Canadian Energy Law : Lawyers & Attorneys for Environmental Energy Law

Under the Agreement, countries have committed to looking at extending the Kyoto protocol with a new round of emission-reduction targets for the post 2012 period. However the heavy lifting of such negotiations have been left for subsequent COP summits in Durban, South Africa in 2011 and South Korea in 2012.

For its part, at COP16 Canada refused to provide a commitment to new Kyoto targets, preferring the more flexible Copenhagen approach. Canada also objected to the commitment for developed nations that are signatories of Kyoto to cut emissions by 25 to 40 percent from 1990 levels by 2020. As a result of its commitments under the Copenhagen Accord, the Government of Canada has pledged to reduce greenhouse gas emissions by 17 percent from 2005 levels by 2020, but only if the United States takes comparable action. These commitments have not changed as a result of COP16.

Following the Cancun summit Canada’s Environment Minister, the Hon. John Baird, described the Cancun Agreement as a modest step forward, noting “It’s a first step to a single, new, legally binding agreement”. Guy Saint-Jacques, Canada's Chief Negotiator and Ambassador for Climate Change noted “We have laid good groundwork for further progress in these complex negotiations.”
 

Subject to certain exceptions, Class 43.1 includes

1. a fixed location device that is a wind energy conversion system that
   
   
   1. is used by the taxpayer primarily for the purpose of generating electrical energy, and
   2. consists of a wind-driven turbine, electrical generating equipment and related equipment, including
      
      
      1. control, conditioning and battery storage equipment,
      2. support structures,
      3. a powerhouse complete with other ancillary equipment,
      4. transmission equipment; and
          
2. fixed location photovoltaic equipment that is used for the purpose of generating electrical energy from solar energy consisting of solar cells or modules and related equipment including inverters, control, conditioning and battery storage equipment, support structures and transmission equipment.

There are certain limitations that apply in determining the amount of CCA that may be deducted in any given taxation year. By virtue of the “available for use rules” in the Act, CCA for a Class 43.1 or 43.2 property that has been acquired and which is not considered available for use at the end of a taxation year may be restricted until such time as the property is available for use. In addition, property that becomes available for use in the year is subject to the “half-year” rule found in the Regulations, whereby only 50% of the normal CCA deduction is permitted in the year an asset becomes available for use. Finally, CCA is prorated in circumstances in which the taxpayer’s taxation year is less than 365 days.

Property included in Class 43.1 or 43.2 may be “specified energy property” in which case, the CCA that may be deducted by a taxpayer in respect of such property is limited to the taxpayer’s income from the business of selling the product of the property. This limitation does not apply to a corporation whose principal business is manufacturing or processing, mining operations or the sale, distribution or production of electricity, natural gas, oil, steam, heat or any other form of energy or potential energy, or to a partnership each member of which is such a corporation.

Canadian Renewable and Conservation Expense (“CRCE”)

Certain expenses incurred by a taxpayer in the pre-production development phase of renewable energy and energy conservation projects, for which it is reasonable to expect that at least 50% of the capital cost of the depreciable property to be used in the project would qualify for inclusion in Class 43.1 or 43.2, may qualify as CRCE if, among other things, they are not:

1. payable to a person or partnership with whom the taxpayer is not dealing at arm's length (such as a parent, subsidiary or sister company), or
2. specifically excluded from CRCE under subsection 1219(2) of the Regulations (see below).

Where expenses qualify as CRCE, they may be deducted entirely in computing Canadian taxable income in the year they are incurred or carried forward indefinitely and deducted in later years.

Examples of the types of expenses that are typically eligible for CRCE include expenses incurred by a taxpayer:

1. for the purpose of making a service connection to the project for the transmission of electricity to a purchaser of the electricity to the extent that the expense was not incurred to acquire property;
2. to determine the extent, location and quality of energy resources;
3. for clearing land to the extent necessary to complete the project;
4. for the construction of a temporary access road to the project site; and
5. for a “test wind turbine” that is part of a wind farm project of the taxpayer. 

Examples of the types of expenses that are not eligible for CRCE include:

1. amounts that would otherwise be included in the capital cost of depreciable property, including all costs directly associated with the acquisition and installation of the property, except those described in i) to v) above as qualifying as CRCE;
2. financing and interest charges;
3. administration and management expenses;
4. amounts paid to a non-resident person or a partnership any of the members of which is not a resident of Canada; and
5. costs related to the acquisition or use of land, as well as the grading and levelling of land, except those described in i) to v) above as qualifying as CRCE.
6. The determination of whether a particular expense incurred by a taxpayer will qualify for inclusion in CRCE must be made based upon a review of all of the facts relevant to a particular situation. 

Special Rules Applicable to Limited Partnerships

Where windpower or solar power projects are carried on through limited partnerships, additional considerations arise. A partnership is not a taxpayer for Canadian tax purposes. Rather, a partnership computes its income (or loss) as a separate person resident in Canada and then allocates the income or loss to its partners. If a taxpayer is a member of a partnership at any time in a particular taxation year, it will include in computing its income its share of the income or loss of the partnership for any fiscal period of the partnership ending in, or at the same time as, such taxation year.

There are two exceptions to this general scheme that are relevant to limited partnerships that carry on windpower or solar power projects.  First, any CRCE incurred by a partnership is not deductible in computing income or loss that is allocated to its partners but, instead, each partner deducts directly its share of any CRCE incurred by the partnership. In addition, in the case of a limited partner, the deduction of any loss of the partnership or CRCE incurred by the partnership is restricted to the limited partner’s “at-risk amount”. Generally, a limited partner’s at-risk amount in respect of its interest in the partnership at any time is equal to the cost of the limited partner’s interest in the partnership plus any income allocated to the partner for fiscal periods ending prior to that time less the sum of any losses of the partnership allocated to the partner for fiscal periods ending prior to that time and any distributions received by the partner from the partnership before that time. To the extent that a limited partner’s share of the loss from the partnership or CRCE incurred by the partnership exceeds the partner’s at-risk amount, such loss or CRCE may be deducted in a subsequent year to the extent that the amount of the loss or CRCE does not exceed the partner’s at-risk amount in that subsequent year.

In Staff Notice 51-333, the CSA emphasize that the standard (as outlined in NI 51-102) to be met by reporting issuers in determining if environmental matters must be disclosed is whether or not the matter is “material”. The CSA offer several principles to guide the determination of materiality, namely that: (i) there is no bright line test, (ii) materiality is context- and timing-dependent; and (iii) trends, demands, commitments, events and uncertainties depend on the probability that such trend, etc., will occur and the expected magnitude of its effect.1

In the context of a wide range of environmental issues, the CSA focused Staff Notice 51-333 on the following types of disclosure:

1. Environmental Risks and Related Matters. The five key disclosure requirements in NI 51-102 that relate to environmental matters are: environmental risk, trends and uncertainties, actual and potential environmental liabilities, asset retirement obligations and the financial and operational effects of environmental protection requirements, including the costs associated with these requirements.

2. Environmental Risk Oversight and Management. Two key sets of disclosure requirements provide insight into a reporting issuer’s oversight and management of environmental risks: environmental policies implemented by the issuer and the issuer’s board governance. A reporting issuer should explain the purpose of its environmental policies and the risks they are designed to address and evaluate and describe the impact that the policies may have on its operations. The reporting issuer should disclose the board of directors’ (or any delegate committee’s) responsibility for the oversight and management of environmental risks.

3. Impact of adoption of International Financial Reporting Standards (IFRS). As reporting issuers make the mandatory transition to IFRS for financial years beginning on or after January 1, 2011, issuers may be required to accrue more environmental liabilities at higher amounts and provide more disclosure regarding these liabilities.

4. Forward-Looking Information Requirements. Issuers are advised that disclosing goals or targets with respect to greenhouse gas emissions or other environmental matters may be considered forward looking information or future oriented financial information and would be subject to the disclosure regime for such information in NI 51-102.

5. Governance Structures Around Environmental Disclosure. Staff Notice 51-333 provides reporting issuers with recommendations regarding governance structures with respect to environmental matters, including reliable internal controls and disclosure procedures. The reliability of these systems is a necessary underpinning for securities regulatory filings, including CEO and CFO certifications under National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. Directors and certifying officers need to know that management has implemented systems, procedures and controls to gather reliable and timely environmental information to be able to certify that the reporting issuer’s filings do not contain any misrepresentations.

The CSA’s Staff Notice 51-333 demonstrates that, regardless of whether or not they are subject to greenhouse gas emissions or other environmental reporting requirements, issuers must seriously consider the effect of environmental matters and climate change on their business and ensure that such matters are adequately disclosed to investors.

We will continue to follow the progress of the Canadian securities regulators in their development of a robust disclosure regime for climate change related matters.  Look for further analysis and observation in future bulletins.

The Project was subject to both provincial review by the British Columbia Environmental Assessment Office (“EAO”) and federal review by the Canadian Environmental Assessment Agency (“CEAA”). The provincial and federal review processes were undertaken separately.

The provincial EAO review process was completed in December 2009. In its report, the EAO found that after mitigation, the Project would not result in significant adverse effects, with the exception of the loss of Fish Lake and Little Fish Lake. The EAO also found that the Project would make a significant economic contribution.

On the basis of the findings of the EAO report, and while the federal review was ongoing, the BC Minister of Environment and Minister of Energy, Mines and Petroleum Resources approved the Project on certain conditions on January 14, 2010.

A federal environmental assessment of the Project was also undertaken as the Project required authorization by the Department of Fisheries and Oceans to permit the destruction of fish and fish habitat, Natural Resources Canada for the construction and operation of an explosives factory and magazine and Transport Canada for the placement of the dam in Fish Creek and the placement of the transmission lines over Big Creek and the Fraser River. 

In its July 2, 2010 report, the CEAA review panel concluded the Project would result in significant adverse environmental effects on fish and fish habitat, on navigation, on the current use of lands and resources for traditional purposes by First Nations and on cultural heritage and on certain potential or established Aboriginal rights or title. The federal panel also concluded that the Project, in combination with past, present and reasonably foreseeable future projects, would result in a significant adverse cumulative effect on grizzly bears in the region and on fish and fish habitat. Of particular interest is the Panel’s conclusion that Taseko would not comply with the DFO’s No Net-Loss Policy. The federal review panel did recognize that the potential employment and economic benefits of the Project were considered by many to be beneficial.

On the basis of the federal review panel’s report, the Government of Canada determined that the significant adverse environmental effects of the Project, specifically the permanent destruction of water bodies, could not be justified by the economic benefits of the Project and approval of the Project by any of the responsible federal authorities was denied. 

The use of existing waterbodies as tailings impoundment areas has always been controversial and Taseko’s Project is not the first where this has been proposed and denied federal approval. The likelihood of federal approval for such a scheme is more unlikely when traditional users can demonstrate continued use or reliance on the waterbody. In addition, project proponents should consider compliance with DFO’s No Net-Loss Policy to be mandatory. Finally, while it is desirable that that end pit lakes or tailings impoundment areas contain suitable fish habitat post-closure, project proponents should not claim that this comprises suitable fish habitat compensation for the purposes of DFO’s Policy or to address local concerns.

NI 51-101 was originally implemented in September 2003 and amended in 2005 and 2007.  The latest set of proposed amendments were published for comment on December 18, 2009 and open for comment until March 2010. The Notice of Amendments identified eight commenters and summarized their comments,  together with CSA responses. Changes were made to the proposed amendments in response to the comments but such changes were not considered material. 

Amendments will be made to the forms and companion policy (51-101CP) related to NI 51-101.  Consequential amendments will also be made to item 5.5 of Form 41-101F1 Information Required in a Prospectus and CSA Staff Notices 51-324 and 51-327 to reflect changes to NI 51-101. Our securities colleagues Keith Chatwin and Chris Scherman have published a more comprehensive update on the amendments on our securities blog.

Development of the regulations

In 2007, GHG emissions from the transportation sector accounted for approximately 27% of Canada's federal emissions inventory. The proposed renewable fuel regulations are part of a broader plan to cut GHG emissions that also includes regulations that will promote more fuel-efficient vehicles (beginning in 2011), among other measures, and are expected to result in an incremental reduction in GHG emissions of approximately one megatonne per year - equal to the emissions of 250,000 motor vehicles - over and above reductions attributable to existing provincial requirements in Ontario, Manitoba, Saskatchewan and British Columbia.

In developing these new regulations, the federal Department of the Environment, commonly known as Environment Canada, consulted with industry, environmental non-governmental organizations, other federal government departments and Canada's provincial and territorial governments. Environment Canada also engaged in discussions with the U.S. Environmental Protection Agency (EPA) and has stated that the general approach of the new regulations is based on the U.S. Renewable Fuel Standard, with modifications to address Canadian conditions and further modifications in response to stakeholder consultations.

Comments or a notice of objection on the draft regulations, published in the Canada Gazette, may be submitted to Environment Canada before June 6, 2010.

Thresholds and excluded fuels

Certain significant segments of the market are not caught by the renewable fuel content requirements of the regulations. Persons that produce or import less than 400 m³ of gasoline, diesel fuel or heating distillate oil in a compliance period, which will generally correspond to a calendar year, are excluded. However, a person producing or importing quantities below this threshold may elect to participate in the compliance unit trading system (discussed below), in which case all applicable requirements of the regulations would apply.

Also excluded from the renewable fuel content requirements are primary suppliers who only import and/or produce diesel fuel, heating distillate oil and/or gasoline, as specified, (a) for particular purposes (including aviation, competition vehicles, scientific research, chemical feedstock and military combat equipment), (b) sold or delivered for use in Newfoundland & Labrador, the Northwest Territories, Nunavut, Yukon, Quebec (North of 60º), or (c) for export or in transit through Canada, or any combination of such uses. The foregoing excluded entities are nevertheless subject to some of the record-keeping provisions of the regulations.

Compliance unit trading system

The regulations include provisions governing the creation of gasoline and distillate compliance units and creating a trading system for "participants" in which such units - each representing one litre of renewable fuel - can be created or obtained in order to meet renewable fuel requirements. Participants include (automatically) primary suppliers, as well as "elective participants" who may, at their option, choose to participate in the trading system provided that they qualify in virtue of carrying out any of the five activities that are listed in the following paragraph.

Compliance units are created by participants at the time of:

• blending renewable fuel with liquid petroleum fuel;
   
• importing liquid petroleum fuel with a renewable content;
   
• using biocrude as feedstock to produce liquid petroleum fuel;
   
• selling neat (pure) renewable fuel to a neat renewable fuel final user for use in a combustion device; and
   
• using neat renewable fuel produced or imported as fuel in a combustion device.

The compliance unit trading system will enable primary suppliers to obtain compliance units where they are not able to blend renewable fuels, recognizing the fact that renewable fuels are most often blended at locations downstream of the refinery, proximate to their point of use.

Generally, compliance units may be used to demonstrate compliance only in the compliance period in which they are created. However, under specified conditions, a limited number of compliance units may be applied toward a previous compliance period and excess units may be carried forward for use in the following compliance period.

Importantly, there can be only one creator for each compliance unit, who is also its initial owner. The regulations state that if there is more than one person described in any of the five methods of creation listed above, the creator of the compliance unit is deemed to be the participant who is designated as being its creator pursuant to a written agreement between such persons. If there is no such agreement, no compliance unit will be created.

Finally, the regulations only permit the trading of compliance units to primary suppliers, and also limit the number of compliance units that a primary supplier may own at the end of each month during a compliance period.

Record-keeping

The regulations also include requirements for record-keeping and reporting to Environment Canada. Applicable to primary suppliers, elective participants, producers or sellers of renewable fuels and sellers of fuel for export, these requirements include the following:

• Auditor's report. Records and reports prepared by participants in the trading system and producers and importers of renewable fuel must be audited by an independent auditor. The audit report must be submitted by June 30 following the end of a compliance period, with initial reports due June 30, 2012.
   
• Registration and reporting for primary suppliers. A one-time registration report must be submitted by primary suppliers at least one day before producing and/or importing the 400^th m³ of gasoline or diesel fuel and/or distillate oil during a compliance period. Such persons must also maintain prescribed records in respect of fuel produced and imported and submit an annual report by April 15 following the end of a compliance period, with initial reports due April 15, 2012.
   
• Compliance unit accounts. Participants must maintain records in respect of compliance units created, transferred, carried forward and back, cancelled and otherwise used as permitted by the regulations and submit a report by April 15 following the end of a compliance period, with initial reports due April 15, 2012.
   
• Registration and reports for producers and importers of renewables. A one-time registration report must be submitted by producers and/or importers of renewable fuels at least one day before producing and/or importing the 400^th m³ of renewable fuel during a compliance period. Such persons must also submit an annual report by February 15 following the end of a compliance period, with initial reports due February 15, 2012.
   
• Measurement methods. Any person who submits a registration report must also submit a one-time report on the methods used for measuring volumes, as well as updates in respect of any change to information in the report.
   
• Records and reports for sellers of fuel for export. Persons other than participants or producers and/or importers of renewable fuels who sell for export a minimum of 1000 m³ of renewable fuel or liquid petroleum fuel with renewable content, must retain certain records and submit an annual report by February 15 following the end of a compliance period, with initial reports due February 15, 2012.

All records or copies of reports and notices and supporting documentation must be retained by the regulated entity for at least five years in Canada for inspection upon request.

Implementation timetable

While certain provisions of the regulations will only come into force on the day they are registered, the 5% renewable requirement for gasoline and the provisions for compliance units, reporting and record keeping (with the exception of the registration and measuring method reports) are scheduled to come into force on September 1, 2010. The initial compliance period for the gasoline requirement will end on December 31, 2011 and each subsequent compliance period will correspond to a calendar year.

The Supreme Court determined that the DFO had erred in adopting a narrow scope of project that did not include the entire proposed open pit mine. Pursuant to CEAA, the Comprehensive Study List Regulations (CSL) prescribes those projects that should be subject to more rigorous forms of environmental assessment under CEAA, including comprehensive study and review panels. The Court reasoned that because the copper and gold open pit mine as proposed by the proponent was one of the types of mines described in the CSL, the entire project as proposed should have been assessed under CEAA. By focusing on the CSL, the Supreme Court was able to avoid addressing the complicated constitutional issues which arise with respect to the overlapping provincial and federal spheres of power and jurisdiction as they relate to the environment. In rendering this decision, the Court has overruled the reasoning of the Federal Court of Appeal in Friends of the West Country Assn. v. Canada (Minister of Fisheries and Oceans) ("Sunpine"), and Prairie Acid Rain Coalition v. Canada (Minister of Fisheries and Oceans) ("TrueNorth").

While the Supreme Court recognized that a requirement to scope projects as broadly as described in the CSL might result in regulatory duplication and inefficiency, the Supreme Court relied on the ability of the federal assessment to be coordinated with the provincial assessment to address this issue. However, experience demonstrates that this coordination does not significantly reduce duplication and, in fact, often increases the legal risk associated with approval of a given project.

Impact of the decision

The Supreme Court's decision in this case will inevitably create inconsistency and uncertainty for project proponents. For example, if two proposed mines subject to a provincial environmental assessment regime are exactly the same except that one mine will result in the diversion of a small fish-bearing stream and the other mine has no elements to bring it under CEAA jurisdiction, both will be subject to the same level of provincial environmental assessment but the former will also be subject to a rigorous federal environmental assessment whereas the latter will not be subject to any federal environmental assessment. Project proponents will now need to carefully consider the timing and sequence of publicly disclosing their projects. To the extent proponents take a piece-meal approach in project disclosure to avoid the result noted above, it is likely to result in future legal challenges related to project-splitting. This results, at least partly, from the Supreme Court's decision to focus on the CSL instead of the pertinent constitutional issues that were discussed in Friends of the Oldman River Society v. Canada (Minister of Transport), Sunpine and to some degree, TrueNorth.

Canadian industrial emitters face deadline for emissions reporting

The Department of the Environment has given notice that Canadian industrial emitters of GHGs have until June 1, 2010 to report their 2009 GHG emissions. The reporting deadline, which was established by Environment Canada, applies to facilities that emit over 50,000 tons of carbon dioxide equivalent (CO_2e) per year. Environment Minister Jim Prentice has indicated that more detailed regulations will be released prior to the Copenhagen talks.

The Western Climate Initiative releases essential requirements of mandatory reporting

The partners of the Western Climate Initiative (WCI) are comprised of seven U.S. states and four Canadian provinces, namely British Columbia (B.C.), Manitoba, Ontario and Quebec. Other U.S. states and Canadian provinces (Saskatchewan and Nova Scotia) are currently WCI observers.

The WCI has recently released its final version of the first group of Essential Requirements for Mandatory Reporting (ERMR). The ERMR requires owners and operators that are subject to the mandatory reporting requirements to submit annual GHG emission reports by April 1 of each year for emissions in the previous calendar year. The initial reporting requirements will apply to the owner or operator of a facility that emits 10,000 metric tons of CO_2e or more per year in combined emissions, from one or more of the listed source categories, in any calendar year starting in 2010. Accordingly, companies subject to the ERMR that commenced operations prior to 2010 will be required to report their 2010 GHG emissions by April 1, 2011.

Subsequent to the year 2010, the ERMR contemplates that the reporting requirements will also apply to: (1) all importers of electricity (both retail providers and marketers) that import electricity into the WCI region, (2) any supplier that within the WCI region distributes transportation fuels in quantities that when combusted would emit 10,000 metric tons of CO_2e per year or more, in any calendar year starting in 2010, and (3) any supplier that distributes within the WCI region residential, commercial and industrial fuels in quantities that when combusted would emit 10,000 metric tons of CO_2e per year or more, in any calendar year starting in 2010.

The impact of the ERMR regime

In order to comply with the WCI-imposed obligations, the B.C., Manitoba, Ontario and Quebec provincial governments are each moving forward with legislation designed to implement the ERMR regime. For example, the B.C. government has announced its intention to introduce a mandatory GHG-emissions reporting regulation during the fall of 2009. The Ontario government has recently stated that its intention is to harmonize Ontario reporting requirements with those of the WCI (as well as with any U.S. federal trading system). Quebec has passed Bill 42 (An Act to amend the Environment Quality Act and other legislative provisions in relation to climate change), which establishes the reporting of GHG emissions by certain categories of emitters to be determined by regulation.

It should be noted that other Canadian provinces have also moved towards the adoption of legislation that will require companies to report GHG emissions. For example, in 2004, Alberta passed the Specified Gas Reporting Regulation, which continues to require industrial facilities that emit more than 100,000 tons of CO_2e in a calendar year to submit annual emission reports. Additionally, on August 14, 2009, the government of Nova Scotia released the Greenhouse Gas Emission and Air Pollutant Regulation. This regulation requires facilities located in Nova Scotia that emit more than 10,000 metric tons of CO_2e in a calendar year to submit annual emission reports.

Measuring and reporting GHG emissions is a labour-intensive process

In order to comply with the various provincial and/or federal legislation that may apply to them, companies will need to determine whether or not they emit the quantity of GHGs that triggers the various legislative reporting requirements. In order to do so, companies will need to measure their GHG emissions in accordance with the prescribed methods set out in the various legislation applicable to them. Measuring GHG emissions will be labour-intensive and will require that a detailed and mapped-out process be followed. Additionally, while governments have generally recognized the importance of standardized measuring methods (so as to help ensure the fair operation of multi-jurisdictional carbon cap-and-trade programs), there is no certainty that all legislation will contain common measuring techniques.

In the event a company is subject to GHG reporting requirements, the applicable legislation will also set out other obligations that the company will need to spend time considering. Typically, these obligations will include monitoring, record-keeping and retention requirements, as well as data-verification requirements. It can also be expected that GHG legislation will increasingly require emitters to reduce their GHG emissions towards established targets and/or to cover their GHG emissions with prescribed emission allowances, units or credits. 

Canadian reporting issuers and the impact of climate change

As was stated by the Canadian Institute of Chartered Accountants (CICA) in a Management's Discussion and Analysis (MD&A) disclosure guide published in November 2008 (the Guide), investors are increasingly seeking more detailed and nuanced information about how reporting issuers view the impact of climate change, in order to assess its effect on a company's current and future financial conditions, results of operations and cash flows. The CICA noted that the business impact of climate change will require reporting issuers - even those that do not directly produce GHG - to implement strategies, both to adapt to the effects of climate change on the reporting issuer's business and, in other cases, to take action to mitigate the extent of their GHG emissions. The CICA Guide outlines five types of information in MD&A that should address climate-change issues:

Business strategy. MD&A should present investors with an overview of the climate-change factors that the reporting issuer has factored into its business strategy.

Risks. MD&A should describe the risks presented by climate change on the reporting issuer, including physical risks (e.g. changes to weather patterns), regulatory risks (e.g. heightened regulatory oversight and scrutiny), reputational risks (e.g. negative customer perceptions of reporting issuers failing to address climate-change issues), litigation risks (e.g. lawsuits against heavy GHG emitters) and any other material risks.

GHG emissions. To the extent that it is material to evaluating the performance and future prospects of a reporting issuer, a reporting issuer's direct and indirect GHG emissions and related intensity data should be discussed in MD&A.

Financial impacts. The impact of climate change on financial operations, cash flows and the financial condition of the reporting issuer should be discussed in MD&A, along with the future financial implications.

Governance processes. MD&A should describe the governance and organizational processes used by the reporting issuer in identifying and managing climate-change issues.

While Canadian securities regulators have not yet specifically mandated the disclosure of climate-change strategies in a reporting issuer's public disclosure record, the requirements of National Instrument 51-102 Continuous Disclosure Obligations (NI 51-102), including the requirements applicable to a reporting issuer's MD&A, are sufficiently broad so as to capture such issues.

A reporting issuer's MD&A, for example, is required to discuss the effect of "known trends, demands, commitments, events or uncertainties" on the reporting issuer's "financial condition, results of operations and cash flows." Moreover, a reporting issuer's annual information form (AIF) is required to disclose such things as the "financial and operational effects of environmental protection requirements" on its financial position, including capital expenditures. An AIF is also required to detail risk factors, such as environmental risks, and "regulatory constraints.and any other matter that would be most likely to influence an investor's decision to purchase" the securities of the reporting issuer. As climate-change concerns continue to escalate and, as a result, increasingly stringent legislation is enacted , regulatory authorities may in the future require Canadian reporting issuers to provide more prominent and expansive disclosure with respect to the impact that climate change will have on their business.

In February 2008, the Ontario Securities Commission (OSC) issued Staff Notice 51-716 - Environmental Reporting, outlining the results of a targeted review by OSC staff of the degree to which Canadian reporting issuers were adequately disclosing information about so-called "environmental matters" in their annual financial statements, MD&A and AIFs. The OSC's written findings suggest that, at the time, the disclosure of certain Canadian reporting issuers with respect to potentially material environmental matters was inadequate and, in certain instances, consisted of insufficient, boilerplate disclosure.

Staff Notice 51-716 should continue to serve as a signal to Canadian reporting issuers that, regardless of whether or not they are subject to specific GHG-emission or other environmental reporting requirements, it is necessary for them to seriously consider the effect of environmental matters and climate change on their business and to ensure that such matters are adequately disclosed to investors. 

The draft Program Guides are available on the Environment Canada website and were announced in the June 13, 2009 Canada Gazette. They are open for a 60-day public comment period ending August 12, 2009. After the comment period, final versions of the Guides will be prepared for expected release in the fall of 2009.

Overview

The Offset System will be a voluntary program administered under the Canadian Environmental Protection Act, 1999. Overall responsibility for the design and operation of the system will be granted to the Minister of the Environment, including establishment of the Offset System program rules; approving protocols used to quantify GHG reductions; registration of projects; and issuance of offset credits to eligible projects.

Each offset credit developed under the Offset System will represent one tonne of GHG (CO2 equivalent) that has been reduced or removed. Credits will be both tradable and bankable, and the system will include and a procedure for tracking all offset credits from issuance to retirement.

Key Elements

Program Rules and Guidance for Project Proponents

Registration

• A proponent can apply to register a single project or an aggregated or bundled project.
• The registration period is effective for eight years. An offset project may apply for re-registration one time only, for a second eight-year period, and registration periods must be contiguous (an exception to this rule is agricultural and forestry sink projects, which may register for three and five registration periods respectively).

Eligibility

• In order to be eligible to receive offset credits, projects must be within the scope of the Offset System and achieve quantifiable, real, incremental, verifiable and unique GHG reductions.
• Offset credits will only be available to projects that lead to reductions in Canada.

Claiming Offset Credits

• Offset credits will only be issued after an eligible verification body has verified the project proponent's GHG reduction claim.
• The Minister of Environment is responsible for the certification and issuance of all credits. Issued credits will be deposited in the project proponent's account in the tracking system.

Program Rules and Verification and Guidance for Verification Bodies

Verification Body Eligibility

• Verification activities for projects in the Offset System must be conducted by an accredited verification body.

Verification Standard

• All credit verifications for the Offset System must be conducted in accordance with the National Standard of Canada CAN/CSA-ISO 14064-3, Specification with Guidance for the Validation and Verification of Greenhouse Gas Assertion.

Conflict of Interest Assessment

• To ensure that verification is conducted by a third-party verifier, the proposed verification body must complete a conflict of interest assessment prior to agreeing with a project proponent to act as a verifier.

What's Next

The Government has indicated that it will continue to monitor developments in the U.S. before finalizing certain aspects of the Offset System (such as project eligibility criteria), so as not to disadvantage Canadian project proponents. However, the manner in which the Offset System will interact with other carbon trading programs, including the Western Climate Initiative, British Columbia's carbon trading system, proposed systems being developed in Ontario and Quebec, and even a future North American program, remains unclear.

On a broader scale, Canada will surely continue to keep a close eye on U.S. policy and legislative developments relating to cap-and-trade. The Hon. Jim Prentice, Minister of the Environment, has stated that as Canada's economy is deeply integrated with that of the U.S., with which we share the same environmental space, the two countries must work toward the same climate change objectives.

The author wishes to thank Annie Pyke, Student-at-law at Stikeman Elliott, for her valuable contribution.

Cost of capital - background

Regulation is a surrogate for competition in the determination of the price that a regulated utility may charge for its services. The major elements of that price are (1) operating, maintenance and administrative expenses, (2) depreciation (return of capital) and (3) cost of capital - the return on the capital (equity and debt) invested in utility assets that provide service. The cost of capital is the largest component of the utility revenue requirement that is included in utility tolls charged to customers.

In the context of transmission pipelines, where the prices of natural gas and oil are determined in the marketplace and pipelines are purely transporters rather than merchants, the ultimate effect of the transportation cost is borne by the producers of the commodity. Simplistically, if the transportation tolls go up, the netback to the commodity producer goes down and vice versa. Cost of capital is therefore a very contentious issue between the pipeline owners and the shippers that use them. The obligation of pipeline management is to seek a return for utility shareholders that is commensurate with the returns available from investments of similar risk. The interests of customers lie in minimization of the tolls paid for safe, efficient transportation service.

The task of the regulator, in this case the NEB, is to determine the fair return, which has been judicially defined (as the "fair return standard") to mean a return that is commensurate with returns available from investments of similar risk, that maintains the financial integrity of the regulated enterprise, and that permits attraction of incremental capital on reasonable terms and conditions.

Historical cost of capital determination

The NEB has historically determined cost of capital for the pipelines it regulates by first setting a deemed capital structure or equity/debt ratio (e.g. 30% equity and 70% debt), then determining the rate of return on equity (ROE) to be applied to the deemed equity. In the past, the deemed equity has been set at a level that the NEB considered reflective of the business risks of the pipeline. The ROE has been set on an equity risk premium (ERP) basis (to reflect the premium required to entice investors to invest in utility equity, rather than in long-term government bonds), adjusted annually using a formula (ROE Formula) that was established in 1995 in the NEB  Multi-Pipeline Cost of Capital Decision RH-2-94 (RH-2-94 Decision). The cost of equity (ROE x deemed equity) plus the cost of debt (actual costs, if prudently incurred) must together result in an overall cost of capital that meets the fair return standard.

The RH-2-94 Decision established deemed capital structures for pipelines within NEB jurisdiction, and stated that it would consider reassessment only in the event of significant changes in business risk, in corporate structure or in corporate fundamentals. The ROE Formula adjusted the ROE annually, based on forecast changes in long Canada bond interest rates, removing the need for frequent cost of capital applications. The NEB also stated that it did not expect to reassess the ROE for at least three years.

In 2001, TransCanada PipeLines Limited (TransCanada) challenged both the capital structure and the ROE applied to its Mainline. The NEB RH-4-2001 Decision in June 2002 declined to adopt an ATWACC approach, increased the Mainline deemed equity by 3% but declined to change the ROE Formula. The decision was upheld on review and subsequently by the Federal Court of Appeal.

The 2009 TQM Decision was the first time that the 1995 ROE Formula had been challenged since 2001.

The TQM Decision

TQM operates NEB-regulated natural gas transportation facilities in Québec on behalf of its owners, Gas Métro Limited Partnership and TransCanada. TQM receives all of its gas through its interconnection with the TransCanada Mainline, and its tolls are included in Mainline tolls as "transmission by others."

The ROE for TQM had been determined by the NEB using the 1995 ROE Formula. In the RH-1-2008 application, TQM relied on changes in financial markets and economic conditions since 1995 to seek review and variance of the RH-2-94 Decision and the determination of an overall fair return on capital through an increase in deemed equity and ROE, or through an ATWACC methodology.

In the TQM Decision, the NEB decided to depart from the traditional methodology and adopted an ATWACC approach on the basis that it most accurately reflected the way investors in pipelines and companies as a whole make decisions with respect to investing capital. This was the first time that an ATWACC methodology has been fully accepted by a North American utility regulator.

Having regard to its philosophy that pipeline companies should be regulated on a goal-oriented basis, the NEB set TQM's cost of capital on an ATWACC basis without specifying a capital structure. This was intended to give TQM the ability to determine its optimal capital structure and choose specific financial instruments without regulatory oversight. The approved TQM ATWACC includes the market cost of debt, rather than the actual cost of debt. Transitional provisions were not deemed necessary, since virtually all of TQM's debt would be reaching maturity in the near future.

The NEB awarded TQM a 6.4% ATWACC for each of 2007 and 2008, finding that it met the three components of the fair return standard (comparable investment, financial integrity, capital attraction). Expressed in ATWACC terms, the approved TQM return before the RH-1-2008 application was 5.5%. In the lexicon of the traditional methodology, TQM was moved from ROE Formula (8.46% in 2007 and 8.71% in 2008) on 30% equity to the equivalent of 9.7% on 40% equity (or 11.2% on 32%).

Significantly, the NEB also accepted the evidence of TQM that (i) Canadian and U.S. financial markets are integrated and, as a result, Canadian pipelines compete for capital with their U.S. counterparts; (ii) U.S. pipelines serve as comparables to Canadian pipelines; and (iii) U.S. local distribution companies serve as comparables to Canadian pipelines such as TQM.

What does this mean for other regulated utilities?

The TQM Decision has not been appealed. There is wide anticipation that it will have far-reaching effects on the regulatory determination of cost of capital in Canada. While the NEB was not the first to adopt a formulaic approach (the British Columbia Utility Commission did that), most other regulators in Canada chose the formula route after the federal regulator did so. The NEB move to a different (ATWACC) methodology, its acceptance of a market-based approach, including comparability of U.S. evidence, and the level of the return allowed to TQM are all precedential decisions that will have to be considered and weighed by other regulators. The NEB itself has already solicited comments (due May 25) on whether an open review of the RH-2-94 Decision should be conducted.

The NEB proceeding took two concurrent paths; one relating to the  constitutional question of whether the Alberta System is properly within federal jurisdiction and therefore subject to NEB regulation, and the other relating to the issuance of a Certificate of Public Convenience and Necessity for the continued operation of the Alberta System (the Certificate). 

Federal jurisdiction

The NEB issued a Declaratory Order that the TransCanada Alberta System is within federal jurisdiction and subject to regulation by the NEB. The NEB decision relied on tests articulated in the 1998 Supreme Court of Canada decision in Westcoast Energy Inc. v. National Energy Board (Westcoast).

Under the Constitution Act, 1867 and the Westcoast tests, a pipeline will fall within federal jurisdiction if it is either (1) part of a federal work or undertaking; or (2) integral to a federal work or undertaking.  The primary factor in the first test is functional integration and common management, control and direction. Secondary factors include common ownership, common purpose and physical connection.  On this point, the NEB determined that the federal undertaking is the transportation of natural gas to markets within Canada and the United States, and that the Alberta System, the TransCanada Mainline and the TransCanada Foothills System together comprise that single federal undertaking.  The NEB also held that the second test was met, concluding that the Alberta System is essential to the combined TransCanada undertaking.

The NEB was also satisfied that the Alberta System is a pipeline within the meaning of the National Energy Board Act, since it is part of a pipeline system that transports natural gas and extends beyond the borders of Alberta.

The NEB Declaratory Order on jurisdiction will take effect upon the effective date of the Certificate, which will be 14 days following its issuance. If a Certificate is not issued, the Declaratory Order is to take effect on the date of the NEB's final decision on TransCanada's application for that Certificate.

Implementation

Subject to the approval of the Governor in Council, the NEB decided to issue the Certificate for the continued operation of the Alberta System.  In doing so, the NEB decided that efficiency required that it accept decisions made by provincial regulators in respect of the Alberta System prior to the jurisdiction transfer, rather than making duplicate decisions that may result in inconsistency and uncertainty. The NEB, therefore, determined that the Certificate will include "Approved but Not Constructed" facilities. The NEB felt that this approach was consistent with the principles that underlie comity and the avoidance of retrospective regulation.

The NEB will commence regulating construction of "Approved but Not Constructed" facilities as soon as a Certificate comes into force. To prevent regulatory gaps, the NEB will enforce provincial approval conditions on the effective date of the certification of these facilities.

Although certain landowners requested that their concerns be heard prior to the granting of the Certificate, the NEB agreed with TransCanada's positions that the landowner concerns were not socio-economic effects under the Canadian Environmental Assessment Act and that the landowner consultation could be undertaken following the issuance of the Decision. The NEB felt that this was appropriate, since there were currently no proposals for the construction of new facilities or changes to existing facilities. The NEB also included a number of conditions to the Certificate regarding the landowner consultation process.

A Certificate may only be issued if the requirements of section 52 of the National Energy Board Act (the NEB Act) are met.  The NEB concluded that the requirements had been met, finding that the Alberta System had adequate supply and was connected to sizeable markets, that continued gas flow at a reasonable level will ensure that the pipeline remains economically feasible and that adequate financing will remain available to the Alberta System. The NEB was also satisfied that the Alberta System is currently safe and will continue to be operated safely.

Further, the NEB stated that under normal business circumstances, it would expect that Alberta System tolls would be approved by the NEB. In the context of the transition to NEB regulation and the need to minimize regulatory uncertainty, the NEB will accept the filing of a tariff, including a schedule of tolls pursuant to the NEB Act to become effective upon the coming into force of the Certificate.

Impact of the decision

TransCanada has announced that federal regulation of the Alberta System means that TransCanada can extend the pipeline across provincial borders, allowing it to provide producers in British Columbia and the Northwest Territories with a direct connection to the pipeline network. This increases the probability that British Columbia and Northern gas will integrate directly with the Alberta hub, North America's largest natural gas trading point. TransCanada has also stated that the attraction of additional gas supplies to the Alberta System will increase the utilization of existing infrastructure, which is expected to result in reduced tolls, improved netbacks, higher royalties and better access to new and existing markets.

As stipulated by the Decision, TransCanada will implement a broad-based public consultation and communications program, including Aboriginal communities, landowners, shippers and interested stakeholders. 

The Decision has no immediate impact on tolls for shippers on the Alberta System. With only "boiler plate" changes to reflect federal jurisdiction, the Alberta System tariff and tolls will be filed with the NEB in their present form and at their present levels. It is expected, however, that the negotiations on Alberta System rate design that have been ongoing for some time will move to the NEB for resolution in a tolls proceeding in the near future.

The authors wish to thank April Kosten, Student-at-Law at Stikeman Elliott, for her contribution.
 

Green infrastructure

The budget contains a pledge by the federal government to provide $1 billion over five years to support a Green Infrastructure Fund.  The Green Infrastructure Fund will be used by the government to support green infrastructure projects on a cost-shared basis.  The budget states that green infrastructure includes infrastructure that supports a focus on the creation of sustainable energy - infrastructure such as modern energy transmission lines and other projects that will contribute to lower carbon emissions.

Clean energy fund

Noting Canada's commitment to reduce greenhouse gas emissions by 20 percent by 2020, the budget lays out the government's objective to support clean energy research and the development of clean energy technologies.  The budget contains a commitment of $150 million over five years to be used for clean energy research initiatives, and a commitment of $850 million over five years for the development and demonstration of "promising technologies", including large-scale carbon capture and storage projects.  The government predicts that through this support over the next five years, a total investment of at least $2.5 billion will be generated in clean energy technologies.

Capital cost allowance for carbon capture and storage

Since 2006, the government has been a significant proponent of the development of carbon capture and storage technologies. The budget notes that $375 million has already been provided to support the development of these technologies, including $250 million in the Budget 2008 for a commercial demonstration of the technology in Saskatchewan and research in Nova Scotia. The remaining $125 million is available for carbon capture and storage projects under the ecoENERGY Technology Initiative of Natural Resources Canada.

The budget contains a pledge by the government to consult with carbon capture and storage stakeholders to identify specific assets used in carbon capture and storage technology with a view to providing accelerated capital cost allowance in respect of such investments.  Such accelerated capital cost allowance advances the timing of capital cost deductions for tax purposes thereby deferring taxation and improving the financial return from investment in an asset.

Energy efficient homes

On an individual level, the budget contains measures designed to promote energy efficiency and conservation through a retrofit program intended to provide home and property owners with grants of up to $5,000 to offset the costs of making energy-efficiency improvements. The budget states that grants will apply to a variety of measures that reduce energy consumption, from increasing insulation to upgrading a furnace.  The budget pledges $300 million over two years to this program to support an estimated 200,000 home retrofits.

Under the Framework, the Government intends to establish a market price for carbon and set up a compliance-based emissions trading market. Sixteen major industrial sectors would be required to reduce their emissions intensity by 18% from 2006 levels by 2010, with 2% continuous improvement in each subsequent year. The Government says it will reduce Canada's GHG emissions by 20% (approximately 165 megatonnes (Mt)) from 2006 levels by 2020. These targets will not make Canada compliant with its obligations under the Kyoto Protocol.

The Government plans to transition from an emission-intensity based target system to a fixed emissions cap system in the 2020-2025 period. It has indicated that in determining the level of the cap, particular consideration will be given to climate change-related regulatory developments in the U.S., with the aim of establishing a North America-wide emissions trading system.

In addition to emissions trading between regulated companies, the Framework also elaborates on some of the voluntary reduction compliance mechanisms available to meet the targets. These include:

• Domestic offset system: credits would be issued for incremental, real, verified domestic reductions or removals of GHG emissions. Functional details of the system, including verification of reductions and issuance and use of offset credits, are set out in the Framework. The Government has also indicated that consideration would be given to reductions originating in the U.S. once the U.S. has a regulatory system in place and compliance-based cross-border emissions trading is feasible.
   
• Credit for Early Action Program: companies that took verified early action to reduce emissions would be eligible for a one-time allocation of 15 Mt in bankable, tradable credits. In addition, firms with eligible reductions above that amount would be allocated credits based on each firm's proportional contribution to the total emission reduction achieved. To qualify, reductions must have been the result of an incremental process change or facility improvement (i.e., they cannot have been the result of business as usual conditions).
   
• Technology Fund: companies would be able to contribute to a fund that would invest in a range of clean technology development projects in exchange for credits that could initially be used to comply with up to 70% of their regulatory obligations. This contribution rate would decline through 2018, at which time this mechanism would be phased out and replaced by other measures, including internal abatement actions and carbon trading. Contributions to other funds that meet the necessary requirements could potentially also be recognized under this compliance mechanism (e.g., provincial funds).

Additions to the April 2007 framework include:

• Pre-certified Investments: companies would also have the compliance option of investing directly in pre-certified large-scale projects (e.g., CCS projects). As an added incentive for participation, firms in the oil sands, electricity, chemicals, fertilizers and petroleum refining sectors could be credited for their investments up to 100% of their regulatory obligation through 2018 (in contrast to the limited, declining contribution limit under the Technology Fund mechanism).
   
• Oil sands upgraders, in-situ plants (i.e., on-site soil remediation facilities) and coal-fired electricity plants that come into operation in 2012 or later would be obliged to comply with targets described as "tough" by the Government, which will provide incentive for facilities to be built carbon-capture ready. These targets are expected to generate an additional 30 Mt in reductions in 2020.
   
• The electricity sector, Canada's top emitting industrial sector, would face an 18% reduction target at the facility level and a task force will be established to work with the provinces and industry to explore ways to meet an additional 25-30 Mt reduction goal from the electricity sector by 2020.

The Government calls the Framework "one of the toughest regulatory regimes in the world to cut GHG emissions", but reaction has been mixed. Certain affected industries expressed cautious approval of the Framework, while federal opposition parties and environmental groups were critical of its use of intensity-based targets (rather than absolute reductions) and its emphasis on CCS technology rather than energy efficiency, or more proven technologies. Ontario and Quebec expressed disappointment over the lack of recognition for companies that have taken early measures to cut emissions. Further, some said that provincial green plans and provincially-driven efforts to establish an inter-provincial cap-and-trade system (perhaps linked with the U.S.) would have a more immediate impact than the Framework.

Business and environmental groups alike have repeatedly called for a uniform approach to carbon regulation in Canada. Industry has expressed concern that the growing regulatory patchwork of federal and provincial schemes, if not harmonized, will result in increased costs, confusion, and decreased investment. While British Columbia, Quebec and Alberta already have regulatory schemes in place, the draft federal GHG regulations are expected in fall 2008. The final federal regulations are expected to be released in fall 2009, with the GHG provisions of the regulations coming into force on January 1, 2010. However, experts predict that the new U.S. administration will establish a national cap-and-trade system and that Canada will be forced to follow suit. Accordingly, while the Government is moving forward with its plans, the state of carbon regulation in Canada remains in flux.

The MCeX was created in 2006 through a joint venture between Montreal Exchange and the Chicago Climate Exchange. The MCeX aims to become the leading market for publicly-traded environmental products in Canada. In October 2007, the MCeX filed an application with its lead regulator, the Autorité des marchés financiers (AMF), requesting approval of market rules designed to govern the trading of MCeX environmental products on its electronic trading platform SOLA®. A decision on its AMF application is expected in the near future.

The MCeX has cited World Bank estimates to the effect that the world market for carbon amounts to about US$100 billion and that trading activity on public carbon markets has grown rapidly in recent years to reach US$30 billion in 2006.

Steam Turbine Energy Generation Systems use steam or hot water in the earth's crust to power turbines for energy generation. Currently in Canada, feasibility testing is underway for what may become Canada's first geothermal energy generation site in the Meager Mountain - Pebble Creek area of British Columbia, where a 100-250 MW electrical facility is currently being assessed for development. The United States, as the world's largest producer of geothermal electricity, generates an average of 16 billion kilowatt hours of energy per year. Today, roughly sixty new geothermal energy projects are under development in over a dozen states that will double current geothermal power production. Recent reports indicate that as much as 20% of U.S. power needs could be met by geothermal energy sources by 2030.

Geothermal projects will raise unique legal challenges, requiring specialized legal expertise in a variety of areas including energy, real estate, municipal planning, corporate and tax structuring.

While Quebec recently implemented a carbon tax on fuel, other Canadian provinces are opting for market-based approaches. Ontario is in favour of a national GHG cap-and-trade scheme (i.e. the trading of emission allowances where the total allowance is strictly limited or "capped"). It has also professed interest in participating in the Western Climate Initiative (WCI), a U.S. state-level organization aimed at cutting GHGs using market-based tools such as cap-and-trade. British Columbia (BC) and Manitoba have already joined the WCI. Plus, the Premier of BC has announced that BC will soon become the first province to legislate binding caps on GHG emissions, including a one-third reduction by 2020. B.C. also recently signed the Climate Action Charter, whereby the province, the Union of BC Municipalities and over sixty local governments committed to becoming carbon neutral by 2012.

Alberta now has its own GHG emissions reduction regime which became effective July 1, 2007. The regime does not impose a hard cap on emissions; instead GHG emissions intensity (i.e. per unit of production) levels must be reduced to 50% of 1990 levels by December 31, 2020. To achieve this, the regime imposes yearly emissions reduction obligations on large industrial emitters (facilities with annual GHG emissions exceeding 100,000 tonnes of carbon) and provides three ways for these emitters to achieve their reduction obligations: (1) improve the facility's efficiency and achieve actual emissions reductions; (2) acquire fund credits which cost $15 per tonne and are paid into an Alberta-based climate change technology fund; and (3) acquire and use emissions offsets from verified, Alberta-based projects. The regulatory framework for offset verification and credit trading is still in development. The regime also imposes certain reporting obligations. Large industrial emitters have until December 31, 2007 to establish their baseline emissions intensity figures.

Announced last April, the Canadian government's proposed green plan, if implemented, would establish Canada's first federally regulated, market-driven emissions trading system. A domestic "inter-firm" trading scheme would allow regulated emitters to buy and sell emission credits among themselves, using a baseline-and-credit model. In the short term, the plan would not set hard caps on emissions but instead use intensity-based targets or "baselines." The plan would also include an offset program allowing emitters to purchase credits to help meet their targets. Ontario recently announced that it will help develop protocols in support of the federal offset program.

These developments in Canada reflect similar developments in the U.S. In early October, the U.S. House of Representatives released a white paper outlining plans for broad climate change legislation, the "cornerstone" of which would be cap-and-trade. Also, a group of the world's most powerful banks have been lobbying the U.S. and other industrialized nations to set up a regulated cap-and-trade system rather than imposing carbon taxes. CIBC World Markets' chief economist Jeff Rubin recently predicted that the next U.S. administration will follow through with adopting green policies that would include "firm and hard emissions reduction targets" and a national cap-and-trade scheme. Rubin further forecasted that Canada would be expected to follow suit.

While the regulatory landscape in Canada remains a patchwork, in light of the soaring interest in emissions trading, it appears likely that emissions trading will form a key component of any comprehensive climate-change legislation implemented in Canada in the future.

The proposed reduction targets would apply to the following major industrial sectors:

• Iron and steel
• Electricity produced by combustion
• Oil and gas (including oil and gas, oil sands, and pipelines)
• Forest products (including pulp and paper, and wood products)
• Smelting and refining (including aluminium and base metal smelting)
• Cement, lime and chemicals production
• Some mining sectors (including iron-ore pelletizing and potash)

Facilities that existed in 2006 would be required to meet GHG reduction targets, while new facilities would receive a three-year grace period. Companies that took "verifiable" action to reduce GHGs between 1992 and 2006 would be eligible for a one-time "credit for early action." These credits would be capped at 15 megatonnes (5 megatonnes in any given year), with eligibility criteria to be developed. Companies could either apply the credits to meet their targets or trade them.

Under the proposed regulations, various tools would be available to help regulated companies meet their reduction targets, including:

• Participating in domestic emissions trading - in a Canada-wide, market-driven "inter-firm trading" system for GHGs, nitrogen oxides (NOx) and sulphur oxides (SOx). Companies that meet their prescribed targets would receive credits they could sell to other companies that exceed their targets. Alternately, credits could be banked for future use.
• Purchasing offsets - by buying credits from projects that result in verified emissions reductions. These credits could be sold to companies to help them meet their targets. The plan contemplates that the offset system would begin "as soon as possible."
• Purchasing credits under the Kyoto Protocol's Clean Development Mechanism (CDM) - by investing in CDM projects in the developing world. Only certain CDM credits (called Certified Emission Reductions) would qualify and they could be applied against up to 10% of a company's total target.
• Making in-house reductions - of up to 5 megatonnes per year during the 2010-2017 period, through improved technology or reduced energy use.
• Contributing to a technology fund - at a starting rate of $15 per tonne of "carbon dioxide equivalent." This could be used to meet up to 70% of a company's target starting in 2010, with the percentage then progressively lowered to only 10% by 2017. The government will also "explore" the idea of "providing credits for certified project investments by individual companies in transformative technology to reduce future emissions."

Significantly, the proposed regulations would not allow Canadian companies to participate in international emissions trading. The Conservative government is opposed to international emissions trading, having repeatedly stated that it amounts to "sending Canadian dollars overseas to buy hot air on the international market." However, opposition parties and many in business favour international trading.

In the coming months, the government plans to meet with its provincial and territorial counterparts, each affected industry sector and other stakeholders to discuss key elements of the proposed regulations. The plan was immediately rejected by the opposition parties and with no significant political support, the content and fate of the proposed regulations are far from certain. However, support from the opposition is not required because the plan would be implemented through regulatory changes only. The government hopes to finalize the air pollutant regulatory framework by fall 2007 and finalize all regulations by 2010.

In addition, it is open to provincial governments to opt for stricter reduction targets. Indeed, it has been reported that Ontario will announce its own green plan on June 11. That plan is widely expected to include stricter GHG reduction targets than the federal plan and to provide support for renewable energy projects. Ontario Premier Dalton McGuinty also recently announced his interest in rallying Canadian provinces to agree on their own national plan to reduce GHGs and to set up an inter-provincial GHG emissions cap-and-trade system.

The Notice of Intent also outlines some of the actions the government intends to implement under the new legislation to meet its goals, including measures to:

• reduce air pollutants and greenhouse gases from key industrial sectors, including fossil fuel-fired electricity generation, upstream oil and gas and downstream petroleum;
• identify indoor air issues that are national in scope and develop measures for improving indoor air quality, including the regulation of products that could result in degradation of indoor air quality;
• strengthen energy-efficiency standards and labelling requirements for consumer and commercial products, including products that may not themselves contain pollutants but whose use or existence may cause air emissions; and
• regulate the fuel consumption of road motor vehicles starting in the 2011 model year and use the government's existing authority to regulate emissions of pollutants in the areas of shipping, railways and aviation.

In the next twelve months, the federal government intends to continue the process of harmonizing Canadian vehicle emission standards with those of the United States and to initiate discussions with the Americans on a coordinated approach to administering cleaner vehicles. Another stated goal for the next year is to align Canadian standards for volatile organic compound emissions from architectural, industrial and maintenance coatings, consumer products, and automobile refinishing coatings with the generally more stringent standards that are in place in the United States.

In addition to advice from NRTEE, the federal government will also consult with stakeholders on the development of proposed regulations to reduce air emissions in key industrial sectors using a three-phase process:

• during fall 2006 and spring 2007, the federal government will consult on the overall regulatory framework that will guide the development of industrial sector regulations, including proposed short-term targets for air pollutants and greenhouse gases, to be reflected in the proposed regulations to come into effect in the 2010-2015 period;
• beginning in summer 2007 and continuing until the end of 2008, the federal government will engage in detailed consultations on the proposed regulations that will apply to individual sectors, including defining sectoral obligations and timelines; and
• in the final phase, the proposed regulations will be approved and published with the initial provisions coming into force by the end of 2010 and the balance of the provisions to follow.

The aim of the consultation process is to set realistic targets and timelines for emission reduction, to identify cost-effective compliance options to meet those targets, and to develop a one-window regulatory tool for compliance assessment, monitoring and reporting to ensure that industry is on track to meet its regulatory obligations.

The proposed legislation promises to be controversial and it will no doubt be a hot topic of debate on Parliament hill. It is unclear at this time if the federal government will be able to muster the necessary support in Parliament to pass the proposed legislation into law in its current form. On November 1, 2006, the federal government announced that it was willing to send the Bill to a special legislative committee to be deliberated on by Members of Parliament from all federal political parties.
 

The OPA published its "Draft Program Rules" on September 7, 2006, which were open for public comment until September 22, 2006. The results of the public consultation process are to be published before the end of the year.

To be eligible under the RESOP, a project must be based in Ontario with an installed generating capacity of 10,000 kW or less (the OPA is considering a separate program for smaller renewable project of 10 kW or less). Projects must use one of the following methods: wind, thermal electric solar, voltaic solar, biomass biogas, biofuel, landfill gas or water.

While an application package is not yet available from the OPA, applicants are being advised that they must provide evidence that each has met the prescribed requirements for application.

For example, an applicant must send out a "community notification" to the relevant local government, setting out, among other things, the size of the project and the estimated commercial operation date of the project .In addition, for projects over 10KW in size, the applicant must provide a "business plan review" that includes written confirmation from a chartered accountant, professional engineer or similar accredited professional that the business plan is complete, and that the applicant's cost estimates and critical path for the project can reasonably be achieved.

Power generators are to be paid a base rate of 11.0 cents per kWh for electricity that is delivered to the grid under contract with the OPA. Twenty per cent of this base rate will be indexed for inflation based on the CPI. In addition, a premium of 3.52 cents per kWh will be paid for electricity delivered during peak hours to generators who can operate reliably during those hours. Note, however, that solar photovoltaic system generators will be paid 42.0 cents per kWh, but this rate will not be subject to indexation for inflation or the peak-hour premium.

All prospective applicants must be aware of the fact that there are, or will be, parts of the Ontario transmission grid that will not be able to accept incremental power, and the OPA may limit applications in certain areas or restricted sub-zones of the province. The OPA will, at some point, publish details of what these restricted areas are, but, importantly, that information is not yet available.

LFN, which is generally described as noise in the frequency range of 10 Hz to 200 Hz, has been linked by media reports to sleep disturbance, fatigue, migraine headaches and depression. LFN emissions were characteristics of some early wind turbine models, particularly where turbine blades were downwind of the main tower. With modern wind turbine designs, which have their blades upwind of the tower, the "wind shade" behind the tower is avoided, and LFN is significantly reduced.

Experts agree that LFN, at sufficient levels, may be a health concern for those who are sensitive to its effects. The effects of inaudible levels of LFN have not been sufficiently studied to date to rule out the possibility of health effects, but commentators have weighed in on each side of the debate. Setbacks and noise surveys are common requirements imposed on new wind farm developments, in part to minimize the risk of wind turbines causing health effects on local residents.

Media reports have recently focussed on claims of adverse health impacts from LFN. Earlier this year, a family from Lower West Pubnico, Nova Scotia abandoned their home, located approximately four hundred metres from the nearest turbine. Daniel d'Entremont and his family complained of lack of sleep, fatigue, headaches and a lack of concentration. And while the d'Entremont family may have legitimate concerns about the particular wind farm they claim was affecting their lives (new sound testing has been commissioned by the federal government), such reports are being used by those opposed to wind farm development to slow down or stop projects.

Several significant Canadian projects have been abandoned in recent months because of public pressure. Brookfield Power abandoned a proposal to build a thirty-turbine farm in the Blue Mountain area because of delays in receiving permits, and Enbridge has cancelled plans to install eleven turbines in the community of Saugeen Shores because of a local requirement for a 250 metre setback. Other projects that have been slow to receive approvals are encountering local criticism based on potential LFN effects.

Ontario Energy Minister Dwight Duncan was recently quoted as saying that some people have moved past NIMBY to NOPE (Not On Planet Earth) or BANANA (Build Absolutely Nothing Anywhere), and that these phenomena are a threat to the province's energy security. It appears that NIMBYism will be with the wind energy industry for some time to come; only a combination of more information and strong political direction will allow the industry to reach its full potential.

The nature of LNG and domestic security concerns have made proposed LNG developments a hot-button issue in the United States. Deep-water port facilities are required to accommodate an increasingly larger LNG shipping fleet. Proximity to mature natural gas markets brings domestic security concerns to the forefront of any development, particularly where port facilities are co-located with the market. Although the LNG process is inherently safe and enjoys a solid safety record, large shipping and re-gasification facilities could be vulnerable to terrorist attacks, and this has caused widespread resistance to LNG developments near large, urban centres. Currently, four LNG facilities are in operation in the United States, but in the last year there has been opposition to the development of facilities in Mississippi, Louisiana, Texas and California based on a variety of environmental and security concerns.

The development of LNG infrastructure in Canada is seen as a partial solution to some of the risks facing such projects in the United States. Importing LNG to Canada permits the gas to be sold in both Canadian and American markets through existing or planned pipelines. There is less public resistance to LNG developments in Canada due, in part, to the fact that the country is perceived as being less of a terrorist target. There is also the ability to construct LNG ports and re-gasification plants in less densely populated areas, which would minimize the possible impact of any safety or security incidents.

Several LNG projects are now in various stages of development in Canada. The most advanced are the Canaport Project near Saint John, New Brunswick and the Bear Head Project in Point Tupper, Nova Scotia. The Canaport Project is being led by Irving Oil, which has partnered with Repsol YPF, a Spanish oil and gas company that will source the LNG. The Canaport Project has received provincial and federal regulatory approval and plans to produce one billion cubic feet per day [1 Bcf/d]. The Irving group of companies also plans to construct a 500-750 MW gas-fired generating station adjacent to the Canaport site. The Bear Head Project is being developed by Anadarko Petroleum and will use the existing Maritimes and Northeast Pipeline to deliver gas into the New England markets. The Bear Head Project has also received provincial and federal approval and plans to produce up to 1.75 Bcf/d.

Existing pipeline infrastructure in Canada and the United States and the move away from coal-fired generation makes LNG an increasingly important component of the North American energy supply, one that offers the energy sector a wide range of project finance and infrastructure opportunities.