Micro-Generation in Alberta – Watt It’s All About

by Lydia Roseman and Doug Evanchuk

As people all over the world become more environmentally conscious, we anticipate more and more Albertans looking for a “greener” way of life. One of the “green” actions that immediately springs to mind is producing one’s own energy using renewable sources. Many of us have driven by a house with solar panels and thought about trying to do the same thing.

Alberta’s regulatory scheme makes this possible through special legislation geared towards “microgeneration”. Microgeneration under the Alberta regulatory scheme means the generation of electricity from renewable or alternative energy sources for one’s own use, in the amount of 5 MW or less.

Alberta has simplified the regulatory process and reduced costs for microgenerators, but it can still be fairly complex to get set-up to produce your own electricity. Below we provide more detail on what it means to be a microgenerator in Alberta then set out the steps required to become one.

Background on Alberta’s Energy Regulation

The legislative framework that enables the generation and provision of electricity in Alberta is extremely complex, involving both provincial and federal legislation and regulations. The two primary pieces of legislation in Alberta are the Electric Utilities Act[1] (the “EUA”) and the Hydro and Electric Energy Act[2] (the “HEEA”).

Under these Acts, all electricity generated in Alberta must generally be exchanged through Alberta’s Power Pool, that is it must be bought and sold on the wholesale electricity market operated by the Alberta Electric System Operator (the “AESO”). Additionally, any connection of generation systems to the interconnected electrical system requires an order from the Alberta Utilities Commission (the “AUC”), unless an exception applies.

Therefore, without any exemption, an individual installing and using a solar panel would need to apply to the AUC and sell the electricity generated to Alberta’s power pool. That would clearly be prohibitive to most individuals looking to simply make life a little greener by generating all or a portion of their own electricity.

To promote this type of green activity, Alberta has created a number of exceptions for “micro-generators” to simplify the process and make it much easier for an individual to generate and use their own electricity.

What Does it Mean to Be an Alberta Micro-Generator?

Where a unit used to generate electricity is used entirely for self-supply (i.e. the energy produced on the property is entirely consumed on the property), that unit is exempted from most of the provisions of the EUA and the HEEA. The electricity generated from that unit does not need to be exchanged through the power pool and the unit does not require approval from the AUC.

Alberta’s Micro-generation Regulation[3] (“Micro Reg”) takes things one step further; it creates a simple process for small Alberta microgenerators to self-supply and sell the excess electricity to the Alberta power pool.

The Micro Reg covers “small micro-generation” (i.e. capacity of less than 150 kW) and “large micro-generation” (i.e. capacity between 150 kW and 5 MW) for electricity produced using renewable, environmentally friendly fuel sources.

The Micro Reg is designed to allow these small renewable generating units to easily both self-supply and sell the excess back to the energy market through an interconnection to an electric distribution system. This is set up through provisions that require the owner of the electric distribution system to provide metering services and net billing to the micro-generator. Additionally, the microgenerator’s retailer or service provider is then required to act as the self-supplier’s market participant, meaning the owner of the unit will not need to negotiate and transact directly with the AESO.

The Micro Reg also greatly reduces the legislative “red tape” that a generating unit must pass through. For example, a microgenerator is not typically required to apply to the AUC to construct or operate the generating unit; instead, it simply provides notice to the owner of the electrical distribution system of its intent. The AUC only becomes involved if the owner disputes whether the unit appropriately falls under the Micro Reg.

Importantly, this Regulation also creates an exception from the requirement in section 18 of the EUA that power be exchanged through the power pool for small micro-generation entering the interconnected electric system. That is, small micro-generators do not need to exchange electricity through the Power Pool.

Becoming a Micro-Generator

Microgenerators are not required to complete an application to the AUC so long as the generating unit will not directly and adversely affect any person, will not have any adverse impact on the environment, and is constructed and operated in compliance with AUC’s Rule 12: Noise Control[4] (i.e. the unit will not exceed the maximum allowable sound level).

While the microgenerator does not need AUC approval, it is required to complete consultation with stakeholders in accordance with the AUC’s Participant Involvement Program Guidelines.[5] If the capacity of generation will be less than 1 MW, the microgenerator must simply notify occupants, residents, and landowners within the first row of surrounding properties. For microgenerators between 1 and 10 MW, the same notification is required and the AUC asks that the microgenerator consider “consultation” with those individuals, if the circumstances require. This must be done prior to submitting a micro-generation notice application.

Instead of an application to the AUC, the microgenerator submits a “micro-generation notice application” to the electric distribution system owner for approval. This application includes an electrical single-line diagram and may include other documents, as applicable.[6] If the system owner determines the microgeneration unit meets the requirements in the Micro Reg, the owner must approve the application and install a meter; if not, the owner must file a notice of dispute with the AUC and the AUC will make the ultimate decision.[7]

Once the microgeneration unit is approved, the system owner is responsible for (and pays for) the installation of the electrical meter and the collection of electricity data. The system owner will also bear the cost of connecting the generating unit to the interconnected electric system unless the cost is “extraordinary”. In that case, the system owner must file a notice of dispute with the AUC, and the microgenerator may be required to reimburse the system owner for a portion of the costs.^.

Microgenerators must also notify their energy retailer that they are becoming a microgenerator. The retailer then acts as the electricity market participant for the microgenerator and net bills the microgenerator. This means that any over-production of electricity, beyond that used as self-supply, will be credited to the microgenerator, any shortfall that is covered by the power pool is billed, and the net amount is either charged or reimbursed to the microgenerator.

Conclusion

While electrical regulation in Alberta is highly complex, processes for “microgenerators” are much simpler. Individuals generating small amounts of electricity for their personal use, using renewable sources, avoid complex AUC processes and interactions with the AESO. However, if the microgenerator is looking to connect its generating unit to Alberta’s electrical grid, there are still some steps that must be followed.

The microgenerator must comply with applicable AUC rules and notify neighbouring properties, the local electrical distribution system owner, and their energy retailer of their intent to become a microgenerator. Once the microgenerator has completed those processes, the “behind the scenes” work is largely conducted by the system owner and the retailer on their behalf. At that point, the microgenerator will simply reap the financial and moral rewards of contributing to a greener electrical market in Alberta.

If you have any questions about microgeneration, please do not hesitate to contact our Regulatory team. We would be more than happy to help you become a microgenerator.

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[1] SA 2003, c E-5.1.

[2] RSA 2000, c H-16.

[3] Alta Reg 27/2008.

[4] https://www.auc.ab.ca/Shared%20Documents/Rules/Rule012.pdf.

[5] https://www.auc.ab.ca/Shared%20Documents/rules/Rule007.pdf.

[6] Additional documents that may be required include a site plan or pictures to illustrate the micro-generation unit location, an electrical permit, an electrical inspection report, a development or building permit and environmental impact assessment documents: <https://www.auc.ab.ca/regulatory_documents/Reference/MicrogenerationNoticeSubmissionGuideline.pdf>.

[7] While a microgenerator does not require AUC approval, it must be able to demonstrate compliance with the Micro Reg and applicable AUC rules on request. Microgenerators may also still require other permits or approvals under federal or provincial legislation or municipal bylaws (for example, a municipal building permit).

Potential Implications of Alberta’s Rescission of the Coal Policy

by Gavin Fitch, Q.C.

On June 1, 2020 the provincial government rescinded a decades-old policy that placed restrictions on the mining of coal in Alberta’s Eastern Slopes.

A Coal Development Policy for Alberta was issued in 1976 and was widely known as the “Coal Policy”. The Coal Policy covered many aspects of the coal development process, from the acquisition of exploration rights and coal leases to royalties, prices and marketing. However, the Coal Policy was best known for dividing a large area of the Eastern Slopes of the Rocky Mountains (where there are substantial coal deposits) into four different land use categories (“Coal Categories”) where coal development was prohibited (Category 1), restricted (Category 2) or generally encouraged (Categories 3 and 4).

In a media release announcing the rescission of the Coal Policy, Alberta Energy stated that with various regulatory, policy and planning advances over the past 45 years, the Coal Policy “became obsolete”. The announcement also stated:

Former category 1 lands will continue to be protected from coal leasing, exploration and development on public lands but will not infringe on private lands or freehold mineral rights. This will support critical watersheds, biodiversity (including numerous species at risk), as well as recreation and tourism activities along the eastern slopes of Alberta’s Rocky Mountains. Leasing outside of these areas will be subject to the same land use planning and management rules that apply to all other resources and industrial uses.

All coal development projects will continue to be considered through the existing rigorous Alberta Energy Regulator review process. This review is based on each project’s merits, including its economic, social and environmental impacts.

To understand what the rescission of the Coal Policy means, and in particular the elimination of the Coal Categories, it is critical to know how the Coal Policy defined the categories, in particular Categories 1 and 2. Category 1 lands were defined as those:

in which no exploration or commercial development will be permitted. This category includes National Parks, present or proposed Provincial Parks, Wilderness Areas, Natural Areas, Restricted Development Study Areas, Watershed Research Study Basins, Designated Recreation Areas, Designated Heritage Sites, Wildlife Sanctuaries, settled urban areas and major lakes and rivers. These are areas for which it has been determined that alternate land uses have a higher priority than coal activity. Category 1 also includes most areas associated with high environmental sensitivity; these are areas for which reclamation of disturbed lands cannot be assured with existing technology and in which the watershed must be protected.

Category 2 lands were defined as those:

in which limited exploration is desirable and may be permitted under strict control but in which commercial development by surface mining will not normally be considered at the present time. This category contains lands in the Rocky Mountains and Foothills for which the preferred land or resource use remains to be determined, or areas where infrastructure facilities are generally absent or considered inadequate to support major mining operations. In addition this category contains local areas of high environmental sensitivity in which neither exploration or development activities will be permitted. Underground mining or in-situ operations may be permitted in areas within this category where the surface effects of the operation are deemed to be environmentally acceptable.

The map from the Coal Policy showing the location of the various categories of land can be found here. Category 1 lands are yellow; Category 2 lands are blue.

As part of the rescission of the Coal Policy, Alberta Energy issued Information Letter 2020-23, which states:

With the rescission of the Coal Policy, all restrictions on issuing coal leases within the former coal categories 2 and 3 have been removed. Alberta will continue to restrict coal leasing, exploration and development within public lands formerly designated as coal category 1. This prohibition on coal activities is being continued to maintain watershed, biodiversity, recreation and tourism values along the Eastern Slopes of Alberta’s Rocky Mountains.

Having regard for how the Coal Policy defined Category 2 lands, and the map showing their location, it is clear that in fact a substantial amount of land in the Eastern Slopes that was formerly restricted from coal development has been now been opened to development. Under the Coal Policy, “limited exploration” was permitted in Category 2 lands but “commercial development by surface mining” was effectively prohibited. This prohibition has been removed.

One of the reasons stated for the rescission of the Coal Policy is that when the Coal Categories were created in 1976 “land use planning hadn’t yet been completed”; and that the categories are no longer needed given “today’s modern regulatory, land use planning and leasing systems.”

Alberta enacted the Alberta Land Stewardship Act (“ALSA”) in 2009 to “provide a means to plan for the future” and to “provide for the co-ordination of decisions by decision-makers concerning land, species, human settlement, natural resources and the environment”. Under ALSA, the province was divided into 7 areas for which a regional plan was to be created. To date, only 2 regional plans have been completed: the Lower Athabasca Regional Plan and the South Saskatchewan Regional Plan (“SSRP”).

The SSRP covers a portion of the southern Eastern Slopes that was also covered by the Coal Policy. However, a large portion of the Eastern Slopes north of the headwaters of the Oldman and Livingstone Rivers fall outside the SSRP and are not subject to any other regional plan. Thus, it seems fair to say that land use planning for the Eastern Slopes is still not completed. Further, with the rescission of the Coal Policy and the elimination of the Coal Categories, there is no land use plan in place for these lands.

The SSRP was adopted in 2014 and last amended in 2018. It is intended to guide development in the South Saskatchewan River basin until 2024. The SSRP addresses potential coal development and specifically states that the government will review the coal categories established by the Coal Policy:

to confirm whether these land classifications specific to coal exploration and development should remain in place or be adjusted. The review of the coal categories will only be for the South Saskatchewan planning region. The intent is for the SSRP and implementation strategies of the regional plan or future associated subregional or issue-specific plans within the region to supersede the coal categories for the purposes of land use decisions about where coal exploration and development can and cannot occur in the planning region.

This suggests that the SSRP contemplated the Coal Categories being replaced or superseded by new “adjusted” land use classifications developed under the SSRP that would guide decision-makers about where coal exploration and development can occur. What has happened instead is the Coal Categories have been eliminated but not replaced with anything new. Further, the intent of the government’s new policy appears to remove the categorization of lands for coal development. Instead, development will be reviewed by the Alberta Energy Regulator on a project-by-project basis, without the benefit of the guidance that would be provided by adjusted land use classifications under SSRP.

 It appears that the Coal Policy was rescinded to spur coal exploration and development in Alberta. The foregoing analysis suggests, however, that the elimination of the Coal Categories without them being replaced by a new planning regime may have unintended consequences.

First, as noted above, it raises the issue of the need to revise the SSRP. This could lead to legal challenges. Second, the environmental assessment process for major resource extraction projects like surface coal mines is already slow and cumbersome. Removing any guidance as to where coal development is appropriate arguably will burden the existing environmental assessment process even more by opening it up to debates about the appropriateness of coal development in a specific location.

Update on Site Rehabilitation Programs in Alberta, British Columbia and Saskatchewan

by Anna Fitz, Student-at-Law, and JoAnn P. Jamieson

On April 17, 2020, the federal government announced $1.7 billion in funding to clean up oil and gas sites in Alberta, British Columbia, and Saskatchewan. The goal of the federal funding was to create immediate jobs in the three provinces while helping companies avoid bankruptcy during the COVID-19 pandemic. 

All three provinces were quick to announce programs in the hopes of creating jobs and getting people back to work. This article provides an update on the programs in each province.

Alberta

Alberta received $1.2 billion, the bulk of the federal funding. On April 24, 2020, the Government of Alberta announced its “Site Rehabilitation Program,” which provides up to $1 billion in grants to oil field service contractors to perform well, pipeline, and oil and gas site closure and reclamation work. 

The goals of the program are to:

·       immediately get Alberta’s specialized oil field workforce back to work,

·       accelerate site abandonment and closure efforts, and

·       quickly complete a high volume of environmentally-significant work.

Inactive oil and gas sites may be nominated by landowners and Indigenous communities. Landowners can nominate inactive sites by emailing the required information (including the legal description of the land, landowners on the land title, and contact information) to the government. Indigenous communities can also nominate inactive sites by email; required information includes the name of the First Nation or Métis settlement, the legal description of the site, and the licensee information sign at the site. A detailed overview of the nomination process can be found here.

In order to be eligible for funding to do the work, service contractors must be located in Alberta and must offer jobs to Albertans. Eligible work includes closure on inactive wells and pipelines, Phases 1 and 2 environmental Site Assessments, remediation, and reclamation. Interested parties can apply on the Site Rehabilitation Program website.

The Alberta government will provide funding for the Site Rehabilitation Program in multiple increments. The first increment, which has now ended, reportedly received significant interest. The second increment is currently on-going, and will close for applications on June 18, 2020. Third and later increments will also become available.  

In addition to the Site Rehabilitation Program, the government of Canada has extended a $200 million repayable loan to the existing Orphan Well Association (“OWA”). Under the OWA, an orphan site is “a well, pipeline, facility or associated site that does not have a legally responsible and/or financially viable party to deal with its decommissioning and reclamation responsibilities.”

The OWA has a procurement process through which it selects from a list of prime contractors, who are then normally responsible for choosing their own subcontractors. However, with the new federal funding, the OWA is planning to collaborate with its prime contractors to select subcontractors (interested parties will be able to apply) for the additional work. The OWA anticipates allocating the new funding through a “staged process.” After further planning, OWA will be providing information about the process on its website.

British Columbia

On May 13, 2020, the Government of British Columbia (“BC”) announced its “Dormant Sites Reclamation Program” with which it is channeling its $100 million in federal funding toward cleaning up dormant sites. In BC, well sites are deemed “dormant” if they do not reach a threshold of activity for five years consecutively, or if they have failed to produce for at least 720 hours yearly.

The program is specifically for B.C. companies and contractors with experience in environmental contracting and/or oil and gas infrastructure abandonment. Applicants must have a valid contract with a BC-based oil and gas activity permit holder for a dormant site.

Eligible applicants can apply online, where the information they will need to provide includes the company details, permit holder name, well authorization number, and estimated cost of each work component.

The B.C. government will provide its funding in two increments, the first from May 25, 2020 to October 31, 2020. Funding for this first increment is up to $50 million. The second increment will commence on November 1, 2020 and run to May 31, 2021.

In both funding increments, the B.C. government will provide financial contribution up to 50% of the total estimated or actual costs (whichever is less), up to a total of $100,000 per application and per closure activity. The program has already received significant interest; in a news release, the province noted it received over 1,100 applications on the first day, which means the program was nearly fully subscribed.

B.C. landowners, local governments, and Indigenous communities can nominate dormant oil or gas sites on their land through an online process beginning June 15, 2020. The BC government noted that such nominations will be a priority in the second increment of funding.

Saskatchewan

On May 22, 2020, the Government of Saskatchewan initiated the “Accelerated Site Closure Program” (“ASCP”). Through this program, the Ministry of Energy and Resources will manage $400 million from the federal government for the abandonment and reclamation of inactive oil and gas wells and facilities.

The ASCP involves multiple phases, the first for up to $100 million (the future funding and applicable phases have not yet been announced). In order to be eligible, licensees must be in good standing regarding debts owed to the Crown as of March 1, 2020 (e.g. the Oil and Gas Administrative Levy, the Orphan Well Levy, etc.). Eligible licensees will receive a minimum of $50,000 toward their abandonment and reclamation projects.

The program provides that licensees nominate their wells and facilities through the IRIS system (Integrated Resource Information System). Service companies, interested in performing the work, must apply through SaskTenders beginning in the first week of June 2020. Further details on the application process, and who to contact with questions, can be found in the following bulletin.

The Saskatchewan government anticipates that up to 8,000 wells and facilities will be abandoned and reclaimed through the ASCP, which in turn will support approximately 2,100 full-time jobs. Saskatchewan plans to develop an Indigenous procurement strategy further into the program.

The first phase of the ASCP is now complete, and eligible licensees have received notice of their allocation.  

Moving Forward

The federal funding is a welcome boost to cleaning up inactive oil and gas sites in Western Canada. This is a significant step to subsidize old, inactive sites and lower the associated environmental risks. As the three programs also create jobs and contracting opportunities for local parties, the federal funding appears to be a big win for both the energy industry and the environment in all three provinces during these difficult times.

If you have further questions about any of the three cleanup programs in Alberta, British Columbia or Saskatchewan, please reach out to JoAnn P. Jamieson or Sean Parker, co-chairs of McLennan Ross LLP’s Energy, Environment and Regulatory Practice Group.

Bill 7: Alberta Government Aims to Set Deadlines for AER Project Approvals

By Marika Cherkawsky and Michael Barbero

On Wednesday, the Alberta Government tabled Bill 7, the Responsible Energy Development Amendment Act, (“Act”). If passed, the Act would allow Cabinet to specify time limits for the review and approval of energy projects by the Alberta Energy Regulator (“AER”). Bill 7 is intended to provide project proponents and other applicants with greater certainty as to approval timelines.   

Bill 7 does not prescribe the maximum timelines, rather it authorizes Cabinet to approve regulations establishing same (see s. 60(2) of Bill 7). In doing so, Bill 7 removes the requirement that the AER must make a written decision, with reasons, within “the time prescribed by the rules” after the completion of:

•  a hearing on an application (s. 35(1));
• a regulatory appeal (s. 41(1)); or
• a reconsideration (s. 44(1)).

Instead, Bill 7 proposes amending section 60 of the Responsible Energy Development Act by including the following subsections:

(2) The Lieutenant Governor in Council may make regulations

• (a) to establish time limits on the exercise of powers, duties and functions by the Regulator;
• (b) to establish time limits in respect of any process, hearing or decision concerning which the Regulator may make rules under this Act or any other enactment.

(3) A regulation made under this section prevails over any rule that is made or amended by the Regulator with which it conflicts or is inconsistent to the extent of the conflict or inconsistency.

Uncertainty remains in relation to how the government will arrive at the prescribed timelines, what consultation or input from the AER will be received and whether or not the imposition of timelines will resolve the concerns voiced by industry. Moreover, the government has made it clear that the AER’s obligations to fully consider social and economic effects and the effects of any activity on the environment and landowners is unchanged.  

The government is hopeful that the changes proposed by Bill 7 will assist in restoring predictability to the regulatory process without sacrificing rigor in conducting assessments of proposed projects. Whether the imposition of deadlines will be effective in achieving this goal remains to be seen.

Alberta Energy Regulator Suspends Environmental Monitoring Due To COVID-19

By Mandy Kinzel and Sean Parker

On May 20, 2020, the Alberta Energy Regulator (“AER”) announced sweeping temporary suspensions to environmental monitoring requirements across Alberta’s energy industry. The suspensions are a follow-up to the Minister of Environment and Parks and Minister of Energy’s earlier suspensions to certain environmental reporting requirements. This is a significant development as the previous measures essentially suspended requirements to report routine monitoring information, while this new step actually suspends the underlying requirement to monitor in certain circumstances. The AER states this step is a measured response to public health concerns from the COVID-19 pandemic including legitimate concerns that energy operators will not be able to meet certain monitoring requirements while complying with the COVID-19 public health orders and guidelines.

Scope of the New Suspensions

While the AER caveats the announcement with the comment that “there must be a demonstration that the public health orders pose a challenge in completing the monitoring activity” and “any deferral of monitoring must have a low risk of potential short- and long-term impacts”, the scope of the monitoring suspensions is significant. The suspension affects the following monitoring activities:

• Surface water quality testing and analysis with the exception of surface water released to the environment.
• All groundwater sampling under Water Act licences and approvals but at least one monitoring event must take place in 2020.
• Soil monitoring and groundwater monitoring under the Environmental Protection and Enhancement Act (EPEA) approvals with the exception of any monitoring necessary to protect human health and ecological receptors. 
• Lab testing of water released except for domestic wastewater.
• Volatile organic compounds and reduced sulphur compound monitoring, including fugitive emissions surveys carried out by third-party contractors.
• Fugitive emissions leak detection and repair (LDAR) programs carried out by third-party contractors. Methane monitoring requirements must still be met.
• Quality Assurance Plan (QAP) audits and verifications, including third-party audits, under the Continuous Emission Monitoring System (CEMS) Code. Approval holders are still required to maintain CEMS monitoring and report exceedances and meet federal multi-sector air pollutants regulation measurement requirements.
• Audits and verifications, including third-party audits, under the Continuous Emission Monitoring System (CEMS) Code. Approval holders are still required to maintain CEMS monitoring and report exceedances and meet federal multi-sector air pollutants regulation measurement requirements.
• Wildlife monitoring programs but wildlife deterrents and mitigations are to remain in place.
• Wetland monitoring.
• All research requirements under EPEA approvals.
• All reclamation monitoring programs. The mitigation and repair of potential impacts, such as weed infestations and soil erosion, must continue.
• Five-year integrity testing of aboveground storage tanks. Monthly visual inspections for evidence of problems must continue.
• In addition, the AER provided the following regulatory modifications:
• Operators that conduct twice-annual surveys to determine the volumes of fluid tailings and treated fluid tailings in their storage facilities are now required to perform only one of those surveys in 2020.
• Pipeline deactivation - Internal and external corrosion mitigation and monitoring must continue on deactivated pipelines that are susceptible to corrosion.
• Approval holders may apply to the AER to modify the frequency and timing of manual stack testing (stack surveys) and similar activities. 

Ongoing Reporting of Emergencies and Documentation of Reporting

 

The AER advises that operators must continue to report emergencies, including incidents, contraventions, and releases that have or may have the potential to impact the environment or public safety. Further, operators must continue to record and retain complete documentation relating to any reporting.

Interaction with Federal Requirements 

Similar to the initial measures implemented by the Province, the federal government has suspended certain requirements to report data due to COVID-19, however the data must still be collected. To date, the federal government has not suspended any monitoring requirements.

Termination

The AER suspensions and modifications will apply for so long as Ministerial Orders 17/2020 and 219/2020 and the public health orders are in effect, which are currently scheduled to last until August 14, 2020. However, the soil monitoring and groundwater under EPEA approvals must resume no later than September 30, 2020, with at least one monitoring event taking place in 2020. All timelines are subject to change as the situation develops.

Effect on Industry 

The suspensions and modifications come as a welcome relief to operators currently strained by COVID-19 restrictions on operations. Industry had raised concerns that the reporting suspensions put in place in March 2020 did not provide sufficient relief as the main challenges during the COVID-19 pandemic relate to attending on site and fulfilling the monitoring requirements, not the reporting of those results. 

For further information on how these developments may impact you or your business, contact JoAnn P. Jamieson in Calgary, Sean Parker in Edmonton or another member of our Environmental, Energy and Regulatory Practice Group.