NUCLEAR LIABILITY:  STATUS REPORT ON BILL C-20

Bill C-20, the proposed legislation to replace the Nuclear Liability Act, has cleared another hurdle in the legislative process.  Following a detailed clause by clause review of the draft legislation, on December 10, 2009 the Standing Committee on Natural Resources reported the Bill to the House of Commons with five amendments.  A copy of the reprinted Bill C-20 with the amendments may be found at
http://www2.parl.gc.ca/HousePublications/Publication.aspx?DocId=4316005&Language=e&Mode=1.

The following is a summary of the five amendments proposed by the Standing Committee: 

1.  Section 22 of Bill C-20 requires the Minister of Natural Resources to review the $650 million limitation on operator liability on a regular basis, and at least once every five years.  Section 22(2) identifies items that the Minister is to consider in the review.  Section 22(b) of the reported Bill is amended to add “nuclear liability limits in other countries” as a matter that the Minister must now consider in this periodic review.

2.  Section 22(3) has been added to the reported Bill.  This amendment requires the Minister to hold public consultations as part of the Section 22 review.  The public consultations are to include participation of both industry and non-industry stakeholders and any parliamentary committee that may be designated or established to review matters relating to the nuclear energy.

3.  During the review of Bill C-20 by the Standing Committee, concerns were expressed by certain of members of the Committee about the length of time that has elapsed since the $650 million liability limit was first set in 2002.  Due to this period being greater than the five year maximum review period referred to Section 22(a), the Standing Committee has proposed a transitional amendment (Section 68.1) to require that the first review under Section 22 must be completed within 15 months after the day on which the Nuclear Liability and Compensation Act comes into force.

4.  Section 23 requires nuclear operators to provide financial security for its $650 million liability obligation and Section 24 requires this financial security to be in the form of insurance with an approved insurer (subject to the possibility of alternate financial security for a portion of the liability obligation - see Sections 24(2) and 24(3)).  However, the insurance market is unlikely to provide coverage for certain operator obligations under Bill C-20.  This gap is resolved by Section 26 which enables the Minister to enter into an agreement with an approved insurer under which Her Majesty in right of Canada reinsures some or all of the risk assumed by the insurer under the insurance required to form part of the financial security that an operator is required to maintain in connection with its liability limit.  Section 26(4) requires the Minister to cause a copy of each reinsurance agreement to be laid before each House of Parliament.  The Standing Committee has proposed an amendment to these provisions (Section 26(5)) which will require the Minister to also cause to be laid before each House a copy of all related risk assessment studies that were completed for the purposes of the reinsurance agreement. 

5.  Under Section 36, the Governor in Council must establish a nuclear claims tribunal as soon as possible after its declaration that a tribunal is required to administer the claims from a nuclear incident (see Section 31(1)).  Section 37(1) requires the tribunal to notify the public, in a manner that it considers appropriate, of the details of the tribunal’s purpose and the means by which the public can obtain information on bringing a claim.  Section 37(2) provides for the mandatory publication of this notice in the Canada Gazette. The Standing Committee has proposed an amendment to Section 37(2) which specifies that the publication requirement be extended to “one or more newspapers in general circulation throughout all of Canada”.

Next Steps for Passage of Bill C-20

The House of Commons has adjourned for the holiday break and is scheduled to return on Monday, January 25, 2010.  Based on the general support of the Liberal Party representatives at the Committee review, nuclear sector stakeholders are hopeful that the Bill, as amended, will proceed efficiently through the Reporting Stage and be adopted at Third Reading.

Bill C-20, upon its passage by the House, will be referred to the Senate where it will undergo three readings including a clause by clause review by the Senate Standing Committee on Energy, the Environment and Natural Resources.  This Senate Standing Committee review would provide interested stakeholders with another occasion to make submissions for further amendments.  If the Senate review does result in amendments, the Bill would be returned to the House of Commons for further consideration and then, upon passage of the amendments, Royal Assent.

There has been speculation in the media that the Prime Minister may choose to prorogue Parliament in the New Year.  If Parliament is prorogued before the Bill receives Royal Assent, Bill C-20 would die on the order paper, similar to its predecessor Bill C-5.  Ordinarily, this would require this legislation to be reintroduced as a new Bill in the new Parliament, beginning once again with first reading in the House of Commons.  However, if we do have a prorogation, we hope that the Government will recognize the importance of this legislation for Canada’s nuclear sector, including in connection with the Government’s recent invitation for proposals for the acquisition of AECL’s commercial CANDU Reactor Division.  The Government, with the support of all opposition parties, could capitalize on the efforts invested in enacting Bill C-20 and its predecessors by bringing forward a motion in the new Parliament to reinstate Bill C-20 at the stage of its parliamentary review reached at the time of prorogation.

Terry McNally (416) 369-6189 terence.mcnally@gowlings.com

ALBERTA’S ELECTRICTY REGIME:  CRITICAL TRANSMISSION INFRASTRUCTURE – WHAT NOW?

Alberta is the only Canadian Province with a fully competitive wholesale/retail electricity market. Generation has been deregulated, save for siting issues, while wires remain regulated, with both their costs and permitting requiring approval of the Alberta Utilities Commission (AUC or Commission).  The Alberta Electric System Operator (AESO), a statutory, not-for-profit corporation, facilitates the wholesale market and is also responsible for the safe, reliable and economic planning and operation of the transmission system.¹

Until December 9, 2009, two regulatory approvals from the AUC were required to construct and operate new transmission facilities in Alberta.  First, the Electric Utilities Act (EUA) required the AESO to obtain approval from the Commission of the need for an expansion or enhancement of the system.  If granted, a Transmission Facility Operator (TFO) then required a permit and licence from the AUC to construct and operate specific facilities to meet that need. In both cases, the Commission was required to make its decision having regard to the public interest; insofar as the AESO’s application was concerned, the Commission was to consider the AESO’s assessment of need to be correct, unless it was satisfied that such assessment was technically deficient or that approval of the need would not be in the public interest.

Effective December 9, however, this two-step regime no longer applies to a discreet class of transmission facility, known as Critical Transmission Infrastructure (CTI).  By virtue of amendments to the legislation², CTI includes four specific projects indentified in the EUA itself, as well as transmission facilities that are included in an AESO plan and which may be designated by the Lieutenant Governor-in-Council, or the Cabinet.  As such, CTI facilities may include interties to other jurisdictions, transmission lines which serve areas of renewable energy, double-circuit facilities energized at 240 kilovolts (kV), transmission facilities that exceed 240 kV, or those which, in the opinion of the Cabinet, are critical to the safe, reliable and economic operation of Alberta’s transmission system.

In short, and while noting that the two-step regime remains fully in force for other proposed expansions or enhancements of the transmission system, the new legislation eliminates the requirement for AUC approval of the need for CTI³, and assigns that responsibility to the Government of Alberta.

The legislation effecting these changes was first tabled by the government in June, 2009 as Bill 50, and was subsequently the subject of much heated debate and discussion, far too complex to be fully addressed in this space. Much of the debate is a matter of public record, in any case.  Those opposed to the change were critical on several fronts. For example, they argued that eliminating the first AUC process/approval removed the ability to publicly test whether these projects are in fact required to meet Alberta’s needs, in favour of a unilateral determination by government on the expenditure of billions of dollars to be ultimately paid for by Albertans.  A further criticism was that short-term political interests could drive these CTI projects, as opposed to reasoned decision-making by the independent Commission that would more properly reflect a transparent assessment of the longer term benefits and costs to the Province of these projects.

In support of the changes in the legislation, the Alberta government and others emphasized, among others matters, the requirement for the expeditious approval of transmission facilities to enable the continued growth of generation to serve Alberta’s fast growing power market.  Supporters also argued that the changes are required to expeditiously address growing reliability concerns about the aging and often constrained transmission system in Alberta, and to harness increasing wind power developments in remote areas of the Province.

As noted, the debate was heated, and often aggressive.  In some respects, it was clearly driven – on both sides – by the lengthy regulatory proceedings undertaken between 2004 and 2007 concerning the AESO’s proposal to enhance the transmission system by adding a 500 kV line between Edmonton and Calgary.  While the AESO’s original need application was approved by the Commission’s predecessor, this project was derailed in late 2007 by reason of procedural irregularities on the part of the regulator, which led to the setting aside of all decisions and proceedings concerning that project.

 

However, that chapter ended with the proclamation of the legislation, and the relevant question for all concerned is: what now?  Little is known with absolute certainty – indeed, there have been some suggestions that the new legislation could itself be the subject of a judicial challenge.  What is clear, however, is that the legislation requires the AESO to direct TFOs to make timely applications to the Commission for the necessary approvals to construct and operate CTI.⁴  Notable among the projects already designated as CTI are not one, but two, HVDC lines between the Edmonton and Calgary regions, each having a minimum initial capacity of at least 1000 megawatts.

The changes in the legislation make it clear that, in a hearing or proceeding on specific CTI facilities, the Commission may not consider whether they are required to meet Alberta’s needs, and neither can it refuse to approve such an application on the basis that the facilities do not meet Alberta’s needs.⁵  The Commission’s own legislation contemplates that it must continue to consider whether applied-for CTI facilities are in the public interest having regard to their social, economic and environmental effects.⁶  Here, a relevant factor may be the declaration which is now found in the Hydro and Electric Energy Act – the basis of such CTI facility applications – that the construction and operation of CTI is not only required to meet Alberta’s needs, but is also in the public interest.⁷

The Commission retains its authority to require changes in the plans and specifications for such CTI facilities, or their location and route, but the legislation also enables the government to prescribe by regulation principles and criteria to which the Commission must have regard when it determines the specific location or detailed routing of CTI facilities.  These regulations have yet to be promulgated.⁸

Transmission facility applications in Alberta are currently subject to extensive public consultation requirements established by the Commission.  If anything, the new legislation serves only to underscore the importance of those obligations.  Commission hearings on CTI facility applications are likely to break new ground, and are sure to engender a further chapter of heated debate and discussion on various issues, not the least of which may be the continuing obligation of the Commission to determine whether applied-for CTI facilities are in Alberta’s public interest.

Any opinions expressed in this article are those of the author and do not represent the views or position of Gowling Lafleur Henderson LLP or any of its clients, and may not be construed as doing so.

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1. Electric Utilities Act, S.A., 2003, c.E-5.1, as amended, ss.16, 17.
2. Electric Statutes Amendment Act, 2009, S.A. 2009, c.44
3. EUA, s.41.2
4. EUA, s.41.3
5. Alberta Utilities Commission Act, S.A. 2007, c.A-37.2, as amended, s.17(2); Hydro and Electric Energy Act, RSA 2000, c.H-16, as amended, s.19(1.1)
6. AUC Act, s. 17(1)
7. HEE Act, s.13.1(2)
8. HEE Act, s.19(2); EUA, s.142(1)(v.4)

Jim Smellie (403) 298-1816 james.smellie@gowlings.com

ERCB’S RULLINGS ON VALIDITY OF FREEHOLD OIL AND GAS LEASES

During the last couple of years the Energy Resources Conservation Board of Alberta has been called upon to rule on the validity of freehold oil and natural gas leases, and has asserted its jurisdiction to do so, striking down two leases.  Prior to 2008, the validity of leases had only been contested in the courts.  The emergence of the ERCB as an alternative forum for litigating exactly the same issues is an interesting development which has some important implications from a procedural and potentially a substantive point of view.

Over the past 50 years, the freehold oil and gas lease has provided a fertile ground for court challenges.  A great deal is potentially at stake.  In some cases, leases covering millions of dollars worth of reserves have been struck down.  A fascinating body of law has developed, focussing on the habendum and several key clauses of the lease, including the shut-in clause, the default clause and the offset drilling clause.

ERCB Decision 2008-047, Desoto Resources Limited

In mid-2008 the Alberta Energy Resources Conservation Board (ERCB or the Board) made what to many was a surprising move by suspending a well licence previously issued by the Board itself on the ground that the licence-holder no longer held a valid lease: ERCB Decision 2008-047, Desoto Resources Limited (June 18, 2008).  Desoto claimed to have the necessary working interests by virtue of some 1970’s-vintage leases granted by PanCanadian Petroleum Limited.  An issue concerning the validity of Desoto’s leases  led to an action being commenced in the Court of Queen’s Bench between Desoto and PanCanadian’s successor, EnCana Corporation.  While the litigation was ongoing EnCana wrote a letter to the Board requesting a review of the well licence on the ground that Desoto was not entitled to the licence because it did not hold a valid lease.

The Board held a hearing and later issued a Decision which reads much like a court ruling, reciting the important evidence which had been adduced before it including the key provisions of the leases.  After considering the jurisprudence, the Board decided that the leases had in fact terminated and that a well Desoto had drilled under the authority of its licence should be shut in.

The leases in question had been granted in 1975 for primary terms of three and five years “and so long thereafter as any of the leased substances is being produced or is capable of production in paying quantities from a well or wells on the said lands”.  Prior to the drilling of Desoto’s successful well, the last well on the lands had stopped producing in 1985.

The central issue was whether the suspended well had remained “capable of production in paying quantities” up to the time Desoto drilled its own well.  After reviewing the case law, the Board held that for a well to be capable of production in paying quantities, it had to be able to begin flowing if it was “turned on” without equipment being added or repairs made.  In this case, there was no evidence that the old well could produce in this sense.  The leases had therefore long since terminated.

Desoto applied for leave to appeal to the Court of Appeal, apparently concentrating on the argument that the ERCB had no jurisdiction to rule on the validity of the lease.  Madam Justice McFadyen ruled that there was no merit to this argument, and so dismissed the application: Desoto Resources Limited v. Energy Resources Conservation Board, 2008 ABCA 349 (Oct. 9, 2008). 

ERCB Decision 2009-037, OMERS Energy Inc.

After the Board made the ruling that it did in the Desoto case – and its jurisdiction to do so had been upheld by a judge of the Court of Appeal in chambers – it is not surprising that interested parties started to invite the Board to shut in other wells held under doubtful leases.  A second case, ERCB Decision 2008-037, OMERS Energy Inc. (Decision 2009-027) arose in a similar fashion – that is, a letter being written to the ERCB arguing that the lessee’s well licence was invalid.  A difference this time was that the challenge was brought not by the lessor but by a toplessee (a company which takes a new lease, to come into effect upon the original lease being struck down).

The leases in this case were also for a five-year term.  Another similarity to the Desoto case is that the lessee, OMERS, relied upon a shut-in well as continuing the leases beyond their primary term.  However, the focus of attention in this case was the leases’ shut-in clause, which provided that the leases would continue in force after the expiration of the primary term if there was a well on the lands which was ”capable of producing the leased substances”.  The Board decided that, for a suspended well to be capable of producing the leased substances, it had to have the ability in its existing configuration and state of completion to produce leased substances in some meaningful or material amount.  A miniscule amount would not suffice.

Prior to being shut in, the well in question had experienced a high water level in the wellbore.  OMERS believed that a poor cementing job was responsible for this problem and had attempted two operations to address the problem.   The Board considered that “it is not clear that after [the date it was shut in, the well] was capable of producing without remedial operations”.  The Board therefore held that the leases had terminated and were not saved by the shut-in clause.

In this case, an application for leave to appeal was successful: OMERS Energy Inc. v. Energy Resources Conservation Board, 2009 ABCA 273 (August 11, 2009).  Madam Justice Paperny granted leave only on the question of whether the Board had erred in its interpretation of the phrase ”capable of producing the leased substances”.

Potential Implications of this Development

It seems that the Board was right in holding that it does have jurisdiction to rule on the validity of leases, as it does on other questions of law which arise incidentally to the Board’s statutory authority.  To be entitled to hold a well licence, a person must satisfy the Board that it is “a working interest participant and is entitled to the right to produce” oil or gas from the well: Oil and Gas Conservation Act, s. 16.

However, the Board’s new practice of exercising this jurisdiction over this specific type of issue raises some interesting issues and potential concerns.  Among these are the following:

• The Courts continue to have an unquestionable jurisdiction over exactly the same issue of lease validity.  This raises the possibility that there could be two competing sets of proceedings, a possibility which in turn could give rise to some possible conundrums.  For example, will a ruling by the ERCB be treated as conclusive (as res judicata) if one of the parties – following an adverse decision by the ERCB – insists on continuing to litigate the issue in court?
• What weight will ERCB decisions be given by the courts in future decisions?  Does it matter that the Board is not a court of law?  The decisions in both Desoto and OMERS appear on their face to be soundly reasoned (although the OMERS decision has generated controversy and is under appeal).  In both cases, the Board undoubtedly benefited from the fact that some of the Board members sitting on those cases were lawyers (one of the three members sitting on the Desoto case and two of the three in the OMERS case).  Arguably, the Board is better equipped than a court would be to address some of the technical issues concerned with (e.g.) the reasons a well was shut in or has remained shut in.
• Are any concerns raised by the fact that the parties to an ERCB hearing do not have the benefit (or burden) of all of the procedures inherent in a court action, such as the ability to compel documentary production or the right to conduct examinations for discovery?  Are these procedural differences likely to lead to different results in some types of cases?
• To the extent that the task of challenging a lease may be easier (in the sense of being more cost-effective and more expeditious) in a proceeding before the ERCB, is the option to challenge leases in this manner likely to encourage such challenges by lessors or the practice of topleasing?
• We shall see if it proves easier to persuade the Board to shut in a well on an interim basis than it is to obtain an interim injunction or another type of order from a court having a similar effect.  The differences in practice might have the potential to strengthen the hand of lessors.
• Will the Board’s public interest mandate have an impact on its decision-making in these cases?  In a civil lawsuit, the court is only interested in doing justice between the parties.  In the OMERS case, the Board gave standing to a lobby group, the Freeholders Petroleum & Natural Gas Owners Association, which was allowed to make arguments in support of the position of the toplessee.  This raises possible issues of fairness.
• Some potentially troublesome issues could arise if the Board were asked to rule on the validity of a Crown lease.  While the Board is not an arm of the provincial Crown, there could be an apprehension that it was not a completely impartial body in any contest between the Department of Energy and an oil company Crown lessee.

For these and other reasons, future rulings by the Board on the validity of leases will be watched with great interest.

A cautionary note is that the ERCB does not have unlimited jurisdiction to rule on the validity of oil and gas leases.  There must be a connection between that issue and a matter falling under the Board’s jurisdiction, such as whether the holder of a well licence has title to the relevant working interests.

(John Ballem is the author of The Oil and Gas Lease in Canada, now in its fourth edition, and is widely recognized as the leading authority on this subject.)

John Ballem, Q.C. (403) 292-9801 john.ballem @gowlings.com

Paul Edwards (403) 292-9815 paul.edwards @gowlings.com

DOES A POOLING TRIGGER AN AMI OBLIGATION? CASE COMMENT ON HUNT OIL V. SHELL CANADA

A recent Alberta decision is the first ruling on whether an Area of Mutual Interest (AMI) obligation (which requires each party to a contract to give the other a chance to participate in any acquisition made within a defined geographic area during a specified period of time) is triggered when one party enters into a voluntary pooling agreement with a third party, thereby acquiring additional interests within the AMI.  Mr. Justice Alan MacLeod of the Court of Queen’s Bench held that, in the circumstances of the case, the AMI obligation did not apply to a pooling arrangement which one of the parties had entered into.

Farmout agreements, under which the holder of an oil or gas lease gives another company an opportunity to earn an interest in the lease, usually by drilling a test well or wells, commonly contain an “AMI” (Area of Mutual Interest) clause.  The test well results, or other operations, may arouse interest in surrounding lands.  The AMI clause provides that if, during some specified period of time, one of the parties to the farmout decides to acquire an interest in any lands within a defined area, it must give the other party an opportunity to participate in the acquisition.

In Hunt Oil Company of Canada, Inc. v. Shell Canada Limited, Shell and Hunt had entered into a Farmout, Participation and Option Agreement, under which Hunt was given the right to earn an interest in one block of lands (Block “A”) by drilling a test well, together with an option to earn in a second block of lands (Block “B”) by drilling a second, option well.  The results of the test well suggested that wells drilled on Block “B” would be marginally economic.  Hunt unsuccessfully proposed a variation to the Agreement, then allowed the Block “B” option to expire.

Farmout agreements respecting lands in the Western Canadian basin commonly incorporate the 1997 Canadian Association of Petroleum Landmen (CAPL) standard form of Farmout and Royalty Procedure, which includes an AMI provision.  The Shell-Hunt Agreement included the CAPL Farmout and Royalty Procedure.

Before Hunt let the option expire, Shell had begun negotiations with a third party, Talisman Energy Inc., to “pool” its interests in Block “B” with Talisman lands which also fell within the AMI.  A pooling agreement was concluded after the expiration of Hunt’s option.  A joint Shell/Talisman well drilled on the Talisman lands was successful.  Hunt’s position was that Shell’s interest in the Talisman lands resulted from an “acquisition” within the meaning of the AMI clause, and that Shell therefore ought to have given Hunt the opportunity to participate in the pooling.

Macleod, J., while recognizing that the pooling agreement with Talisman gave Shell rights within the AMI that it had not previously held, concluded that the AMI clause was not intended to apply to interests acquired in this manner.  Poolings are often “regulatory” or “compulsory” in nature.  In Alberta at least, Regulations require a party holding only a part of a “drilling spacing unit” to pool its interests with the remaining interests in the spacing unit before it may drill a well.  Hunt conceded that the AMI clause in the Farmout, Participation and Option Agreement would not have applied to a compulsory pooling.  The pooling between Shell and Talisman was voluntary, in that it was not required by Regulation in order to form a spacing unit, or for any other reason.

The court concluded that even voluntary poolings were not caught by this AMI clause.  The clause was silent on whether a pooling arrangement could amount to an “acquisition” within the meaning of the clause.  However, the court considered that the objective of the CAPL AMI clause (which – like all AMI clauses – was to negate the parties’ normal right to compete with one another in making certain land acquisitions) was not served by treating pooling agreements as “acquisitions”.  From Shell’s point of view, the pooling with Talisman was financially neutral, in that Shell had to give Talisman interests (also falling in the AMI) of equal value to the interests of Talisman which Shell obtained through the pooling.

The judge chose not to base his decision on the point that Shell’s pooling with Talisman was a “non cross-conveyance pooling” (in that it was not structured so as to involve a formal conveyance to Shell of any portion of Talisman’s interests, or vice versa).

In reaching its decision the court rejected expert opinion evidence from an experienced landman called by Hunt to the effect that industry practice was to treat voluntary poolings as acquisitions for purposes of AMI clauses.

Macleod stated that his decision should not be interpreted as meaning that no AMI obligation can ever be triggered by a pooling agreement, and that each case would depend on its facts including (in particular) the way the AMI clause was worded.  Nonetheless, in the face of this decision, any one wishing to argue that an acquisition pursuant to a pooling triggers an AMI obligation will clearly be facing an uphill battle.

Paul Edwards (403) 292-9815 paul.edwards@gowlings.com

USE OF DUTCH HOLDCO TO INVEST IN CANADIAN ENERGY

Much of Canada’s resource sector is owned by US-based investors. US investors should consider the most tax effective arrangement to acquire and hold Canadian resource assets. One common strategy is to use a corporation resident in the Netherlands for this purpose.

A US resident investor who acquires shares of a Canadian corporation the principal value of which is derived from Canadian resource property will generally be subject to Canadian capital gains tax on the disposition of those shares.⁹ However, a Dutch resident investor who sells shares of a Canadian corporation the principal value of which is derived from Canadian resource property may be exempt from paying any Canadian capital gains tax on the disposition under the Canada – Netherlands Tax Treaty.¹⁰

Article XIII of the Canada – Netherlands Tax Treaty provides that gains on the alienation of shares of a Canadian corporation the principal value of which is derived from “immovable property” is subject to Canadian capital gains tax. However, for these purposes “immovable property” “does not include property (other than rental property) in which the business of the company, partnership, trust or estate is carried on”. The Canada Revenue Agency has confirmed that “immovable property” under the Canada – Netherlands Tax Treaty does not include Canadian resource property which is “actively exploited or held for future exploitation.”¹¹ The Canada Revenue Agency has also stated that:

In our view, oil and gas reserves and royalty interests will be excluded from the definition of immovable property for the purposes of paragraph 4 of Article XIII [of the Canada – Netherlands Tax Treaty] if the owner is actively engaged in the exploitation of natural resources and if such assets are actively exploited or kept for future exploitation by such owner. […]

We contrast this with a passive investor or an investor who is in the business of buying and selling working interests or royalties for speculation purposes without being directly involved in the exploitation of the underlying reserves. In our view, such investors would not be considered to be actively engaged in the exploitation of natural resources. It is also our opinion that the mere buying and selling of working interests or royalties would not constitute exploitation.¹²

Therefore, a Dutch holding company (unlike a US resident person) that disposes of shares of a Canadian resident corporation the principal value of which is derived from Canadian resource property and which resource property is actively exploited or held for future exploitation should be exempt from Canadian capital gains tax on disposition. US investors acquiring shares of a Canadian oil and gas company should thus consider making their investment through a Dutch Holdco to avoid Canadian capital gains tax on the disposition of those shares.

In establishing this type of tax planning structure, US residents need to be aware of so-called "treaty shopping" restrictions, that is, restrictions with respect to the use of tax treaties in tax planning. International tax law is complex and requires careful consideration of domestic law and bilateral tax treaties. Gowlings tax lawyers, members of Taxand, a global network of leading tax advisors, can assist foreign investors in planning the most tax effective arrangement for their acquisition of Canadian energy assets.

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9. Convention Between Canada and The United States of America With Respect to Taxes on Income and on Capital, Article XIII, paragraphs 1 and 3.
10. Convention Between Canada and The Kingdom of the Netherlands  For the Avoidance of Double Taxation and the Prevention of Fiscal Evasion With Respect to Taxes on Income, Article XIII, paragraphs 1, 4, and 7.
11. CRA, Advanced Tax Ruling No. 2000-0015753 (July 13, 2000).
12. CRA, Views No. 9506785, “Property – in which business of company carried on” (September 8, 1995).

John McClure (403) 298-1053 john.mcclure @gowlings.com

Lauchlin MacEachern (403) 298-1974 lauchlin.maceachern @gowlings.com