FEBRUARY 2015
2014 IN REVIEW: TOP 10 LEGISLATIVE AND
REGULATORY CHANGES FOR THE CANADIAN
OIL AND GAS INDUSTRY
OIL AND GAS BULLETIN
2014 was a landmark year for legislative and regulatory changes relevant to the oil
and gas sector. The federal government not only introduced pipeline safety legislation
in furtherance of its Responsible Resource Development policy framework, but also
required additional financial reporting from the natural resource industry. Ottawa was
conspicuous by its absence in 2014 respecting greenhouse gas policy, perhaps the
biggest regulatory story of the year. However, several of the provinces jumped into the
breach through their own carbon mandates, a trend which may continue in 2015.
Provincial energy regulation was especially active in
2014, if not exactly coherent with each other. British
Columbia introduced LNG-driven reforms in tax and
facilities regulation to provide clarity to potential
investors. Alberta enhanced its aboriginal consultation
framework and significantly expanded the energy
regulator’s jurisdiction. Saskatchewan, Manitoba
and Ontario were relatively quiet on the legislative
front. Québec and New Brunswick took measures to
block oil and gas development generally, and fracking
in particular.
On the international front, the federal government
sanctioned Russia’s oil and gas industry, monitored US
political developments on Keystone XL and weathered
impacts of rapidly declining oil prices, including a
deferral of the federal budget until later this year. These
political issues will continue to intersect with economic
and regulatory ones in 2015. For Canadian energy
companies, we expect that navigating the shoals of
legislation and regulations across the country will never
be as important – or difficult – as in the upcoming year.
the Canada Oil and Gas Operations Act to increase the
National Energy Board’s (“NEB”) oversight powers as
well as pipeline operators’ liability. Together with new
rail safety and tanker safety regulations, these regulatory
changes enhance the federal regime for transporting oil,
petroleum, and natural gas products.
New NEB powers include:
• ordering any company that operates a pipeline
from which an unintended or uncontrolled
release of oil, gas or any other commodity
occurs, to reimburse government institutions
for costs incurred in taking any action
respecting the release;
• ordering pipeline companies to maintain funds to
pay for the abandonment of their pipelines; and
• taking, under certain circumstances, any action
it considers necessary respecting an unintended
or uncontrolled release of oil, gas or any other
commodity from a pipeline.
New liability measures include:
1. Safety in Numbers? “Polluter Pay”
To Be Enshrined Under New Federal
Pipeline Legislation
On December 8, 2014, Canada’s Minister of Natural
Resources introduced Bill C-46, entitled the Pipeline
Safety Act. It amends the National Energy Board Act and
• reinforcing the “polluter pays” principle;
• confirming that liability of pipeline companies
is unlimited if an unintended or uncontrolled
release of oil, gas or any other commodity is a
result of fault or negligence;
OIL AND GAS BULLETIN | FEBRUARY 2015
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• establishing liability limits, without proof of
fault or negligence, at no less than $1 billion for
companies that operate pipelines with capacity
to transport at least 250,000 barrels of oil per
day and at an amount prescribed by regulation
for companies that operate any other pipelines;
• requiring that pipeline companies maintain
the financial resources necessary to pay the
applicable liability limits; and
• requiring pipeline companies to remain
responsible for their abandoned pipelines.
In addition, Bill C-46 allows the Governor in Council to
establish, in certain circumstances, a pipeline claims
tribunal to examine and adjudicate compensation claims
for damage caused by an unintended or uncontrolled
release of oil, gas or any other commodity from a
pipeline. Other anticipated federal policy development
includes enhanced involvement of Aboriginal
communities in pipeline safety operations and further
NEB guidance on best available technologies.
• is listed on a stock exchange in Canada; or
• has a place of business, does business or has
assets in Canada and, for at least one of its two
most recent financial years, meets at least two
of the following three thresholds:
○○ the company has at least CDN $20 million
in assets;
○○ the company has at least CDN $40 million
in revenue; and/or
○○ the company employs an average of at
least 250 employees.
The Act requires affected entities to report certain
payments respecting the commercial development of
oil, gas or minerals during a financial year that exceed
the amount prescribed by regulation. If no amount is
prescribed, then the threshold amount is CDN $100,000
and includes payments to all levels of government,
domestically and internationally of the following nature,
either monetary or “in kind”:
Bill C-46 will place a new, significant onus on pipeline
companies to ensure that: (a) operations do not
result in releases; and (b) if such releases occur,
necessary financial resources to meet any liability exist.
Accordingly, pipeline companies must assess their
safety and financial obligations to ensure they meet
legislated requirements once Bill C-46 becomes law.
• taxes, other than consumption taxes and
personal income taxes;
2. Publish What You Pay - Ottawa
Enhances Financial Transparency
for Oil and Gas Companies
• production entitlements;
On December 16, 2014, the Government of Canada
gave Royal Assent to the Extractive Sector Transparency
Measures Act, sweeping legislation which establishes
new mandatory reporting standards for extractive
companies. Its focus is payments made to foreign and
domestic governments at all levels. The purpose of these
new requirements is to improve transparency within the
natural resources industry and to achieve alignment with
similar measures set out in the European Union and the
United States. Key aspects of the new legislation include
who is required to report, what must be reported, and
the scope of compliance.
Reporting is now required for any entity engaged in
the commercial development of oil, gas or minerals
in Canada or elsewhere, including exploration and
extraction and the acquisition or holding of permits,
licenses, leases or other authorizations for such purpose
and that either:
• royalties;
• fees, including rental fees, entry fees and
regulatory charges as well as fees or other
consideration for licences, permits or
concessions;
• bonuses, including signature, discovery and
production bonuses;
• dividends, other than dividends paid as ordinary
shareholders; and
• infrastructure improvements payments.
The Act does not specifically include “Aboriginal
government” in the definition of Payees. However,
section 29 clarifies that reporting to an Aboriginal
government will be required two years after the Act is
brought into effect by Order in Council.
Turning to compliance, the Canadian Government
may require the provision of any information and
documents, including a list of projects for the
commercial development of oil, gas or minerals in
which the entity has an interest and the nature of that
interest, an explanation of the treatment of the payment
by the entity, a statement of any policies that the entity
has implemented for the purpose of compliance with
the proposed legislation and the results of an audit of
its report.
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In the event of non-compliance with the reporting
requirements, the Canadian Government may impose
corrective measures. In addition, any person or entity
would be liable to a fine of not more than $250,000 for
the following:
• failing to comply with the reporting standards or
any corrective measures;
• knowingly making false or misleading
statements or providing false or misleading
information; or
• structuring payments or any other financial
obligations or gifts, whether monetary or in kind,
that relate to its commercial development of oil,
gas or minerals, with the intention of avoiding
the requirement to report.
The Act grants no exemptions. It instead includes a
broad due diligence defence against liability, if the
person or entity can establish that it “exercised due
diligence to prevent” the commission of the offence. The
new legislation will significantly increase the complexity
and depth of financial reporting requirements for the
Canadian oil and gas industry – as well as the risks of
non-compliance and reputational damage.
3a No Change? The Absence of Federal
Climate Change Policy in 2014 Is A Key
Regulatory Development
Notwithstanding Prime Minister Harper’s suggestions
in late 2013 that a national climate change regime
would be forthcoming, the absence of federal legislation
on climate is one of the most important policy
developments of 2014. Perhaps as important are the
activities Canadian provinces take independently of the
federal government, outlined in greater detail below.
3b All Change? – Provinces Move Forward
On Climate Change Policy
On October 20, 2014 the British Columbia government
introduced new legislation to control greenhouse gas
(“GHG”) emissions from industrial operations. Bill 2, the
Greenhouse Gas Industrial Reporting and Control Act is a
critical change in the province’s approach to GHGs and
more closely aligns BC with the Alberta approach. The
bill proposes intensity-based emission standards, and
the broadening of alternative compliance mechanisms
to include credits from offsets, payments to technology
funds, and earned credits.
In Alberta, at the end of 2014, the provincial government
extended the four key regulations that set out Alberta’s
intensity-based greenhouse gas regulation program
– the Specified Gas Emitters Regulation, the Specified
Gas Reporting Regulation, the Administrative Penalty
Regulation, and the Climate Change and Emissions
Management Fund Administration Regulation - to June
2015. Until the change, all four regulations were set to
expire on December 31, 2014.
The Alberta regulatory regime has been in place since
2007 and provides the framework for the reduction
of greenhouse gas emissions intensity levels from
large industrial emitters. Alberta requires facilities that
emit more than 100,000 tonnes of GHGs a year to
reduce emissions intensity by 12 per cent. Companies
may choose to pay $15 per tonne for every tonne of
emissions over their required reduction into the Climate
Change and Emissions Management Fund.
In addition to being necessary to maintain its regulatory
framework, the Alberta Government states that the
extension until 2015 is to “ensure the smooth transition
from the current strategy to the new framework
expected be in place in the new year”. The Alberta
Government further indicates that it is “exploring options
to address climate change”. There are no further details
on what those options include.
In 2014, provinces moved forward on cross-border
policy development. In November, 2014 Ontario and
Québec issued a Memorandum of Understanding
agreeing to collaborate on “concerted climate change
actions”. This will likely include harmonizing data
collection and greenhouse gas reporting requirements,
exploring the use of market based mechanisms in
Ontario, sharing knowledge and promoting the transition
to a low carbon economy through initiatives such as
setting a price on carbon and adopting cleaner fuel
standards. Ontario and Québec have agreed to increase
collaboration with the Canadian Government as well
as provincial and territorial governments. The OntarioQuébec Memorandum of Understanding does not create
legally binding obligations on either province and
may be terminated on two months’ notice.
In December, 2014 the governments of Ontario, Québec
and British Columbia, together with the government of
California, issued a Joint Statement on Climate Change.
The result was an agreement to collaborate on mid-term
GHG emissions reductions to maintain momentum
toward 2050 targets. The December announcement
follows on from the California Air Resources Board and
Québec Ministry of Sustainable Development holding the
first joint action of GHG allowances. The joint QuébecCalifornia program permits companies to trade carbon
allowances across jurisdictions to comply with GHG
emission limits.
OIL AND GAS BULLETIN | FEBRUARY 2015
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In a federal election year with plunging oil prices,
climate change legislation at the national level will
likely remain elusive. However, provinces have clearly
stepped into the climate change space. Whether this
creates a jurisdictional collision course or simply a
stopgap until the federal government enters into the
legislative fray remains to be seen. One thing is certain.
It will be essential for Canadian oil and gas companies
to understand and respond to the impacts of climate
change regulation, whether at the provincial, federal or
ultimately both levels of government.
4. Finally LNG? British Columbia’s
Introduction of an LNG Tax Regime
On October 21, 2014, the British Columbia Government
introduced Bill 6, the Liquefied Natural Gas Income Tax
Act. The bill, which creates BC’s first liquefied natural
gas (“LNG”) tax regime, is viewed by policy-makers
and industry alike as critical for the progress of LNG
in Canada. Specifically, the bill provides clarity for
project proponents to reach a final investment decision.
Under Bill 6, BC’s new tax regime will take effect on
January 1, 2017.
BC’s proposed LNG tax essentially has two parallel,
but different, rates of taxation. A lower tax rate will
apply if an LNG operator has losses and can claim
depreciation for costs it incurs in developing its LNG
facilities. A higher tax rate will apply when there are
no losses or depreciation.
The lower tax rate applies as follows:
• when commercial LNG production begins, an
operator will pay a 1.5% tax on “net operating
income”; and
• no federal depreciation or capital cost allowance
is recognized. There is a special deduction from
a capital investment account. This account
includes all costs associated with constructing
the LNG plant.
The higher tax rate applies as follows:
• if there is no capital investment account and no
losses to be claimed, a higher rate of tax will
apply. This rate is currently 3.5%; and
• any taxes paid under the higher rate can
be deducted as a credit in determining tax
exposure under the second rate.
The new BC LNG tax applies on a project by project
basis. It applies even if a project operator or participant
is not a resident of, or permanently established in,
Canada. Project proponents may not be subject to
federal or provincial income tax, yet still captured by
the LNG tax regime. We anticipate more regulatory
detail on the LNG tax in 2015, particularly respecting
administrative and enforcement measures and the
prescribed rate for adjusted capital investment
account deductions.
5. LNG Redux? More Regulations
from the OGC
On July 21, 2014, the British Columbia Oil and Gas
Commission (“OGC”) enacted the new Liquefied Natural
Gas Facility Regulation (“Regulation”). This provides a
new regulatory framework for LNG facilities and updates
LNG-related provisions previously in the BC Pipeline
and Liquefied Natural Gas Facility Regulation. The OGC
has also issued version 1.0 of its Liquefied Natural
Gas Facility Permit Application and Operations Manual
(“LNG Facility Manual”), which provides guidance for
applicants seeking to construct an LNG facility. The
Regulation is limited to LNG facility sites only, and not
upstream aspects of natural gas extraction, production
and transportation.
The Regulation covers a wide scope of technical
requirements for LNG facilities:
• the LNG facility permit application process,
through the construction, operation,
decommissioning and reclamation
phases; and
• notice and reporting requirements for all project
applicants and permit holders during various
project phases.
The regulation further empowers the OCG to make
individual facility-specific decisions based on the
technical details set out in project applicants’ reports
and sets out overarching occupational health and safety
program requirements, including emergency response
planning.
One of the complexities of the new LNG framework is
the OGC’s discretion to exempt an LNG facility permit
holder from one or more provisions of the Regulation
on a case-by-case basis. Although an LNG project
proponent may successfully apply for, and receive
an exemption, the OGC retains the ability to impose
conditions on that exemption. It therefore remains to be
seen how widely the OGC will grant exemptive relief to
LNG facility permit holders.
Turning to the LNG Facility Manual, it sets out an
overview of the current provincial LNG scheme, as well
as detailed guidelines for the rules and procedures set
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forth in the Regulation. More specifically, it addresses
LNG facility life cycle matters including water use,
engineering and geotechnology.
The Regulation and the LNG Facility Manual establish
an overview of the LNG approval regime in British
Columbia. They provide guidance to LNG facility
proponents and permit holders on a variety of
regulatory and technical issues. Despite this additional
guidance, areas of uncertainty remain within British
Columbia’s LNG regulatory system. These questions will
undoubtedly emerge on a case by case project basis.
So too, will challenges to the OCG’s newly released
framework for LNG development.
6. Under Water? The BC Water
Sustainability Act Receives
Safe Passage
On May 20, 2014, the BC Water Sustainability Act (the
“WSA”) received Royal Assent. The WSA is a major
reworking of BC’s water protection, management and
regulation. Key elements of the WSA include:
• eliminating a distinction between the surface
water and groundwater under the old Water Act
- the first time that BC has extended
the regulatory regime for surface water
to groundwater;
• non-domestic users of groundwater must
apply for a license if they plan to divert or
use groundwater;
• groundwater users will be prioritized on the
same “first in time, first in right” basis as
surface water users currently are under the
Water Act, with the exception of a super-priority
for “essential household uses”;
• current groundwater users will be required to
transition to the WSA regime by applying for,
and obtaining, a water-use license;
• domestic users of groundwater are not required
to obtain a water license or pay annual water
rental fees;
• the quick-licensing procedures for certain
classes of applications, primarily small scale
domestic and irrigation use, have been retained
under the WSA;
• existing licenses granted under the Water Act
will be grandfathered into the new regime under
the WSA; and
• the WSA increases the provincial government’s
ability to regulate water use during times
of scarcity.
Water Sustainability Plans are a critical portion of the
WSA. Under the Act the BC government has broad
powers to develop and enforce such plans. A further
change to the rules is the ability for the development
of Water Sustainability Plans to be delegated to groups
other than the provincial government, which is intended
to encourage community involvement.
The WSA retains the general rule from the Water Act that
where water is diverted, it must be put to a “beneficial
use”. This term was not defined in the Water Act.
Instead, the WSA defines “beneficial use” as using water
“as efficiently as practicable” and in accordance with
any applicable regulations.
Turning to timing, the WSA sets a default 30 year review
period for all water licenses. The new review period will
apply to existing licenses. There are three exceptions to
the default review period:
• licences issued for a power purpose or a
storage purpose related to a power purpose;
• licences issued under the Industrial
Development Act; and
• licences reviewed or issued following
a review under the 1998 Water Use
Plan Guidelines.
The WSA retains the Water Act’s offences and
enforcement measures. However, it grants discretion to
the Comptroller of Water Rights to impose administrative
monetary penalties on persons who have contravened
the WSA, breached a term or condition of a water
license, or failed to comply with an order under the
WSA. Administrative penalties offer an alternative to
ticketing or criminal prosecution and allow the WSA to
be enforced without having to establish liability in court.
Persons receiving administrative monetary penalties are
entitled to notice, a hearing, and the ability to appeal
the decision of the hearing to the Environmental Appeal
Board. The amount of the administrative monetary
penalties will be established by regulation.
7. Matters Under Consultation – Changes
To First Nations Engagement in Alberta
2014 brought a major development in Alberta’s
approach to consultation with First Nations. The Alberta
government released the final version of its Consultation
Guidelines in July 2014 to clarify the First Nation
OIL AND GAS BULLETIN | FEBRUARY 2015
6
consultation processes. Alberta’s Consultation Guidelines
outline activities in various sectors, including pipelines
and petroleum, natural gas and oilsands that require
consultation.
The Consultation Guidelines’ primary effect is the
identification of anticipated levels of consultation for
various activities within each industry sector, and the
timelines within which consultation is expected to take
place for each of these activities. The guidelines provide
additional clarity on the roles and responsibilities for
each of the parties involved in First Nation consultation
processes in Alberta, specifically government, project
proponents and First Nations. The Consultation
Guidelines highlight the following three goals:
• stakeholders gaining a better understanding
of First Nations’ concerns regarding potential
adverse impacts of a project on the exercise
of treaty rights and traditional uses;
• substantially addressing these concerns
through a meaningful process; and
• developing positive working relations.
The 2014 guidelines are only a starting point.
Stakeholders will need to be aware of, and rigorously
comply with, their respective duties to consult as well
as recent Supreme Court of Canada decisions on First
Nations consultation and emerging law at the lower
court levels.
8. How Far, AER? Alberta Energy
Regulator Expands Its Jurisdiction
In 2014, the Alberta Energy Regulator (“AER”) – the
entity responsible for providing “the efficient, safe,
orderly and environmentally responsible development
of energy resources in Alberta” - implemented the third
and final phase of its mandate under the Responsible
Energy Development Act (“REDA”).
Under the prior legislative framework for oil and gas
development in Alberta, there were several decisionmakers operating under various statutes as follows:
• Alberta Environment and Sustainable Resource
Development (“ESRD”) granted surface leases
to companies to develop on public lands and
regulated reclamation and remediation under
the Public Lands Act;
• the Energy Resources Conservation Board
(“ERCB”) granted licences and approvals for oil
and gas wells and facilities as well as regulated
most aspects of those facilities including
construction, operations and abandonment;
• both the ERCB and ESRD granted licences
and approvals respecting air, land and water
impacts; and
• Alberta Energy had a policy setting role as well
as responsibility for the sale of oil and gas rights
for the 80% of oil and gas resources in Alberta
owned by the province.
Under REDA, Alberta Energy’s role in the disposition of
oil and gas rights is unchanged. The mandates of ESRD
and the ERCB were combined into a single regulator
known as the AER with the ERCB dissolved. 2014
ushered in an expansion of the AER’s jurisdiction
under REDA as follows:
• the AER now has authority over various
provisions in the Public Lands Act, the
Environmental Protection and Enhancement
Act and the Water Act to the extent that
those provisions relate to “energy resources
activities”, specifically oil and gas operations
and coal mining, but not power generation or
electricity transmission and distribution; and
• Crown surface dispositions and environmental
approvals will now be obtained under the single
umbrella of the AER.
Respecting procedural rule changes, it is now within
the AER’s discretion to disregard Statements of Concern
(“SOC”) filed under REDA under circumstances set out in
section 6.1 of the AER’s Rules of Practice. This includes
circumstances where the AER determines that the
concern has been adequately dealt with or addressed
through a hearing or other proceeding under any other
enactment or by a decision on another application.
Previously, all persons who could establish that they
may be directly and adversely affected by the regulator’s
disposition of an application were granted standing.
Industry stakeholders will need to monitor closely the
AER’s practices to determine whether the regulator
continues to apply the “directly and adversely affected”
test as its predecessor did. The practical implications
for AER hearings – including application delay – may
be significant.
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9. Plus tard, Couillard? Emergence of New
Oil and Gas Policy in Québec
Québec has a long history of oil and gas exploration
dating back to the 1950s. In the 1970s, the Parti
Québécois government established a government
entity, société québécoise d’initiatives pétrolières
(“SOQUIP”) charged with oil and gas exploration to
increase Québec’s energy independence. After a period
of unsuccessful exploration, SOQUIP was disbanded
and exploration ceased. As the combination of hydraulic
fracturing and horizontal drilling opened up new
reservoirs, there was renewed interest in Québec’s Utica
shale. The Québec Oil and Gas Association (“QOGA”)
was created to encourage dialogue in Québec about the
potential of the province’s emerging oil and gas industry.
Since 2005, over 30 modern shale gas wells have been
drilled. Several companies, notably Questerre, Junex and
Lone Pine have operations and land holdings in Québec.
In 2013, the Parti Québécois government imposed a
five-year ban on fracking in the St. Lawrence Lowlands,
the region between Montreal and Québec City, until
a strategic environmental assessment on shale gas
development was completed.
The Québec Environmental Review Board review
indicated that the risks outweighed the benefits of
fracking. In late 2014, Québec Premier Couillard
stated that given the findings of the review board, his
government would not support fracking at this time.
Premier Couillard did not close the door to fracking in
the future, however, and said his government is not
opposed to developing the province’s energy resources.
The Québec oil and gas industry is facing a new policy
framework under Premier Couillard. On November 7,
2014, the Minister of Energy and Natural Resources and
the Minister Responsible for Plan Nord announced the
beginning of a consultation process on Québec’s new
energy policy set to be released in Fall 2015.
The Québec Government will publish four documents
intended to initiate and encourage discussions on
the new energy policy. The first document, entitled
“Contexte, défis et vision” (“Context, Challenges and
Vision”) sets out the framework for the consultation
process. The other documents will address the issues
of: (i) renewable energy; (ii) efficiency and energy
innovation; and (iii) fossil fuels. Public roundtable
meetings will be held in January, March and May 2015
on these topics.
10.Fracking in Fredericton New Brunswick Places a Moratorium
on Hydraulic Fracturing
Shale gas and the method used to extract it – hydraulic
fracturing or fracking – prompted a series of high profile
protests and galvanized the 2014 New Brunswick
provincial election. During the campaign, Liberal Premier
Gallant promised to impose a moratorium on the
practice “until the risks to the environment, health
and water are fully understood”.
On December 18, 2014 the New Brunswick Minister of
Natural Resources introduced Bill 9, An Act to Amend
the Oil and Natural Gas Act to the Legislative Assembly
of New Brunswick. Bill 9 will create a moratorium on
all forms of hydraulic fracking in the province of New
Brunswick, irrespective of whether the process uses
water or another substance to extract natural gas
from subsurface shale rock. The Bill will also put an
end to any fracking projects currently underway in the
Province, as no “grandfathering” of projects will be
permitted outside of the moratorium.
The moratorium will continue in place until the following
five conditions are met:
• “social licence” for hydraulic fracking is
established through consultations between
fracking corporations and the community;
• further information on the impacts on air,
health and water prior to the development
of a regulatory regime for fracking in
New Brunswick;
• establishment of a plan to mitigate impacts
on public infrastructure and to address issues
such as waste water disposal;
• the Province establishes a process to fulfill its
First Nations consultation obligation; and
• a royalty structure ensures that the benefits
of fracking are maximized for residents of
the Province.
There are currently several companies exploring
for shale gas in New Brunswick, most notably SWN
Resources Canada. These activities will be permitted
to continue under the moratorium, provided that no
fracking activity on test wells is undertaken. New
Brunswick is the fourth province to create a moratorium
on fracking. The others are Québec, Nova Scotia and
Newfoundland and Labrador.
AUTHORS
Alan Ross
Calgary
403.232.9656
aross@blg.com
Landon Miller
Calgary
403.232.9771
lmiller@blg.com
Michael A. Marion
Calgary
403.232.9464
mmarion@blg.com
Michael G. Massicotte
Calgary
403.232.9602
mmassicotte@blg.com
Karen Salmon
Calgary
403.232.9476
ksalmon@blg.com
Rick Williams
Vancouver
604.640.4074
rwilliams@blg.com
OIL AND GAS GROUP
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