is no reporting associated with observation wells, their current operating status is unknown. We will review this parameter.

The LCA appears to have broken parameters (e.g., pipeline abandonment rate). Is this a known issue?
Yes, we are aware of this issue and are working on a fix. Please email @email with any other concerns.

Concerning crossover timelines, how are recently reactivated wells factored into the projection? Previously, it would take 12 months to obtain full asset value. For example, reactivating all wells in a particular area three months before application.
The crossover timeline parameter is refreshed quarterly and factors in all wells that have recent production regardless of the current life-cycle status defined in Directive 013. Once a well is reactivated (and is considered active), the number of months of reported production required to effectively forecast the crossover timelines will depend on the unique circumstances of that well.

Can companies replicate the crossover calculation model?
The methodology for assessing crossover is estimated using the timeframe when forecasted operating income will no longer be sufficient to address the closure costs associated with those wells. Licensees should be able to conduct this assessment using their reserves and economic assessments in combination with their detailed liability assessment report available within OneStop.

For previous year rates, does LCA consider holdings at year-end, or does it take currently held licences and assess how those assets performed in previous years?
Some parameters relate to current licences, whereas others are behavioural and consider the previous years' behaviour.

The AER has said that the licensee evaluation is solely based on a licensee's Alberta‑based performance and operations; however, the use of financial statements contradicts this as they are company wide, not province specific, and include working interest arrangements. Can you please explain?
This is correct. Financial statements are company wide and include all jurisdictions and working interest arrangements. Financial risk is the only parameter that considers operations and working interests outside Alberta. The remainder of the parameters are specific to Alberta.

If we received a three-year abandonment extension, does that help avoid tier 3 on the mineral expiries parameter?
The calculation evaluates letters sent and does not factor in extensions. We are looking into a solution.

Are extension requests for suspension or abandonments factored in as a noncompliance in the Directive 013 compliance rate or is the deadline date adjusted?
As per Section 6 in Directive 013, under the our compliance assurance program, self-disclosures or extensions pertaining to Directive 013 requirements are not accepted. So, wells will continue to remain noncompliant until the requirements are satisfied. In rare, unique scenarios (only), we may issue alternative requirements that licensees are required to meet and report to the AER through the designated information submission system. These requirements will help keep the well in compliance with Directive 013 and do not factor into the Directive 013 compliance rate in the LCA system.

Directive 020: Well Abandonment does not set timelines or deadlines for well abandonments. Abandonment deadlines extensions granted under other AER rules and directives (e.g., mineral lease extensions) are not factored into the Directive 013 compliance rate. Licensees are expected to maintain their wells in compliance with Directive 013 until full well abandonment (downhole and surface) is completed and reported to the AER.

Please explain mineral lease expiry scoring
This parameter considers the number of letters issued compared to a licensee's inactive well inventory. More information can be found in Manual 23.

Companies that participated in the area-based closure (ABC) program were given a waiver to push out closure activity on type 6 Directive 013 wells. Is this considered when reviewing Directive 013 noncompliance?
Presently, the LCA system considers high-risk and medium-risk type 1 to type 5 wells only for the Directive 013 noncompliance parameter. It excludes low-risk and medium-risk type 6 wells.

Participants of the ABC program were not given a waiver to push out closure activity but only approved an alternate suspension or inspection requirement for medium-risk type 6 wells. This enabled reallocation of resources to support focused and efficient closure work. Licensees were still required to comply with the alternate suspension or inspection requirement for medium-risk type 6 wells and ensure compliance was maintained.

Directive 013 was also updated with the release of Directive 088 to indicate the changes made to align with the Inventory Reduction Program. For details regarding medium-risk type 6 well suspension and inspection requirements, please refer to section 3.2.1 and 3.2.2 of Directive 088.

Could the AER consider a more well-specific approach for the marginal well parameter? Perhaps consider the liability of the specific well relative to its production? As it stands, the parameter penalizes shallow-gas producers.
This issue will be evaluated as part of the liability road map.

Can you explain how the release and spill rate metric is calculated? How does it result in a percentage value?
This parameter looks at the number of unique incidents as a function of a licensee's active wells and facilities and averages it over the last three years. This metric attempts to normalize the rate across peers of different sizes. This is expressed as a percentile.

Does the inspection noncompliance rate include all types of noncompliance or only specific ones?
The inspection noncompliance rate evaluates only high-risk unsatisfactory field inspections relative to all field inspections. This will be clarified in Manual 023.

For the inspection noncompliance follow-up rate, response timeline also include the AER inspector timelines. How will the AER address this?
This parameter looks at all inspection follow-ups (high and low risk) and is calculated using the completed date of the follow-up rather than the closeout date. Licensees should and are prompted to complete their inspections when responding to the AER before the inspection follow-up date. If a licensee does not properly indicate that the follow-up is complete, the inspection will be completed by the AER at the same time as the inspection is closed.

Further to the Field Surveillance Inspection System (FIS) field inspections, we can pull inspection results (licensee totals versus AER totals). However, there does not appear to be a report or visibility to the follow-up data used in the LCA?
Licensees can access their inspection details through the Digital Data Submission (DDS). This information can be filtered, and licensees can identify which inspection follow-ups were completed before the follow-up deadline and those completed after the follow-up deadline.

When extensions are requested or granted for inspection follow-up, AER upkeep of the deadline is required. Sometimes this results in missed deadlines. Can this be addressed?
Extensions to the follow-up deadline date granted by the AER will change the date by which a licensee's follow-up is evaluated. Requests for extensions must be made before the deadline.

Where there is no peer comparison percentile shown but a parameter value is given for the producer, will there be a fix so that the tier given to the company can be corrected?
Yes, the intent is to ensure peer comparison is correct. This issue will be addressed.

Would industry be able to see performance ranges for the tiers? We see operations noncompliance parameters that appear to be incorrectly tiered. Is this being considered?
Information in Manual 23 on categories has been released. If you believe you have been incorrectly tiered, email @email. We are aware of some issues and are working on fixes.

A parameter for our peer group is weighted 0 per cent and is showing up as a tier 3 peer comparison. Is this going to be corrected?
We are aware of this issue and are working on fixing it.

Security Q&As

Is there a circumstance where, even if the maximum security deposit is paid, a licence transfer could be denied?
If security is required as a condition of approval on a licence transfer application, the licensee asked to pay the security would have to agree to that condition of approval and complete the payment before a disposition is issued. If the licensee does not agree to that condition, the application is closed. No conditions, including security, would be required in the event an application is denied.

Will security requirements be refined when the liability amounts in Directive 011 are updated?
Liability estimates will be refined over time as part of the objectives of the liability management framework. This includes reviewing security requirements and adjusting the parameters as the liability estimates change and the liability management framework progresses towards its outcomes.

What are the possible security deposit types? Are other forms of security going to be reviewed or accepted?
We accept cash and letters of credit only. See Directive 068: ERCB Security Deposits for more information. The Oil and Gas Conservation Rules grant the AER broad authority to collect security. Within the oil and gas sector, security is collected for transfers, the Inventory Reduction Program, the large facility program, oilfield waste liability, and LLR. Future programs are anticipated for inclusion in the liability management framework.

Where can a security calculation model be accessed?
Manual 023 was recently updated to include the security calculation model. We are assessing what other information can be provided in Directive 088 and Manual 023 in the future.

Will security deposits be calculated in the same way if the transferring licences are coming from an insolvent company?
We do not treat insolvent applicants any differently. All licence transfer applications, including those involving insolvent parties, will trigger a holistic licensee assessment. Because of the assessment, licensees may be required to provide a security deposit as a condition of approval, the same as transactions with companies not in insolvency.

Is the total liability used for security always the inactive wells and facilities, marginal wells, and site-specific liability assessments, or can it be based on only some of these factors?
If these factors apply to an application, they will be considered.

Would a security refund request from a licensee who holds no licences (and has not for the past couple of years) trigger a full LCA assessment?
All applicants are treated the same. A holistic assessment would apply, and further scrutiny may apply to licensees with minimal performance history data.

Is interest accumulated also returned when a security refund is granted?
Accrued interest is only released if full security is refunded.

Waste management facilities must post full security. In the past, security was returned after a full year of operating. Will the LCA enable a refund for these facilities?
See section 7 of Directive 068 for more information on security refunds.

Data Q&As

If a data request is made to one party in a transfer, is the other party notified for awareness?
We don't typically notify the other party for confidentiality reasons. We encourage (but do not mandate) all parties involved in a transfer to maintain open lines of communication and transparency with each other.

The Licence Transfer System in the DDS has issues transferring Rec/Rec Exempt wells. Has that been corrected?
This was corrected in February 2022. Should you encounter further technical issues, please email @email.

If we are doing multiple DDS transfers per week, are we expected to submit the closure spend target data each time? Is this going to be part of the DDS transfer as an upload?
The reason for submitting closure spend target data for each application is to ensure transferors get credit for closure spend on transferred licenses. Closure spend data is recorded per licence and must be reported in OneStop before a transfer is completed to ensure full credit is given.

Do I need to update working interest participant (WIP) data for each licence in OneStop before submitting a transfer application?
We encourage licensees to update WIP information through OneStop. While updated WIP information is not required before an application is submitted, it is required as part of a transfer application.

What are the differences between the DDS and OneStop liability reports?
The OneStop liability report provides improved identification of inactive wells and facilities. It also includes liability for sweet multiwell batteries overridden to $0 within the DDS report. Licensees are encouraged to use the new OneStop liability report.

Will DDS reporting be discontinued?
We are reviewing the timeline for transitioning from the DDS to OneStop. More information will be provided as it becomes available.

Inventory Reduction Program Q&As

Inquiries to the ABC email address are asked to submit an inquiry form. Which email address and which inquiry form submission should be used for each type of question?

There are currently two inboxes, one for ABC and one for inventory reduction. The intake form allows us to track and provide consistent responses in the interim while we transition to a single inbox. Inquiries about the 2021 ABC program should be directed to @email, and inquiries about the current (2022) and future years should go to @email.

Is the AER exploring an accommodation for eligible closure-focused companies inside of the mandatory spending target? Can companies transfer liability to a qualified closure company to satisfy annual spending targets?
Companies, including a qualified closure company, must meet eligibility requirements under Directive 067 to hold licences. We would then assess them as they would any other licensee. Transferring liability to closure-focused companies would not be considered “closure spend” under the mandatory targets program.

Company-specific mandatory spend targets are based on the proportion of inactive liability and the level of financial distress. Can you please provide the formula, or explain how this is calculated in more detail?
Proactive closure work is the goal, and the mandatory targets are designed with the capability of the licensee in mind. For 2022, there are two capability groups:

  • For more financially capable licensees (licensees with low and medium levels of financial distress), the mandatory spend target is set at 4 per cent of their inactive liability.
  • For less financially capable licensees (licensees with high levels of financial distress), the mandatory spend target is 3.3 per cent of their inactive liability.

The industry-wide closure spend target for 2022 is $422 million. Each licensee was assigned their relative proportion of the industry-wide target based on the amount of inactive liability they hold relative to the rest of licensees within the same capability group.

Please elaborate on why WIP closure spend on inactive sites is not taken into consideration.
The Inventory Reduction Program and associated closure spend targets apply to licensees only. WIP information may not be accurate in our systems. Allowing WIPs credit for their share of the closure spend would require splitting liability among the parties. This approach would be a significant change and requires more assessment, including whether additional regulatory changes are needed.

There are some WIPs not paying bills. What action can the AER take?
We have no authority over WIP agreements between companies as they are private business contracts. However, WIPs have the legislative responsibility to pay their proportionate share of closure costs. If a WIP has failed to meet its obligations and meets the criteria to be deemed a defaulting WIP under section 70(2)(b) of the Oil and Gas Conservation Act, their share of outstanding costs may be claimed by the remaining WIPs through the working interest claim process set out on the Orphan Well Association's website.

If a WIP defaults on its obligations but does not meet the criteria under section 70(2)(b) of the OGCA to be deemed a defaulting WIP, then the remaining WIPs can submit an application to the AER for a cost determination, provided that the closure activity has been directed by the AER. The application requirements are set out in section 3.071 of the Oil and Gas Conservation Rules. To start this process, please contact @email.

Could security be requested in situations where WIPs are not participating in closure spend?
We have no authority over WIP agreements between companies as they are private business contracts. WIPs that are licensees will also have to meet their own closure spend target.

Will closure activities completed on licences transferred within a calendar year be considered part of the new licensee's mandatory spend? How will the AER be promoting closure activity and adjusting mandatory spend where there have been large transactions midyear as part of the transaction review?
Only the licensee of record can submit closure spend. Licensees must report spending before a transfer is completed for it to be counted towards their target. Any spend reported after the transfer will be allocated to the new licensee. If a licensee conducts closure work on a recently acquired licence, the spend will count towards that licensee's closure spend target. Licensee closure spend targets are calculated in July and are not adjusted midyear to account for transfers. The effects of transfers will be incorporated into the following year's spend targets.

Can closure spend exceeding the mandatory annual target be carried forward to a future year's target requirements?
No, this is not an option. We might consider this option as the program evolves.

There have been discussions about increasing the licensee annual spend target to 7 per cent of the inactive liability. Is the 5 per cent annual increase in the industry target the way of achieving this goal?
The industry target forecast provided in June 2021 increased the industry target by 5 per cent annually. This increase was based on the estimated growth in inactive liability. However, targets and forecasts will be adjusted annually based on actual industry closure performance and growth in inactive liability. The more spend data we receive, the better our forecasts.

Can we include the spend incurred from July to December 2021 used to close sites that were part of the 2022 minimum spend target calculation?
No, only closure spend made within a calendar year counts towards that year's target. Please email @email for clarity on your specific situation.

Is the AER considering a five-year rolling mandatory closure spend target?
No. The mandatory closure spend target is an annual minimum requirement. We might consider a rolling closure spend target in the future.

For the ‘pay security in lieu of a target under $50k' option, can interest accrued on an LLR deposit be applied against the security owing?
This option is being considered. More information will be provided when it becomes available. Please email @email with questions regarding your specific situation.

How do we know if we have opted into the voluntary spend target when submitting a 2022 closure plan?
Licensees can access the voluntary spend target page in OneStop through the menu Close > Closure Target > Voluntary Target. On this page, they can commit to their voluntary spend target, view the status of their commitment, and download voluntary target program incentive letters.

Previously, when ABC spend projects were submitted in OneStop, licensees had to commit to the voluntary spend target to get the medium type 6 well exemption. Is this still the case?
The medium risk type 6 well alternative suspension (option 3) previously offered in the ABC program is now available to all licensees that submit at least one confirmed ABC project every year. Please refer to Directive 013 for more information. The voluntary target program offers two incentives for 2022 as outlined in Manual 023.

According to Manual 023, a licensee's commitment to a voluntary target expires at the end of the calendar year, so by what date do they have to recommit?
The deadline to recommit is January 31.

How is the voluntary target calculated? How does it interact with the mandatory target?
For 2022, the mandatory target that applies to all licensees is set at either 4 per cent or 3.3 per cent of the inactive liability, based on a licensee's level of financial distress. The voluntary target is set at 0.3 per cent of the inactive liability and is added to the mandatory target. These participants are assessed for compliance to both the mandatory and voluntary spend targets.

Where can suggestions be directed regarding the voluntary closure incentives?
Please send your suggestions to @email.

Why has the AER restricted eligible spend to inactive sites?
The purpose of inventory reduction is to reduce liability on the landscape. At this time, the annual closure spend targets are calculated based on inactive liability. Work on active sites is permitted, provided it is moving towards a closure milestone that year (i.e., abandoning an active well).

Would a remediation certificate count as a closure milestone and make that spend eligible, even if the site is still in use?
If a site is active, work completed will not count towards eligible spend.

Can spend on a contaminated site upstream (CSU site) count as part of the year's minimum spend target (i.e., remediation on a RecExempt/RecCert site)? If not, will this be considered in the future?
If closure work is conducted on an inactive site, it will count towards the spend target.

Under the current system, licensees do not get credit for reclamation completed while waiting for vegetation growth.
The current legislation requires a site to reach a closure milestone—either abandonment or reclamation certification. However, expenses for reclamation-related activities can be reported for the closure spend target in OneStop. Additional milestones will be evaluated as we continue to implement the liability management framework.

Regarding multiwell pads with both active and inactive wells, the Directive 011 reclamation liability is tagged to the first well drilled on the pad. If that well is inactive, then the full liability is included as inactive liability, but because the pad still has active wells, it cannot be reclaimed. Would the AER consider splitting the reclamation equally among the wells on a pad or keeping the reclamation out of our inactive liability calculation until the entire pad is inactive?
We will track this as input from industry and will add it for assessment as part of our liability road map.

Can you confirm whether spend towards reclamation of remote sumps (which hold waste associated with inactive and active wells), borrow pits (which have been used to build roads and infrastructure associated with inactive and active wells), and removal of surface equipment associated with inactive SAGD wells (currently suspended) would be eligible?
Spend is tied to a licence. Infrastructure associated with inactive wells would count towards a licensee's spend target. Sites without a licence are not considered eligible at this time but will be considered for future enhancements.

How does the AER know if reclamation is complete? Is inactive liability reduced if reported complete?
The reduction of inactive liability relies on the reclamation certificate being obtained.

Manual 023 indicates Alberta Energy will provide site rehabilitation program (SRP) funding information to the AER to facilitate subtraction of those amounts from our spend submission. Will the AER provide that information before the ABC deadline? Does this mean industry will no longer be required to provide the breakdown of SRP costs and company costs in the closure cost submissions for individual projects?
We will work with the Government of Alberta and industry to ensure we are capturing correct SRP funding in the calendar year. Licensees have been contacted directly for the 2021 deadline. Please email @email if you have more questions. There is a closure spend report in OneStop that indicates what has been subtracted from the total reported spend. Industry must continue to report the total amount of closure costs in OneStop to ensure proper tracking and compliance.

Will SRP closure spend be calculated and removed from each licensee's ABC spend based on information received from the Government of Alberta or from the documentation provided by the licensees before the March 31 ABC reporting deadline?
We are evaluating both options for the SRP-funded portion of a licensee's closure spend. Currently, licensees provide letters that the AER then verifies. We are working with industry on a solution that minimizes the administrative burden on licensees.

It is understood that ABC spend amounts for 2021 need to include SRP portions. If we have already submitted spend on a project, can we resubmit spend for that licence with the SRP portions included? Will it overwrite the previous submission?
Licensees are required to report gross spend, and new submissions overwrite previous submissions. Only one spend submission per year per licence for each spend type is used against the spend target. Each individual row within a bulk upload is considered a submission on a specific licence such that only those submissions you would like to overwrite need to be submitted again. Email @email if you have questions.

Will there be further instructions on reporting SRP spending?
The deadline for reporting SRP spend was March 31. Direct specific questions to @email.

In our 2020 reported spend, can we add additional spend to account for SRP spend?
Yes, licensees are encouraged to continue to report historical spend information as it provides us with more accurate data for use in any future assessments.

Do you need an ABC project registered to get the abandonment relaxation for medium risk type 6 wells or is it automatically granted if you are compliant with the mandatory closure spend?
Yes, each year licensees must submit at least one confirmed ABC project and must meet their mandatory closure spend target to use option 3 outlined in section 3.2.1of Directive 013 for medium risk type 6 wells.

Are company-specific incentives available to better facilitate closure and inactive liability management?
Incentives related to the voluntary closure spend target are applied at the industry level. However, licensees can continue to meet with the relevant AER business teams regarding the potential for area-specific variances. This process has been and remains available to licensees outside of the Inventory Reduction Program. New program incentives related to the voluntary closure spend target program are being considered. Please contact @email with any incentive suggestions for consideration.

Manual 023 states extensions may be rescinded on specific well licences if there are landowner or stakeholder concerns. What type of concerns would warrant recission?
The decision to rescind an extension would depend on site-specific conditions (e.g., a lengthy history of landowner or stakeholder concerns about a specific site).

Confirm that gross spend is reported in OneStop and not the net spend incurred by the licensee?
This is correct. Gross spend is reported in OneStop.

When entering spend in OneStop, where does Authorization ID come from?
The Authorization ID is either the well, facility, or pipeline licence number.

I understand closure costs must be submitted before the licence is transferred. Are there plans to enable the submission of costs incurred in previous years following a transfer?
No, all submissions must be made by the licensee of record. Once a licence is transferred, the previous licensee ceases to have access to information about that licence. As outlined in Directive 088, if a licence transfer application includes inactive licences, the transferor must update their reported closure activities and spends in the DDS system before submitting the application. We will not retroactively adjust the closure spend reporting after the transfer is approved.

OneStop bulk upload is having issues. When will this be fixed?
This bug has been resolved.

Liability Q&As

Under the new directive, will companies still receive monthly LMR information?
We are transitioning to a new liability framework. The requirements of Directive 006: Licensee Liability Rating (LLR) Program will be removed in phases. The LLR requirements are still in place, and the relevant LMR information is still available in the DDS system. More information on the transition will be shared when it becomes available.

Can operators request a voluntary licensee-initiated variation of an LLR parameter and site-specific assessment to include such items as groundwater protection, surface casing vent flow, and not constructed (paper) batteries? If so, what is the estimated time for review and acceptance of the applied-for reductions?
We are looking at which LLR parameters to incorporate in the new framework and are working on a road map for liability adjustments. Changes in LLR parameters will be made for industry as a whole and not for individual licensees. We will provide more information on our website as it becomes available.

Will the liability management framework include liability reduction programs like Directive 011: Licensee Liability Rating (LLR) Program: Updated Industry Parameters and Liability Costs well declaration form or multilicence well pad?
We continue to assess liability programs and what changes might be required to align with the new liability management framework.

Are there plans to change the Oilfield Waste Liability Program?
We will be reviewing Directive 024: Large Facility Liability Management Program , Directive 075: Oilfield Waste Liability (OWL) Program, and other liability management programs over the next few years.

Can the industry inactive liability be published in OneStop monthly?
We will consider this in future enhancements to OneStop.

How do calculations roll up into estimated magnitude of liability?
Directive 011 and site-specific liability assessments are used to calculate liability. A report is available through OneStop showing liability by individual licences.

Are marginal wells (defined in Directive 011 as wells producing 1.59 cubic metres of oil equivalent per day or less) included as inactive well liability?
Inactive liability includes inactive wells and inactive facilities. Marginal wells are included as part of the active well liability.

In the old LLR system, sweet oil batteries had liability overrides. In Directive 088, these sweet multiwell batteries are now included in the summation of deemed liabilities with no overrides. Many of these batteries consist of only a tank and separator, yet often carry the same liability burden as actual 10+ well facilities. Basically, many of these minor small facilities are "paper batteries" as they report to Petrinex as a battery, but they now carry significant liability. Will there be opportunities to clear these up? Do they need to be relicensed?
We have included this issue on our liability road map and are looking at potential solutions.

Deemed asset values don't appear in the liability report in OneStop. Is this available somewhere?
Deemed asset values are available in the DDS. We are not using deemed assets in the same way in the new liability management framework, so they did not carry over to the liability report in OneStop.

Can you provide a means for licensees to apply to have company-specific liabilities replace Directive 011 values? We need the ability to apply for flexible closure costs to match improvements in practices.
Licensee closure spend data reported through the Inventory Reduction Program will be used to improve liability estimates for industry. Licensees are encouraged to report historical data.

Our deemed liability cost includes groundwater protection on several wells that we believe should not have additional liability associated. Temporary overrides were added back from the DDS to OneStop and increasing our liability; however, these were not reviewed. How is this getting resolved?
This issue has been included on our liability road map for future consideration.

The AER will not publish updated values for liability costing. Can we know general costs so external packages can be evaluated?
Directive 006 and Directive 011 provide general estimates for liability. Site-specific liability assessment information is confidential. We encourage you to speak with the licensee involved in the potential sale for more information.