Oil and Gas Rights Regimes
and related
Access and Benefit Issues
in Yukon and Northwest Territories
Nigel Bankes
Professor of Law
The University of Calgary
[email protected]
November 2000
Table of Contents
1.0
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1
The constitutional context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1.1.1 The status of the territories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1.1.2 Aboriginal land claim agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
2.0
The federal oil and gas regime in the Northwest Territories . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.1
The CPRA Regime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.2
Grandparenting of rights under the CPRA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.3
Forms of tenure and available methods of disposition . . . . . . . . . . . . . . . . . . . . . . . 10
2.4
The Exploration Licence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
2.5
The Pre-condition for an SDL, the Declaration of Significant Discovery . . . . . . . . . . 13
2.5.1 Substantive Requirements for a DSD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
2.5.1.1
Disputes as to the existence of a significant discovery . . . . . 17
2.5.1.2
Disputes as to areal extent . . . . . . . . . . . . . . . . . . . . . . . . . 20
2.5.2 Procedural Requirements and Protections . . . . . . . . . . . . . . . . . . . . . . . . . . 24
2.5.3 Amendment or Revocation of a DSD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
2.5.4 Issuance of the SDL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
2.5.5 Rights granted by an SDL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
2.5.6 Liabilities of an SDL holder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
2.6
The Condition Precedent for a PL, the Declaration of Commercial Discovery . . . . . 28
2.6.1 Issuance of a PL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
2.6.2 Rights granted by a PL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
2.6.3 Liabilities of persons having interests in a DCD . . . . . . . . . . . . . . . . . . . . . . 30
2.7
The s.106 Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
2.8
Transfers and Registration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
2.9
Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.0
Benefits Requirements, Surface Rights and Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.1
Benefits Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
3.1.1 Crown surface and subsurface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
3.1.2 Crown subsurface, Inuvialuit or First Nation surface . . . . . . . . . . . . . . . . . . 36
3.1.2.1
Sahtu and Gwich’in . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
3.1.2.2
Inuvialuit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
3.2
Surface Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
3.2.1
Sahtu and Gwich’in Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
3.2.2
Inuvialuit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
4.0
Inuvialuit and First Nation Rights Regimes in the NWT . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
-i-
5.0
Yukon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
5.1
Grandparenting of federal rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
5.2
The Yukon Rights Regime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
5.2.1 Method of disposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
5.2.2 Permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
5.2.3 Conversion of a permit to a lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
5.2.4 Leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
5.3
Transfers and registration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
5.4
Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
5.5
Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
5.6
Access and Surface Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
5.7
First Nation Oil and Gas Regimes in Yukon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
6.0
Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
6.1
The distinctive features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
6.2
The Common features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
-ii-
Oil and Gas Rights Regimes and Related Access and Benefit Issues in Yukon and Northwest
Territories
1.0
Introduction
The combination of important gas discoveries by Chevron,1 Ranger and Paramount in the Deh Cho,
Fort Liard area in 1998 and 1999 and high oil and gas prices over the last 12 months has caused the
industry to re-examine the potential for the discovery and economic recovery of hydrocarbon resources
in Yukon (YT) and Northwest Territories (NWT). Not since the days of the National Energy Program
(and in particular the petroleum incentives program (PIP) in the early 1980s) have we seen such a high
degree of interest in these two jurisdictions. During the summer of 2000 a diverse range of companies
picked up federal Crown acreage 2 in the Beaufort Sea - Mackenzie Delta area of NWT3 and in the
Central Mackenzie Valley.4 These companies have committed to spending some $525 million over the
terms of their exploration rights. In addition, three companies, Anderson, Chevron and Petro Canada
picked up Delta acreage from the Inuvialuit this summer. In Yukon, the Yukon Government (YTG) held
its first sale of oil and gas rights in 1999 in which Anderson Resources acquired two parcels comprised
of some 800 square kilometers in the Eagle Plain area with work expenditure bids of over $20 million.5
Yukon will hold a further rights sale this fall. A major northern gas pipeline either through Yukon or
down the Mackenzie Valley now seems inevitable.
1
K-29 well, producing 70 mmcf per day since April, 2000 on an estimated field size of 400 - 600 bcf, and the
more recent M-25 well expected to commence production at 50 mmcf per day ramping up to 75 mmcf per day. See
generally Brackman, “The Northwest Territories Petroleum Industry”, June 2000.
2
Northern Oil and Gas Directorate at <http://www.inac.gc.ca/oil/>.
3
Shell Canada Ltd, Amoco Canada, Burlington Resources and Chevron Resources, Petro Canada and
Anderson Resources and Anadarko Canada (10 parcels in total).
4
Northrock Resources, Berkley Petroleum, International Frontier Resources, Pacific Rodera, Enron Oil and
Gas, AEC West, Renaissance Energy, Paramount Resources, Canadian Natural Resources and Anderson Resources.
5
Yukon Department of Economic Development at <http://www.economicdevelopment.gov.yk.ca/>.
1
Both Yukon and NWT contain sedimentary basins that have hardly been explored. For example, there
have been less than 100 wells ever drilled in Yukon’s eight sedimentary basins,6 and only 800 or so in
the Deh Cho region.
While the potential is there, the costs of course are high. While these costs relate primarily to physical
factors (climate, location and geology) and absence of infrastructure (both roads and pipelines) some of
these costs include the information costs of learning to deal with new lands and regulatory regimes
operated by territorial and federal governments and by aboriginal peoples (Inuvialuit and First Nation).
While considerable progress has been made in the last ten years in settling aboriginal land claims in both
Yukon and NWT, the task is not complete in either jurisdiction. Thus there are no land claim
agreements in the southern part of the NWT in the Deh Cho, the North Slave and the South Slave
areas, and some of the Yukon First Nations (especially in the prospective south east portion of the
territory) have yet to enter into final agreements. Furthermore, the settlement of claims leads to greater
complexity and diversity of regulatory regimes especially those related to land and water use and
environmental protection.
This paper provides a survey of the oil and gas rights regimes operating in Yukon and NWT. The paper
goes into most detail on the issues of continuance (i.e. moving from one form of tenure to another) and
access and benefit issues. Where possible, the paper also refers to the practice of aboriginal resource
owners. The paper does not cover the regulation of oil and gas activities pursuant to either general
conservation laws or general environmental and land and water use laws.7
6
North Coast, Old Crow, Kandik, Whitehorse Trough, Bonnet Plume, Eagle Plain, Peel Plateau, Liard Plateau.
7
Land and water management issues are discussed to some extent in a survey paper presented at the CPLF
Conference in Jasper, June 2000, Carpenter, Low and Olynyk, “Oil and Gas Developments in Western Canada in the
New Millennium: the Changing Legal Framework in the Northwest Territories, the Yukon and Offshore British
Columbia” (to be published in the Alberta Law Review).
2
The paper proceeds as follows. The first part of the paper offers some brief constitutional observations
relating to the status of the territories and the status of land claim agreements. Part 2 analyzes the
federal disposition scheme in the NWT while part 3 deals with benefits and access issues in the NWT.
Part 4 deals briefly with the rights regimes developed by the Inuvialuit and First Nations within the
NWT and Part 5 deals with the Yukon regimes. The final part offers some brief conclusions.
1.1
The constitutional context
Two aspects of the constitutional context for operations in NWT and Yukon merit attention, the first
relates to the status and law making powers of the two territories, and the second relates to the status of
modern land claim agreements.
1.1.1
The status of the territories
Let us begin with the NWT. The NWT differs from its provincial counterparts in at least two ways.
First, apart from small blocks of land within the communities that are vested in the Commissioner, title
to all public land is vested in the Crown in right of Canada for the benefit of Canada and not for the
benefit of territory.8 Furthermore, such private lands as there are are confined to lands held by the
Inuvialuit and First Nations under the terms of modern land claim agreements, and small blocks of land
within community boundaries.9
Second, the law making powers of the legislature are stipulated in s.16 of the NWT Act and not in ss.
8
In other words s.109 of the Constitution Act (and its equivalents in the later terms of union and the natural
resources transfer agreements) does not apply.
9
And oil and gas rights are reserved to the Crown on any Crown grant: Territorial Lands Act, RSC 1985, c.
T-7, s.15.
3
92 - 93 of the Constitution Act, 1867. While these law making powers are very broad and sometimes
mimic provincial heads of power,10 it is critical to appreciate that they are not exclusive powers. This
arises from the fact that Parliament’s power to make laws for the Territories arises not from the
Constitution Act, 1867 but from s.4 of the Constitution Act, 1871. In exercising its powers and
delegating law-making authority to the NWT legislature, parliament has taken care to condition its grant
of law-making powers with the words “subject to ... any other Act” (in the chapeau to s.16). As a
result, while, for example, the NWT legislature could ground an oil and gas conservation law on an
existing head of s.16, the field is fully occupied by the federal Canada Oil and Gas Operations Act
(COGOA).
The situation is very different in Yukon as a result of the Canada-Yukon Oil and Gas Accord of May
28, 1993 which was implemented by the Canada-Yukon Oil and Gas Accord Implementation Act.11
The Accord Act did three things. First, it amended the list of powers accorded to the territorial
legislature by adding a set of powers designed to mirror s.92A which was added to the Constitution
Act, 1867 in 1982.12 Second, it authorized a transfer of the administration and control of oil and gas
rights to the Commissioner for the use and benefit of Yukon.13 The actual transfer occurred by Order in
10
E.g. Northwest Territories Act, RSC 1985, c. N-27, s.16(h) property and civil rights in the Territories, and (t)
generally, all matters of a merely local or private nature in the Territories.
11
SC 1998, c.5. The case law on the implementing legislation for the east coast accords suggests that the
Courts will, if necessary, look to the Accord itself for assistance in interpreting the implementing legislation. See
Mobil Oil Canada Ltd. v. Canada-Newfoundland Offshore Petroleum Board, [1994] 1 SCR 202 esp. at 219 and St
John’s (City of) v. Canada (Canada-Newfoundland Offshore Petroleum Board, [1998] NJ 233 (SCTD). Quaere
whether it will also be legitimate to use the Accords as an aid to the interpretation of the Yukon Oil and Gas Act.
Note that s.1.1(c) of the Accord provides that the Yukon regime should establish a regime which “provides stability
and fairness, reflects standards of resource management and conservation practices in Canada, and promotes
confidence and predictability for industry.”
12
Id., s.4 adding s.17.1 to the Yukon Act.
13
Id., s.8 adding a new s.47.1 to the Yukon Act. Note that Yukon is also given jurisdiction and authority over
the “adjoining area” which consists of a small marine area beyond the limits of the Territory (which ends at the low
water mark) but landwards of a set of straight baselines drawn along the northern coast and described in id,
Schedule 1.
4
Council in November 1998.14 Third, the area of application for both COGOA and the Canada
Petroleum Resources Act (CPRA) was amended to create the space within which the territorial
government might develop and apply, not just oil and gas disposition laws, but also, oil and gas
conservation laws.15 Surface title has not been transferred to the Commissioner and thus the Territorial
Lands Act and Territorial Land Use Regulations (TLURs) continue to apply.
1.1.2
Aboriginal land claim agreements
Section 35(3) of the Constitution Act, 1982 affords constitutional protection to land claim agreements,
not only those in existence at the time of that amendment but also those to be negotiated in the future. In
addition to their constitutional status, all of the modern generation of land claim agreements have been
ratified by federal legislation which, in at least some measure, is designed to give these agreements the
force of law.16 The agreements therefore bind not just the parties to the contract or treaty but also third
parties.17 Finally, in some cases, the Crown, under the terms of the agreements, also committed to
14
PC 1998-2022, November 19, 1998.
15
SC 1998, c.5 ss.11 and 13 respectively amend the areas of application of these two federal statutes.
16
The Western Arctic (Inuvialuit) Claims Settlement Act, SC 1984, c. 24, s.3 provides that “The Agreement
is hereby approved, given effect and declared valid” and goes on to state that “On the extinguishment of the native
claims ... the beneficiaries under the Agreement shall have the rights, privileges and benefits set out in the
Agreement.” The Gwich’in Land Claim Settlement Act, SC 1992, c.53 provides that “The Agreement is hereby
approved, given effect and declared valid” followed by a “for greater certainty” provision to establish that “where
the Agreement confers on any person or body a right, privilege, benefit or power, requires any person or body to
perform a duty or subjects any person or body to a liability, that person or body may exercise the right, privilege,
benefit or power, shall perform the duty or is subject to the liability to the extent provided for by the Agreement” and
a further “for greater certainty provision” designed to ensure vesting of title in designated Sahtu organizations as
provided for in the Agreement. The Sahtu Dene and Metis Land Claim Settlement Act, S.C. 1994, c. 27, s.4 is to the
same effect. Section 6(2) of the Yukon First Nations Land Claims Settlement Act, SC 1994, c.34 simply provides that
“For greater certainty, such an agreement is binding on all persons and bodies that are not parties to it.”
17
For example s.22 of the Sahtu Agreement undoubtedly creates consultation and benefit obligations for
licensees not only with respect to both Sahtu title lands but also with respect to Crown lands within the settlement
area. For a dramatic example of the implementing legislation for a land claim agreement creating obligations or
terminating statutory privileges for third parties see Carcross\Tagish First Nation v. Canada, [2000] FCJ 318 (TD)
5
introduce further specific resource management and planning implementation legislation. In the NWT
this legislation includes the Mackenzie Valley Resource Management Act 18 and in the Yukon it
includes a new environmental assessment regime.19 In general these new statutory regimes apply to all
persons operating within the area of application of the land claim agreement and will apply to aboriginal
and non-aboriginal title lands. There is a growing body of case law dealing with the interpretation and
application of modern land claim agreements and the environmental management regimes which they
have spawned.20
In the Northwest Territories there are three relevant agreements, the Inuvialuit Final Agreement, 1984
(IFA), the Gwich’in Final Agreement, 1992 (GA) and the Sahtu Dene and Metis Agreement, 1993
(SA). While some of the provisions of the IFA apply in Yukon with respect to the Yukon North Slope,
the main land claims regime for Yukon is established by the Umbrella Final Agreement between
(the terms of s. 4 of the Yukon First Nations Land Claims Settlement Act, SC 1994, c.34 caused a loss of s. 87 Indian
Act tax exemption for all Yukon First Nation Citizens, not just those party to a Final Agreement.)
18
S.C. 1998, c.25, and see also the Mackenzie Valley Land Use Regulations, SOR/98-429. The MVRMA
defines the Mackenzie Valley so as to exclude the Inuvialuit region.
19
See Chapter 12, Development Assessment, of the Yukon Final Agreements. In the meantime the existing
environmental assessment regime of the Canadian Environmental Assessment Act, SC 1992, c.37 is grandparented,
see Vuntut Gwitchin First Nation v. Canada (Minister of Indian and Northern Affairs), [1999] 1 CNLR 299 (FCTD),
aff’d, [1999] 1 CNLR 306, application for judicial review of decisions to issue land-use permit to Northern Cross to reenter an existing well on a federal SDL denied, Justice Rouleau referring to the grandparenting effect of s.12.9.5 of the
Vuntut Gwitchin Final Agreement.
20
The case law includes Cree Regional Authority v. Canada (1991), 81 DLR (4th) 659 (FCA) and Eastmain
Band v. James Bay and Northern Quebec Agreement (Administrator) (1992), 99 DLR (4th) 16; Nunavut Tunngavik
Inc. v. Canada (Minister of Fisheries and Oceans) (1998), 162 DLR (4th) 625 (FCA) and Nunavut Tunngavik Inc. v.
Canada (Minister of Fisheries and Oceans), [1999] FCJ 493 (TD), aff’d by Federal Court of Appeal, oral reasons
delivered from the bench October 17, 2000. The NTI cases support the view that the land claim agreements may
constrain discretionary powers in general statutes (in this case the Fisheries Act); Qikiqtani Inuit Association v. AG
Canada as representative of The Minister of Indian Affairs and Northern Development and Nanisvik Mines Ltd.
[1999] 3 CNLR 213 (FCTD) (judicial review application of the first licensing decision of the Nunavut Water Board).
An infringement of a modern land claim agreement may be saved if it can meet the justification test developed by the
Supreme Court in R. v. Sparrow, [1990] 1 SCR 1075 and applied in the context of treaties in R. v. Badger, [1996] 1 SCR
771, Campbell v. British Columbia (Attorney General) [2000] BCJ 1524 (SC).
6
Canada, Yukon and the Council of Yukon First Nations. This Agreement establishes the basic template
for each of the individual First Nation Final Agreements in Yukon. At the time of writing seven First
Nations have concluded Final Agreements. They are as follows: Vuntut Gwitchin, the Champagne and
Aisihik First Nations, the Teslin Tlingit Council, Nacho Nyak Dun, the Little Salmon/Carmacks First
Nation, the Selkirk First Nation and the Tr’ondek Hwech’in First Nation.
These agreements all provide that the Inuvialuit or First Nation shall have title to selected lands, some as
to surface title only and some including the subsurface title. However, such lands are not enclaves within
the territories. Indeed, all of the agreements negotiated to date stipulate two things. First, that the lands
are not “lands reserved for Indians” within the meaning of s.91(24) of the Constitution Act, 186721 nor
reserves within the meaning of the Indian Act and, second, that, subject to the terms of the agreement,
all federal and territorial laws of general application will apply to the aboriginal lands.22 Inconsistent
provisions will not apply. It is this these two provisions that allows us to say, for example, that federal
oil and gas conservation legislation will apply on Inuvialuit, Gwich’in and Sahtu lands and that, equally,
federal disposition legislation will not apply to subsurface lands held by these First Nations or the
Inuvialuit.
There is one caveat with respect to this last point and it relates to self-government. In the case of
Yukon, the settlements of First Nation claims within the framework established by Umbrella Final
Agreement (UFA) have each been accompanied by self-government agreements (SGAs).23 The SGAs
contemplate that First Nations may make laws in relation to a large range of matters including the use
and management of settlement lands. The agreements go on to provide that such First Nation laws may
21
SFA s.3.1.8
22
SFA, s.3.1.21
23
See for example the Champagne and Aishihik First Nations Self-Government Agreement, May 29, 1993 and
see also Yukon First Nations Self-Government Act, SC 1994, c.35.
7
displace territorial laws of general application (s.13.5.3). This would allow, for example, a First Nation
to pass its own oil and gas conservation law that would displace the relevant Yukon law.
We have yet to see the final results of self-government negotiations in the NWT. In some areas of the
NWT there are on-going negotiations with at least some of the First Nations with outstanding title
claims and these negotiations include negotiations on self-government.24 The existing land claim
agreements all contain provisions contemplating further negotiations on self-government (SA, Chapter 5
and Appendix B, GA, Chapter 5 and Appendix B, and IFA, s.4(3))
2.0
The federal oil and gas regime in the Northwest Territories
This part of the paper reviews the federal Crown’s oil and gas disposition scheme under the Canada
Petroleum Resources Act (CPRA). This Act applies to oil and gas resources in NWT that are still
vested in the federal Crown for the benefit of Canada.
2.1
The CPRA Regime
The basic CPRA regime dates back to 1986.25 The CPRA, introduced by the then federal
conservative administration, swept away the Canada Oil and Gas Act (COGA)26 which had entered
into force in 1982 as part of the National Energy Program. It is, I think, worthwhile recalling some of
the more important changes that the CPRA made to COGA on the basis that those who do not learn
the lessons of history are doomed to repeat them. The CPRA did the following: (1) it abolished
24
See the Dogrib Agreement in Principle, initialed August 9, 1999.
25
SC 1986, c.45, continued as RSC 1985, (2nd Supp), c.36.
26
SC 1980, 81-82, c.81. On COGA generally see Hunt, “Management of Federal Petroleum Lands In Canada”
in Saunders (ed), Managing Natural Resources in a Federal State, 1986
8
retrospectively as well as prospectively the Crown share, as well as any special back-in rights held by
Petro-Canada as a Crown corporation, 27 (2) it shifted the royalty regime out of the Act and put it in the
regulations and, when once introduced, the regulations provided a fiscal regime that was considerably
less onerous than that established by COGA, (3) it restored the freedom of interest holders to transfer
their interests without seeking the consent of the Minister and it relaxed and ultimately removed28
serious restrictions on the ownership of production rights by non-Canadians, and, (4) it considerably
circumscribed the discretion retained by the Minister in his or her administration of the Act. We shall
return to this last point momentarily but we can see this change revealed in such things as the insistence
upon a single bid variable for the issuance of rights as well as the administrative review proceedings
included in the new CPRA. This latter trend was reinforced by the transfer of certain administrative
responsibilities from the Canada Oil and Gas Lands Administration to the National Energy Board
(NEB) in 1994.29
2.2
Grandparenting of rights under the CPRA
It will be recalled that, for the most part, COGA forced rights holders under the old Canada Oil and
Gas Land Regulations to convert their interests into new exploration agreements under COGA with
significant work obligations and relinquishment provisions. A limited number of rights holders were
grandparented through. These included Imperial’s Norman Wells property operating under the terms of
the 1944 Proven Area Agreement as well as leases that were actually producing at the time, or on
27
See Hunt, “The Impact of Crown Interests upon Private Sector Rights and Remedies: The Case of the
Canadian Oil and Gas Industry” in Bankes and Saunders (eds), Public Disposition of Natural Resources, 1983.
Inuvialuit rights under the IFA to succeed to the Crown’s share were, however, fully protected: CPRA, s.117(2).
28
SC 1993, c.47.
29
SC 1994, c.10
9
which a discovery well had already been drilled.30 All of these rights, as well as newer rights created
under COGA, were further grandparented through under the terms of the CPRA.31
2.3
Forms of tenure and available methods of disposition
The CPRA established an unusual three stage tenure scheme: an exploration licence (EL), a significant
discovery licence (SDL) and a production licence (PL).32 The main reason for the introduction of the
intermediate SDL was to provide a secure tenure form for those licensees that had made a significant
discovery but were unable to proceed to production because of the absence of infrastructure or
because of project economics.
Under the CPRA, the Minister, with only minor exceptions, may only grant interests in Crown reserve
lands (lands in respect of which no interest is in force) pursuant to a call for bids.33 Subject to preconditions referred to below, the Minister may issue a gazetted call for bids for any of the three forms of
tenure. A call for bids (in practice preceded by a call for nominations) must, in addition to other terms
and conditions, specify (s.14(3)(g)) “the sole criterion that the Minister will apply in assessing bids
submitted in response to the call.” The Minister is not required to issue an interest as a result of a call
30
Supra note 25, ss.62 - 72. The federal crown has a 5% gross royalty and a one third net profit interest in
the Norman Wells property.
31
CPRA, ss.110 - 117.
32
Unlike the two stage tenure scheme that prevailed under COGA and provincial regimes. Interests under
the CPRA are effectively subject to partition by the interest holders. This arises from the definition of “share” and
the language of s.23 which permits an EL to be held with respect to a portion of the lands. The owner of such a
divided share has some distinct rights including the right to make a separate SDL application. I think that the
rationale for this provision goes back to the roll-over of interest from the old oil and gas land regulations to COGA
when separate interest holders were forced to negotiate, as a block, a single new EA. Some interest holders wanted
to take their interest as a divided interest rather than as undivided interest in the whole.
33
CPRA ss. 13 and 14. Section 17 refers to some minor exceptions; exchange of interests and interests and
interests that “through error or inadvertence, become Crown reserve lands.” Even in such cases there is still a duty
to publish notice of an intention to issue such an interest.
10
for bids but if s/he does so, s/he must gazette the terms and conditions of the interest.
To date, all northern calls have proceeded on the basis of work commitments as the single bidding
variable using a scale issued by the Department for valuing different types of work.
Before issuing a call for bids the Department (i.e. the Northern Oil and Gas Directorate) consults with
affected interests including First Nations and Inuvialuit. In areas of settled claims consultation or
notification may be required by a land claim agreements (see Part 3 of the paper). In areas where land
claims have yet to be settled, consultation will be required by the Supreme Court decisions on
aboriginal rights and aboriginal title.34 As a matter of practice, the Department will not issue a call for
nominations or bids in an area of unsettled claims without the support of the local communities. Thus,
while the Fort Liard community supported the issuance of new lands in that area of the Deh Cho and
supported two rounds of bidding in 1994 (8 ELs for 149, 817 hectares) and 1995 (6 ELs for 145, 257
hectares), there has been no rights issuance since then in that region notwithstanding significant and
continuing industry interest due to the important discoveries in the area.
2.4
The Exploration Licence
An exploration licence may be granted for a term that shall not exceed nine years. An EL may not be
renewed or extended beyond that term (s.26(2)), except where the licensee is drilling over, in which
case the interest is maintained “for so long thereafter as may be necessary to determine the existence of
34
Where title is at issue see Delgamuukw v. The Queen in Right of B.C. (1997), 135 DLR (4th) 194 (SCC) esp.
at paras 165 - 169. In the specific context of SW NWT see Liidlii Kue First Nation v. Canada (Attorney General),
[2000] FCJ 1176. Where aboriginal or treaty rights are at issue see Halfway River First Nation v. British Columbia
(Ministry of Forests) (1999), 64 BCLR (3d) 206 (CA), and, in the case of well licensing decisions see Kelly Lake Cree
Nation v. British Columbia, [1999] 3 CNLR 126 (BCSC). It is not always clear when the duty to consult crystalizes.
Does it first require proof or acceptance of a right or title and an infringement? The relevant cases are discussed in a
recent paper by Hunter, “Consultation with First Nations[:] When does the obligation arise?” paper prepared for
Canadian Aboriginal Law 2000 Conference hosted by Pacific Business and La Institute, October 19th and 20th, 2000.
11
a significant discovery based on the results of that well” (s.27).35 The general practice is to issue
licences for the full nine years in the Beaufort Sea\Delta region and for slightly shorter periods further
south36 and to divide the full term into two periods. The work commitment is related to the first period
of the licence. The requirement of drilling a commitment well of sufficient depth to evaluate a
prospective horizon is framed as a condition precedent to obtain tenure for the second period. Failure
to drill a well within the first period (plus allowed time for diligent drilling over) will result in reversion of
the lands to the Crown. The EL does not contain further relinquishment provisions unlike the procedure
followed in the early days of COGA. However, if the licensee does not apply for and obtain a PL or an
SDL within the term of the EL, the EL (or the balance of the EL) will automatically revert to the Crown
at the end of the term, subject of course to continuance by diligent drilling over and pending
consideration of the DSD application.37
35
A purposive interpretation suggests that the interest will be continued until the licensee has had the
opportunity to apply for a declaration of significant discovery and have issued to it an SDL. Section s.26(2)
governing maximum term is expressly stated to be subject to s.27. Section 12(3) provides for the extension of
interests and relief from obligations but only on specified grounds (international boundary disputes, serious
environmental or social problems and dangerous or extreme weather conditions) and on the basis of order in council
prohibiting work. The National Energy Board, Guidance Notes for Applicants; Applications for Declarations of
Significant Discovery and Commercial Discovery, January 1997 states at 3 that following receipt of a DSD application
the NEB will inform the relevant Department so that “if appropriate” that Department “can arrange for the existing
licence to remain in force during the examination by the NEB of the application.” That the point is far from academic
is suggested by the Newfoundland Offshore Board’s decision in respect of the East Rankin DSD Application,
October 27, 1994 in which the Board noted as follows (at 3) “Pursuant to an ... an agreement ... between the interest
owners and the Board, ELs 193 and 288 were amended so that the four sections within EL 293 to which the
application for a DSD referred were transferred to EL 288. This was done to ensure that those four sections would
not revert to Crown reserve status had EL 293 expired in the interim.” The difficult case is clearly the situation in
which the well has been drilled and completed before EL expiry for in my view the classical drilling-over problem is
adequately dealt with by ss.26(2) and 27(1).
36
Central Mackenzie Call, 2000, 8 years; Beaufort Call, 1999, 2000, 9 years.
37
CPRA, s.26(6). And see note 35. This a statutory and automatic forfeiture as against which the courts
have no power to relieve: Martin Mine v. R (1985), 62 BCLR 107 (BCCA). In a free mining context the consequences
of a statutory forfeiture are dire; less so in the petroleum context since no third party may obtain rights without a
new bidding round but one can imagine situations in which a First Nation with an unextinguished title might have a
sufficient interest to contest the continued validity of an EL.
12
The EL grants the licensee the non-exclusive right to explore for oil and gas and the exclusive rights to
drill a well, test for petroleum, to develop the lands to produce petroleum and the exclusive right to
obtain a PL. The precise status of the licence remains unclear. Certainly the EL must, despite the label
of “licence”, represent a contract between the Crown and the explorer.38 Whether or not the interest
amounts to an interest in land is much more debatable. Since the EL itself carries no right of production
it cannot qualify as a statutory profit a prendre unlike the PL or the Alberta Crown lease.39 However,
it is entirely possible40 that the Courts would classify the EL as an interest in land, either on the basis
that it is a sui generis interest, or on the basis that a production licence is an interest in land in the form
of a profit a prendre and that the EL represents, at the very least, an option to acquire a PL provided
that the licensee can fulfil certain conditions precedent. The ability to fulfil these conditions, unlike the
contingencies associated with a right of first refusal,41 lies with the licensee and should be susceptible of
objective verification.
2.5
The Pre-condition for an SDL, the Declaration of Significant Discovery
Section 30 of the CPRA tells us that an SDL may be issued in one of two ways but in either case the
SDL can only be issued with respect to lands in respect of which there is a declaration of significant
discovery in force. The legislation originally reserved the responsibility to issue a DSD to the Minister.42
38
This is borne out by the standard form licence, the bidding documents and s.24.1 of the CPRA.
39
St. Lawrence Petroleum Ltd. v. Bailey Selburn Oil and Gas Ltd, [1963] SCR 482 and see the discussion by
the Appellate Division in Alberta (1962), 41 WWR 210.
40
Contra, Van Penick, “Legal Framework in the Canada Offshore” paper present to the CPLF East Coast
Seminar, September 2000; and see also Vandergrift v. Coseka Resources Ltd. (1989), 67 Alta. L. R. (2d) 17 at 30 (QB)
(dealing with an Alberta Crown natural gas licence).
41
Canadian Long Island Petroleums v. Irving Industries, [1975]2 SCR 715.
42
The full procedure envisaged using the provisions which are still used in s.106 for decisions under ss.33,
36 and 105 of the Act. The critical change that was effected by the 1994 amendments was not so much the
substitution of the NEB for the Oil and Gas Committee but the substitution of the NEB for the Minister.
13
This responsibility was transferred to the National Energy Board in 199443 along with the responsibility
to hold any hearings and to consider any objections either to the issuance of the DSD or as to its areal
extent. As a result, it is quite clear that the DSD decision is intended to be a technical decision with no
opportunity at the political level to second-guess the technical advice.44 A complete picture of the DSD
process can only be obtained by considering the relevant provisions of both the NEBA and the CPRA.
Of all the decisions to be made under the CPRA, it is this “continuance” decision that is likely to be the
most contentious for there are significant interests at stake. A refusal to grant a DSD or a decision to
reduce the area claimed for a DSD will result in the reversion of the excluded areas to the Crown. 45 In
many jurisdictions this type of decision is retained within government rather than being accorded to an
independent board like the NEB, and the relevant statutory language in those jurisdictions is framed in
more subjective and discretionary terms than we see in the CPRA.46 In those jurisdictions, the
discretionary language and the technical nature of the decisions require a reviewing court to accord the
decision-maker a high degree of deference thus making it impractical to seek judicial review except in
the most egregious circumstances.47
43
SC 1994, c.10.
44
The s.106 scheme (see discussion below) differs from the current scheme insofar as under the s.106
scheme the Committee’s jurisdiction is confined to making a recommendation to the Minister. Under the Accord
legislation the Committee still makes a recommendation to the Offshore Board.
45
The countervailing argument for any proposal to accord a generous interpretation to the applicant on the
basis of the significant interests that it has a stake will be based on public policy grounds, i.e. an overly broad DSD
determination might have the effect of postponing further drilling by the licensee and exclude all other companies
from similar exploration: see Oil and Gas Committee, PetroCanada East Rankin Application, April 1992, at 11.
46
See e.g. Petroleum and Natural Gas Act, RSBC 1996, c.361, ss. 52 and 53 and Alberta Mines and Minerals
Act, Petroleum and Natural Gas Tenure Regulations, Alta. Reg. 263/97 and see in particular the definitions of
“producing well” and “productive” and ss.14 et seq., esp s.15(1)(e). In Alberta we can see that the procedural
protections accorded to lessees have become more extensive over time and include opportunities for notice and
objection.
47
One of the very few examples where a claim was launched is R. v. Industrial Coal and Minerals, [1979] 5
WWR 103 (Alta. App. Div), rev’g [1977] 4 WWR 35, application for judicial review denied.
14
While these provisions of the CPRA have not yet been the subject of judicial comment, the companion
provisions of the Atlantic Accord Act 48 have been, and while care must be taken in using the Accord
precedents (since the review structures are not quite parallel), we can learn some lessons from that
jurisprudence. In addition, both the NEB and the two Offshore Boards have issued guidance notes in
one form or another49 and at least some of the relevant decisions are available for public review.
2.5.1
Substantive Requirements for a DSD
Section 28(1) of the CPRA indicates that “where a significant discovery has been made” on lands that
are the subject of an interest or a share of an interest, the interest holder may apply to the Board for a
DSD. The Board, following the procedures laid out in NEBA, “shall ... make a declaration of significant
discovery in relation to those frontier lands in respect of which there are reasonable grounds to believe
that the significant discovery may extend” (CPRA, s.28(1)). The phrase “significant discovery” is
defined by s.1 to mean “a discovery indicated by the first well on a geological feature that demonstrates
by flow testing the existing 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.”
There have been several contentious cases testing the application of this definition. Some cases have
revolved around the question of whether or not there has been a discovery within the meaning of the
definition, while other disputes have focused upon the areal extent of the discovery. The definition has
proven difficult to apply but it seems to contain two basic elements or tests:
48
Canada- Newfoundland Atlantic Accord Implementation Act, SC 1987, c.3.
49
NEB, Guidance Notes, supra note 35; CNOPB, Procedures Regarding Applications for Significant and
Commercial Discovery Declarations and Amendments, and Criteria for a Significant or Commercial Discovery
Declaration; CNSOPB, Memorandum Respecting Board Procedure Applicable to Applications for DSDs and DCDs
and Memorandum Respecting Board Review Criteria Applicable to Applications for DSDs and DCDs.
15
C
first, there must be a discovery50 indicated by the first well51 on a geological feature52 which
discovery well demonstrates by flow testing the existence of mobile53 hydrocarbons in that
geological feature, and
C
second, the discovery well, together with geological and engineering factors, suggests the
existence of an accumulation of hydrocarbons that has potential for sustained production.
The italics serve to identify the three separate verbs contained within the definition. We should also
observe that the second element or test will need to be used for two purposes. It will form part and
parcel of the determination of the existence of a significant discovery, but it will also be relevant to
determining the areal extent of the discovery. The areal extent of the discovery is of course a requisite
part of the declaration that must be made in accordance with s.28(1) of the CPRA, i.e. “those frontier
lands in respect of which there are reasonable grounds to believe that the discovery may extend.”
The concept of an areal extent raises the question of whether a DSD can, should, or must be limited to
particular zones. The practice of both the Department formerly and now of the NEB is simply to
describe the relevant sections of frontier lands to which the discovery relates. The DSD does not
identify particular zones and as a result the DSD must apply to all the frontier lands contained within the
description (i.e. down to the basement). In my view there is nothing inevitable about this conclusion and
indeed arguably it flies in the face of the actual language of s.28(1) which contemplates a discovery only
in relation to those frontier lands for which there are reasonable grounds to believe that the discovery
50
Mobil Oil Canada Ltd, supra note 11 at 218: “a ‘significant discovery’ is, first and foremost a
‘discovery’”.
51
Id., at 218 “first and only well”; see further discussion, infra.
52
The term “geological feature” is not a defined or a precise term. It does allow for some margin of
appreciation. See Oil and Gas Committee Report on Esso Minuk I-53, January 9, 1991 at 10.
53
East Rankin Oil and Gas Committee Report, supra, note 34 suggesting that flow testing requires mobility.
16
may extend.54
2.5.1.1
Disputes as to the existence of a significant discovery
In at least two cases under the Accord Act, the initial decision of the Offshore Board was to reject the
application completely. One of those decisions (East Rankin) was reversed by the Offshore Board
following the recommendations of the Oil and Gas Committee. The second decision (King’s Cove) was
confirmed by the Committee but the final Board decision was subsequently quashed on a judicial
review application before Justice Barry of the Newfoundland Supreme Court in Petro-Canada v.
Canada-Newfoundland Offshore Petroleum Board55. I shall deal first with the King’s Cove case.
Petro-Canada (PC) had drilled the King’s Cove Well in 1990 and drillstem testing produced
insignificant quantities of hydrocarbons. The Board, having followed the procedure laid out in the
Accord Act, accepted the Committee recommendation and rejected the application. PC sought judicial
review alleging, inter alia, errors of law in the way in which the Board had interpreted the definition of
significant discovery by setting the standard of proof too high. Justice Barry, after referring to the
Board’s treatment of the evidence, commented at length as follows:
It is a reasonable inference ... that the committee and the board were, at least at times,
requiring the applicants to prove, on a preponderance of probabilities, a likelihood of
sustained production rather than just a potential. That is not what s.47 [CPRA, s.1]
requires. That section only requires the applicants to establish that information on their
well “suggests” the “potential” for sustained production of hydrocarbons. Webster’s
... defines “suggest” as “to bring to one’s mind by association of ideas”. It defines
54
The only party with an interest in articulating this position is of course the Crown. It is clear that once a
DSD has been issued describing lands down to the basement, an SDL must be issued for all of the SDL lands
contained within the original EL.
55
(1995), 127 DLR (4th) 483 (Newf. S.C.).
17
“potential” as “possibility; powers or resources not yet developed”. It defines
“possibility” as “that which may be possible; a contingency” and “possible” as “not
contrary to the nature of things; that may be or happen; that may be done,
practicable”. 56
....
The standard of “reasonable grounds”, found also in s.70(1) [CPRA, s.28(1)] means,
however, that the board need not accept purely speculative submissions by the
applicants, that is, those ungrounded in factual data and scientific theory. But there is a
difference between pure speculation and hypothetical submissions. The committee did
not always expressly draw that distinction. For example, it treated projections of
deliverability performance using assumed reservoir properties as inadequate because
“they must be considered purely hypothetical”.
Justice Barry went on to say that the Offshore Board must review data, hypotheses and theories
presented by the applicant and must
... expressly explain why it is left with no “suggestion” of a “potential” for sustained
production ... If the board is left with reasonable grounds ... that is, grounds based upon
unrefuted data, hypotheses and theories, the applicant should obtain a declaration of
significant discovery.
Barry J. went on to conclude that the Board had addressed itself to the wrong question and thereby
committed an error of law. This was “an interpretation which the words in the statute cannot reasonably
bear and, whether the test is correctness or unreasonableness is a ground for setting aside the board’s
decision.”57
Justice Barry did however agree with the Board that it was entitled to consider the question of
economics “and therefore of the volume of recoverable oil” in making its decision and that this was not
56
Id., at 500.
57
Id., at 507
18
a matter that was relevant only to a declaration of commercial discovery. He expressly endorsed the
conclusion that “In a broad sense, evidence is required to suggest that the feature is of sufficient
magnitude and quality to hold reasonable promise of continuous production of a volume to warrant the
effort of producing it.”58
In the second case, the East Rankin DSD application, the Board, as already mentioned, ultimately
accepted the Committee’s recommendation to grant a DSD. In the course of its report the Committee
offered some useful observations on the definition of a significant discovery. First, with respect to the
flow testing requirement, the Committee noted that while flow-testing is the only permissible means of
testing the existence of hydrocarbons:59
... there is no stipulation ...as to the magnitude of the flow in either volume or rate, nor is
there a stipulation that would preclude the presence of other fluids - such as formation
water - entering the wellbore in conjunction with the hydrocarbons.
Second, the Committee suggested that flow testing did not require production at the surface. Instead
they suggested that the Act contemplated the “flow of reservoir fluids into the wellbore, and towards
the surface which, dependent on strength and duration, could allow sampling of fluids and monitoring of
reservoir flow characteristics at the bottom of the well, at the surface, or both.”60 In light of these
interpretations the Committee concluded, despite interpretive difficulties, that a DST that resulted in the
flow of some 1.75 cubic meters of reservoir oil over an 8 hour period met the first branch of the
statutory test.
58
Id., at 510 expressly endorsing the Committee’s approach in the next case we shall look at, the East Rankin
DSD.
59
Report and Recommendation of the Oil and Gas Committee, Petro Canada East Rankin, H-21, SDA
Application, April 1992, i.e. the statutory definition precluded use of coring or wellbore logging or high resolution
seismic (at 13).
60
Id., at 14.
19
Third, in considering the second part of the test, the Committee asked itself the following question:61
Is flow testing to be used only to demonstrate the existence of mobile hydrocarbons?
Or is flow testing also to be used in suggesting sustained production potential? If so,
what weight should be given to other factors of a geological or engineering nature when
assessing the potential for sustained production?
In its conclusions the Committee emphasized the importance of a sound geological model to link
observed wellbore geology with continuation of reservoir sediments and to suggest potential for
sustained production. The Board subsequently agreed with these observations.
2.5.1.2
Disputes as to areal extent
Equally if not more contentious has been the question of the areal extent of a DSD. This too has been
the subject of litigation in Mobil Oil Canada Ltd. v. Canada-Newfoundland Offshore Petroleum
Board.62 The facts here involved a discovery well originally drilled in 1982 on an exploration licence
issued under the terms of COGA. Mobil and partners sought a DSD for the discovery well and 41
surrounding sections. The Department advised issuance of a 14 section DSD. Following Mobil’s
revised application for 30 sections and further review by the Department recommending an 11 section
DSD, the Minister issued a DSD for those 11 sections. Mobil unsuccessfully sought judicial review
under the old Act.63
There was no further well drilled on the block but, upon proclamation of the Accord legislation, Mobil
commenced a new DSD application. This application was summarily dismissed by the chair of the
61
Id., at 9.
62
Supra, note 11.
63
Mobil Oil Canada Ltd. v. Canada (Minister of Energy, Mines and Resources) (1990), 35 FTR 50.
20
Board who refused to put the matter before the full Board and accordingly declined also to allow Mobil
to put its arguments to the Oil and Gas Committee. The matter ultimately reached the Supreme Court of
Canada. The unanimous decision of Justice Iacobucci for the full court concluded that the Board had
erred by failing to accord Mobil the right to make its submission to the full Board. However, the Court
did uphold the Chair’s decision on the grounds that it decision was so obviously correct that nothing
would be served by sending the matter back to the Board.64 The decision stands as authority for the
propositions that a particular geological feature can only support one significant discovery and that the
only way to expand the areal extent of a DSD, once made, is by drilling a further well as contemplated
by what in our case is s.28(4) of the CPRA.
Two other decisions with respect to applications from Imperial Oil for Beaufort Sea structures illustrate
both the difficulties inherent in making these types of declarations but perhaps also the effects of
insulating technical decisions from political review. One decision was made by the Minister following Oil
and Gas Committee Review and the second was made by the NEB under the current provisions of
NEBA and the CPRA.
The first decision was with respect to Imperial’s application for the Minuk I-53 well.65 This application
was considered on the basis of the CPRA as it stood before the 1994 amendments transferred the
DSD jurisdiction to the NEB. The Minister originally proposed to limit the DSD to 10 sections and
Imperial sought a hearing before the Oil and Gas Committee seeking inclusion of some 17 sections.
Essentially the points of contention were as to whether: (1) a gas bearing zone extended to a separate
fault block within the feature, and (2) an untested zone in the well was part of a wedge of sediments that
64
The Court also held, supra, note 11 that (at 223) the matter need not have been referred to the Committee
since the Committee’s jurisdiction was confined to technical matters and this was not a technical matter but simply a
question of the proper interpretation of the statute.
65
Supra, note 52.
21
were of reservoir quality and containing hydrocarbons.
The Committee took the view (at 8 and 9) that it was not necessary for an applicant to have flow-tested
a zone on a geological feature before that zone could be included in considering the reasonable areal
extent of a DSD. Had that been the intent, the Committee opined, it would have been easy for the
legislation to have been so worded. The Committee also took the view that an applicant might be able
to adduce technical evidence to establish reasonable grounds for concluding that separate fault blocks,
even if not in communication with the fault block on which the discovery well was drilled, might contain
hydrocarbon accumulations. As a result of its review, the Committee recommended including a further
4 sections within the DSD.
However, the Minister clearly preferred to accept the advice of the Department, based primarily, and
interestingly enough, upon its interpretation of the CPRA rather than upon a technical difference of
opinion. The Department emphasized that a DSD should be limited to that part of a zone in which flow
testing had occurred to demonstrate the existence of hydrocarbons and should include other parts of
the same zone in communication with the tested part and as to which geological and engineering factors
suggests the accumulation of hydrocarbons extends. It should exclude “all portions of the geological
feature which fall outside those zones or are fault-separated from those zones, i.e. areas which are not
in communication with the flow tested area.”66 It would obviously still be open to the Crown, as owner,
to articulate this interpretation of the legislation but it would now be forced to do so by making
representations to the NEB as a directly affected party and ultimately by applying to the Federal Court
of Appeal alleging a jurisdictional error or an error of law.67
A second application from Imperial in respect of the Nipterk P-32 well was put on hold pending the
66
Letter to the author from Mimi Fortier, Northern Oil and Gas Directorate, June 10, 1996.
67
See below for the discussion of procedure.
22
outcome of the Minuk application (the Minister’s decision on Minuk was issued July 11, 1994) and
when it was brought forward, responsibility for DSD matters had already been transferred to the
NEB. 68 Once again, the only issue was that of areal extent. One of the issues that the Board had to
consider was whether the existence of numerous faults across the Nipterk anticline suggested
compartmentalization into discrete traps or whether the traps might be in communication because of
sand contact points above the water contact. The Board had this to say:69
In determining the areal extent of a significant discovery, where the contact points
across a fault occur above the water contact and the sand is of good reservoir quality
for the migration of hydrocarbons, the Board generally assumes that the accumulation is
in a single structure separated by a fault. Based on this approach, the two parts of the
structure would be in communication and the SDA can reasonably be considered to
encompass the entire structure.
While the formal part of the decision is framed in terms of “reasonable grounds”, the decision contains
several indications that the Board was giving Imperial the benefits of any doubts. Thus in deciding
whether to include one zone within the DSD determination the Board (at 2) referred to “the possibility”
that the sands would improve thereby making the structure capable of sustained flow and in the
concluding part of its decision the Board noted that the benefit of any doubt had been given to Imperial
on a whole range of issues.
In conclusion, it seems fair to observe that the Courts, the Committee and the NEB approach the
determination of the existence and areal extent of a DSD with a very firm view of the “final effect” of
denying a DSD application and the significant effect that denial may have on an interest owner’s
68
National Energy Board, Report Regarding South Nipterk DSD, Imperial Oil Limited - Application Dated
March 1991, (Amendment March 1992). Report issued in Draft 30 April 1998; finalized without amendment June 12,
1998.
69
Id., at 2 to 3.
23
investment. As a result, the prevailing interpretation of the requirements of the CPRA emphasizes the
low thresholds that an applicant must meet and offers the benefit of any doubt to the applicants.
Furthermore, the removal of the Minister from the process means that technical persons are now
making the final decisions on technical grounds based solely on the evidence adduced before them
rather than simply making a recommendation to a Minister who may advert to more general
conceptions of the public interest in making his or her decision. Indeed, under the current procedure,
there is really no person who will be arguing for a more restricted interpretation of the DSD. The
Minister might have an interest in doing so but while no doubt a directly affected party, he or she will
not be privy to the data on which the application was based.
2.5.2
Procedural Requirements and Protections
The procedure for obtaining a DSD is complex and unique. Section 28(1) of the CPRA contemplates
that the NEB may prescribe the manner and form of an application and the information to be provided.
The Board’s Guidance Notes70 indicate that the applicant must establish its title to commence the
application and should, in general, provide all the data and interpretations in support of its contention
that the well has made a significant discovery and as to the areal extent of that discovery. The data may
include petro physical and lithological descriptions, flow test information, velocity maps, interpreted and
uninterpreted seismic sections and analysis and geological argument and supporting data and
interpretations. The applicant is also invited to identify “the related interests, and interest holders” and to
comment on whom else “would be directly affected by the decision.” The latter is important because
s.28.2 of NEBA requires that the Board,
At least thirty days before making a decision ... shall ... give written notice of its
intention to make the decision to any person the Board considers to be directly affected
70
Supra, note 34.
24
by the decision.
The Board has interpreted the phrase “directly affected” rather narrowly. 71 The question of who may be
a “directly affected” party is proving contentious in the analogous situation of the declaration of
commercial discovery in respect of Chevron’s Liard K-29 gas well. The NEB proposed to issue the
DCD for an area that covers some but not all of the area covered by Chevron’s SDL as well as some
additional areas. None of the notified parties sought a hearing and the NEB issued the DCD on January
5, 2000. Canadian Forest Oil (CFO) held an interest in EL 363 immediately adjacent to SDL 99 and
on its northern boundary. CFO did not receive notice of the Board’s intention to grant the DSD since
the Board did not consider CFO to be directly affected. CFO took a different view and accordingly
commenced an application for leave to appeal questioning both the Board’s determination that CFO
was not a directly affected party and also the NEB’s determination as to the areal extent of the DCD.
The application has yet to be heard although we do have a decision from the Federal Court of Appeal
on an interim matter related to a claim to confidentiality with respect to technical material provided by
Chevron in support of its application.72
71
See para. 4.5 of the guidance notes, supra, note 35. The notes indicate that the a person should have “a
direct or related stake” and that the Board will notify the applicant and others who already qualify as directly
affected if it views others as directly affected. This is not unimportant since the draft decision itself may contain
confidential information that an applicant may seek to protect. See Transcript of Pre-hearing Conference re Ranger
Oil Ltd, DSD Application, October 6, 1999 at Q484 Board indicating that First Nations not considered to be directly
affected in the absence of an adjacent EL, and at Q367 - 372 where all three interested parties indicated that the
Board’s draft decision should be treated as confidential. Note however that in at least some cases the NEB has
issued a press release indicating its intention to make a decision and making the report generally available; see News
Release 98\17 re Imperial Oil South Nipterk DSD application.
72
Canadian Forest Oil Ltd. v. Chevron Canada Resources and Ranger Oil Ltd, [2000] FCJ 963 (FCA). CFO
had commenced its application and the Board argued that it could not provide as part of the record information
supplied by Chevron in support of its DCD application because of s.101 of the CPRA. The court ruled that the
information should be provided because it fell within the exception of s.101(3) which allowed confidential material to
be divulged if in relation to “proceedings relating to the administration or enforcement” of NEBA or the CPRA. The
court however did give Chevron the opportunity to apply under Rule 151 of the Federal Court Rules for an
appropriate order seeking to maintain the confidentiality of the information. The appropriate application was made
and the order made by the Federal Court October 18, 2000 allowing counsel for CFO and one approved advisor to
have access to the material on terms. Thanks to Peter Noonan, Counsel NEB for providing me with a copy of the
order.
25
The Board’s consideration of the initial application is carried out by an investigative panel of the Board.
If the matter proceeds beyond that point and an affected party seeks a hearing, the Board will appoint a
separate adjudicative panel. Any person who has received notice may, within 30 days, request a
hearing and the Board is obliged in such event to hold a hearing and to provide notification to and to
allow “each person who requests a hearing”73 to make representations and introduce witnesses and
documents. Thus far the Board has only had one application that has proceeded to a hearing. The
conduct of that hearing in respect of a DSD application from Ranger Oil raised significant complexities
because of the confidentiality of the information as to which not all interested persons were privy. As a
result of a prehearing conference the Board issued a hearing order74 indicating that it would conduct a
partitioned75 in-camera hearing of the objections to the proposed declaration after which the Board
would make its decision, which decision would be made public.
Following the hearing, the Board must make its decision and give notice of the decision to any person
who requested the hearing and, if such a person requests reasons, publish or make available the
reasons for the decision (NEBA, s.28.2(7)). Board decisions are subject to judicial review in the form
of an appeal, with leave, to the Federal Court of Appeal (NEBA s.22) on a question of law or
jurisdiction. The Board’s usual powers to review its own decisions under s.21 of NEBA do not apply,
presumably because the procedure for revocation or amendment is dealt with specifically in the CPRA.
2.5.3
Amendment or Revocation of a DSD
73
Presumably the Board must have a discretion to hear other persons as well for otherwise we might have
the anomalous situation of an adjacent owner seeking a hearing while the applicant was content to rest with the draft
decision and therefore not accorded standing at the hearing as of right.
74
MH-5-99.
75
I.e. each party would have the opportunity to appear before the Board in camera, present its witnesses for
examination by the Board and make oral submissions. The other parties would not have the opportunity to cross
examine. At the pre-hearing conference, supra, note 71, several options were discussed before the group settled by
consensus on this manner of proceeding.
26
“Based on the results of further drilling” a DSD may be revoked, increased in size or decreased in size
by decision of the Board where there are reasonable grounds for doing so (s.28). The procedure to be
followed is the same as for the initial application.
2.5.4
Issuance of the SDL
As stated above, an SDL may be issued in one of two ways for lands in respect of which a DSD exists.
First, and most obviously, where DSD lands are included in an existing EL the Minister shall, on the
application of the licensee or the holder of a divided share, issue an SDL for all the lands contained
within the EL (s.30(1)). Second, where the DSD extends to Crown reserve lands, an SDL may only be
issued by following the call for bids procedure laid out in s.15 and discussed above (s.30(2)).
2.5.5
Rights granted by an SDL
Section 29 of the CPRA indicates that an SDL carries exactly the same rights as those accorded to the
holder of an EL. Unlike an EL however, an SDL continues in force for so long as there is a DSD in
force for those lands or until the SDL is replaced by a production licence premised upon a declaration
of commercial discovery (s.32(3)). A reduction in the size of a DSD causes a corresponding reduction
in the size of the SDL (s.31). An increase in the size of the DSD will not similarly accrue to the SDL
holder unless the incremental lands happen to be subject to an EL which is held by the owners of the
SDL (s.31(2)).
2.5.6
Liabilities of an SDL holder
While the duration of an SDL is unlimited, the holder of an SDL may be required by order of the
27
Minister to drill a well on the lands as prescribed in the terms of the order.76 The licensee is however
entitled to the extensive procedural protections described in s.106 and dealt with in greater detail below
(s.2.7). Failure to comply, as with any failure to meet the requirements of the CPRA, COGOA or the
regulations, may trigger the issuance of a compliance notice and ultimately cancellation of the interest.
However, this procedure too is subject to the s.106 review procedure.
2.6
The Condition Precedent for a PL, the Declaration of Commercial Discovery
The procedure for obtaining a production licence parallels that for the application for an SDL, the
condition precedent in this case being the issuance of a DCD. The relevant language and procedure
parallels that for the DSD. Thus, the licensee applies to the NEB which must apply a “reasonable
grounds test” to determine the area of application. The same rules apply to amendments and
revocations.
The definition of “commercial discovery” adds the concepts of reserves and economic viability to the
idea of a discovery. Thus a commercial discovery means:
a discovery of petroleum that has been demonstrated to contain petroleum reserves that
justify the investment of capital and effort to bring the discovery to production.
The Act does not indicate how this is to be demonstrated but in some cases (see e.g. the facts of King’s
Cove or East Rankin) an applicant will obviously need to drill an additional well or wells. The Board’s
Guidelines77 indicate that, in addition to any material that might have been submitted in support of a
76
CPRA, s.33; actually the order may be made with respect to any party having an interest in the area
covered by a DSD (i.e. the holder of an SDL or of an EL) but as a practical matter the power is much more significant
in the context of the SDL of potentially unlimited duration.
77
Supra, note 35.
28
DSD as well as any other regulatory filings (e.g. a development plan under COGOA), applicants should
provide:
a summary of the general approach to development envisaged for the pool including
information on
C
C
C
the scope, purpose, and nature of any anticipated development;
the production rate, estimated amounts of oil and gas proposed to be recovered,
reserves and recovery methods
planned production system and possible alternatives
Applicants should be able to demonstrate the extent of reserves and provide well-specific details on
such parameters as net pay and flow history.
2.6.1
Issuance of a PL
As with an SDL, the Minister shall, provided that the applicant is incorporated in Canada (s.44, grant a
PL (s.38) to the holder of an SDL or EL with respect to lands included within that interest that are
already the subject of a DSD. 78 Where the DSD extends to Crown reserve lands the Minister may
grant a PL but only in accordance with a call for bids under s.15.
2.6.2
Rights granted by a PL
In addition to the rights granted by an EL and an SDL, the PL grants the exclusive right to produce
78
Both demands should be enforceable by mandamus since there is no discretion left to be exercised. For a
recent review of mandamus in the context of east coast benefits plans see City of St. John’s Case, supra note 11.
There are some other possibilities available on a discretionary basis: (1) a PL to one interest owner in respect of 2 or
more CDAs (or portions thereof) held by that owner and (2) a PL to two or more interest owners in respect of one or
more CDAs. Presumably this is designed to give the interest holders a greater degree of flexibility perhaps to assist
with financing or for other security reasons.
29
petroleum from the lands subject to the interest, and title to the petroleum so produced.79 A PL is
issued for a 25 year term and is extended as of right where commercial production is occurring at that
time and for so long as commercial production continues. In addition, the Minister may by order extend
the term of the PL where production has ceased before the end of the term or ceases thereafter where
the Minister has reasonable grounds to believe that production will re-commence. A production licence
may be terminated before its term or may be reduced in size if the supporting DCD is revoked or
amended (s.40(1)). An increase in the size of the DCD will accrue to the benefit of the PL holder only
to the extent that the relevant lands are held under an existing EL or SDL held by the production
licensee.
2.6.3
Liabilities of persons having interests in a DCD
Where land is held under a DCD and where production has not commenced, the Act (s.36) reserves to
the Minister the power to make an order reducing the term of the relevant interest to three years. The
order is subject to the s.106 review procedure and it ceases have effect where commercial production
commences within the time prescribed.
2.7
The s.106 Procedure
As we have already noticed, the procedure for granting or changing a DSD or DCD, is both insulated
from political interference and affords directly affected parties a high degree of procedural protection.
Until the transfer of responsibility for these procedures to the NEB in 1994 these steps used to be
subject to the procedure laid out in s.106 of the Act. This section offers a high degree of procedural
protection but it does not offer the same degree of insulation from political influence as does the current
79
These rights are expressed to be subject to the possibility that the Minister may authorize any interest
holder to produce petroleum to aid in the exploration or drilling for or development of petroleum on any frontier
lands on such terms and conditions as the Minister deems appropriate.
30
DSD/DCD procedure insofar as the section leaves the ultimate decision with the Minister.
The s.106 procedure applies to some of the most important discretionary powers of the Minister under
the Act. These powers include: the power under s.33 to issue drilling orders, the power under s.36 to
issue development orders and the power under s.105 to cancel an interest for failure to comply with a
ministerial compliance order. In each of these cases the s.106 procedure contemplates the following
steps: (1) written notice to all persons whom the Minister considers to be directly affected, (2) an
opportunity for the person receiving the notice to request a hearing and the duty of the Minister to grant
such a hearing before the Oil and Gas Committee, and (3) an oral hearing with all the trappings of a
quasi-judicial tribunal including examination of witnesses and compellability of documents. (4)
Following the hearing the Committee makes recommendations to the Minister who makes the ultimate
decision and must supply reasons if requested. The Minister’s decision is subject to judicial review on
standard grounds.80 The Oil and Gas Committee is established pursuant to COGOA (s.6) which
stipulates a membership of five persons not more than three of whom shall be employees in the public
service of Canada.
2.8
Transfers and Registration
The CPRA does not impose any restrictions on the right to assign an interest or a share in an interest.
However, s.85 does require that an interest holder should give the Minister notice of an interest or
arrangement that results or may result in a transfer, assignment or other disposition of the interest (s.85)
together with a copy of the agreement or, where the Minister approves, a summary. The Minister no
longer has the power to withhold approval for such a transfer (as s/he did under COGA) and thus the
arrangement seems designed solely for the purposes of record keeping.
80
There is no privative clause; indeed s.106(10) specifically acknowledges the possibility of judicial review.
This may diminish the deference that the Court might otherwise show.
31
The Department maintains a public register. Only interests and instruments can be registered. An
instrument refers to a document in respect of a security interest. As is typical with these Crown registry
systems, registration constitutes notice and a registered interest prevails over an unregistered interest
(s.94).81 There is one exception to this insofar as s.94(5) establishes that an operator’s lien (defined in
s.84) will take priority without the need for registration although the same section does permit the
registration of a postponement of the priority of that lien.
2.9
Royalties
Section 55 of the CPRA reserves a royalty to the Crown at such rates as “may be prescribed”. 82 The
scheme itself is implemented by the Frontier Lands Petroleum Royalty Regulations.83 Like all modern
royalty schemes the federal scheme is complex and the devil is in the details but the basic scheme can
be stated as a gross royalty until payout and thereafter the greater of a 5% gross royalty or 30% of net
revenues. The gross royalty starts at 1% for the first 18 months of production rising by increments of
1% every 18 months to a maximum of 5%. Unlike schemes with high gross royalties at the front-end,
this represents a scheme under which the Crown and the lessee share the risk, with the Crown standing
to gain on the up-side in the event of low-cost discoveries or higher than anticipated prices.84
3.0
Benefits Requirements, Surface Rights and Access
81
It is not a Torrens system and the act of registration will not cure a title defect.
82
The royalty rate may be changed from time to time and such changes will bind the licensee whose
standard form licence is made subject to the CPRA, COGOA and such regulations under either Act as may be made
at any time.
83
SOR/92-26.
84
The current royalty regime was commented on, apparently adversely, in the Mackenzie Valley
Environmental Impact Review Board’s decision on the Ranger Oil, Canadian Forest Oil, Chevron Canada Pipeline
Application, December 1999, at 6.4.5 (economic benefits).
32
This part of the paper canvasses the related topics of surface access and benefits requirements. The
two are related because of the relevant provisions of the three NWT land claim agreements. I shall deal
first with benefits requirements and then deal with the issue of access.
3.1
Benefits Requirements 85
Benefits requirements for northern operations are a function of s.21 of the CPRA, the bidding
documents, s.5.2 of COGOA and the relevant provisions of the applicable land claim agreements.
Briefly, all Calls for Bids on federal lands in the north require successful bidders to adhere to a
statement of principles on Northern Benefits Requirements. The principles cover such matters as
industrial benefits, employment and training, consultation, compensation for damage to hunting and
trapping interests, and an annual reporting requirement. The document focuses on regional benefits
(rather than aboriginal or Canadian benefits) and operates at an in-principle level that is short on
specifics.
Section 21 of the CPRA also states that:
No work or activity on any frontier lands that are subject to an interest shall be
commenced until the Minister has approved, or waived the requirement of approval of,
a benefits plan in respect of the work or activity pursuant to subsection 5.2(2) of the
Canada Oil and Gas Operations Act.
Thus the primary requirement for a benefits plan comes from COGOA.
85
See also Keeping, “Local Benefits and Mineral Rights Disposition in the Northwest Territories: Law and
Policy” in Ross and Saunders (eds), Disposition of Natural Resources: Options and Issues for Northern Lands, 1997
and Keeping, Local Benefits from Mineral Development: The Law Applicable in the Northwest Territories, 1999.
33
COGOA provides that no person shall carry out any work without an operating licence and an
authorization for the specific work or activity (s.4). More specifically, no authorization for the
development of a pool or field may be granted without the approval of a development plan (s.5.1).
Approval of a development plan, in turn, requires approval of a benefits plan by the Minister or
Ministerial waiver of that requirement (s.5.2). In addition, s.5.2(2) provides that no authorization for
any work or activity shall be granted without approval of a benefits plan or a ministerial waiver. A
“benefits plan” is defined as:
... a plan for the employment of Canadians and for providing Canadian manufacturers,
consultants, contractors and service companies with a full and fair opportunity to
participate on a competitive basis in the supply of goods and services used in any
proposed work or activity referred to in the benefits plan.
The Minister may require that a benefits plan:86
... include provisions to ensure that disadvantaged individuals and groups have access
to training and employment opportunities and to enable such individuals or groups or
corporations owned or cooperative operated by them to participate in the supply of
goods and services....
Thus, in theory, all activities on federal lands require a benefits plan directed at Canadians in generally
and perhaps specifically at disadvantaged Canadians, and the legislation does not distinguish between
exploration activities and development activities. However, the practice is somewhat more nuanced and
varies depending upon the precise status of the lands. In all cases, however, the bidding documents
note that the successful bidder will be required to adhere to the terms of the applicable land claim
agreement.
86
COGOA, s.5.2(3).
34
3.1.1
Crown surface and subsurface
Where the Crown owns both the surface and the sub-surface for the entire block, the Department
follows the practice of accepting the Northern Benefits Statement of Principles as the Benefits Plan for
the exploration phase.87 A separate Benefits Plan is only required of an operator at the development
phase.88 Where the relevant lands fall within a land claim settlement area however, the land claim
agreement may impose additional procedural obligations. Thus the Sahtu and Gwich’in agreements
require prior notification by government to the First Nations on the bidding documents (including with
respect to benefits plans) (SA 22.1.2, GA, s.21.1.2) but the agreements also go on to require
consultations89 by the licensee with the First Nations on a number of matters including environmental
and benefits issues (SA 22.1.3, GA 21.1.3). However, the effect of the consultation is strictly limited by
the statement in the Agreements to the effect that “Such consultations are not intended to result in any
obligations in addition to those required by legislation.” While the benefits regimes under the Sahtu and
Gwich’in agreements are identical, licensees within the Sahtu region should be aware that most of the
authorities under the Sahtu agreement are devolved to local and regional corporations.90 By contrast,
authorities under the Gwich’in agreement are centrally exercised by the Tribal Council.
87
See (1997), 4 (1) Northern Oil and Gas Bulletin.
88
These plans are descriptive rather than prescriptive in nature: e.g. Shiha Energy Transmission Ltd, Fort
Liard Development project, Benefits Plan, November 1999, at 1.
89
Note that “consultation” is a defined term as it is in the Yukon agreements. The definition involves
detailed notice, time for the party consult to develop and present views and the full and fair consideration of those
views by the other party.
90
Pursuant to the terms of the Register of Designated Sahtu Organizations, June 16, 1994. The relevant
organizations include for Fort Good Hope, the Yomoga Lands Corporation and the Metis Local #54; for Colville Lake
the Ayoni Keh Land Corporation; for Norman Wells the Ernie McDonald Land Corporation; for Tulita the Tulita
Land Corporation and the Fort Norman Metis Land Corporation; and for Deline the Deline Land Corporation. There
are three separate land districts responsible for title lands: K’Asho Gotine District (Colville and Fort Good Hope), the
Tulita District Norman Wells and Tulita) and the Deline District (Deline).
35
The IFA contains only limited provisions dealing with benefits requirements for oil and gas operations
that occur entirely on Crown surface lands within the region but does contemplate that the Crown’s
general guidelines may apply and that a Cooperation agreement between the Inuvialuit and the Crown
may be sufficient to satisfy statutory requirements.91
Where there is no settled claim, the matter will be covered by the Statement of Principles and by the
common law duty of consultation developed through the aboriginal rights and title case law.92
3.1.2
Crown subsurface, Inuvialuit or First Nation surface
3.1.2.1
Sahtu and Gwich’in
Where the blocks are wholly or partially on settlement lands in NWT, additional rules apply. Under the
heading “Interim Measures” (i.e. interim, pending transfer of oil and gas resources to the GNWT
pursuant to a Northen Accord) the Sahtu and Gwich’in agreements (SA, 22.2.1, GA, s.21.2.1)
provide that any person who proposes to explore for, develop or produce oil and gas on lands the
surface to which is owned by the First Nation, shall submit a benefits plan to the Minister for approval.
That person must also consult with the First Nation “prior to the submission and during the
implementation of the benefits plan” (SA, s.22.2.1(c)). The Minister may require that such a benefits
plan contain provisions to ensure access to training and employment opportunities and to facilitate
participation by Gwich’in or the Sahtu in the supply of goods and services. It is clear that the language
of this clause is based upon the COGOA provisions quoted above, but, unlike the COGOA provision, it
requires direct consultation with the Sahtu and Gwich’in.
91
IFA, ss.16.11 and 16.12 and supra, note 87 (Oil and Gas Bulletin).
92
See supra, note 34.
36
Two comments are in order. First, while the obligation is limited to activities on lands the surface of
which is owned by the First Nation the Sahtu in particular have insisted that the obligation will be
triggered at any time that the area of a licence includes any Sahtu surface lands even if the licensee does
not intend to carry out actual operations on Sahtu lands but will effect all of its drilling and other
operations on Crown surface lands. Second, in practice, even though the SA and GA speak in terms of
consultation, both the Gwich’in and Sahtu have been able to insist that the licensees negotiate benefits
agreements with them. The resulting benefits “plans”, which are couched in the language of binding
contracts, are then submitted to the Minister for approval indicating on the part of the First Nation that
the licensees have fulfilled their consultation obligations and that both parties consider this to be a
benefits plan within the meaning of the land claim agreement.
The Sahtu benefits agreements negotiated to date for the Tulita District have dealt with employment and
training and business opportunities. Business opportunities may include the first opportunity of qualified
businesses to negotiate contracts and, if negotiations fail and it becomes necessary to call for bids, may
include a bidding preference for Sahtu Dene and Metis businesses. In the case of the Sahtu, the benefits
agreements will be negotiated with all the land corporations having an interest in that region. If the lands
included affect more than one region a separate agreement may be required with that other region.
Agreements may be short term, medium term or long term and the Sahtu have generally expressed a
preference not to enter into long term agreements given the “interim” nature of the relevant provisions of
the Agreement. The agreements are not negotiated at a high level of detail and do not (as do the
comparable Inuvialuit agreements) stipulate the specific businesses that are to benefit.
3.1.2.2
Inuvialuit
The core of the Inuvialuit socio-economic benefits regime is found in Article 10 of the Inuvialuit Final
37
Agreement (IFA).93 Article 10 deals with existing interests on Inuvialuit mineral lands as well as new
Crown interests on Inuvialuit surface lands. The article, in combination with s.7.18(d), guarantees rights
holders access to Inuvialuit Lands subject to the payment of compensation, and subject also to the
requirement that “a developer” must, before exercising its rights, “have concluded a valid Participation
Agreement with the ILA setting out the rights and obligations of the parties respecting the activity for
which access has been granted.” The IFA stipulates that the agreement must not include royalty
revenues but may include such terms and conditions as the following (IFA, s.10(3)):
(a)
costs associated with any ILA inspection of the development work sites and the
nature of such inspection;
(b)
wildlife compensation, restoration and mitigation;
(c)
employment service and supply contracts
(d)
education and training; and
(e)
equity participation or other similar types of participatory benefits.
Canada has the right to prescribe “procedures and timetables” for the negotiation of participation
agreements after negotiations of its own with the Inuvialuit but, so far as I am aware, no such procedure
or timetable has ever been established. In the event that the Inuvialuit and industry cannot agree on the
terms of a Participation Agreement, either party may initiate arbitration. There have been no arbitrations
on this part of the IFA.
93
See also s.16(11) which provides that:
With respect to Crown lands and [Inuvialuit surface lands] within the [ISR],
general guidelines developed by governments relating to social and economic
interests, including employment, education, training and business opportunities
to favour natives, shall be considered and applied, as reasonably as possible, to
each application for exploration, development or production rights.
38
The Inuvialuit have negotiated both co-operation and participation agreements with industry for their
lands. The Inuvialuit Lands Administration (ILA) uses a Co-operation Agreement to establish the basic
principles and procedures under which a series of activities on Inuvialuit Lands will be conducted.
These agreements are multi-year agreements that define the fundamental features of the relationship,
and provide a framework within which to negotiate participation agreements. Participation Agreements
for the ILA are of shorter duration and are site and activity specific and may identify particular Inuvialuit
businesses that are expected to provide material or personnel. The ILA will not grant any form of
property right to a party for access to Inuvialuit lands unless and until the party has negotiated a
Participation Agreement.
These last comments with respect to the Inuvialuit practice illustrate the degree of overlap between
benefits and access.
3.2
Surface Access
Surface access to do work will require both regulatory approvals under COGOA and relevant licences
or other more secure interests in land. The land use permitting procedure under the MVRMA and the
Territorial Land Use Regulations and the links to CEAA94 are beyond the scope of this paper.95 Crown
title lands in the NWT are administered under the terms of Territorial Lands Act 96 and leases of
Crown lands may be obtained under the terms of the Territorial Lands Regulations.97
94
Supra note 18.
95
See Carpenter et al, supra note 7, section 2.4.3.
96
RSC 1985, c. T-7.
97
CRC 1978, c.1525.
39
3.2.1
Sahtu and Gwich’in Agreements
Section 21.4.6 of the SA (GA, 20.4.6) provides that:
any person having a right to explore for, develop or produce minerals under or on
Sahtu lands has a right of access ... with the agreement of the designated Sahtu
organization or, failing such an agreement, an order of the Surface Rights Board.
Article 27 of the SA (GA, s.26) provides for the establishment of a surface rights board by legislation
but, as of the date of writing, no such Board has been established. In the interim, SA s.27.3.1
contemplates that the general arbitration panel established by Article 6 of the SA shall have jurisdiction
“except that where the resolution of any matter ... is provided for in legislation, such legislation shall
apply until such time as surface rights legislation comes into effect.” The term legislation includes
regulations. Are there such provisions? The answer is not as clear as one might anticipate.
Section 5.01 of COGOA 98 provides that where a person occupies land under a lawful right or title, no
person can enter those lands for exploration or development purposes without the consent of the owner
or in accordance with “the terms and conditions of a decision of an arbitrator made in accordance with
the regulations.” At the present time there are no such regulations. In the absence of any regulations it
would seem that the bare empowering provision in COGOA is insufficient to remove jurisdiction from
the Sahtu arbitration panel. Equally, however, it is clear that the panel’s jurisdiction is subject to preemption by the promulgation of an appropriate regulation.
To date there have been no references to arbitration and access agreements have been negotiated by
98
The provision (which used to be s.102 of the CPRA) was included in COGOA by SC 1992, c.35, s.8 and
then further amended by SC 1994, c.43.
40
the licensee and the relevant land corporation. 99 Access agreements may be short term, medium term or
long term. Short term agreements are used for a specific operation such as a seismic project. Medium
term agreements cover the duration of the EL, while a long term agreement would cover the duration of
the EL and any subsequent SDL or PL that may be issued with respect to the lands. All agreements
will provide for a lump sum signing fee with additional payments for seismic, well sites, temporary roads
and for borrow material. A long term agreement would also include additional fee items for gathering
lines and permanent roads. Access agreements grant licensees a right of access to and the right to use
the subject lands for the duration of the agreement for exploration (and or production and
transportation as the case may be in the case of long term agreements) to the extent necessary or
convenient for the licensee’s operations. This broad grant is subject to a case-by-case approval for
routes and activities based upon an access plan. In practice this will be the same plan submitted to the
Land and Water Board under the MVRMA in support of a land use permit application. Failure to
approve results in immediate submission of the dispute to arbitration.
3.2.2
Inuvialuit
We have already noticed that article 10 of the IFA provides for the negotiation of participation
agreements where a developer requires Inuvialuit surface lands. In return, ss.10.1 and 10.2 of the IFA
guarantee the rights holder necessary surface access subject to the payment of compensation for
damage and any diminution in value of the lands, but provide that such guaranteed access cannot be
exercised before the rights holder has negotiated (subject to arbitration if necessary) a PA setting out
the rights and obligations of the parties with respect to the activity for which access is being granted.
4.0
Inuvialuit and First Nation Rights Regimes in the NWT
99
This section is based on the practice in the Tulita District of the Sahtu settlement region. There are two
ELs that cover Gwich’in surface lands one held by Grand River Resources and the other held by Foxboro Resources.
I understand that access and benefit agreements have recently been concluded but am not aware of the details.
41
Under each of the three NWT land claim agreements, the Inuvialuit or First Nation obtained fee simple
title to a certain amount of mineral lands including oil and gas rights (Inuvialuit, 5,000 square miles;
Gwich’in 2,342 square miles and Sahtu, 700 square miles). As significant mineral owners each of the
Inuvialuit, Sahtu and Gwich’in have the opportunity to develop a leasing policy and negotiate
agreements that meet their needs.100 Of the three, the Inuvialuit have had the longest experience and
have developed a set of rules and procedures and standard forms and approaches to the different types
of commercial interests that developers might require on Inuvialuit lands.
The Inuvialuit have adopted a negotiated concession model for their oil and gas lands. Using that model
the Inuvialuit have negotiated concession agreements with Imperial (the Tuk concession, October 1,
1986, amended October 1, 1993), with Shell (January 1992) and most recently with Chevron (two
parcels), Petro Canada and Anderson (2000). While the details of these arrangements are not generally
available, especially the very recent agreements, it is possible to give some idea of their general terms
based in part on publicly available bidding documents that include a model agreement.
The older agreements provide for signing bonuses (for example $1 million in the case of the Imperial
and Shell agreements), rental fees ($100,000 per year for Shell and Imperial), a three tier royalty (a
basic royalty of 5%, an additional royalty of 5% after first payout,101 and, after second payout, an
additional royalty that is the greater of the additional 5% royalty or a 25% NPI), a carried interest
creating an option to participate (similar to the “back-in” idea under the old Crown share arrangements
under COGA; the Inuvialuit interest is financed by the lessee with the lessee recovering the loan from
100
The ILA has laid out in great detail in its Rules and Procedures the different forms of permits and leases
etc available from the ILA. For an overview of some disposition regimes see Rodney Snow, “Resource Dispositions
on Settlement Land in Yukon and Northwest Territories” in Ross and Saunders, supra note 86. Snow’s paper
focuses on hard rock mineral dispositions.
101
First payout refers to recovery of all development and operating costs; second payout occurs after
recovery of all exploration development and operating costs plus a return allowance.
42
production), commitment wells (in default of drilling a significant penalty is payable), and rigorous
relinquishment provisions (for example in the case of the Shell concession Shell was obliged to
relinquish 50% of the lands by the tenth anniversary date and a further 30% of the original area by the
20th anniversary). The basic concession term was 30 years with renewal options for further 10 year
periods.
Some of the features of the most recent round include: the use of a cash bonus bidding system based
upon a prescribed work program (the Inuvialuit received a total of $75.5 million for the four parcels); a
gross royalty system prescribing 5% for the first 4 years of production, 10% for years 5 - 8, and 15%
thereafter; work commitments on each parcel and an Inuvialuit back-in interest.102 The exploration
phase of the agreements is divided into an initial ten year term with two five year extensions.
Relinquishments continue to be required at the end of the initial term and each extension with the ability
to retain proven acreage. Continuance beyond the initial term and extensions depends upon commercial
production or deemed production. Election to proceed to a renewal term during the exploration phase
constitutes a commitment to carry out the work or pay penalties in default. Given the prospect of a
transportation system, the current agreements also condition continuance beyond the exploration phases
on actual production commencing within a number of years of the development of a transportation
infrastructure for that particular product (i.e. oil or gas). The lessee’s operations are subject to ILA
rules including amendments to those rules saving only some of the core rights of the lessee.
Since other parts of this paper focus on continuance provisions, it seems appropriate to deal with
continuance under the Inuvialuit scheme in a little more detail. There are two essential elements to
continuance beyond the exploration phase. The first element is a discovery. The procedure
contemplated here is for the lessee to notify the lessor of its intention to make a declaration of discovery
102
Under the bidding documents the Inuvialuit may acquire a 25% working interest in each block upon the
declaration of a discovery with the Inuvialuit being responsible for their share of development and production costs
accruing from the Discovery date.
43
and to provide supporting information as to the proposed productive acreage block. The lessor may
accept the proposal and the configuration of the block, failing which the matter goes to arbitration from
which decision shall be final and binding. The second element is actual or deemed commercial
production. Deemed production will not be available if there is transportation in place and the lessee
has failed to take advantage of that facility within the prescribed time.103
At the time of writing Gwich’in have not disposed of any of their oil and gas rights. The Sahtu (in the
form of the Tulita Land Corporation) did grant oil and gas rights in May 1998 to International Frontier a
company with an adjacent block of Crown lands. That agreement, which involved a number of different
parcels, was based on a modified CAPL freehold lease. The royalty provided for base gross royalty
and an NPI after payout. The agreement also provided for a significant cash bonus.
As exploration occurs on adjacent Crown lands we can expect to see greater interest from industry in
acquiring aboriginal lands. We can perhaps also expect First Nation land corporations to follow the
Inuvialuit lead and develop more formal and exacting disposition arrangements.
5.0
Yukon
In implementing its oil and gas regime the Yukon chose to combine in a single statute both its disposition
scheme and its oil and gas conservation scheme. Thus, Part 2 of the Oil and Gas Act (YOGA)
describes the disposition scheme, while Part 3, a law of general application, establishes the
conservation scheme. There is no separate oil and gas conservation board. Before analysing the Yukon
103
The model agreement attached to the bidding documents is not very clear on termination of the lessee’s
interest after the lease has ben continued by commercial production. Article 4 provides that “This lease ... shall
continue ... so long thereafter as any lands are comprised in a Productive Acreage Block where at least one Well has
Commercial Production or deemed Commercial Production.” Does the interest cease immediately upon cessation of
commercial production? I.e. is termination automatic or must the lessor exercise a right of re-entry?
44
regime I shall offer a few comments on the limited nature of the grandparenting of existing federal rights
that was effected by the Accord Act.
5.1
Grandparenting of federal rights
At the time of the transfer to Yukon there were in existence three different types of federal rights: (1)
producing leases that had been granted under the Canada Oil and Gas Land Regulations and which had
been successively grandparented through COGA and the CPRA,104 (2) a number of CPRA significant
discovery licences and, (3) at least one CPRA exploration licence. The Accord Act (s.20(1))105 makes
all of these interests subject to Yukon oil and gas laws106 but also provides for limited grandparenting of
these rights The grandparenting provided for by the Accord Act is limited to ensuring that: (1) the term
(i.e. duration) of an existing interest is not reduced (s.20(2)(b)), and (2) that certain prescribed rights
(s.20(2)(a)) (i.e. not all of the rights conferred) may not be diminished.
The limited nature of the grandparenting is most significant in relation to the holders of SDLs and ELs.
Such interest holders no longer have the right to obtain a production licence (and, in the case of the EL
there is also no prospect of obtaining the transitional SDL) but in lieu thereof have the exclusive right to
obtain production rights, pursuant to Yukon oil and gas laws, for any lands subject to the licence “in
which oil or gas is determined to be commercially producible.”107
104
The leases include the producing Kotaneelee gas property which is tied in to the Westcoast pipeline
system and for which the federal royalty is grandparented.
105
Supra, note 11.
106
The degree of grandparenting under the Accord Act is therefore much less extensive than the
grandparenting accomplished by the Natural Resources Transfer Agreements of 1930. For commentary on that
exercise see Thompson, “Sovereignty and Natural Resources - A Study of Canadian Petroleum Legislation” (1966-67,
1 Val. U.L. Rev. 283 and Harrison, “The Legal Character of Petroleum Licences” (1980), 53 Can. Bar Rev. 485
107
Note as well that s.20(4)(b)(i) of the Accord Act does not extend the rights of an SDL holder where there
has been a determination “under Yukon oil and gas laws to the effect that there is no potential for sustained
45
The relevant provisions of the Accord Act are reproduced verbatim in s.41 of YOGA while s.42 of
YOGA gives the Commissioner in Executive Council the power to make regulations to replicate the
relevant provisions of the CPRA and the Oil and Gas Land Regulations if necessary.108 Section 43
allows the Minister to replace federal dispositions with Yukon dispositions with the consent of the
interest holder.
5.2
The Yukon Rights Regime
The Yukon disposition scheme contemplates a two part tenure scheme of permits and leases that is
closely modeled on the disposition schemes under Alberta’s Mines and Minerals Act and British
Columbia’s Petroleum and Natural Gas Act. The Minister may issue leases directly without going to
a permit first, but the assumption within Yukon government (and YOGA, unlike the CPRA does not
restrict this discretion) is that rights will ordinarily be issued in the form of a permit in the first instance
unless the lands are expected to be capable of production at the outset.
5.2.1
Method of disposition
Section 15 of the Act contemplates that the Minister may issue dispositions:109 (1) following a call for
production of oil or gas”. Clearly there will be some nice questions that will arise here such as: (1) will a Yukon lease
granted out of an EL or SDL grant rights down to the basement or just to the deepest productive horizon, (2) is there
a difference between the “potential for sustained production” test of the CPRA and the Accord legislation, and the
productive zone\producing well tests of YOGA?
108
This provision would seem to have been added out of an abundance of caution for it is clear, for example,
that the holder of an EL does not have the right to insist upon the grant of an SDL if it makes a significant discovery.
109
Of course this looks very familiar to anyone used to s.16 of Alberta’s Mines and Minerals Act. The term
disposition is actually very broad and includes not only permits and leases which are specifically referred to but also
any other instrument or contract that conveys rights to oil and gas.
46
bids, (2) on application, or (3) pursuant to any other procedure determined by the Minister.110 In
practice, and as a matter of policy as in Alberta, it is clear that practically all dispositions will be issued
pursuant to the call for bids process. The Department of Economic Development describes this as a
five step process involving the following elements: (1) internal departmental review, (2) consultation with
First Nations, (3) call for nominations, (4) a review process involving the Department and First Nations,
and (5) the call for bids.
It is important to emphasize the role of First Nations in this process. First, under s.13 of the Act the
Minister may not issue a new disposition or licence oil and gas activity within the traditional territory of a
First Nation without the consent of that First Nation where that First Nation has not yet entered into a
land claim agreement with Canada. Where the First Nation consents or where it has entered into a final
agreement there must be consultation,111 on a reciprocal and confidential basis, between Yukon and
affected First Nations before any disposition occurs. In addition, s.6 of the Disposition Regulations
(DRs)112 requires (see step 4 above), and without a requirement of reciprocity, a more detailed review
process that is designed to determine environmental, socio-economic or surface access concerns that
could arise as a result of oil and gas activities or operations. In effect, this procedure is designed to
inform the development of a summary of concerns and any related special conditions to which the
disposition might be issued pursuant to s.9(2) of the DRs.113
110
See also s.27 authorizing “special agreements” and dispositions the terms of which may vary from the Act
with the approval of the Commissioner in Executive Council.
111
A defined term, see supra, note 89.
112
In force September 1, 1999.
113
See 1999 call for bids referring to the possible imposition of terms and conditions to maintain the habitat
of the Porcupine Caribou Herd; to protect the Peel River watershed and to maintain tourism and aesthetic values;
work seasons might be restricted and there could be special conditions relating to drilling fluids and waste
discharges.
47
Thus far Yukon has held one complete bidding round (in 1999) for two blocks in the Eagle Plain and
Peel Plateau regions which effectively surround three existing SDLs. Both permits were issued to
Anderson Resources. A second round is currently underway and as a result of the call for nominations
one block will be made available in the same region. The call for bids must stipulate a single bidding
variable which will be used to assess the bids (DPRs, s.9(2)(f)). To date this has been a work bid.
5.2.2
Permits
A permit (which shall have a maximum size of 500 sq. kms) may be granted for a maximum of ten years
(YOGA, s.31) and may be split into two periods, an initial term with a right of renewal for a second
term contingent upon the drilling of one well to completion during the first term (s.34)or any extension
thereof by diligent drilling over (s.35). Both the 1999 and 2000 calls for bids stipulated a six year initial
term followed by a second term of four years contingent upon drilling an exploration or delineation well
that would reach a depth sufficient to evaluate a prospective horizon as described in the application for
a well licence. A permit grants: (1) the right to explore for and the right to drill and test for oil and gas,
(2) the right to recover and remove oil and gas recovered for testing and (3) the right to obtain an oil
and gas lease. Somewhat surprisingly none of these rights are described as exclusive rights.114
5.2.3
Conversion of a permit to a lease
A permittee gets to keep its discovery and therefore may go to lease on the entire area of the permit
(i.e. unlike in Alberta there is no maximum area) provided that it can establish the existence of a
productive zone throughout the permit area. The actual process for converting a permit to a lease in
114
The permit form itself simply reproduces the language of the Act.
48
Yukon is clearly modelled on the similar procedure in Alberta.115 A permittee may apply for a lease at
any time during the term of its permit indicating the existence of productive zones for spacing areas
included within the application. “Productive zone” is a defined term and means:
... a geological formation or zone
(a) in which a producing well has been completed, or
(b) which, in the opinion of the Division Head is capable of producing
oil or gas in paying quantity.
The Act in turn defines a “producing well” as
in relation to an oil and gas permit,116 means a well that, in the opinion of the Division
Head, is capable of producing oil or gas in paying quantity from the geological
formation or zone in which oil and gas rights are granted under the permit or lease.
Where the permittee fails to make an application, the Minister shall determine the location of any lease
to be issued to the permittee. In either case, the areas granted by the lease shall be confined to spacing
areas with one or more productive zones and the rights granted shall only extend down to the base of
the productive zone that is stratigraphically the deepest in that spacing area.
Unlike the CPRA, no special procedural protections apply to this conversion decision which will
therefore be subject to judicial scrutiny only on the basis of the usual administrative law grounds and
with a standard of review that will have to take into account both the technical nature of the decision
115
But without the bells and whistles of the Alberta scheme including the idea of potentially productive
parts of locations: PNG Tenure Regulations, supra, note 46, s.17.
116
It is not clear why this phrase is included especially in light of the concluding words of the definition.
49
and the subjective framing of the relevant definitions.117
5.2.4
Leases
As noted above, while a lease will ordinarily be issued as a result of the conversion of a permit, it may
be issued directly by any of the means contemplated for permits. Either way, the lease will grant “the
right to oil and gas in the location of the lease” (s.38). Leases are issued for a 10 year term renewable
for further terms of 5 years, subject to terms and conditions prescribed by the Minister, and shall extend
only to spacing areas containing one or more productive zones and only down to the deepest
productive zone (s.39).
5.3
Transfers and registration
The rules for transfers and registration are very similar to those in force in Alberta. Thus, the holder of a
disposition is free to transfer its entire interest or an undivided share in a disposition (s.52). Transfers
are not effective against the Commissioner until registered. Registration constitutes notice and registered
transfers take priority over unregistered transfers. A disposition holder (other than a permittee) may
transfer a portion of the location with the permission of the Minister (DPRs, s.24(3)). Persons may also
register security notices in respect of security interests (YOGA, s.55). As with the CPRA, this is a
Torrens system.
5.4
Royalties
Section 44 of YOGA reserves a royalty to the Commissioner on all oil and gas recovered pursuant to
117
Justice Barry’s judgement in the Petro Canada case, supra, note 53 contains a good discussion of the
relevant factors in an oil and gas context.
50
an oil and gas disposition. The royalty is to be fixed by regulation (s.46). Notwithstanding the fact that
two permits have been issued under the new regime and with a further bidding round expected later this
fall, there is no royalty regime in place. The YTG has issued a series of discussion papers on the
subject118 and has posted draft regulations on its website but these have still to be finalized. The YTG
has also consulted with YFNs through the YTG-YFN oil and gas working group as the government is
required to do pursuant to s.23.2.7 of the Yukon Final Agreements.
The material available from the YTG suggests that they have rejected the royalty model presented by
the CPRA royalty regulations and have instead elected to pursue a gross royalty scheme based upon
the original Alberta model with some price sensitivities. Oil royalties will commence at 5% for the first
36 production months rising thereafter in accordance with a price-sensitive formula and may not exceed
15%. The gas regime will be similar with separate product royalties for sulphur and other gas products.
5.5
Benefits
The Yukon Final Agreements do not provide a comprehensive set of provisions relating to benefits
arrangements. Instead, arrangements are generally tied to the development assessment process (yet to
be finalized) and contemplate that where a project is subject to panel review (obviously only the more
significant projects and likely not the initial exploration work), the responsible Yukon Minister may
require that the developer, the Yukon government and the affected First Nation negotiate a project
agreement that may deal, inter alia with employment, business and investment opportunities and other
measures to mitigate negative socio-economic effects of the project.119 The discretionary and relatively
narrow ambit of this provision suggests that, unlike the situation in the NWT, the relevant provisions of
YOGA will likely prove to be more significant than the land claim agreements.
118
Discussion Paper, Yukon Oil and Gas Royalty Regime, April 1998.
119
See Schedule A of the Chapter 27 provisions of the respective Final Agreements.
51
Section 68 of YOGA requires the negotiation of benefits agreements before any oil and gas activity is
undertaken under the authority of a licence in the Yukon. Section 68 is found in Part 3 of the Act
dealing with oil and gas operations and is therefore a law of general application. The target of the
provisions is therefore the licensee rather than the permittee or the lessee. The section contemplates tripartite agreements between the licensee, the Yukon government and the Yukon First Nation(s) in
whose traditional territory the activity will occur. The agreements are to contain benefits in the form of
employment and training opportunities and goods and services opportunities for both Yukon First
Nation citizens and other Yukoners. Benefits are to be commensurate with the nature, scale, cost and
duration of the activity but shall not place an excessive burden on the licensee. The requirement for a
benefits agreement may be waived by the Minister and the First Nation and is not required where
projected expenditures will be less than $1 million dollars (the prescribed amount) in any one year. The
Yukon government has developed a draft form of agreement that is available on its website.
5.6
Access and Surface Rights
The ability of a permittee or lessee to access lands for the purposes of exercising its rights is the subject
of both s.69 of YOGA and the federal Yukon Surface Rights Board Act (YSRBA).120 The issue of
access is of course most contentious with respect to YFN Category B lands, i.e. lands for which the
mineral estate is in the Crown and the surface estate is held by the YFN. Where the surface estate is in
the Crown access will continue to be governed by the Territorial Lands Act,121 and the Territorial
Land Use Regulations122 (covering land use permits) and the Territorial Lands Regulations.
120
RSC 1995, c. Y-4.3.
121
Supra, note 9.
122
CRC 1978, c. 1524.
52
Section 69(1) of YOGA states that any person may enter on to and use the surface of lands for the
purposes of exercising the rights conferred by a disposition or a licence. However, this basic statement
of an entitlement is qualified in at least two fundamental ways. First, it is subject to YOGA, the
regulations and any other law in force in Yukon and second, it is subject to either the consent of an
interest holder or an order of the YSRB to the extent that the YSRB has jurisdiction. 123
Under the YSRBA, the Board (s.42) is required to grant an access order in favour of an applicant who
has “a right of access” as that term is used in s.1 of Schedule II of that Act.124 Paragraph (j) of that
section includes persons who hold new or existing mineral rights on category B settlement lands.
“Minerals” include oil and gas and a new mineral right is a mineral right other than an “existing mineral
right” which term refers to a mineral right in existence at the date of a final land claim agreement.
The Board may include a variety of terms and condition in an access order including compensation,
routing requirements, terms relating to abandonment and restoration and appropriate security for
commitments as well as limitations as to the timing of access and as to the right of the YFN to carry out
inspections to verify compliance.
Unlike the position in the NWT where there is a growing body of practice favouring reliance on
negotiated agreements rather than resort to arbitration or a surface rights procedure (should such a
procedure be put in place in the NWT), there is, as yet, no similar body of practice, at least in relation
to oil and gas.
123
The section also contemplates that a further surface access regime might be developed under YOGA to
the extent that the YSRBA might not afford jurisdiction. Note however that s.21 of the Accord Act, supra note 11,
provides that where Yukon oil and gas laws confer a right of access and provide for dispute resolution in relation to
that right of access they shall provide that such disputes be resolved by means of access orders under the YSRBA.
124
These provisions of the YSRBA give effect to chapters 8 and 18 of the Yukon Final Agreements.
53
5.7
First Nation Oil and Gas Regimes in Yukon
At the time of writing none of the seven First Nations that has executed a Final Agreement in Yukon
has developed an oil and gas leasing policy and none of them has executed an oil and gas disposition.
However, as part of the development of YOGA, First Nations did participate in a joint working group
with the Yukon Government with a view to developing a “common” oil and gas regime. The premise
here was that Yukon was a relatively small jurisdiction and that the very number of distinct First Nations
might lead to a multiplicity of rights regimes. Better therefore to try and develop within YOGA a
disposition system that First Nations might elect to apply on First Nation lands.
The concept of a common regime is primarily reflected in s.11 of YOGA which allows a YFN to
adopt125 Yukon oil and gas laws as its own and permits the negotiation of administrative arrangements
to facilitate First Nation management of its oil and gas resources. Clearly, the YOGA disposition system
(unlike the YOGA conservation regime) cannot apply of its own force to Category A First Nation lands
but a First Nation could elect to adopt it as its own disposition regime. That said, and as we have noted
above, the YOGA disposition system does itself permit of substantial flexibility in the selection of a
method of disposition. Thus a First Nation that elects to apply the YOGA model could still elect to
dispose of rights using a negotiated concession model rather than the permit\lease model detailed in the
Act and the disposition regulations.
6.0
Conclusions
The northern oil and gas regimes examined here have developed over the last twenty years. They will
continue to evolve to meet new challenges and this is true of both the public disposition systems as well
as the disposition systems operated by aboriginal owners. What is distinctive about these northern
125
See SGAs, s.20.
54
systems and what is simply characteristic of provincial leasing systems?
6.1
The distinctive features
The distinctive features include:
C
the ability to go to a production tenure on an entire discovery, at least to the extent that the
discovery falls within the exploration tenure;
C
disposition schemes that are dominated by work bidding requirements rather than rent recovery
schemes;
C
in the case of the CPRA, objective and formal procedures administered by an independent
quasi-judicial tribunal for determining the existence of a discovery and satisfying the conditions
for continuance, (less so in the case of Yukon);
C
in the case of the CPRA long term rights in the form of an SDL pending development of
infrastructure;
C
special provisions for access and benefit requirements for aboriginal peoples in recognition of
the reality of land claim agreements throughout much of the territories.
6.2
The Common features
The common features include:
55
C
An emphasis on single bidding variables through which to assess competing bids.
C
Registry and transfer systems that look much like provincial Crown systems.
56