Lawson Lundell LLP
  January 30, 2007 - British Columbia

A Regulatory Roadmap: Successfully Navigating Oil and Gas Licensing Regimes in the North
  by Keith B. Bergner and Mariana Storoni

This paper was presented at The Canadian Institute’s 2nd Annual Oil & Gas Law Summit Overcoming the Regulatory Challenges and Uncertainties to Keep Your Project on Track on January 22 – 23, 2007 in Calgary, Alberta.

Oil and gas exploration in Canada’s North has a long history that dates back to the oil well drilled in Norman Wells in 1920. The North is recognized as holding a significant portion of Canada’s potential for undeveloped oil and gas. Canada’s Northwest Territories (“NWT”), Nunavut and the Arctic Offshore hold an estimated 33 percent of Canada’s remaining conventionally recoverable natural gas resources and 25 percent of the remaining recoverable resources of light crude oil. It is estimated that potential natural gas resources in the NWT are approximately 82 trillion cubic feet; the NWT’s potential for crude oil is estimated at 5.7 billion barrels.1

The high potential of Canada’s North for oil and gas is brought into focus in light of the Mackenzie Gas Project, and the consequent opportunities to develop and produce potential new gas discoveries. The Mackenzie Gas Project will encompass the development of three anchor fields in the Mackenzie Delta, the construction of gathering and processing facilities, and a 1,200-kilometre gas transmission pipeline to Alberta. The Beaufort-Mackenzie Basin is estimated to contain discovered and undiscovered marketable gas resources of 10.9 trillion cubic feet and 45.8 trillion cubic feet respectively.2 If approved and built, the project’s infrastructure will serve to open up Canada’s North to investment in further exploration and development.

The purpose of this paper is to provide a guide to the regulatory approval processes for oil and natural gas exploration and production in the NWT. The first section of the paper discusses the federal oil and gas licensing regime which applies throughout the NWT. The second section provides a roadmap to the additional oil and gas regulatory approval processes in four specific regions of the NWT.

Rights over petroleum (oil or gas) in the Northwest Territories are governed by the Canada Petroleum Resources Act, R.S.C. 1985, c. 36 (2nd Supp.) (“CPRA”). The CPRA licensing regime north of 60º is administered by the Department of Indian Affairs and Northern Development (“DIAND” or “Minister”).

There are three types of interests in oil and gas that may be granted under the CPRA:
Exploration Licences, Significant Discovery Licences, and Production Licences. This section of the paper will briefly describe the process required to obtain each type of licence.  

A. Exploration Licence (“EL”)
Exploration Licences confer on the licensee, with respect to the lands to which the licence applies:

(a) the right to explore for, and the exclusive right to drill and test for, petroleum;

(b) the exclusive right to develop those lands in order to produce petroleum; and

(c) the exclusive right, subject to compliance with the other provisions of the CPRA, to obtain a Production Licence on those lands.3

ELs are issued in a public bidding process.4 The DIAND conducts the bidding process in two phases: a call for nominations, followed by a call for bids.

Call for Nominations
Calls for nominations, although not required by law, are usually initiated annually by the DIAND upon the request of either a local northern group or a private corporation. This process provides industry with the opportunity to identify blocks of land it would like to see posted for bidding. The DIAND’s call for nominations document identifies the region in which nominations are sought and specifies the maximum size limit for blocks. The call for nominations document sets out the terms and conditions associated with the resulting cost for bids. These generally include: the bid selection criterion, minimum bid requirements, 25 percent bid deposit, work deposit where applicable, insurance fees, Environmental Studies Research Fund levies, term of licence, rentals applicable, allowable expenditures, conditions relating to the environment, northern benefits requirements, considerations relating to land claim settlement agreements, and form of EL. The document also sets out the deadline by which posting requests must be received for consideration by the Minister for inclusion in a subsequent call for bids.

All nominations received through this process are given full consideration for inclusion in a call for bids. However, the DIAND reserves the right not to proceed with a call for bids. A call for nominations was recently issued by the DIAND, in August 2006, in respect of the Fort Liard area in the southern NWT. The area included in the 2006 Fort Liard call for nominations covers approximately 130,023 hectares. The area available for nominations was divided into nine parcels which varied in size from 25 to 54 sections. The call closed on September 15, 2006 but no nominations were received.

Call for Bids
After consultation with local stakeholders in the proposed area reveals that exploration would be favourable, and once the location, size and terms of the proposed EL are finalized, the DIAND may issue a call for bids. The call for bids must remain open for at least 120 days.5 Upon closing of the call for bids, all bids are received and assessed against the criteria stated in the call, which is typically the value of the work proposal, that is, the total amount of money that the bidder proposes to spend doing exploratory work on the parcel within a specified time period. While the DIAND is not required to select any bid,6 ELs are generally awarded to the highest bidder.

A call for bids was recently issued in respect of two parcels located in the Beaufort Sea/Mackenzie Delta area of the NWT and closed on May 2, 2006. Parcel MD-1 was approximately 56,400 hectares, and the size of parcel MD-2 was 99,900 hectares. Encana Corporation, Anadarko Canada Corporation and ConocoPhillips Canada Resources Corp. submitted the winning bid on parcel MD-1 for $40.2 million. An EL for parcel MD-2 was awarded to Shell Canada Limited, which bid $11.5 million. A map showing the location of the winning bids (as well as existing interests) is attached as Appendix A.

A new call for bids was issued in January 2007 for exploration rights on four parcels of land in the Central Mackenzie Valley region of the NWT covering 311,340 hectares. The call for bids closes on May 8, 2007.

Terms of an Exploration Licence
A share in an EL can be issued to multiple parties.7 Each party would receive an undivided share in the EL, identified by a percentage. For example, EL434, which was issued pursuant to Parcel MD-1 in the 2006 call for bids, was granted to three parties: Encana  Corporation (37.5 percent), Anadarko Canada Corporation (37.5 percent) and ConocoPhillips Canada Resources Corp. (25 percent).

An EL may be issued for a maximum term of nine years and cannot be extended or renewed, except in the limited circumstances described below.8 When the term of an EL expires, the lands to which the EL relates that are not subject to a production licence or significant discovery licence become Crown reserve lands, that is, lands where no interest is in force.9

The term of an EL is usually divided into two periods, which may vary in length depending on the location. The length of Period I recognizes the time necessary to undertake an exploration program culminating in the drilling of a well. For example, Period I will reach its maximum length of six years in regions where operating seasons are shortened by ice movement, access across sensitive terrains or other environmental factors. In less physically and technically challenging terrain, Period I could be as short as three or four years. The drilling of a well in Period I qualifies the licence holder to retain the licence for Period II.

When DIAND selects the value of the work proposal, as it typically does, as the bidding criterion, the winning bidder’s commitment is secured by a 25 percent deposit. Expenditures are currently allowed for seismic exploration and drilling at representative rates which are periodically reviewed and appended to each EL. The deposit is refundable, as expenditures are made, at a rate of $1 for every $4 spent. Any work or activity undertaken during Period I is credited against the work deposit and refunded in accordance with the licence’s schedule of allowable expenditures.

Period II of the EL carries payment obligations in the form of escalating rentals on a per hectare basis. Rentals are required in full at the beginning of each year in Period II of the EL and are fully refundable as allowable expenditures are incurred.

The length of Period II recognizes the time necessary to make a significant discovery. A “significant discovery” is defined by the legislation as:

[A] discovery indicated by the first well on a geological feature that demonstrates by flow testing the existence of hydrocarbons in that feature and, having regard to geological and engineering factors, suggests the existence of an accumulation of hydrocarbons that has potential for sustained production.10  

Although the maximum term for an EL is nine years, once an EL holder has begun the drilling of a well, the EL continues in force as long as may be necessary to determine the existence of a significant discovery based on the results of that well, and provided that drilling is being pursued diligently.11 When drilling of that well is suspended due to dangerous or extreme weather conditions or mechanical or other technical problems, the drilling of that well is deemed by the legislation to be being pursued diligently during the period of suspension.12 If the drilling of the first well cannot be completed due to a mechanical or other technical problem and the drilling of a second well in the EL is commenced within 90 days of the cessation of operation, the drilling of the second well is deemed to have been properly commenced within the term of the EL.13  

An EL may be amended, with the agreement of the Minister, to enlarge or reduce the lands included in it provided that the amendment is not inconsistent with the CPRA or the regulations.14 However, an EL will generally not be amended to include new lands except in limited circumstances. New lands will, in practice, only be issued under a licence following the completion of a call for nominations and call for bids.  

B. Significant Discovery Licence (“SDL”)
Where petroleum exploration conducted under an EL results in a significant discovery, the licence holder may apply for a SDL. The SDL regime is aimed at encouraging exploration of resources in remote lands where there are no immediate prospects of commercial production. An SDL allows the licence holder to retain rights in the discovery until the resources become commercially reasonable to produce. The rights conferred by the SDL are identical to those provided by the EL.15

In order to obtain a SDL, the applicant is first required to obtain a declaration of significant discovery from the National Energy Board (“NEB”).16 The declaration process confirms a hydrocarbon discovery which satisfies specific technical criteria and describes the area over which the discovered resources extend. The NEB's technical determination involves examination of geophysical records and mapping, the regional and local geology, the petrophysical analysis of the discovery well, the reservoir continuity and quality, and a full analysis of any relevant test data. Once a declaration of significant discovery is in force and all or a portion of that area is subject to an EL, the EL holder may apply for an SDL for the area of significant discovery covered by the EL.17 On the issuance of a SDL, the SDL replaces the EL in relation to the significant discovery area.18 Where a significant discovery area extends to Crown reserve lands, a SDL may be issued following the bidding process described above.19 

SDLs are granted for an indefinite term, lasting as long as the significant discovery declaration remains in force, and until a production licence is issued in relation to the same area.20 The absence of a time limit reflects the common reality that a discovery may be of a size and in a location that make it uneconomic to develop at the time. There are, however, some limitations to the term of a SDL. In particular, the NEB may amend or revoke a declaration of significant discovery where, based on the results of further drilling, there are reasonable grounds to believe that a discovery is not a significant discovery or that the lands subject to the SDL differ from the significant discovery area.21 A declaration of significant discovery cannot be amended to decrease the significant discovery area or revoked earlier than (a) the date on which the EL expires, in the case of SDLs granted over lands subject to an EL, and (b) three years after the effective date of the SDL in the case of SDLs granted over Crown reserve lands.22 A revocation of the declaration would end the term of the SDL. A SDL takes a prescribed form23, but the Minister and licence holder may also agree on any other terms and conditions which are not inconsistent with the CPRA or the regulations.24 No rentals are applied to SDLs.

C. Production Licence (“PL”)
Once the developer has determined that the discovery can be commercially produced, a holder of an interest such as an EL or a SDL is eligible to apply to the NEB for a declaration of commercial discovery.25 A “commercial discovery” is defined by the legislation as “a discovery of petroleum that has been demonstrated to contain petroleum resources that justify the investment of capital and effort to bring the discovery to production”.26 In order to evaluate the application, the NEB must make a technical assessment of the size of the commercial discovery area based on well data, and oil and gas reservoir characteristics. The NEB must also assess whether the discovery justifies the capital investment that is required to bring the discovery to production.

The declaration of commercial discovery defines the extent of the area to be developed and is required prior to application for a PL. The declaration may apply to lands outside of those covered by an existing EL, SDL or other interest, but in those cases the Minister may call for bids and issue a PL pursuant to the bids process.27 The NEB may revoke the declaration of commercial discovery if there are reasonable grounds to believe that the discovery no longer justifies commercial development, and it may amend the declaration by increasing or decreasing the size of the commercial discovery area.28  

A PL may only be held by a corporation incorporated in Canada.29 It may be issued to one or more applicants in respect of one or more commercial areas.30 For instance, several EL or SDL holders may combine their interests to share a PL, or one company may obtain several PLs on the basis of a single EL. Further, the Minister may, on application by two or more companies for PLs, consolidate those PLs into a single licence.31  

The following rights are conferred by the PL in relation to the commercial discovery area:
(a) the right to explore for, and the exclusive right to drill and test for, petroleum;

(b) the exclusive right to develop the lands subject to the PL to produce petroleum;

(c) the exclusive right to produce petroleum from the PL lands; and

(d) title to the petroleum so produced.32

A PL is issued for a term of 25 years and is extended automatically if commercial production is underway at the end of the term.33 The PL also qualifies for extension if production has ceased but it is possible the production might recommence at some time in the future.34 In cases where the commercial production of petroleum has not commenced, the Minister may issue a development order in relation to any portion of the commercial discovery area. The effect of such order is to give notice to the interest holder that a further order may be made within six months reducing the term of the any existing interest held in respect of that area.35  

As is the case with ELs, when a PL expires, the lands subject to it revert to Crown reserve lands.36 As a result, those lands can only be the subject to further exploration by first engaging the bidding process for the issuance of a new EL.37

Currently, the primary distribution of PLs are clustered around Fort Liard and Cameron Hills in the southern part of the NWT. Of course, this corresponds with the existence of pipelines and facilities to accommodate commercial production. Maps showing the location of existing interests around Fort Liard and Cameron Hills are attached as Appendix C.

In the central Mackenzie Valley, the existing PLs are centered around Norman Wells, again corresponding to the existing pipeline and production facilities. A map showing the existing interests in the central Mackenzie Valley is attached as Appendix D. In Beaufort Sea and the Mackenzie Delta there is an existing PL corresponding with the Ikhil pipeline, which provides gas to the community of Inuvik. A map showing the existing interests in this area is attached as Appendix E.

There are also existing dispositions in the Eastern Arctic Offshore and Sverdrup Basin.

D. Royalty Regime
During production, the PL holder pays a royalty to the Crown.38 Royalties of one percent of gross revenues are payable for the first 18 months of production; two percent for the following 18 months, and so on, to a maximum of five percent. After “project payout”, the royalty remains at five percent of gross revenues or 30 percent of net revenues, whichever is greater. 39

“Project payout” is reached when the cumulative adjusted gross revenues (“CAGR”) of the PL holder in relation to the project exceed the adjusted cumulative cost base (“ACCB”) of the PL holder in relation to that same project. The CAGR is calculated by adding, in respect of that month and the preceding months: (a) the gross revenues of the PL holder from that petroleum, (b) any insurance proceeds payable to the PL holder under an insurance policy for loss of revenue from that project, and (c) the absolute value of the adjusted cumulative cost base of the PL holder in relation to the project if it has a negative value.

The cumulative cost base of a PL holder in relation to a project is calculated by adding, in respect of that month and the preceding months:

(a) allowed capital costs (listed under Schedule I of the Frontier Lands Petroleum Royalty Regulations);

(b) capital cost adjustments (five percent of the allowed capital costs before the project commencement date, and one percent of the allowed capital costs after the project commencement date);

(c) allowed operating costs (listed under Schedule I of the Frontier Lands Petroleum Royalty Regulations);

(d) operating cost adjustments (ten percent of the allowed operating costs); and

(e) prescribed royalties; and

(f) a return allowance equal to the long-term government bond rate plus 10 percent.

The cumulative cost base thus calculated is then adjusted by subtracting any entitlement to insurance proceeds for loss or damage to property. The aggregate of the cumulative cost base for each month equals the ACCB, which is compared to the CAGR to assess when project payout has been reached. As stated above, at that time, royalties payable level off at five percent of gross revenues or 30 percent of net revenues, whichever is greater.

The oil and gas royalty regimes in other parts of Canada differ from the federal regime in force in the Northwest Territories. For example, the royalty rate for natural gas in Alberta is determined according to the energy content of the gas, and is sensitive to the current level of market prices and the vintage classification of the reserves, with adjustments for low productivity wells.40 Distinction is made between old gas and new gas, and among natural gas components: methane, ethane, propane, butane and pentanes-plus. With respect to oil, Alberta royalties are determined according to a formula that includes a production-sensitive component and a pricesensitive component. At the reference well rate, the base royalty is 10 percent and the marginal royalty is 40 percent.

A project is currently underway to review and modernize the Frontier Lands Petroleum Royalty Regulations. The objectives of the project are to identify areas where the regulations could be modernized to better meet today’s operating practicalities, to strengthen royalty accountability and assurance, improve fairness, and streamline royalty administration.41

E. Confidentiality Issues
One issue of concern for prospective EL, SDL or PL holders is often the protection of commercially sensitive information. The CPRA protects the confidentiality of documentation and information provided to the government for the purposes of the CPRA, or for the purposes of applications to the NEB for significant or commercial discovery declarations, whether or not the information or documentation is required to be provided.42 The government is precluded from disclosing such information without the written consent of the person who provided the information.43

This confidentiality protection does not apply, however, where the disclosure of the information is required for the purposes of the administration or enforcement of the legislation or for legal proceedings relating to its administration or enforcement.44 The meaning of this exception was addressed by the Federal Court of Appeal in Canadian Forest Oil Ltd. v. Chevron Canada Resources et al.45

That case arose when Chevron Canada Resources (“Chevron”) made a commercial discovery at one of its gas wells in the Fort Liard area and subsequently applied to the NEB for a declaration of commercial discovery. Before issuing the declaration, the NEB was required by law to give 30 days’ notice to anyone it considered to be directly affected by the declaration. However, the NEB issued the declaration to Chevron without notifying Canadian Forest Oil Ltd. (“CFO”), which held an EL covering an area near Chevron’s well, because it did not consider CFO to be “directly affected”. CFO then applied to the Federal Court of Appeal for judicial review of the NEB’s decision to issue the declaration.

CFO’s application for judicial review included a request that the NEB provide a certified copy of all documents that were before it when it made the decision to issue the declaration of commercial discovery to Chevron. The NEB produced all of that material, but withheld, pursuant to s. 101 of the CPRA, the technical and financial information filed by Chevron.

At the Federal Court of Appeal, Chevron argued that s. 101 protected the confidentiality of the information. CFO contended that s. 101 permitted the disclosure of the information given that the judicial review constituted a legal proceeding relating to the “administration or enforcement” of the legislation. The Court noted that the objective of the confidentiality provisions of the  

CPRA was to facilitate full and frank disclosure by resource companies seeking exploration and production rights. However, the Court agreed with CFO that the judicial review was a legal proceeding relating to the administration or enforcement of the legislation and that, as a result, the NEB was permitted to disclose the technical information to CFO. In spite of this conclusion, the Court did not order the immediate production of the Chevron materials on the basis that the most sensitive technical and financial information contained in the documents may not be relevant to the judicial review. Rather, the Court invited Chevron to apply to the Court for an order of confidentiality.

The CPRA does not apply to subsurface resources owned by Aboriginal groups under land settlement agreements. The grant of interests in oil and gas on lands owned by Aboriginal groups is governed by the terms of the applicable settlement agreement. Below is a brief overview of the distinct regulatory approval processes involved in obtaining oil and gas interests in the Inuvialuit Settlement Region, the Gwich’in Settlement Area, the Sahtu Settlement Area and the Southern Mackenzie Valley.

A. Inuvialuit Settlement Region

The Inuvialuit Final Agreement (“IFA”) is a land claim agreement concluded in 1984 that applies throughout the Inuvialuit Settlement Region (“ISR”). The IFA transfers land title for 91,000 km2 from the Crown to the Inuvialuit. As a result, the Inuvialuit Land  Corporation (“ILC”) owns the surface and subsurface rights to 13,000 km2 (“7(1)(a) lands”) and the surface rights alone to 78,000 km2 (“7(1)(b) lands”). The Crown retains ownership over 80 percent of the land in the ISR. A map of the ISR is attached as Appendix F.

The CPRA regime described above governs the issuance of oil and gas rights on Crown reserve lands and Inuvialuit 7(1)(b) lands in the Northwest Territories. On 7(1)(a) lands, these matters are governed by the Inuvialuit Land Authority (“ILA”) Rules and Procedures.

The principal vehicle for the issuance of oil and gas interests in 7(1)(a) lands is the Concession Agreement. A Concession Agreement applies to a specified area of land and grants the holder the right to explore for, develop, operate, produce, win, take and remove oil and gas from that area. It also grants a non-exclusive right to conduct geophysical operations. The holder commits to financial, working interest and royalty arrangements. In addition, the concession holder is required to enter into an Operating Agreement, a Comprehensive Cooperation and Benefits Agreement, and a Participation/Access Agreement with the Inuvialuit. In cases where an operator does not have the subsurface rights to an area under a Concession Agreement but wishes to undertake exploration, the operator may apply to the ILA for a Reconnaissance Permit, which confers the non-exclusive right to explore for oil and gas on 7(1)(a) lands.

In addition to acquiring subsurface rights under the CPRA or ILA Rules and Procedures as applicable, operators that wish to work on Inuvialuit lands must first obtain from the ILA rights of access and land use authorizations.

B. Gwich’in Settlement Area
The Gwich’in Comprehensive Land Claim Agreement was concluded in 1992 and established the Gwich’in Settlement Region. The Gwich’in Settlement Region is made up of three different areas. One of those areas is the Gwich’in Settlement Area (“GSA”), which covers approximately 57,000 km2 and is entirely within the Mackenzie Valley and the Northwest Territories.

There are three basic types of land ownership within the GSA: (1) Gwich’in Lands; (2) Federal Crown Lands; and (3) NWT Commissioner’s Lands. A map of the GSA is attached as Appendix G.

On Gwich’in Lands where the Gwich’in own only the surface resources, petroleum rights are issued by DIAND pursuant to the CPRA. In addition, a developer must first negotiate an Access Agreement with the Gwich’in Tribal Council through the Gwich’in Land Administration.

On Gwich’in Lands to which the Gwich’in hold rights to both the surface and subsurface, the rights to explore and test for oil and gas are issued by the Gwich’in Tribal Council. On these lands, the Gwich’in Tribal Council may issue a call for bids over specified lands. The principal vehicle for rights issuance on these lands is a Concession Agreement negotiated between the developer and the Gwich’in Tribal Council. Concession Agreements are intended not only to grant rights to explore and develop oil and gas resources, but also address other matters, such as commitments to financial working interest and royalty arrangements. Furthermore, to access Gwich’in Lands for the purposes of resource exploration and development, the developer must first acquire negotiate an Access Agreement with the Gwich’in Tribal Council through the Gwich’in Land Administration.

On Crown Lands and NWT Commissioner’s Lands within the GSA, the DIAND is responsible for managing the petroleum resources under CPRA. When dealing with Crown Lands, in addition to fulfilling the requirements under CPRA described above, the proponent must submit a Benefits Plan to the DIAND for approval. The DIAND may require that the Benefits Plan ensure training, business and employment opportunities to the Gwich’in.  

C. Sahtu Settlement Area
The Sahtu Dene and Metis Comprehensive Land Claim Agreement was signed in 1993. The Sahtu Settlement Area is the region where the terms of the Agreement apply. The Sahtu Dene and Metis have title to over 41,000 km2 of land, of which almost 1,900 km2 include ownership of subsurface resources. A map is attached as Appendix H.

On lands where the Sahtu own the subsurface resources, the District Land Corporations issue rights to explore and test for oil and gas. The principal vehicle for rights issuance over these lands is a Freehold Lease Agreement negotiated between the developer and the District Land Corporation for the lands in question. For access to or across Sahtu lands for the purposes of resource exploration or development, the developer is also required to obtain a right of access from the landowner and to notify the Sahtu Secretariat Incorporated before exercising that right. On lands where the Sahtu hold title to only the surface, oil and gas interests are administered by the DIAND pursuant to the CPRA. In addition, in order to access Sahtu lands for the purposes of resource exploration or development, the developer must first obtain permission from the landowner in the form of a signed Access Agreement with the District Land Corporation for the lands in question.

On Crown Lands and Northwest Territories Commissioner’s Lands within the SSA, the DIAND is responsible for managing the petroleum resources under CPRA. When dealing with Crown Lands, in addition to fulfilling the requirements under CPRA described above, the proponent must submit to DIAND for approval a Benefits Plan that provide local individuals and businesses opportunities to participate in economic activity.

D. Southern Mackenzie Valley
The Mackenzie Valley Land and Water Board (“MVLWB”) regulates all uses of land, water and deposits of waste in the Southern Mackenzie Valley, which is also known as the Deh Cho Region. In addition to the interests issued by the DIAND under CPRA, additional authorizations for exploration and development activities are required from the MVLWB and other regulatory authorities.

In May 2001, the Deh Cho signed a Framework Agreement and an Interim Measures Agreement with the governments of Canada and the NWT. The Framework Agreement is intended to establish the basis for negotiation of an agreement-in-principle and eventually a final agreement. The topics for negotiations include land, resources, harvesting rights and governance in the Deh Cho region.

The Interim Measures Agreement provides for Deh Cho involvement in resource management decision-making in their traditional territory, pending negotiation of a final agreement. The Deh Cho will be able to participate in the Mackenzie Valley Environmental Impact Review Board’s work and the governments have agreed to establish a Deh Cho panel of the MVLWB. The Interim Measures Agreement also requires consultation with the Deh Cho on certain land and resource activities in their region, and provides for negotiation of impact benefit agreements.

The Interim Resource Development Agreement, which was signed in 2003, is aimed at fostering resource development in the Deh Cho territory and to accrue benefits to the Deh Cho territory and to accrue benefits to the Deh Cho from Canada in the interim of a Deh Cho Final Agreement.

This paper has attempted to provide a roadmap to the oil and gas regulatory approvals required in the NWT by the federal regime administered by the DIAND and the regional regimes. In addition to the approvals described in this paper, prospective petroleum explorers and producers are advised to ensure compliance with all regulatory requirements such as, for example, environmental and water permits. Readers seeking more information on these topics should consult the guide “Doing Business in Northern Canada”, which is available on Lawson Lundell’s website.

This is a general overview of the subject matter and should not be relied upon as legal advice or opinion. For specific legal advice on the information provided and related topics, please contact Keith Bergner at (604)631.9199 or [email protected] or Mariana Storoni at [email protected] or (60)631.9245.

Copyright © 2007, Lawson Lundell LLP

About the Authors

Keith B. Bergner
Keith Bergner is a partner at Lawson Lundell. He is a member of the Bar in British Columbia (1997), Northwest Territories (2000) and Nunavut (2002). Keith represents clients in the areas of regulatory/energy and aboriginal law. Having spent three years in Lawson Lundell's Yellowknife office (from 1999-2002), Keith is an important member of the firm's Northern Practice Group.

Keith has represented clients before all levels of court including the Supreme Court of Canada, as well as regulatory, tribunals such as the National Energy Board and various provincial/territorial utilities commission. He is also familiar with and works with the numerous regulatory bodies created under the Mackenzie Valley Resources Management Act in their permitting and environmental screening and review processes. Keith has been involved in a number of significant regulatory hearings and alternative dispute resolution processes before public utility commissions addressing oil and gas, electricity and mining projects. He currently acts as co-counsel for the Government of the Northwest Territories in the Mackenzie Gas Project proceedings before the National Energy Board. Keith has authored articles in the fields of aboriginal and energy law, and is a frequent speaker at conferences.

Mariana Storoni
Mariana Storoni is an associate at Lawson Lundell. Mariana was called to the British Columbia Bar in 2006 after completing her studies in science and law. Mariana practises in the areas of regulatory/energy law, administrative law and civil litigation. She has represented a public utility before the British Columbia Court of Appeal, and assisted with matters before the National Energy Board and the British Columbia Utilities Commission. Prior to joining Lawson Lundell in 2006, Mariana worked for three years at a Vancouver firm which specializes in aboriginal law. Mariana has co-authored articles and newsletters in the fields of aboriginal and energy law.

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(1) Indian and Northern Affairs Canada, Northern Oil and Gas Annual Report 2005 at 8.
(2) Sproule Associates Limited, Natural Gas Resource Assessments and Deliverability Forecasts, Beaufort-Mackenzie and Selected Northern Basins (May 2005) (Report prepared for the Mackenzie Explorer Group and filed in the Mackenzie Gas Project proceeding as Exhibit “N-MEG-5O”). A study prepared for Imperial Oil Resources Ventures Limited by Gilbert Laustsen Jung Associates Ltd. estimates the volume of discovered recoverable marketable natural gas resources in the Beaufort-Mackenzie Basin at 7.4-10.9 trillion cubic feet, and the volume of undiscovered recoverable marketable natural gas resources at 7.9-18.8 trillion cubic feet.
(3) CPRA, s. 22.
(4) CPRA, s. 14(1).
(5) CPRA, s. 14(4).
(6) CPRA, s. 16(1).
(7) CPRA, s. 23.
(8) CPRA, s. 26(2).
(9) CPRA, s. 26(6).
(10) CPRA, s. 2.
(11) CPRA, s. 27(1).
(12) CPRA, s. 27(2).
(13) CPRA, s. 27(3).
(14) CPRA, s. 25(1).
(15) CPRA, s. 29.
(16) CPRA, s. 28(1).
(17) CPRA, s. 30(1).
(18) CPRA, s. 32(1).
(19) CPRA, s. 30(2).
(20) CPRA, ss. 32(3), 42(1).
(21) CPRA, s. 28(4).
(22) CPRA, s. 28(5).
(23) An example of a standard form Significant Discovery Licence is attached as Appendix B
(24) CPRA, s. 30(3).
(25) CPRA, s. 35(1).
(26) CPRA, s. 2.
(27) CPRA, s. 38(2).
(28) CPRA, ss. 28(4), 28(5), 35(3).
(29) CPRA, s. 44.
(30) CPRA, s. 38(1).
(31) CPRA, s. 39.
(32) CPRA, s. 37(1).
(33) CPRA, ss. 41(1), 41(3).
(34) CPRA, s. 41(4).
(35) CPRA, s. 36(1).
(36) CPRA, s. 42(2).
(37) CPRA, s. 14(1).
(38) CPRA, s. 55(1).
(39) Frontier Lands Petroleum Royalty Regulations, SOR/92-26, s. 3(1).
(40) Alberta Energy, Oil and Fiscal Gas Regimes: Western Canadian Provinces and Territories.
(41) Indian and Northern Affairs Canada, Northern Oil and Gas Annual Report 2005 at 25.
(42) CPRA, s. 101(2).
(43) CPRA, s. 101(2.1), (3).
(44) Ibid.
(45) (2000), 257 N.R. 277 (F.C.A.).

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