2016 was a busy year from some of the energy regulators. The National Energy Board was moving two pipeline projects forward with approvals of the Trans Mountain expansion and Enbridge's Line 3, both with Federal Government approvals following in December 2016. The NEB also approved its first 40 year export license, with two more following later in 2016, and the controversial Energy East hearing kept the NEB engaged with the recusal of the entire Panel on apprehension of bias and suspension of the hearing until a new panel could be appointed. In 2016, the Supreme Court of Canada weighed in on the standard of review in relation to administrative tribunals and clarified the thorny issues of interjurisdictional immunity and cooperative federalism, issues particularly pertinent in the context of interprovincial pipelines. The Alberta Utilities Commission, Alberta Energy Regulator and British Columbia Supreme Court also released decisions in 2016, covering a multitude of issues of interest to energy participants. And with that, we highlight below some of the top 10 regulatory decisions of impact from 2016.

1. Trans Mountain Expansion Project Is Approved

On May 19, 2016, the National Energy Board (the NEB), issued a lengthy report recommending that the Governor in Council (GIC) approve Kinder Morgan Canada Inc.'s Trans Mountain Expansion Project (the Project).

The NEB assessment, pursuant to the National Energy Board Act (NEB Act) and the Canadian Environmental Assessment Act, 2012 (CEAA 2012), focussed on whether the Project could be constructed, operated and maintained in a safe manner. Ultimately, the Board determined that it could.

Approximately 400 intervenors and 1,250 commenters participated in the hearing, many of them opposed to the Project, and citing concerns related to the risk of a spill, upstream climate change impact and environmental effects. Seventy-three Indigenous groups (representing 83 Indigenous communities) intervened, 35 providing oral evidence before the NEB. A number of government agencies also participated including Environment and Climate Change Canada, Department of Fisheries and Oceans, Health Canada, Transport Canada, Natural Resources Canada, Indigenous and Northern Affairs, Parks Canada Agency, and Port Metro Vancouver.

The $6.8 billion Project, which would nearly triple capacity to ship oil from 300,000 barrels per day to 890,000 barrels per day from Edmonton, AB to Burnaby, BC, was approved, subject to 157 conditions. The conditions largely related to emergency preparedness and response, environmental protection, consultation with those affected by the Project, including Indigenous communities, socio-economic matters, and integrity of the pipeline. For further discussion of the Trans Mountain decision, see Positive Recommendation - National Energy Board Conditionally Approves Trans Mountain Expansion Project our blog post.

As required by the NEB Act, the NEB submitted its recommendation to the Minister of Natural Resources Canada. The Government of Canada's review of the Project was subject to the new interim rules announced January 27, 2016, which apply pending the results of its formal review of the federal environmental assessment legislation and the NEB processes announced December 2015. For further discussion of the interim rules, see our previous post In Process? New Federal Rules for Pipeline Approvals.

On November 29, 2016, the GIC approved the Project and determined that the Project was not likely to cause significant adverse environmental effects. In approving the Project, the GIC also directed the NEB to issue a Certificate of Public Convenience and Necessity to Trans Mountain subject to the 157 terms and conditions identified by the NEB. The Government's accompanying explanatory note, highlights the recent updates to the pipeline safety regime through the Pipeline Safety Act, and its recently announced $1.5 billion in new investment in a national Oceans Protection Plan in relation to ship source spills.

With continued vocal opposition to its construction from parties including municipalities, environmental groups and certain Indigenous groups who may seek legal action with respect to the Government's determinations, whether this approval is the final word on the matter and whether it will result in construction remains to be seen. That said, the Government of British Columbia's January 11, 2017, announcement of issuance of an Environmental Assessment Certificate for the BC portion of the project moves the Project one step closer to completion. At a time of market volatility and challenges to energy infrastructure build, the Trans Mountain approval and B.C. government support is a critical positive step, notwithstanding potential headwinds in 2017 from legal and civil disobedience which may impact its ultimate in-service.

2. Enbridge's Line 3 Replacement Program Receives Approvals

In April 2016, the NEB issued a report recommending that the GIC approve Enbridge's Line 3 Replacement Program (the Line 3 Program) subject to 89 conditions. The Line 3 Program proposed to replace 1,067 kilometres of Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba, with 1,096 kilometres of new pipeline. The original pipeline was built over 40 years ago. Enbridge proposed to operate the replacement pipeline at the original pipeline's capacity of 760,000 barrels of oil per day. The majority of the Line 3 replacement pipeline would be constructed within a right of way that parallels and overlaps existing Enbridge pipeline rights of way, including the Enbridge Mainline corridor.

Intervenors included 35 Indigenous groups, 8 commercial parties, 5 government participants and 2 individuals. The NEB assessment was pursuant to the NEB Act, the CEAA 2012 and the National Energy Board Onshore Pipeline Regulations. The NEB determined that the Line 3 Program was in the public interest and that the replacement of existing pipeline constructed to modern standards would result in a safer system. The NEB imposed 89 project-specific conditions to enhance public safety and environmental protection, and address concerns raised during consultations with Indigenous groups. Thirty-seven conditions related to the construction of the replacement pipeline, and the remaining conditions related to the decommissioning of the existing pipeline and the construction of project-related facilities.

On November 25, 2016, the Government of Canada also approved Enbridge's Line 3 Program with the conditions recommended by the NEB. As noted above, on January 27, 2016, the Government of Canada introduced interim measures outlining how it would consider major projects undergoing review. In its accompanying explanatory note the Government of Canada specifically outlined the measures implemented in accordance with the interim measures, one of which involved additional consultation of indigenous peoples and the affected communities.

Consultation included the use of an online questionnaire. Results showed that the majority of those who participated supported the Line 3 Program citing safety, economic benefits and jobs. In addition, the Crown spent over two years consulting with indigenous peoples and the public. Of note, the Line 3 Program, which traversed 1,046 km of privately owned land, was supported by landowner groups.

For more on the Government of Canada's pipeline approvals, see our Federal Liberal Government Approves Line 3 and Line 2 Pipelines blog post.

3. The NEB Issues its first 40 Year Export Licence

On January 7, 2016, the NEB approved its first 40 year export licence to a joint-venture company, LNG Canada Development Inc. (LNG Canada), giving the green-light for the export of LNG at the outlet of the loading arm of the proposed natural gas liquefaction terminal to be located near Kitimat, British Columbia.

LNG Canada applied to the NEB in July 2012, originally seeking a 25 year licence. The original application was approved in February 2013 issuing Licence GL-3000 (LNG Canada received GIC approval in the same month).

In June 2015, the legislative regime under which Licence GL-300 was issued changed with the Royal Assent of the Economic Action Plan 2015 Act, which, in part, amended subsection 119.01(1.1) of the NEB Act. The amendment provides for the issuance of natural gas export licences for a term not exceeding 40 years if the gas to be exported meets the definition of natural gas. Prior to that amendment, licences could not exceed 25 years.

In July 2015, LNG Canada applied to the NEB pursuant to Section 117 of the NEB Act for a licence for a term not exceeding 40 years.

The NEB Act requires the NEB to assess whether the natural gas proposed to be exported exceeds the surplus remaining after due allowance has been made for the reasonably foreseeable requirements for use in Canada (known as the Surplus Criteria). In performing it assessment the NEB determined that the quantity of natural gas that LNG Canada proposed to export was surplus to Canadian needs and was satisfied that Canada, and North America overall (in the context of free trade within a North American energy market), is large and can accommodate Canada's reasonably foreseeable demand and plausible potential increase in demand.

The NEB also considered the stability of the deregulated natural gas markets in North America noting that they have functioned efficiently since 1985. The NEB saw no evidence to suggest that this would not continue in the long term future.

The NEB approved two further 40 year export licences for LNG projects, in July of 2016 for WCC LNG and in October of 2016 for Pacific Northwest LNG1.

Whether the shift in political paradigm in the south will impact the deregulated North American natural gas market remains to be seen. Given the NEB's consideration of the stability of the North American natural gas market in reaching its decision to grant the long-term licence to export liquefied natural gas, inefficiencies in that market could cause the NEB to hesitate before granting such licences in the future.

4. The Recusal of the NEB Energy East Panel and Suspension of the Hearing2

On September 9, 2016, the Energy East Hearing Panel, made up of Members George, Mercier and Gauthier, issued Decisions on the motions made by Stratégies Énergétiques and Association Québécoise de lutte contre la pollution atmosphérique and Transition Initiative Kenora (TIK). Those motions sought the recusal of Members Mercier and Gauthier from both the Energy East and Eastern Mainline applications as well as the recusal of Member George from the hearing panel on Energy East. The motions also sought the suspension of the Energy East hearing until a new panel could be assigned and the withdrawal of NEB Chair Mr. Watson and Vice-Chair, Ms. Mercier from their functions as Chair and Vice-Chair with respect to the Energy East and Eastern Mainline applications. The motions were based on the NEB members' participation in the National Engagement Initiative launched in November of 2014, and specifically meetings held in January 2015, in Quebec.

From December of 2014 to May of 2015, the NEB held meetings with, among others, municipal and provincial leaders and staff, Indigenous organizations, landowners and environmental groups. The NEB also met with professional and industrial organizations. That included a meeting with Mr. Charest, the former premier of Quebec, attended by Member Gauthier, Chair Watson and Vice-Chair Mercier. As outlined in Member Gauthier's decision, the NEB was unaware at the time of the meetings that Mr. Charest was a consultant for TransCanada Pipelines Limited (one of the applicants).

Two Decisions were issues on September 9, 2016, one by Panel Members Mercier, Gauthier and George, and a separate Decision issued by the NEB Chair and Vice-Chair.

In the Panel Decision, the Panel Members explained the rationale for determining that they should recuse themselves from the hearings. Members Gauthier and Mercier reiterated that their participation in the Quebec meetings were with good intentions and in good faith. However, both Members decided to recuse themselves in order to preserve the integrity of the process and help maintain a climate of trust and impartiality. Despite the fact that Member George did not attend any of the National Engagement Meetings nor the Quebec meeting, he acknowledged that he did engage in extended deliberations with his fellow panel members following the National Engagement Meetings. Emphasizing the need for impartiality and integrity, Member George also decided to recuse himself.

In a separate Decision, the Chair and Vice-Chair of the NEB decided to step down from their activities in those positions with respect to the Energy East and Eastern Mainline applications. While reiterating that the Chair and Vice-Chair must engage actively with Canadians, they concluded that they would recuse themselves as their attendance at the Quebec meetings may cast doubt on their ability to continue to act as Chair and Vice-Chair in relation to the applications. The Chair and Vice-Chair further confirmed that Board staff who attended the Quebec meetings would no longer be involved in the Board's assessment of the application. The Chair and Vice-Chair denied the request that the newly constituted panel conduct an investigation into the engagement meetings as that would frustrate the intended effect of the recusals and could lead to apprehensions associated with the new panel.

Note that the appointment of a new panel on January 9, 2017, may not be enough to move the Energy East proceeding forward. On January 10, 2017, TIK filed a Notice of Motion seeking to void the entire proceeding on the basis of apprehension of bias arising from the recusals by the Panel. Whether the proceeding ultimately will begin again remains to be seen.

5. The Supreme Court of Canada affirms Reasonableness Standard of Review in Edmonton (City) v Edmonton East (Capilano) Shopping Centers

In an important decision for regulatory bodies, the Supreme Court of Canada confirmed the deference to be accorded to tribunals when interpreting their home statutes. In Edmonton (City) v Edmonton East (Capilano) Shopping Centers3 (Edmonton (City)), the Supreme Court of Canada confirmed the "reasonableness" standard of review in all cases where an administrative tribunal interprets its home statute.

In Edmonton (City), the owner of a shopping centre (the Company) complained about its property tax assessment to Assessment Review Board for the City of Edmonton (the Board), on the ground that the assessed value was higher than market value and unfair when compared to the assessed value of similar properties. In proceedings before the Board, the City of Edmonton (the City) asked the Board to increase the assessed value, on the ground that the previous assessment was based on a miss-classification of the property at issue. The Board ruled to increase the assessment.

The Company appealed and questioned whether the Board's enabling statute (the Municipal Government Act RSA 2000 c M-26 (MGA) gave the Board the authority to increase the assessed value following a taxpayer's complaint. The Alberta Court of Queen's Bench set aside the Board order and directed the matter back to the Board for a new hearing. The Alberta Court of Appeal affirmed that order. The Supreme Court of Canada considered the standard of review applicable to the Board's interpretation of the MGA. In a 5-4 decision, the majority of the Supreme Court of Canada ruled that the reasonableness standard of review is presumed to apply in cases where an administrative tribunal is interpreting its home statute. The minority in this case would have applied the correctness standard.

We expect that Edmonton (City) will make it more difficult for energy industry participants to successfully challenge decisions by their regulators in court. Under the reasonableness standard of review, a court reviewing a tribunal's decision against the reasonableness standard will defer to the tribunal's decision, provided that the decision is within a range of possible acceptable outcomes. Following Edmonton (City), the reasonableness standard will be presumed to apply even where there is a statutory right of appeal from the tribunal's decision (as compared to a common-law right to judicial review), as is the case with the Alberta Energy Regulator (AER) (on leave) and the Alberta Utilities Commission (AUC) (also on leave).

6. The SCC weighs in on Interjurisdictional Immunity and Cooperative Federalism Rogers Communications Inc v Châteauguay (City)

On June 16, 2016, the Supreme Court of Canada released its decision in Rogers Communications Inc. v Châteauguay (City)4 (Rogers), clarifying the limits of the doctrines of cooperative federalism and interjurisdictional immunity to interprovincial and federal undertakings. While Rogers was not an interprovincial pipeline project, the Supreme Court established boundaries which have significant implications for decisions relating to interprovincial pipelines and powerlines under the NEB jurisdiction.

The decision focused on the question of whether a municipality may intervene in the siting of a radio-communication antenna system and if so, the scope of the intervention, given the well-established exclusive federal jurisdiction in the sphere of radio-communications.

The federal Minister of Industry had authorized Rogers to install an antenna system on property in Châteauguay. Châteauguay, arguing that the health and well‑being of people living near the installation would be at risk, adopted a municipal resolution authorizing the service of a notice of establishment of a reserve (Notice) that prohibited all construction on the property in question for two years. A few days before the Notice was due to lapse, it was renewed for two additional years. Rogers contested the Notice, arguing that the Notice was ultra vires because it constituted an exercise of the federal power over radio-communication, and was either inapplicable on the basis of the doctrine of interjurisdictional immunity or inoperative on the basis of the doctrine of federal paramountcy.

The majority held that the Notice of a reserve was ultra vires, because it constituted an exercise of the federal power over radio-communication, which is an exclusive federal power. The majority went on to clarify and set the limits of a number of important constitutional principles including cooperative federalism, ultra vires and interjurisdictional immunity. This decision is important to the Canadian energy industry because jurisdictional questions will continue to arise in the interjurisdictional pipeline approval process. The principles and limits articulated by the SCC in Rogers are likely to be very relevant and instructive in interprovincial pipeline approval decisions in the future.

For more on this decision and a summary of the limits of the various constitutional principles noted above, see our The Limits of Ultra vires, Interjurisdictional Immunity and Cooperative Federalism in Interprovincial Pipeline Approvals: Application of Rogers Communications Inc v Châteauguay (City) 2016 SCC 23 blog post.

7. The AUC 2016-2017 GCOC Determined the Return on Equity for Alberta Utilities5

On October 7, 2016, the AUC issued its decision in the 2016 Generic Cost of Capital Proceeding (the 2016 GCOC). The 2016 GCOC was initiated by the AUC to set the deemed capital structures and generic returns for 2016 and 2017. A number of rate payer groups intervened in the process that also involved virtually all the Alberta utilities. The interveners' experts proposed a range of 7% to 7.5% return on equity (ROE), while the Alberta utilities experts proposed a range in and around 9% to 10.5% ROE and a recommended equity component of in or around 40%. An oral hearing took place in May and June 2016, and the AUC issued its decision in October 2016. The AUC determined that the allowed rate of return on equity (ROE) was 8.3% in 2016, and 8.5% in 2017. The ROE was applied uniformly to several of Alberta's major gas and electricity utilities. The AUC accounted for the difference in risk between the various utilities by adjusting the approved deemed equity ratios on an individual utility basis.

The allowed ROEs and approved deemed equity ratios for 2016 and 2017, from this decision do not apply to certain Alberta utilities because they are regulated pursuant to the Electric Utilities Act Regulated Rate Option Regulation and the Gas Utilities Act Default Gas Supply Regulation, respectively. Nor do they apply the various investor-owned water utilities under the AUC's jurisdiction.

Of note in this decision were the Commission's findings with respect to investor perceptions of near term market uncertainty. The Commission found that compared to investor uncertainty which existed in the 2013 GCOC, it was reasonable to conclude that recent instability in investor perceptions of near-term market uncertainty, are indicative of increased investor uncertainty in the 2016-2017 period.

The AUC further confirmed that some amount of upward pressure on the return expectations of investors since the 2013 GCOC decision was due to an increase in perceived business risk of the affected utilities. The AUC held that this perception existed, in part, as a result of investor uncertainty about how the AUC will continue to interpret and apply the Stores Block principles as reviewed in the Utility Asset Disposition Decision of the AUC and confirmed by the Alberta Court of Appeal. Specifically, the AUC recognized that the perception was in part based on uncertainty relating to "the parameters of an "extraordinary retirement" to future case-by-case examples of assets unexpectedly being removed from utility service prior to the full recovery of their undepreciated capital costs." (para 521). However, despite the upward pressure on investor perceptions, the AUC found that there was no appreciable increase in earnings volatility risk under the performance-based regulation.

8. The AER Defines "communication" for the purposes of Pool Delineation

In June 2016, the AER approved an application to merge two oil pools, which required it to determine whether the two pools were in communication.

The issue before the AER was whether, on the evidence of pressure data, the two pools are separate and if they are not, whether the communication between them was "effective" enough to find that they are the same pool. One of the impacts of the pool re-delineation was a potential common carrier application to gain access to the gathering and processing system currently serving one of the pool's wells.

Pursuant to Section 33 of the Oil and Gas Conservation Act (OGCA), the AER has the authority to re-delineate pool boundaries after the initial assignment of wells to a pool upon additional information becoming available. While there is no prescribed test, the AER and its predecessors have historically taken into account reservoir characteristics, including geology, geochemistry, gas composition, pressure data, and other relevant matters. In this case, the AER relied primarily on pressure data. The AER found a slow but steady decline in pressure of the reservoir observed in one pool well and the apparent drainage or depletion of its reserves. It also found that the only producing wells that could affect production from that well were the wells in the second pool.

On the issue of effectiveness of the communication, the AER held that the OGCA does not require or establish thresholds of communication for the purposes of determining whether pools that are in fact physically connected can appear to be separate for the purposes of pool delineation. For the purposes of determining whether pools appear to be separate, the AER defined "communication" as "the ability of production from one or more wells in a reservoir to affect production by depleting reserves that might otherwise be produced from another well in the same reservoir." The AER concluded that the two pools did not appear separate and as a result, the pool boundaries were re-delineated to merge the two pools.

The AER encourages well licensees to apply for pool re-delineation when new information is available that would substantially change existing pool boundaries. As set out in Directive 065: Resources Applications for Oil and Gas Reservoirs, the interpretation of pool reserves and delineation may impact regulatory requirements for the operation and development of oil and gas pools in Alberta, as well as equity issues between operators. Pool delineation can be critically important as it affects oil and gas operators' rights to and interests in the production from the reserves, and may have other regulatory implications. Pool delineation disputes can be vigorously contested and result in highly technical and lengthy proceedings. The AER has provided some further clarity on how it will approach these disputes by clearly defining what amounts to "communication" for the purposes of pool delineation.

9. AUC Decision in Grizzly Bear Creek Wind Power Project provides Template for Wind Farm Approvals

In May 2016, the AUC approved applications for the construction and operation of the Grizzly Bear Creek Wind Power Project. The AUC determined that the wind farm, as a "power plant," is subject to the legislative and regulatory scheme provided by the Hydro and Electric Energy Act (HEEA), Section 17 of the Alberta Utilities Commission Act (AUCA) and AUC Rule 007: Applications for Power Plants, Substations, Transmission Lines, Industrial System Designations and Hydro Developments. While the applicable test for power plant approvals is the public interest test, the HEEA does not permit the AUC to take into account the potential need and cost of a project. The AUC reiterated that the public interest test will be largely met if applications are shown to be in compliance with existing provincial health, environmental, and other regulatory standards in addition to the public benefits outweighing negative impacts. The AUC adopted this approach as "an effective framework for the assessment of wind energy projects."

The specific issues raised in this proceeding included the applicant's consultation and participant involvement program; noise impact assessments, compliance with the AUC regulatory requirements for noise and health impacts arising from the project's noise; safety concerns; potential property impacts; potential environmental impact; construction impacts and decommissioning.

The AUC, adopting its prior ruling with respect to effective consultation under Rule 007, found that the applicant met the objectives of the program. While the project will likely meet the permissible sound levels, the AUC conditioned the project approval with all noise mitigation measures proposed in the application as well as a requirement to verify and confirm that the project complies with the requirements of Rule 012. The AUC found that, notwithstanding the potential for annoyance, wind turbine noise below 40 dBA and compliant with Rule 012 will not cause sleep disturbance or adversely impact the health of residents living in proximity to the project. The AUC was also satisfied that the implementation of the applicant's monitoring, safety and emergency response measures would mitigate the possible risks of ice throw events and potential turbine fires.

While the AUC recognized that the wind turbines would change the landscape of the project area it found insufficient evidence that land use or property value would be impacted. Acknowledging that the project would impact birds and bats, the AUC accepted the applicant's mitigation measures as approved by Alberta Environment and Parks as conditions of the project approval. The AUC also accepted the applicant's mitigation measures to reduce construction impacts in the project area as well as its commitment to comply with regulatory requirements for decommissioning and reclamation.

Regarding a fund for decommissioning costs, the AUC found that there is no statutory requirement for the establishment of a fund for decommissioning costs for wind farms. The AUC accepted evidence that decommissioning costs will be paid out of moneys recovered from the sale of the salvage from the proposed wind turbines and, possibly, cables.

With the guidance provided by the AUC on the framework and considerations, this decision serves as a template for wind farm facilities approvals. Also of note, while a decommissioning fund is not currently required, that does raise the question of whether such a fund should be established in future, particularly in light of the issues arising in the oil and gas context in Alberta.

10. British Columbia Supreme Court Decides that the Province Cannot Abdicate its Authority

In January 2016, the British Columbia Supreme Court released its reasons for judgment in Coastal First Nations v. British Columbia (Environment)6 (Coastal First Nations). The applicant, Coastal First Nations, sought, by way of judicial review, a series of declarations setting aside an equivalency agreement that the BC Environmental Assessment Office (EAO) had entered into with the NEB. The equivalency agreement had allowed for the EAO to rely on an environmental assessment from the NEB related to Enbridge's Northern Gateway project. The equivalency agreement was intended to avoid redundancy in the approval process and provided that any environmental assessment by the NEB would constitute an equivalent environmental assessment for the EAO. Coastal First Nations argued that by entering the agreement, the EAO abdicated its decision-making authority and Coastal First Nations also argued that they were owed a duty to consult prior to the equivalency agreement being entered into.

The British Columbia Supreme Court held that British Columbia's Environmental Assessment Act (EAA), the main legislative framework governing the Province's environmental assessment projects, did not allow the Province to abdicate its decision-making authority as the purpose behind the EAA was to promote economic interest in British Columbia and to protect its land and environment. Accordingly, the Court held that the equivalency agreement was invalid to the extent that it purported to remove the need for reviewable projects, such as the Northern Gateway project, to obtain an environmental assessment certificate under the EAA. The Court declared that the Province must exercise its decision-making authority under the EAA in relation to the Northern Gateway project.

The Court also considered whether there was a constitutional obligation on the Province to consult with First Nations before engaging in government action that may adversely affect First Nations' rights. The Court held that both the federal and provincial Crown do owe "specific responsibilities to consult First Nations as their respective legislative powers intersect." However, the Court held that in this case the Province did not owe a duty to consult prior to entering into the equivalency agreement because there was little possibility that Coastal Fist Nations' rights would be adversely impacted by the equivalency agreement as the Province retained the ability to unilaterally terminate the agreement and as such, the Province would not have been bound by the decision of the NEB. Nonetheless, the Province did owe Coastal Fist Nations a duty to consult and accommodate on the Northern Gateway project and the duty to consult if the equivalency agreement was not terminated.

The Coastal First Nations decision is important as it makes it clear that provinces cannot abdicate their duty to consult to the federal Crown in respect of projects that require both federal and provincial approval.


1. BLG was counsel on this matter.

2. BLG was counsel on this matter.

3. 2016 SCC 47.

4. 2016 SCC 23.

5. BLG was counsel on this matter.

6. 2016 BCSC 34.

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