Zaid Mahayni - 2001 CEPMLP LLM Dissertation

THE PROMOTION OF GAS INVESTMENTS IN CANADIAN
FRONTIER AREAS
By
Zaid Mahayni
MN: 009943036
Dissertation submitted to the Centre for Energy, Petroleum and
Mineral Law and Policy, University of Dundee
in partial fulfilment of the requirements for
the Degree of Masters of Laws in Petroleum Law and Policy
September 2001

The Promotion of Gas Investments in Canadian Frontier Areas 1
DECLARATION
THE MATERIAL CONTAINED IN THIS DISSERTATION IS THE WORK
OF THE AUTHOR. NONE OF THE MATERIAL HAS BEEN SUBMITTED
PREVIOUSLY FOR A DEGREE IN THIS OR ANY OTHER UNIVERSITY
_________________
Zaid Mahayni
(researcher)

ABSTRACT
Presently, analysts are denoting the formation of a supply shortfall in North America.
Consequently, it will become inevitable to develop Canadian frontier areas. Moreover, the
speculation of ‘bullish’ prices will certainly attract the attention of international investors.
When considering an investment in Canadian gas assets, interested investors will analyse
the overall prospectivity of investments in Canada before analysing the economics specific to a
particular project. The analysis of Canada’s prospectivity involves the examination of various
aspects, mainly technical, legal, fiscal and geopolitical. Within this precise structure, this study
will try to examine what particular issues are presently marking the investment climate in
Canada.

TABLE OF CONTENTS
LIST OF ABBREVIATIONS............................................................................................. 6
LIST OF TABLES ..............................................................................................................7
CHAPTER I: INTRODUCTION........................................................................................ 8
CHAPTER II: TECHNICAL PROSPECTIVITY.............................................................. 10
1. CURRENT CANADIAN GAS RESERVES AND PRODUCTION LEVELS................10
2. CANADA’S GAS PRODUCING AREAS.......................................................................11
2.1 Western Canada’s Sedimentary Basin ................................................................ 11
2.2 Mainland Territories............................................................................................ 14
2.3 Mackenzie/Beaufort and Arctic Islands .............................................................. 15
2.4 Offshore Atlantic.................................................................................................16
3. The Canadian Gas Transportation System ............................................................ 17
CHAPTER III: LEGAL PROSPECTIVITY ......................................................................20
1. AN OVERVIEW...............................................................................................................20
2. INTRA-NATIONAL AND INTERNATIONAL BOUNDARY DISPUTES .................. 20
2.1 International Boundary Disputes.........................................................................20
2.1.1 The Canada/US Gulf of Maine Dispute ........................................................... 21
2.1.2 The Canada/France Maritime Dispute ............................................................. 22
2.2 Intra-National Boundary Disputes ......................................................................23
3. THE ISSUE OF ABORIGINAL CLAIMS.......................................................................27
3.1 The Source of Aboriginal Title ...........................................................................28
3.2 The General Features of Aboriginal Title ........................................................... 29
3.3 The Content of Aboriginal Title..........................................................................29
3.4 The Test for Proof of Aboriginal Title................................................................ 30
3.5 Indian Oil and Gas Act........................................................................................ 31
3.6 Negotiated Agreements....................................................................................... 33
4. LICENSING TERMS .......................................................................................................34
4.1 Method of Award ................................................................................................ 35
4.1.1 The Discretionary Licence Allocation System................................................. 36
4.1.2 The Auction Licence Allocation Method......................................................... 37
4.1.3 Comparison of the Auction and the Discretionary Methods in the
Achievement of Government Objectives ..................................................................39
4.1.3.1 Capture of Economic Rent ............................................................................39
4.1.3.2 Avoidance of Licensee Working Capital Depletion .....................................40

4.1.3.3 Promotion of Small and Medium Sized Applicants......................................41
4.1.3.4 Promotion of Local Suppliers .......................................................................41
4.1.3.5 Limitation on the Entry of Foreign Oil Companies ......................................42
4.1.4 Method of Award: Recommendations ............................................................. 43
4.2 Licence Terms and Conditions............................................................................44
4.2.1 Duration of the Licence.................................................................................... 44
4.2.2 Size of Area......................................................................................................44
CHAPTER IV: FISCAL PROSPECTIVITY .....................................................................46
1. IMPORTANCE OF THE ISSUE...................................................................................... 46
2. ATTRACTIVENESS OF BACK-ENDED FISCAL TERMS..........................................46
3. ROYALTIES..................................................................................................................... 47
4. INCOME TAXES .............................................................................................................51
5. DEDUCTIONS AND WRITE-OFFS ...............................................................................52
6. OBSERVATIONS ............................................................................................................53
CHAPTER V: GEOPOLITICAL PROSPECTIVITY ....................................................... 55
1. CANADA: A DEREGULATED GAS MARKET............................................................ 55
1.1 Development Stages of a Gas Industry: The Pre-Competition Phase................. 55
1.2 The Main Competitive Market Models............................................................... 56
1.2.1 Pipeline-to-Pipeline Competition.....................................................................56
1.2.2 Mandatory Third Party Access.........................................................................57
1.3 The Canadian Gas Liberalisation Experience ..................................................... 57
1.4 Implications of North American Liberalization ................................................. 59
2. INCREASING NORTH AMERICAN GAS DEMAND.................................................. 59
2.1 Current Export Levels and Export Points ........................................................... 59
2.2 Regulatory Requirements for Exports.................................................................60
2.3 Natural Gas Consumption By Sector ..................................................................62
3. BENEFITS UNDER THE NAFTA .................................................................................. 63
3.1 History of the NAFTA ........................................................................................ 63
3.2 The Energy Sections of the NAFTA...................................................................64
3.3 Investment ...........................................................................................................66
3.3.1 NAFTA Provisions Governing Investment...................................................... 66
3.3.2 Investment Opportunities ................................................................................. 66
4. POSSIBILITY OF BECOMING AN LNG SUPPLIER................................................... 68
4.1 Problems with LNG Exports in General ............................................................. 69

4.1.2 Transportation Costs ........................................................................................ 69
4.1.2 Inflexible Contractual Obligations .................................................................70
4.1.3 The Weather Problem and Insufficient Storage Facilities ............................... 71
4.2 The Feasibility of an LNG Project in Canada ..................................................... 72
4.3 Recommendations ............................................................................................... 74
CHAPTER VI: CONCLUSION.......................................................................................... 76
ANNEXES............................................................................................................................ 80
BIBLIOGRAPHY ...............................................................................................................92

LIST OF ABBREVIATIONS
AGR --------------------------------------------Asian Gas Report
bcf-----------------------------------------------Billion Cubic Feet
bcf/d --------------------------------------------Billion Cubic Feet Per Day
bcm ---------------------------------------------Billion Cubic Meters
BTU --------------------------------------------British Thermal Unit
Conn.J.Int’l L. --------------------------------Connecticut Journal of International Law
C$ -----------------------------------------------Canadian Dollar(s)
cm-----------------------------------------------Cubic Meters
Great Plains Nat. Resources J. ------------Great Plains Natural Resources Journal
IPF ----------------------------------------------International Petroleum Finance
Land & Water L. R. -------------------------Land & Water Law Review
LNG --------------------------------------------Liquefied Natural Gas
Mbtu--------------------------------------------Million British Thermal Units
Mtpa --------------------------------------------Million Tonnes Per Annum
mt/yr--------------------------------------------Million Tonnes Per Year
NAFTA: L. & Bus. Rev. Am. -------------NAFTA: Law and Business Review of the Americas
Nat. Resources & Env’t---------------------Natural Resources and Environment
NEB --------------------------------------------National Energy Board
NGLJ -------------------------------------------(The) Natural Gas Lawyer’s Journal
NWT--------------------------------------------Northwest Territories
OGLTR ----------------------------------------Oil & Gas Law & Taxation Review
OGJ---------------------------------------------Oil & Gas Journal
PIW---------------------------------------------Petroleum Intelligence Weekly
PLI/Comm -----Practising Law Institute/Commercial Law and Practice Course Handbook Series
Pub. Util. Fort.--------------------------------Public Utilities Fortnightly
tcf -----------------------------------------------Trillion Cubic Feet
tcm----------------------------------------------Trillion Cubic Meters
Tulsa J. Comp. & Int’l L.-------------------Tulsa Journal of Comparative & International Law
U.S.-Mex.L.J.---------------------------------United States-Mexico Law Journal
WCSB------------------------------------------Western Canada Sedimentary Basin
WGI --------------------------------------------World Gas Intelligence

LIST OF TABLES
Established Natural Gas Reserves Per Province ...................................................................10
Future Potential of the WCSB............................................................................................... 81
Typical Gas Well Drilling Costs By WCSB Area ................................................................ 82
Alaska - Canadian & US Markets Proposed Routes............................................................. 83
Offshore Atlantic: Gas Discovery Areas...............................................................................84
Canadian and US Natural Gas Pipelines...............................................................................85
Canada/United States Beauford Sea Boundary Claims......................................................... 86
Georges Bank Boundary Drawn by International Court of Justice.......................................87
The Canada/France Boundary as Delineated by the Arbitration Court.................................88
The Nova Scotia/Newfoundland Disputed Boundary........................................................... 89
Alberta Natural Gas Prices – AECO/NIT .............................................................................90
Gas-Fired Capacity Additions (US Example).......................................................................91

CHAPTER I: INTRODUCTION
The Canadian natural gas industry is constantly being shaped by new realities and hence,
new policies. The reality today is that a supply shortfall is gradually forming, causing anxiety to
consumers, producers and inevitably policy-makers. In reaction to this shortfall, the
development of frontier areas has become unavoidable.1
According to experts,
“ ‘[f]rontier’ countries usually need the capital and expertise of foreign petroleum companies.
Only with them can a frontier country earn revenues from petroleum exports to finance its own
development and meet its own energy needs [and expected revenues from exports]”2
Canada needs to re-evaluate its investment climate and examine whether the incentives
presently offered are adequate in attracting upstream investment. The task is even more difficult,
given that the world is currently in a period of unprecedented opportunities for international
petroleum exploration.3
In other words, Canada has to compete in the international marketplace
for a limited amount of investment capital.
In their investment decisions, potential investors will seek to minimize risks and costs
and maximize profits. As Michael Bunter4
suggests, one method investors may use to evaluate
projects would be to complete a prospectivity matrix. This matrix is composed of four main
components and inspires the structure of this study. The four components of Mr. Bunter’s
prospectivity matrix and the four main chapters of this study are: technical prospectivity, legal
prospectivity, fiscal prospectivity and geopolitical prospectivity.
1
According to Section 2 of the Canada Petroleum Resources Act, R.S., 1985, c.36 (2nd
Supp.),
http://laws.justice.gc.ca/en/C-8.5/text.html, “frontier lands means lands that belong to Her Majesty in
right of Canada, or in respect of which Her Majesty in right of Canada has the right to dispose of or
exploit the natural resources, and that are situated in (a) the Northwest Territories, Nunavut or Sable
Island, or (b) submarine areas, not within a province, in the internal waters of Canada, the territorial sea
of Canada or the continental shelf of Canada, but does not include the adjoining area, as defined in
section 2 of the Yukon Act.” See also, National Energy Board, Canadian Energy: Supply and Demand to
2025, June 30, 1999, p. 43, Visited on March 8, 2001, http://www.neb.gc.ca/energy/sd99/index.htm
2
S. S., Hollis, and J. W., Berresford, Structuring Legal Relationships in Oil and Gas Exploration and
Development in ‘Frontier’ Countries, in T. W., Walde, and G. K., Ndi, International Oil and Gas
Investment: Moving Eastward?, p. 29.
3
M., A., Garcia Schreck, The Taxation Problem and the Promotion of Petroleum Investments, p. 1.

This study will adapt the prospectivity matrix to gas investments in Canadian frontier
areas. By doing so, it will be made more clear where Canada needs to place emphasis in
improving its investment climate.
Due to limitations, many pertinent elements (i.e. financing conditions, environmental
considerations, contractual rules, etc.) will not be covered in this study. Nevertheless, the
presented study will offer a good basis for prospective investors and will demonstrate the
multiplicity of factors influencing investment decisions.
4
M. A., Bunter, B and R Co. Ltd., No. 6 Whinacres, Cowny LL32 8ET, phone 01492-592492, fax
01492-585433, email: mike.bunter@btinternet.com

CHAPTER II: TECHNICAL PROSPECTIVITY
1. CURRENT CANADIAN GAS RESERVES AND PRODUCTION LEVELS
In 2000, Canadian natural gas production amounted to174.5 bcm (6.2 tcf), about two
percent above the 1999 production level and four percent above the 1998 production level.5
Of
this total Canadian production, Alberta accounted for 81 percent, British Columbia 12 percent,
Saskatchewan four percent, Nova Scotia two percent and Ontario and the Northwest Territories
the remainder.6
A study by the Canadian Gas Potential Committee estimates that there is 570 trillion
cubic feet (tcf) of discovered and undiscovered natural gas in Canada, in both conventional and
unconventional reservoirs.7
Another study by the National Energy Board brings up this estimate
to between 662 and 733 tcf, of which 303 tcf comes from frontier areas.
As of the 31st
of December 1999, the estimates in billion cubic metres (bcm) of
established natural gas reserves, per producing province, were as follows:8
Initial Remaining
British Columbia 604.8 236.7
Alberta 3,919.3 1,207.2
Saskatchewan 192.4 70.3
Ontario 44.1 12.0
NWT and Yukon 28.2 17.7
Nova Scotia 85.0 85.0
Total 4,873.8 1,628.9
5
National Energy Board, 2000 Annual Report, March 17, 2001, p. 17, Visited on July 30, 2001,
http://www.neb.gc.ca/about/ar/2000/ar2000.pdf; National Energy Board, 1999 Annual Report, pp. 15-16.
6
National Energy Board, supra note 5, p. 17.
7
Canadian Gas Potential Committee, Natural Gas Potential in Canada,
http://www.geo.ucalgary.ca/NatGasCan/intro.htm
8

It should be noted that established remaining reserves at the year-end of 1999 constituted
a decline of one percent from the previous year. In fact, reserve replacement is not rapid enough
to compensate for the practiced levels of production. This will be seen in greater detail in the
following section.
2. CANADA’S GAS PRODUCING AREAS
Geologically, it is mainly four areas, current or potential, which account for Canadian
natural gas production. These are:
- Western Canada’s Sedimentary Basin (WCSB);
- The Mackenzie Delta / Beaufort Sea;
- Mainland Territories (Yukon, Northwest Territories);
- Offshore Atlantic.
Each one of these areas will be described shortly in the following sections.
2.1 Western Canada’s Sedimentary Basin
Most of Canada’s reserves are located in the Western Canada’s Sedimentary Basin
(WCSB), which is located mainly in Alberta but which also extends to British Colombia,
Saskatchewan, and slightly into Manitoba and the Northwest Territories.9
Studies estimate that
the WCSB contains approximately 78 percent of Canada’s gas. Actually, in 1999, as much as
95.5 percent of Canadian gas produced came from the WCSB.10
The topology of the WCSB differs significantly from one region to the other. In the
southeastern part of the basin, land is easy to access, as it is rather constituted of flat prairies. On
the other hand, the western part of the basin, due to its proximity with the Rocky Mountains, is
characterized by access limitations and increased drilling depths and complexity. When it comes
9
See Annex A.
10
T. J. Woods, Canadian Prospects Push Toward 30-tcf North American Natural Gas Market, 99:4 OGJ
64 (2001), p. 64.

to the northern end of the basin, land is often covered with muskeg and drilling has to be carried
out in the winter when the ground is frozen.11
The costs and amount of drilling and development possible are therefore variable from
one region to the other. According to the National Energy Board (NEB),
“[…] a shallow well in Southeastern Alberta or southwestern Saskatchewan may cost less than
$100,000, whereas a deep well in the Foothills produces many times more but may cost up to
$10 million. Reserves and productivity also tend to vary according to area. The shallow wells in
southeastern Alberta and southeastern Saskatchewan generally have initial productivity rates of 6
thousand m3
/d (0.2 MMcf/d). In contrast, some deep wells in the Foothills exhibit initial
productivity rates of 600 thousand m3
/d (21 MMcf/d).”12
In 1999, total production from the WCSB amounted to 6 tcf, an average of 16.4 bcf/d. In
spite of this, the remaining reserves-to-production ratio has been significantly declining.13
This
means that unless new gas fields are connected, current levels of production are not sustainable.
Some experts have estimated that production from the WCSB is declining at a rate of 20 percent
per year, or some 3 bcf/d.14
Just as a reference, this equates to the total natural gas consumption
in Alberta, British Columbia and Saskatchewan in 1999.15
It has been demonstrated that one half
of the WCSB 2001 production has to be provided from wells drilled or connected since January
1998. Therefore, in order to maintain Canadian gas deliverability16
, producers must increase
their drilling activities and invest into higher-cost regions.17
Fortunately for investors, studies
have suggested that approximately 165.6 tcf of gas remain to be discovered in Alberta alone.18
Nevertheless, there are many obstacles that need to be overcome. First of all, recently
drilled wells seem to be producing at lower rates than wells drilled over five years ago.
11
National Energy Board, Short-term Natural Gas Deliverability from the Western Canada Sedimentary
Basin: 2000-2002, December 2000, p. 4, Visited on March 8, 2001,
http://www.neb.gc.ca/energy/emagdel.pdf
12
Ibid. See Annex B.
13
E., Verbicky, Decline in Output From New Fields Threatens Canadian Exports, 64:5 Petroleum
Economist 74 (1997), pp. 74-76.
14
National Energy Board, supra note 11, p. vi.
15
Ibid.
16
Future deliverability=[deliverability from existing wells-decline]+[productivity of a typical new well
multiplied by number of new wells], ibid., p. 2.
17
National Energy Board, Short-term Natural Gas Deliverability from the Western Canada Sedimentary
Basin: 1998-2001, September 1999, Visited on March 8, 2001, http://www.neb.gc.ca/energy/ema99.pdf
18
Canadian Gas Potential Committee, supra note 7.

Secondly, production from new wells has a tendency to decline more rapidly in comparison to
that of old wells.19
Therefore, to maintain the same levels of production in the future, it appears
that the number of wells must increase, with lower per well production capacity. One more
problem that needs to be mentioned is that, historically, it has been demonstrated that industry
investment in drilling is low when current returns on investments are poor. Consequently, since
drilling is risky for producers, it will only be justified if the price of gas is high enough or if the
fiscal burden is relaxed enough.
Financially speaking, producers will exaggerate their forecasted returns on investment as
a way to compensate with future uncertainty. In 1998, when the price of gas bottomed to below
$2 per million Btu and oil prices were a record low in 25 years, returns on investments fell to 3.9
percent. Just as a comparison returns on investment in 1996 and 1997 were just over 10
percent.20
In 2000, as the price of gas skyrocketed, a record of 16,507 wells were drilled,
exceeding the 1999 drilling activity by 55 percent.21
Interestingly, the 2000 drilling level was
double the forecast made by the National Energy Board in 1999, anticipating 8407 wells
drilled.22
Therefore, if investment is to be made on drilling activity, then producers need to be
anticipating high returns on their investment and once again, these returns will be overestimated
as compensation with future uncertainty. According to discussions between the NEB and
Canadian gas producers in 1999, it is expected that 8,700 gas wells will be drilled in 2001 and
8,900 gas wells in 2002. If this forecast is achieved, if the geological characteristics of new
wells correspond to present expectations and if old wells maintain projected output, then total
deliverability in 2002 can reach 17.5 bcf/d.23
19
National Energy Board, supra note 11, p. vi.
20
Energy Information Administration, U.S. Department of Energy, U.S. Natural Gas Markets: Recent
Trends and prospects for the Future, May 2001, Visited on July 30, 2001,
http://www.eia.doe.gov/oiaf/servicerpt/naturalgas/pdf/oiaf00102.pdf
21
22
National Energy Board, supra note 11, p. vii.
23
Ibid.

Experts estimate that a good number of drilling activity and investment will be diverted
from the WCSB towards other Canadian natural gas areas.
“Canada […] has relatively unexplored arctic and offshore basins that show excellent future
geological potential, with the east Coast offshore basins already producing crude oil and
expecting natural gas production by late 1999.”
24
These areas will be described in the following sections.
2.2 Mainland Territories
The Northwest Territories and the Yukon, sometimes referred to as “North-of-60” due to
their location to the north of the 60th
parallel, are believed to hold a potential of some 75 tcf.25
On average, “North-of-60” has tended to yield small production levels. Since 1992, this area has
marketed on average a mere 22 bcf/year. Three fourths of total “North-of 60” production comes
from Kotaneelee (17 bcf) while the remaining comes from the Norman Wells oil field26
(4bcf)
and from Painted Mountains (less than 1 bcf).27
It is believed that the “North-of-60” area will increase its output levels as new
discoveries come into production. It has been advanced that by 2005 “North-of-60” gas
production could exceed 200 bcf/y, about 9 times more the current production level.28
Some of
the most promising discoveries made in the Mainland Territories have been those made in the
Fort Liard region in 1999. The NEB estimates that the Fort Liard gas potential is in the vicinity
of 5 tcf. Chevron’s first well, K-29, alone is believed to hold reserves of approximately 400,600
bcf and is expected to produce 70 to 100 million cubic feet a day of raw gas. According to
experts, “these discoveries are huge by Canadian standards”.29
The Fort Liard region has
actually been in production since August 2000, with five wells marketing over 2 bcf/y.30
24
B., DeBaie, Resource Base, Pipeline Networks Position Canadian Producers for Greater Share of US
Oil and Gas Demand, 97:26 OGJ 34 (1999), p. 35.
25
Anonymous, Canada’s Northwest Yields Major Gas Reserves, 10:10 WGI 3 (1999), p. 3.
26
The Norman Wells oil field holds reserves of 260 million bbl of oil and is expected to have an
estimated gas potential of 3 tcf. See T. J., Woods, supra note 10, p. 67.
27
T. J., Woods, ibid., p. 66.
28
T. J., Woods, ibid., p. 67.
29
Anonymous, supra note 25, pp. 3-4.
30
T. J., Woods, supra note 10, p. 67.

Exploration activities in “North-of-60” have been rather cyclical, dependent especially
on economic and political factors. For example, the Norman Wells have first been put to
production during the Second World War where a sharp increase in demand justified exploration
and development in new regions. Another significant boom in exploration was triggered by the
1973 oil shock.31
It is important to stress that gas sold under long-term contracts is often indexed to the
price of oil. Therefore, an increase in the price of oil will in return increase the price of gas.32
Since the North-of-60 area is characterized with high-cost drilling, at depth exceeding 3,000
metres, exploitation and development is only justified if speculations on gas prices are ‘bullish’
enough. 33
Consequently, a large number of gas reserves in the NWT or even in Alberta have not
been connected even decades following their discoveries. Indeed, until recently, gas prices have
not been strong enough to make development economical.34
2.3 Mackenzie/Beaufort and Arctic Islands
Exploration in this region began in the late 1960s and since then, many discoveries have
been made both onshore and offshore. The Beaufort Sea/Mackenzie Delta region contains about
13.5 tcf of proven resources35
and 55 tcf of undiscovered reserves.36
Similarly, the Arctic Islands
are believed to contain 15 tcf of discovered resources and 90 tcf of undiscovered resources.37
Various arctic exploration and development companies are seriously considering the
construction of a pipeline linking the North Slope and Mackenzie/Beaufort and Arctic islands to
markets in the United States. An Energy Resources Director for the Yukon government, Brian
Love, said in a statement that, assuming there is sufficient demand:
31
L., Coad, et al., Northwest Territories, Department of Finance, A Comparison of Natural Gas Pipeline
Options for the North, October 2000, Visited on March 8, 2001, pp. 15, 16.
http://www.fin.gov.nt.ca/pipeline/A_Comparison_of_Natural_Gas_Pipleine_Options_for_the_North1.pd
f
32
It should also be noted that an increase in the price of oil will increase demand for natural gas as a
substitute for oil. This increased demand will in turn increase the price of gas.
33
Anonymous, supra note 25, p. 3.
34
J., Masseron, Petroleum Economics, pp. 436-437, 442.
35
R. H., Woronuk, Canadian Gas Potential Committee, Canadian Gas Supply: Going Up? Or Down?, p.
3, Visited on March 7, 2001, http://tabla.geo.ucalgary.ca/NatGasCan/opipaper.pdf
36
37
Ibid.

“[i]f Alaska gas is rolled in, there is enough ‘critical mass’ to make Canadian connections to the
Delta/Beaufort region economic.”38
Actually, according to preliminary estimates, the North Slope should hold some 30 tcf of gas.39
Many believe that the economics of Arctic development are “better now than they have ever
been”. As evidence, some have cited:
“[…] US demand forecasts, new technologies that have slashed construction costs and eased
some environmental concerns, aboriginal land claim settlements and the nearly-completed 3,000-
km Alliance pipeline from British Columbia to Chicago, which has reduced the distance required
for an Arctic pipeline within Canada to 900 miles, from 1,400 miles.”40
Interestingly, in December 2000, BP, ExxonMobil and Phillips took the decision to order
a $75 million feasibility study relating to the transportation of Alaska North Slope gas to
Canadian and American markets.41
It has been advanced that the materialization of this project
would be at a cost of at least $10 billion.42
Despite the industry’s enthusiasm and despite the fact
that five different routes have been proposed43
, gas deliveries to the North American pipeline
grid will probably not materialize for another 7-10 years.44
2.4 Offshore Atlantic
Discoveries have been made in three different areas of the offshore Atlantic45
: the
Scotian Shelf, the Grand Banks and the Labrador Shelf. These areas are believed to contain 6
tcf, 5.1 tcf and 4.2 tcf of gas respectively.46
As it will be seen in further sections of this paper, there have been intra-national
boundary disputes over offshore petroleum rights between the federal government of Canada
38
W. J., Simpson, Canada: Arctic Pipedreams, 67:2 Petroleum Economist 21 (2000), p. 21.
39
Ibid.
40
Ibid., p. 22.
41
See Annex C.
42
Anonymous, Why Alaska-Lowe 48 Pipeline is Suddenly a ‘This-Decade Project’, December 2000, Gas
Matters, pp. 11-13.
43
See L., Coad, et al., supra note 31.
44
T. J., Woods, supra note 10, p. 67. The delay in the materialization of the project probably exists due
to administrative requirements and construction time lag.
45
See Annex D.
46
T. J., Woods, supra note 10, p. 68.

and the maritime provinces of Newfoundland47
, Nova Scotia, New Brunswick and Prince
Edward Island. Such legal disputes have had and will unfortunately continue to have, until they
are completely resolved, a great weight on investment in Canadian maritime offshore areas.
These types of disputes, sometimes referred to as the ‘Seaweed Rebellion’, are common to
federal states and have also marked the history of countries like the United States and Australia.
3. The Canadian Gas Transportation System
The North American gas market is highly integrated48
, with many thousands of
kilometers of pipeline connecting Canadian supply basins with Canadian and US regional
markets.49
The Canadian pipeline system is composed of gas gathering, transmission and
distribution systems that transport processed gas. Gas storage is another important element in
the gas transportation system and is located in both producing and consuming regions of North
America.50
Depending on the territorial jurisdiction, two separate bodies regulate the Canada/US
pipeline system: the American Federal Energy Regulatory Commission (FERC)51
and the
Canadian NEB52
.
The major Canadian pipelines include the Alliance pipeline, the Vector pipeline, NGTL,
TransCanada, Westcoast, Alberta Natural Gas pipeline (ANG/Foothills), Foothills
(Saskatchewan), Trans Quebec and Maritime (TQM) and Maritime & Northeast pipeline. In
47
See H. E., Johansen, et al., Mineral Resource Development: Geopolitics, Economics and Policy, pp.
67-71.
48
There are over 16 pipeline interconnections between Canada and the United States. Therefore,
Canadian gas can penetrate US markets via a wide range of routes. See International Energy Agency,
Natural Gas Pricing in Competitive Markets, p. 64.
49
See Annex E.
50
National Energy Board, Canadian Natural Gas Market: Dynamics and Pricing, November 2000, p. 9,
Visited on March 8, 2001, http://www.neb.gc.ca/energy/emadp00.pdf
51
More precisely, FERC is responsible for regulating access to and tariffs for using the interstate
pipelines and storage facilities linked to those pipelines. State public utility commissions however
regulate distribution activities. See International Energy Agency, supra note 48, p. 69.
52
Except for the NOVA transmission pipeline, which the province of Alberta regulates. Ibid., pp. 68-70.

addition to these systems, most large distribution companies operate high-pressure lines within
the boundaries of individual provinces.53
The TransCanada and the Foothills system has been de-bottlenecked54
in the Fall of 1998
and helped in eliminating the ‘trapped’ gas phenomenon in Alberta. This expansion also helped
in ‘harmonizing’ prices between different Canadian price hubs.55
TransCana Pipeline Ltd.
dominates the pipeline infrastructure with a delivery capacity of 7.3 bcf/d. It delivers WCSB gas
to the US Midwest and East markets.
Announced in 199656
, the $3.4 billion Alliance pipeline57
has commenced service in the
late 2000. It extends 1,900 miles and has a capacity to deliver about 1.3 bcf/d of WCSB gas to
the Chicago area. From the Chicago hub, another newly built pipeline, the Vector pipeline, can
transport up to 700 MMcf/d of gas back into Canada to serve southwestern Ontario.58
On the East Coast, the 700-mile Maritime & Northeast pipeline, in service since the fall
of 2000, is able to transport 360 MMcf/d of Sable Island gas to serve US Northeast markets.59
Therefore, the North American transportation continuously keeps on growing, to keep
pace with growing demand. The EEA projects that 27 bcf/d of new pipeline capacity will be
required by 2010 to maintain the reliability of the natural gas delivery system.60
53
National Energy Board, Natural Gas Market Assessment: 10 Years after Deregulation,
September 1996, p. 15, Visited on March 8, 2001, http://www.neb.gc.ca/energy/ngma96.pdf
54
Debottlenecking occurs when an appliance is improved in order to perform greater task requirements.
If the appliance is said to be revamped, this means that it has been replaced by a new appliance of higher
capacity.
55
Vollman, K. W., National Energy Board Business Plans and Priorities, presented to a Joint
Conference of the Interstate Natural Gas Association of America and the Canadian Energy Pipeline
Association, p. 2, (Calgary, Alberta, National Energy Board, April 19, 2000).
56
B., DeBaie, supra note 24, p. 37.
57
The Alliance pipeline project involves Westcoast Energy Ltd., Enbridge Pipeline Inc., Coastal Corp,
Duke Energy and Williams. See J., Oosterbaan, et al., Canadian Gas Supply Outlook Gives Cause for
Optimism, 97:26 OGJ 40 (1999), p. 40.
58
59
B., DeBaie, supra note 24, p. 37.

In order to begin the construction of a section or part of a pipeline, an interested
company must be in conformity with the requirements of Section 31 of the National Energy
Board Act.61
Essentially, the interested company must obtain the approval of the NEB
authorizing the construction. In examining the project, the NEB will take into account all
considerations that appear to it to be relevant, and may have regard to the following:
“(a) the availability of oil, gas or any other commodity to the pipeline;
(b) the existence of markets, actual or potential;
(c) the economic feasibility of the pipeline;
(d) the financial responsibility and financial structure of the applicant, the methods of financing
the pipeline and the extent to which Canadians will have an opportunity of participating in the
financing, engineering and construction of the pipeline; and
(e) any public interest that in the Board's opinion may be affected by the granting or the refusing
of the application”62
If the NEB is satisfied that the pipeline is required by the present and future public
convenience and necessity, then a Certificate will be issued, granting the company leave to
construct.63
The Certificate can be made subject to any terms and conditions the NEB considers
necessary or desirable in the public interest.64
One could reproach that the legislator has not given clearer and more specific
recommendations to the NEB in authorizing construction projects. Besides, there is no mention
of many pertinent considerations such as the design and capacity of the pipeline.65
However, by granting this extent of flexibility, the legislator in reality acknowledges the NEB’s
expertise in the subject.
60
Energy and Environmental Analysis Inc., Gas Market Compass, Overview for the Basic Outlook,
August 8, 2000, p. 5, Visited on March 7, 2001, http://www.eea-inc.com/compass/co0800a.pdf
61
R.S.C. 1970, c. N-6; “Except as otherwise provided in this Act, no company shall begin the
construction of a section or part of a pipeline unless:
(a) the Board has by the issue of a certificate granted the company leave to construct the line;
(b) the company has complied with all applicable terms and conditions to which the certificate is subject;
(c) the plan, profile and book of reference of the section or part of the proposed line have been approved
by the Board; and
(d) copies of the plan, profile and book of reference so approved, duly certified as such by the Secretary,
have been deposited in the offices of the registrars of deeds for the districts or counties through which the
section or part of the pipeline is to pass.”
62
Section 52, National Energy Board Act.
63
Ibid.
64
Section 54(1), National Energy Board Act.
65
For an example of such mention, see Section 15(3)(c)(iii), Petroleum Act 1998, c.17 (U.K.)

CHAPTER III: LEGAL PROSPECTIVITY
1. AN OVERVIEW
Various elements inevitably affect investment prospectivity in Canada from a legal point
of view. This chapter is concerned with the following factors:
- Boundary disputes at an international and intra-national level;
- Aboriginal claims;
- Licensing requirements.
2. INTRA-NATIONAL AND INTERNATIONAL BOUNDARY DISPUTES
2.1 International Boundary Disputes
The history of Canada is rich with various boundary disputes, at an international level
and at an intra-national level. At an international level, two landmark disputes have been raised,
and later settled. One occurred with the United States over the boundary separating the fishery
zones and continental shelf areas in the Gulf of Maine. The other, with France, concerned the
delimitation of maritime areas between Canada and the French Island of St. Pierre and
Miquelon.
One dispute that still remains to be settled is the one with the United States over parts of
the Beaufort Sea in the Arctic. Canada has long defined its western boundary to be at the 141o
W
meridian extended northward to the pole. The United States, on the other hand, argues for a
median line demarcation using the coastal configuration as the base from which the boundary is
extended.66
The Canadian Department of Foreign Affairs and International Trade declared that it was
conscious of the importance of the matter to the petroleum industry and assured that the
resolution of the issue remained a priority on its agenda.67
Due to the increasing appeal of the
66
See H. E., Johansen, et al., supra note 47, p. 59; See Annex F.
67
The Federal Department of Foreign Affairs and International Trade, Agenda 2003: A Sustainable
Development Strategy for the Department of Foreign Affairs and International Trade, June 2000, p. 29,
Visited on August 11, 2001, http://www.dfait-maeci.gc.ca/foreignp/agenda2003/pdfs/dfait-e.pdf; For a

disputed region to the gas industry, it would not be surprising to see sincere efforts by both
Canada and the United States to resolve their dispute. It is after all in their interest since the
region could constitute a good source of government revenue and due to the necessity of
increasing North American supply.
One proposed solution would be to establish a joint development arrangement over the
disputed territory until the matter is resolved. Canada and the United States could formulate
some sort of regime that corresponds to their interests. There are presently some 15 joint
development zones worldwide.68
There are therefore numerous working models available that
may inspire Canada and the United States if they manifest interest in establishing this type of
agreement.
2.1.1 The Canada/US Gulf of Maine Dispute
The Canada-US dispute started in the mid-1960s when it became evident that petroleum
might be found in the waters between Nova Scotia and New England in the Gulf of Maine and
Georges Bank area.69
In 1964, the Canadian government began issuing exploration licences,
despite the protest of the United States, which claimed sovereignty over part of these waters.70
The matter was referred to the International Court of Justice (ICJ) by Order of 20 January 1982.
In its October 12, 1984 judgement, the ICJ defined the maritime boundary that divides the
continental shelf and the exclusive fisheries zones of Canada and the United States.71
The ICJ
underlined that:
"[n]o maritime delimitation between States with opposite or adjacent coasts may be effected
unilaterally by one of those States. Such delimitation must be sought and effected by means of an
agreement, following negotiations conducted in good faith and with the genuine intention of
achieving a positive result. Where, however, such agreement cannot be achieved, delimitation
should be effected by recourse to a third party possessing the necessary competence […] In
either case delimitation is to be effected by the application of equitable criteria and by the use of
more complete examination of the dispute. See E., Franckx, Maritime Claims in the Arctic: Canadian and
Russian Perspective, pp. 75-107.
68
Some of which relate to fisheries. See G., Blake, et al., Boundaries and Energy: Problems and
Prospects, pp. 13-16.
69
One study by the US Department of Interior at the time had estimated potential petroleum reserves in
the Georges Bank area to be in the vicinity of 200 million barrels of crude and 4.9 tcf of gas. See H. E.,
Johansen, et al., supra note 47, p. 59.
70
Ibid.
71
See Annex G.

practical methods capable of ensuring, with regard to the geographic configuration of the area
and other relevant circumstances, an equitable result."72
In general, it is in the interest of States to seek an agreement without referral of their
dispute to an Arbitration tribunal. Not only is the process often long and expensive, but it can
also be risky as to the outcome.73
2.1.2 The Canada/France Maritime Dispute
The Canada-France Maritime Boundary was referred to a Court of Arbitration
established by the two parties by an Agreement signed in Ottawa on March 27, 1972.74
In resolving the overlapping continental shelf claims, the Court was asked to apply fundamental
norm “which requires the delimitation to be effected in accordance with equitable principles, or
equitable criteria, taking into account all the relevant circumstances, in order to achieve an
equitable result.”75
The Canada/France boundary dispute also had an impact on oil and gas development in
the disputed region, as put to evidence in the following facts:
“The Court was […] informed by the Parties of their interest in potential hydrocarbon
exploitation in areas of overlapping claims. Some permits had concurrently been issued for
exploration by both governments but after reciprocal protests, no drilling was undertaken.”76
The Arbitration Court successfully delineated the boundaries of the continental shelves
of each Party in a three votes to two judgment.77
Mr. Allan E. Gotlieb, appointed by the
Canadian government, dissented due to the ‘contradiction and inconsistency’ in the delimitation
methods used. According to Mr. Gotlieb:
72
Case Concerning Delimitation Of The Maritime Boundary in the Gulf of Maine Area (Canada/United
States of America), 1984 I.C.J. Reports, par. 112, http://www.icj-
cij.org/icjwww/idecisions/isummaries/icigmsummary820120.htm
73
J. G., Merrils, International Dispute Settlement, Third Edition, p. 293.
74
Court of Arbitration for the Delimitation of Maritime Areas Between Canada and France: Decision in
Case Concerning Delimitation of Maritime Areas (St. Pierre and Miquelon), [June 10, 1992], 31 I.L.M.
1145 (1992).
75
Ibid., p. 1163, par. 36.
76
Ibid., p. 1175, par. 89.
77
Ibid., p. 1176, par. 93. See Annex H.

“[…] the majority of the Court has reached a result which is disproportionate in light of the
relevant geography. A result which is so disproportionate cannot be equitable. The result,
therefore, is not in accordance with international law.”78
Mr. Prosper Weil, appointed by the French government, also dissented but, for different
reasons than Mr. Gotlieb. Mr. Weil wrote that:
“My essential reason for voting against the Decision is that the delimitation in the strange form
of a mushroom which is its result does not seem to me to be founded ‘on the basis of the law’.”79
Mr. Weil disagreed with the Majority Decision, mainly for its choice of certain delineation
methods. For example, Mr. Weil attacked the Majority’s use of the frontal projection theory in
the generation of the north-south corridor80
. According to Mr. Weil:
“The frontal projection theory has been rejected by the practice of States both for the
determination of outer limits and for delimitation between States. The outer limits of maritime
jurisdictions are commonly determined today by reference to the so-called arcs of circle method
[…] I may add that even if one were to accept the frontal projection theory as correct, a corridor
running due south would only be justified if the southern coast of the French islands ran exactly
along a west-east axis.”81
2.2 Intra-National Boundary Disputes
Offshore petroleum development generated many disputes between the Federal
government of Canada and Canadian coastal provinces. The facts giving rise to the disputes may
be summarized as follows:
“Offshore energy exploration first occurred off the coast of Prince Edward Island in 1943 under
provincial jurisdiction. British Columbia began issuing permits for offshore energy exploration
in 1949. Federal licensing of offshore energy operations began in 1960, two years after the
promulgation of the Convention on the Continental Shelf by the United Nations. Federal
regulations declared provincial permits invalid and instructed holders of provincial permits to
apply for federal licences. The provinces did not accede to this usurpation of provincial authority
and continued to exercise jurisdiction over offshore lands.”82
In regards to the dispute with British Columbia, the matter was referred to the Supreme
Court of Canada.83
In November 1967, it was concluded that, since the territorial sea and
78
Ibid., p. 1181, par. 3.
79
Ibid., p. 1197, par. 2.
80
See Annex H.
81
Ibid., pp. 1201-1202, par. 12-15.
82
E., A., Fitzgerald, The Seaweed Rebellion Federal-State/Provincial Conflicts Over Offshore Energy
Development in the United States, Canada and Australia, 7 Conn.J.Int’l L. 255 (1992), pp. 280-281.
83
Reference re the Off-Shore Mineral Rights of British Columbia, [1967] S.C.R. 792 (1967).

continental shelf were outside of British Columbia, the province lacked jurisdiction over them.84
The Supreme Court of Canada determined that the provincial boundary actually terminated at
the low-water mark.85
Therefore, since the territorial sea and continental shelf were sovereign
rights, recognized under international law, they fell as a result under Federal jurisdiction.86
Despite the Supreme Court’s decision, the Federal government was still willing to
negotiate offshore management and revenue sharing with the Atlantic Provinces. Experts
believe that this Federal government policy was intended to demonstrate the success of its
National Energy Program.87
The Federal government has signed two agreements with two
different Provinces. One with Nova Scotia, implemented in the Canada-Nova Scotia Offshore
Petroleum Resources Accord Implementation Act, 198888
(hereafter Canada-Nova Scotia
Agreement), and one with Newfoundland, implemented in the Canada-Newfoundland Atlantic
Accord Implementation Act, 1987 (hereafter Canada-Newfoundland Agreement).89
In general terms, the two agreements resemble each other. The Provincial limits of
offshore areas are defined, depending on the geographic area. In many specific locations, the
limit of the offshore area is fixed beyond the low-water mark.90
A joint administrative board is
created91
with the responsibility to conclude with the appropriate departments and agencies of
the Government of Canada and of the Government of the Province memoranda of understanding
in relation to:
“(a) environmental regulation;
(b) emergency measures;
(c) coast guard and other marine regulation;
(d) employment and industrial benefits for Canadians in general and the people of the Province
in particular and the review and evaluation procedures to be followed by both governments and
the Board in relation to such benefits;
(e) occupational health and safety;
84
Ibid., p. 815.
85
Ibid., p. 817.
86
Ibid., pp. 817-821.
87
E., A., Fitzgerald, supra note 82, p. 285.
88
Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act, 1988, c. 28,
http://laws.justice.gc.ca/en/C-7.8/22527.html
89
Canada-Newfoundland Atlantic Accord Implementation Act, 1987, c. 3, http://laws.justice.gc.ca/en/C-
7.5/text.html
90
Section 5, Canada-Nova Scotia Agreement; Section 5, Canada-Newfoundland Agreement.
91
Section 9, Canada-Nova Scotia Agreement; Section 9, Canada-Newfoundland Agreement.

(f) a Nova Scotia trunkline within the meaning of
section 40; and
(g) such other matters as are appropriate.”92
In the Canada-Nova Scotia Agreement, it is established that, before issuing a pipeline
construction certificate offshore, the NEB must give the provinces a reasonable opportunity to
acquire on a commercial basis at least fifty per cent in ownership interest.93
Under both the
Canada-Nova Scotia and the Canada-Newfoundland agreements, the provinces may levy and
collect taxes on offshore areas as if they were onshore. These taxes could be in the form of
royalty, consumption taxes, income taxes, etc.94
Moreover, both agreements provide for the
creation of a development fund95
, and a drilling fund is established under the Canada-Nova
Scotia Agreement96
.
Just to make matters more complex, disputes in Federal systems are not limited to
Central government-Provinces/Territories. Disputes may also arise between Provinces
themselves. This eventuality was foreseen in Section 6 of the Canada-Newfoundland
Agreement. According to the second paragraph of Section 6:
“6(2) Where a dispute between the Province and any other province that is a party to an
agreement arises in relation to a line or portion thereof prescribed or to be prescribed for the
purpose of the definition "offshore area" in section 2 and the Government of Canada is unable,
by means of negotiation, to bring about a resolution of the dispute within a reasonable time, the
dispute shall, at such time as the Federal Minister deems appropriate, be referred to an impartial
person, tribunal or body and settled by means of the procedure determined in accordance with
subsection (3).”
For many years, Nova Scotia and Newfoundland have been in dispute over offshore
boundaries in the English Channel.97
Having been unable to bring about a resolution of the
dispute by means of negotiation, the Federal Minister of Natural Resources, pursuant to the
92
Section 46(1), Canada-Nova Scotia Agreement; Section 46(1), Canada-Newfoundland Agreement.
93
Section 40(2)(3), Canada-Nova Scotia Agreement.
94
Sections 212, 213, 216 and 217, Canada-Nova Scotia Agreement; Sections 97-99, 207-213, Canada-
Newfoundland Agreement.
95
Part VI, Canada-Nova Scotia Agreement; Part VI, Canada-Newfoundland Agreement.
96
Part VII, Canada-Nova Scotia Agreement; None established under the Canada-Newfoundland
Agreement.
97
See Annex I.

above provision and with the consent of the parties referred the dispute, on March 31, 2000, to
an Arbitration Tribunal.98
According to its mandate, the Tribunal was asked to determine the line dividing the
respective offshore areas of the Province of Newfoundland and the Province of Nova Scotia in
two phases. In the first phase, the Tribunal must examine whether the line dividing the
respective offshore areas of the two provinces has been resolved by agreement. In the second
phase, the Tribunal must determine how in the absence of any agreement the line dividing the
respective offshore areas of the Province of Newfoundland and the Province of Nova Scotia
shall be determined.99
The Arbitration Court has given a ruling on the first part of its mandate. It unanimously
concluded that:
“’[…] the documentary record looked at as a whole does not disclose the existence of an
agreement resolving the offshore boundaries of Newfoundland and Labrador and Nova Scotia,
within the meaning of the Terms of Reference. This is true whether the criterion be taken to be
the international law of agreements or Canadian public law. In particular, the Tribunal concludes
that the parties at no stage reached a definitive agreement resolving their offshore boundary.”100
A decision on the second phase of the mandate still remains to be given. As long as the
boundary location is under review, investment in the disputed area will remain unattractive since
there is uncertainty over the validity of licences issued. As scholars note,
“[o]il companies are normally careful not to acquire concessions in politically-sensitive areas,
although it sometimes happens. Oil exploration is a sophisticated and costly business and few
companies are willing to risk adventures in disputed areas.”101
Actually, a large area around the disputed boundary remains unexplored. The resulting
absence of sufficient geological data on the region will increase exploration risks for lease-
holders.102
98
Arbitration Between Newfoundland and Labrador and Nova Scotia Concerning Portions of the Limits
of their Offshore Areas as Defined in the Canada-Nova Scotia Offshore Petroleum Resources Accord
Implementation Act and the Canada-Newfoundland Atlantic Accord Implementation Act, Award of the
Tribunal in the First Phase, Ottawa, May 2001, par. 1.3, http://www.boundary-dispute.ca/
99
Ibid., par. 3.2.
100
Ibid., par. 7.1.
101
G., Blake, et al., supra note 68, p. 5.

3. THE ISSUE OF ABORIGINAL CLAIMS
Native title is a fundamental issue when it comes to oil and gas development in Canada.
Indeed, the assertion of aboriginal title can challenge the power of the Crown to issue a
disposition and hence, the validity of that disposition.103
Moreover, as Vance Langford notes:
“[t]he socio-economic impacts of international mining projects and the rights of local
communities are being given increasing recognition by governments, law makers and
commercial enterprises involved in the global mining industry […] In the legal form, the
legislation and jurisprudence regarding the rights of local communities to land, mineral resources
and traditional rights continue to evolve […] In the commercial form, hard lessons have been
learned from mining ventures that failed to develop effective partnerships with local
communities.”104
The concept of aboriginal rights is deeply rooted in the evolution of Canada as an
independent state. These rights have even been enshrined in the highest hierarchy of Canadian
legislative instruments. Indeed, Part II of the Constitution Act, 1982105
, entitled the “Rights of
the Aboriginal People of Canada”, ensures constitutional status to aboriginal rights that existed
in 1982.
The following sections will offer the interpretation of the concept of aboriginal title in
Canadian law and will examine its source, its general features, its content and the test for its
proof. The importance of this concept cannot be underlined enough since it is a prime issue in
the exploration and development of most Canadian gas areas. As an example, in 1972, the
issuance of land claims by Dene and Metis Native people in the broad Mackenzie Valley
region106
led to a two-decade moratorium on new licences. Oil and gas exploitation was actually
halted at the borders of Alberta and British Columbia.107
The moratorium only ended with the
1990 Comprehensive Land Claim Agreement between the Dene people and the Federal
government. According to the settlement, the Dene people were given rights of ownership and
102
Nova Scotia Petroleum Directorate, Exhibitor at the Offshore Europe Conference 2001 Oil & Gas
Exhibition and Conference (Aberdeen, Scotland, 4-7 September 2001).
103
R. H., Bartlett, Aboriginal Title at Common Law and the Oil and Gas Industry in Canada, 1 OGLTR
12 (1994), p. 12.
104
V., Langford, The Impact of Aboriginal Title on Mineral Rights Agreements in Canada: Legal and
Commercial Realities, 2 C.A.R. 1 (1998), p. 85.
105
Constitution Act, 1982, http://laws.justice.gc.ca/en/const/
106
See Re Paulette and Registrar of Land Titles, [1973] 39 DLR (3d) 45 (NWTS Ct).
107
Anonymous, supra note 25, p. 3.

participation in oil and gas development. The Dene people have actually engaged in joint
ventures with oil companies in the region.108
Another illustration of the potential impact aboriginal title may have is the Alberta
Lubicon Band case. In 1983, the Lubicon Band sought an interim injunction to restrain on-going
oil and gas exploration and development in an area of 8,500 square miles in northern Alberta.
Despite the fact that the injunction was not granted109
, Alberta still agreed in a settlement to
transfer 245 square kilometers to the Band in order that it recognizes dispositions granted to oil
and gas companies.110
3.1 The Source of Aboriginal Title
For a long time, the source of aboriginal title was uncertain. In the 1888 Privy Council’s
decision in St Catherine’s Milling and Lumber Co. v. R.111
, it was concluded that the source of
Aboriginal title in Canada could only be ascribed to the general provisions made in the Royal
Proclamation, 1763. According to this decision, Aboriginal title was a “personal and
usufructuary right, dependent upon the goodwill of the sovereign”.112
In a commentary on
Aboriginal Title At Common Law and the Oil and Gas Industry in Canada, Richard H. Bartlett
described the St Catherine’s Milling decision as “driven by policy and practice”.113
In a subsequent decision, Calder v. AG of British Columbia114
, the Supreme Court of
Canada underlined that Aboriginal title does not take source from the Royal Proclamation as
such but is only recognized by that instrument. In fact, the actual source of Aboriginal title
arises from the prior occupation of Canada by Aboriginal people.115
108
R. H., Bartlett, supra note 103, p. 15.
109
Ominayak v. Norcen Energy Resources, [1984] 4 CNLR 27, 29 Alta LR (2d) 152; The decision sets a
precedence that favours oil companies in the consideration of the balance of convenience test. It was held
that oil companies would suffer large and significant damages and a loss of competitive position in the
industry if the injunction were to be granted.
110
Ibid.
111
(1888), 14 A.C. 46.
112
Ibid., p. 54.
113
114
[1973] S.C.R. 313.

3.2 The General Features of Aboriginal Title
Aboriginal title contains general features that take source both from common law and
from ‘Aboriginal perspectives’. Canadian courts have repeatedly described aboriginal title as a
sui generis interest in land that is distinguished from “normal” proprietary rights. First of all,
Aboriginal rights are inalienable.
“Lands held pursuant to aboriginal title cannot be transferred, sold or surrendered to anyone
other than the Crown and, as a result, is inalienable to Third parties.”116
Secondly, Aboriginal title is to be held communally:
“Aboriginal title cannot be held by individual aboriginal persons; it is a collective right to land
held by all members of an aboriginal nation. Decisions with respect to that land are also made by
that community.”117
3.3 The Content of Aboriginal Title
Until the Delgamuukw decision, described by the critical literature as “the most
important land title case in Canada’s history”118
, the content of Aboriginal title was left
undetermined. Many previous decisions declined to explain what it meant, as it was not
“necessary to express any opinion upon the point”119
. In Delgamuukw, Chief Justice Antonio
Lamer ended over two centuries of legal ambiguity on the topic.
“[…] I have arrived at the conclusion that the content of aboriginal title can be summarized by
two propositions: first, that aboriginal title encompasses the right to exclusive use and occupation
of the land held pursuant to that title for a variety of purposes, which need not be aspects of those
aboriginal practices, customs and traditions which are integral to distinctive aboriginal cultures;
and second, that those protected uses must not be irreconcilable with the nature of the group’s
attachment to that land.”120
Consequently, it is clear that Aboriginal people may have interest in land, including
rights of governance. There are two types of interests that Indians may have in land: it is either
reserve land or title land. If it is reserve land, then Aboriginal people may use it without
“restrictions to practices, customs and traditions integral to distinctive Aboriginal culture”.121
On
115
116
Delgamuukw v. British Columbia, [1997] 3 S.C.R. 1010, par. 112.
117
Ibid., par. 115.
118
S., Persky, Delgamuukw: The Supreme Court of Canada Decision on Aboriginal Title, (back cover).
119
St Catherine’s Milling and Lumber Co. v. R., supra note 111, p. 55.
120
Delgamuukw v. British Columbia, supra note 116, par. 117.
121
Section 18 of the Indian Act, R.S.C., 1985, c. I-5

the other hand, if it is land on which Aboriginal people successfully obtain title, then there are
inherent limitations on the possible usage of that land. Chief Justice Lamer gives the following
examples:
“[…] if a group claims a special bond with the land because of its ceremonial or cultural
significance, it may not use the land in such a way as to destroy that relationship (e.g., by
developing it in such a way that the bond is destroyed, perhaps by turning it into a parking
lot).”122
If Aboriginal people wish to use a title land in a way “irreconcilable with the nature of the
group’s attachment to that land”, then they must surrender that land to the Crown and actually
convert it into non-title land.123
This implies that land right is lost if not ‘used’ correctly.
Also, it is important to note that infrigements on Aboriginal title may be justified, since
Aboriginal rights recognized and affirmed by Section 35(1) of the Constitution Act, 1982 are not
absolute. Infrigements will be justified only if it satisfies the following test:
“First, the infrigement of the aboriginal right must be in furtherance of a legislative objective that
is compelling and substantial […] The second part of the test of justification requires an
assessment of whether the infrigement is consistent with the special fiduciary relationship
between the Crown and aboriginal people.”124
Hence, both the Federal and Provincial level may infringe on Aboriginal title for such
things as environmental protection, which would affect the broader Canadian community as a
whole.
3.4 The Test for Proof of Aboriginal Title
In the Delgamuukw decision, the Supreme Court of Canada enunciated the test for proof
of Aboriginal title in the following manner:
“In order to make out a claim for aboriginal title, the aboriginal group asserting title must satisfy
the following criteria: (i) the land must have been occupied prior to sovereignty, (ii) if present
occupation is relied on as proof of occupation pre-sovereignty, there must be a continuity
between present and pre-sovereignty occupation, and (iii) at sovereignty, that occupation must
have been exclusive.”125
http://laws.justice.gc.ca/en/I-5/64916.html, as interpreted in Delgamuukw v. British Columbia, ibid., par.
121.
122
Ibid., par. 128.
123
Ibid., par. 131.
124
Ibid., par. 161-162.
125
Ibid., par. 143.

At this point, it should be asked whether an Aboriginal group of people, who
successfully proves its title on a specific area of land could benefit from oil, gas or mining
exploration and development on that land. This will be the topic of the next section.
3.5 Indian Oil and Gas Act
Section 91(24) of the Constitution Act, 1867 extends the legislative authority of the
Parliament of Canada to “ Indians, and Lands reserved for the Indians”.126
It is under that
authority that the Parliament of Canada enacted the Indian Oil and Gas Act127
and the Indian
Act. As the Supreme Court of Canada describes:
“[t]he overall purpose of the statute [the Indian Oil and Gas Act] is to provide for the
exploration of oil and gas on reserve lands through their surrender to the Crown. The statute
presumes that the aboriginal interest in reserve land includes mineral rights.”128
According to the prevailing practice in Canada, Natives, despite their assertion of
aboriginal title, are only paid oil, gas or mineral royalties if they have interest in specifically
designated lands. Also according to practice, Aboriginal people do not hold the authority to
grant dispositions for resource development.129
In order to exploit the natural resources in either
reserve lands or title lands, Aboriginal people must surrender to the Crown their interests in
conformity with Sections 38 to 41 of the Indian Act. Section 37(2) of the Indian Act enunciates:
“Except where this Act otherwise provides, lands in a reserve shall not be leased nor an interest
in them granted until they have been surrendered to Her Majesty pursuant to subsection 38(2) by
the band for whose use and benefit in common the reserve was set apart.”
Even if the above section only considers “land in a reserve”, it must be interpreted to
include title land. Indeed,
“[…] aboriginal title also encompasses mineral rights, and lands held pursuant to aboriginal title
should be capable of exploitation in the same way, which is certainly not a traditional use for
those lands.”130
126
Constitution Act, 1867, http://laws.justice.gc.ca/en/const/
127
R.S.C., 1985, c. I-7, http://laws.justice.gc.ca/en/I-7/65328.html
128
129
130

When surrendered to the Crown, petroleum exploitation benefits (e.g. royalties) on
reserve or title land are collected by Her Majesty in right of Canada, in trust for the Indian bands
concerned.131
The royalty rate is however set and determined by the Minister of Indian Affairs
and Northern Development, with the approval of the council of the band concerned.132
From an investment perspective, the obligation to surrender lands to the Crown prior to
development could be supported on many grounds. First of all, confusion is avoided in the gas
industry as to the identity of the appropriate licensing authority. Second of all, development
rules and conditions could be expected to remain relatively consistent, as one same body
establishes them.133
Third of all, one may expect an added stability and confidence in rules
enacted by the Federal government in contrast to those established by individual communities.
Fourth of all, many petroleum companies already have close working relationships with the
Federal government and the land surrender obligation helps maintain this relationship in the
development of new acreage.
On the other hand, the obligation to surrender lands for development must be carefully
exercised and must not contradict the right of Indians to self-determination. The first and second
paragraphs of Section 1 of both the International Convenant on Economic, Social and Cultural
Rights134
and the International Convenant on Civil and Political Rights135
enunciate that:
“All peoples have the right of self-determination. By virtue of that right they freely determine
their political status and freely pursue their economic, social and cultural development.
All peoples may, for their own ends, freely dispose of their natural wealth and resources without
prejudice to any obligations arising out of international economic cooperation, based upon the
principle of mutual benefit and international law. In no case may a people be deprived of its own
means of subsistence.”
Therefore, Section 1(2) of the above Convenants provides that Natives have the right to
control and benefit from natural resources on their lands. When land is surrendered to the Crown
for development, the Federal government must ensure that the Native groups concerned remain
131
Section 4(1) of the Indian Oil and Gas Act.
132
Section 4(2) of the Indian Oil and Gas Act.
133
Therefore, prospective investors do not have to carry out a new detailed research for every area that is
of interest to them.
134
(1976) 993 UNTS 3.
135
(1976) 999 UNTS 171.

the primary beneficiaries of any potential arrangements with petroleum companies. The
resources must be used in a way that coincides with the groups’ interests.136
3.6 Negotiated Agreements
Various agreements have been negotiated between the Federal government and
Aboriginal tribes. In the Mackenzie Valley and the Mackenzie Delta regions, one may cite the
Gwich'in Comprehensive Land Claim Agreement (December 1992), the Sahtu Dene and Metis
Comprehensive Land Claim Agreement (June 23, 1994), the Inuvialuit Final Agreement (July
1984) and the Nunavut Land Claims Agreement (July 9, 1993). 137
The Gwich'in Comprehensive Land Claim Agreement, the Sahtu Dene and Metis
Comprehensive Land Claim Agreement and the Nunavut Land Claims Agreement provide the
tribes in question with a share of resource royalties from the Mackenzie Valley. All of the four
above agreements provide mineral rights on specific areas of land (4,299 square kilometres for
the Gwich'in, 1,813 square kilometres for the Sahtu Dene and Metis, 13,000 square kilometres
for the Inuvialuit and 37,000 square kilometres for the Nunavut).138
At the present time, the Federal government is still working with individual communities
in the hope of an agreement. Some affirm that the overall climate is much more encouraging for
investors than what it was a decade ago. Throughout the late 1990s, as evidence, the Ministry of
Indian Affairs and Northern Development and the gas industry have been able to work in close
cooperation. And, in effect,
“[…] agreements have recognised and have given effect to past resource dispositions. Aboriginal
people have not been concerned to prevent development and indeed have been proponents of oil
and gas development, once they have been given an opportunity to participate in the economic
benefits.”139
However, some warn that:
136
A. Cassese, Self Determination of Peoples: A Legal Reappraisal, pp. 57-59.
137
E., Weick, Native Claims, Visited on March 8, 2001,
http://members.eisa.com/~ec086636/native_claims.htm
138
Ibid.
139

“[t]he age of First Nations representatives is declining, and their relative youth is sometimes
accompanied by impatience. Time may be short; shorter that what is required for effective
consensus-building, comprehensive regime-building, and systematic planning. Experience with
land claims might suggest that a final settlement on all deals of offshore development without
demonstrations and some degree of political confrontation. The danger is excessive
expectations.” 140
4. LICENSING TERMS
Section 13(1) of the Canada Petroleum Resources Act is clear on the fact that only the
Federal Minister of Natural Resources can issue interests141
in regards of frontier lands. Before
issuing interests in land, the Minister of Natural Resources must make a call for bids in
accordance with Section 14 of the Canada Petroleum Resources Act.
Section 24 of the Canada Petroleum Resources Act governs the nature of licensing terms
and conditions on Crown Lands. According to this Section:
“1) An exploration licence shall contain such terms and conditions as may be prescribed and may
contain any other terms and conditions, not inconsistent with this Act or the regulations, as may
be agreed on by the Minister and the interest owner of the licence.
(2) The Governor in Council may make regulations prescribing terms and conditions required to
be included in exploration licences issued in relation to all frontier lands or any portion
thereof.”142
Essentially, an examination of licensing terms will therefore encompass two focal
aspects:
- The method of award of interests; and
- The terms and conditions contained in granted interests.
The following sections will examine which choices regarding these two aspects are most
appropriate in promoting investment in frontier areas. This examination will inform the reader
140
Maritime Awards Society of Canada, B.C. Offshore HydroCarbon Development: Issues and
Prospects, March 2001, p. 15, Visited on August 12, 2001,
http://www.penr.bcit.ca/petrotech/OffshoerHydrocarbonreport.pdf
141
Section 2 of the Canada Petroleum Resources Act defines interest as including: “any former
exploration agreement, former lease, former permit, former special renewal permit, exploration licence,
production licence or significant discovery licence”.
142
The same rule applies to Significant Discovery Licences (Section 30(3), Canada Petroleum Resources
Act) and to Production Licences (Section 38(3), Canada Petroleum Resources Act).

of the various forms licensing terms may take and will take into account the recommendations
of experts in the field.
4.1 Method of Award
In awarding licences, a government will have the choice between two major allocation
methods: the auction method, typical of Canada and the United States and the discretionary
method, typical of the United Kingdom.
In an auction system, licences are awarded to the highest qualified bidder. Conversely, in
a discretionary system, government officials award licences according to a body of pre-
determined criteria, political or administrative. This section will offer a comparison between the
auction and the discretionary methods of allocation and will re-evaluate Canada’s decision to
opt for the auction method of award.
Just as a clarification point, various terms are used around the world to describe licensing
arrangements. In Australia, Norway and the UK, the term ‘licence’ is used. If the grant is
restricted to exploration, it may be called a ‘permit’. On the other hand, if it refers to
exploitation activities, it may be referred to as a ‘lease’. The terms ‘permit’ and ‘lease’ are
actually employed in Canada143
and the United States.144
In Canada, the term licence is also used, as specific types of licences need to be issued in
conjunction with a permit or a lease.145
It is important to explain that licences, leases and
143
Section 2, Canada Petroleum Resources Act, Sections 10, 15, 20, 22, Indian Oil and Gas Act.
144
P., Cameron, Petroleum Licensing: A Comparative Study, p. 5. Less frequently today, one may
sometimes come across the use of the word concession. “The term "concession" does not have a clear
meaning in international law. To the extent that it is understood as necessarily involving the outright
grant of exclusive exploration and production rights for a very extended period of time, with very small
compensation to the host country, and without any control by the government over operations, the
concession system is now dead. However, if an oil concession is more broadly defined as an exclusive
grant of exploration and production rights in exchange for payments to the government based upon
production, then concessions are in fact the most prevalent form of agreement in the world today.” D. G.,
Ebner, Smaller Exploration Companies on the International Frontier, 37 Nat. Resources J. 707, p. 712.
145
For instance, Section 34(1), Canada Oil and Gas Land Regulations, C.R.C.-c.1518,
http://laws.justice.gc.ca/en/T-7/C.R.C.-c.1518/163513.html, states that “[a] permittee must be the holder
of a licence before he may carry out exploratory work on Canada lands.” It should be noted that there are

permits (often referred to as dispositions) may be auctioned.146
For the sake of simplicity and to
stay consistent with the academic literature, the term licence throughout the rest of this section
comprises also permits and leases.
Licences may be sought either through a government invitation (invited applications) or
by the own initiative of the persons interested (non-invited applications). Non-invited
applications will have a tendency to be non-competitive in nature. In fact, they will seldom be
used in the discretionary licence allocation systems. In addition, they certainly contradict the
spirit of the auction method.147
It is important to note that governments will benefit more from increased competition
between applicants. In an auction system, the applicants will tend to bid higher. Conversely, in a
discretionary system, competition will encourage applicants to submit more attractive offers.
4.1.1 The Discretionary Licence Allocation System
In the discretionary system, government civil servants are assigned the task to rank the
applicants according to a defined set of criteria, sometimes referred to as the ‘bidder
dimensions’. Basically, the ‘bidder dimensions’ represent the civil servants’ examination of the
following characteristics:
- The applicant’s past performance;
- The applicant’s competence to explore the area offered for licensing;
- The applicant’s exploration plan for the area; and
- The applicant’s financial strength.148
three categories of licences: (a) Exploration licence (Section 22, Canada Petroleum Resources Act); (b)
Significant discovery licences (Section 29, Canada Petroleum Resources Act);
(c) Production licence (Section 37, Canada Petroleum Resources Act);
146
Articles 14 and 2, Canada Petroleum Resources Act.
147
T., Daintith, and G., Willoughby, Manual of United Kingdom Oil and Gas Law, p. 21.
148
K., Sinding, Auctions and Discretion in Oil and Natural Gas Licensing,, p. 26. The selection criteria
that may be used are enumerated in detail in P., Cameron, supra note 144, pp. 25-26.

It is important to note that the above criteria may somewhat contain an element of bidding in
them. The exception would be where the government needs to make a qualitative assessment of
an application.149
One important point of worry with the discretionary system is the fear of corruption in
the civil servants’ body. Interestingly, it is believed that mere suspicions of corruption might
reduce the efficiency of the entire licensing system.150
4.1.2 The Auction Licence Allocation Method
The auction mechanism includes various types of bidding. In Federal licensing auctions,
even though the Petroleum Resources Act is silent over the bid criterion to be used151
, the bid
criterion currently used is the value in Canadian dollars of the work proposed for the first period
of the licence.152
The government may choose to conduct various other types of bidding such as bonus
bidding, royalty bidding or profit bidding. In the bonus type of bidding, the winner of the bid
has to pay the bonus at the outset for the licence. On the other hand, in the royalty type of
bidding, the applicants will specify the royalty rate they are willing to pay if a discovery is
made. Finally, in the profit-bidding scheme, the applicants will specify what share of profits
they are willing to transfer to the government. 153
Work commitment bidding, royalty bidding and profit bidding are thought to be very
attractive to the applicants. Indeed, these mechanisms keep petroleum companies from having to
pay, upfront, large amounts of money in order to obtain a licence. Generally, this is an
acceptable result since governments tend to have lower discount rates than private companies.
149
Ibid.
150
P., Cameron, supra note 144, p. 19.
151
Section 14(2)(g) of the Canada Petroleum Resources Act.
152
Indian and Northern Affairs Canada, Northern Oil and Gas Annual Report 2000, p. 7, Visited on
August 6, 2001, http://www.ainc-inac.gc.ca/oil/Pdf/report00.PDF
153

Nonetheless, these mechanisms might not always be possible to institute, especially if the public
treasury of the host country is poor.154
One essential worry with the auction system is the risk of collusion in the bidding. As
Geoff Frewer writes:
“[O]wnership of infrastructure provides consortia with strategic assets giving significant market
power in the vicinity of the infrastructure. As a consequence, the number of consortia bidding for
acreage may be quite small even though there are a larger number of companies involved, and this
gives rise to concerns about collusion between bidders reducing the level of the bids”.155
When it comes to fair play on the part of the government, the auction mechanism is
thought to be relatively transparent. According to Geoff Frewer, transparency is achieved since
it is more difficult for governments to discriminate under an auction system, in favour of a
certain specific group of applicants.156
It is crucial to understand that the auction method may incorporate some discretionary
elements in the selection of licensees. Therefore, even under the auction mechanism, the ‘bidder
dimensions’ may be evaluated. Professor Kenneth W. Dam rightfully argues that:
“One could use a simple formulation such as that to be found in the U.S. Outer Continental Shelf
Lands Act of 1953 permitting the licensing authority to reject bidders who are not ‘qualified’ and
‘responsible’. The discretion granted to the licensing authority would not be greater than it was
under the British system. But one could also impose more detailed requirements. Just as one could
easily exclude from bidding eligibility all corporations not incorporated locally, so one could also
if blessed with skill in legal drafting, assure that all bidders had the requisite financial resources
and technical know-how and could specify in advance a minimum level of drilling activity for
each block.”157
It is crucial for the reader to keep this last quote in mind throughout the rest of this section.
As it will be demonstrated, this last contention constitutes the backbone of many arguments in
support of the auction mechanism.
154
K., Sinding, supra note 148, p. 15.
155
G., Frewer, Auctions vs. Discretion in the Licensing of Oil and Gas Acreage, in G., MacKerron, and
P., Pearson,(eds.), The International Energy Experience: Markets, Regulation and the Environment, p.
168.
156
Ibid.
157
K., W., Dam, Oil Resources: Who Gets What How?, p. 33.

Now that the functioning of the auction and discretionary methods of award has been
compared, it should be examined which one is more efficient in achieving the typical
governmental objectives sought in licensing arrangements.
4.1.3 Comparison of the Auction and the Discretionary Methods in the Achievement of
Government Objectives
This section will start by examining which licence allocation method is better able to
conciliate the interests of both the licensees and the government in the sharing of economic rent.
4.1.3.1 Capture of Economic Rent
Economic rent occurs when the value of the extracted resources exceeds all operating
and management costs. When costs are just slightly greater than costs, then we will speak of a
‘marginal field’.
The auction mechanism, and more precisely the bonus-bidding type of auction, is
believed to be an efficient way for the government to capture economic rent from the outset of
the licence. This is an important advantage, since, as Geoff Frewer mentions, timing of the
receipts may be important, especially when government finances are under pressure.158
When it comes to bidder psychology, each applicant is ready to sacrifice a certain
amount of the expected economic rent in return for the licence. As applicants try to outbid each
other, larger part of the economic rent is transferred to the government.
One risk faced by applicants is to bid higher than the real value of the economic rent.
This, however, should be of rare occurrence since applicants usually apply a large degree of
cautiousness. Moreover, as Professor Kenneth Dam notes:
“A company that consistently overestimates the value of oil properties will tend to disappear
from the business. At the very least, it will hire better geologists.”159
Furthermore, Geoff Frewer, speaking of the harms overbidding, warns that:
158
G., Frewer, supra note 155, p. 169.
159
K., W., Dam, supra note 157, p. 6.

“In the short run, [overbidding by applicants] might inflate the revenues received by the
government but in the longer term it could depress industry returns and lead to sub-optimal or
cyclical investment levels.”160
In comparison with the auction system, the discretionary method is thought to be less
effective in capturing economic rent early in the life of a licence. Governments applying the
discretionary method will therefore have to seek, after the licence has been awarded, alternative
methods to recapture the economic rent. The principal recapture methods used are royalties,
taxation and government participation. These instruments can be used either in combination or
separately. For petroleum companies, these ‘retrospective measures’ constitute an important risk
and may discourage investment.
4.1.3.2 Avoidance of Licensee Working Capital Depletion
It is important for any government to maximise investment in exploration and to achieve
a fast rate of development and production. One traditional argument in favour of the
discretionary method of allocation is that it avoids the depletion of the licensees’ working
capital. The reasoning behind this argument is that the licensees do not have to spend large
amounts of money from the outset of the licence as it is done under the auction method.161
Such an argument is based on many assumptions that compromise its validity. The first
assumption is that the auction mechanism imposes the full payment of the bid from the outset of
the licence. As Professor Dam notes, the bid can very well be paid in instalments over the span
of the licence. Moreover, the bidding may take place in terms of work value or royalty and not
necessarily in terms of cash.162
This argument also assumes that the applicants in the auction mechanism will go as far
as to compromise their exploration resources just to win the licence. Actually, even if this was
the case, trading in licences may still be possible.163
160
G., Frewer, supra note 155, p. 167.
161
162
163

As a final point on this topic, it has been advanced that:
“[F]inancing problems that have arisen in obtaining large-scale funds for development are largely
a consequence of the discretionary licensing system itself or of the uncertainty created by the
threat of new government regulation and taxes.”164
4.1.3.3 Promotion of Small and Medium Sized Applicants
The discretionary method is thought to be more efficient in the promotion of small and
medium sized applicants. The reasoning behind this argument is that smaller companies do not
have the financial resources to outbid large companies. A barrier to entry is thus created.165
Here again, the auction approach may adopt some discretionary dispositions favouring
these small and medium sized companies. Actually, this argument ignores two important facts.
Firstly, smaller companies may enter into joint bidding in order to increase their chances to win
the licence. Secondly, smaller companies may simply refuse to bid higher than larger ones
simply because they do not have the same estimations of tract value.166
4.1.3.4 Promotion of Local Suppliers
Another argument in favour of the discretionary approach is that it may better protect the
local industry. Knud Sinding identifies two implications in pursuing a ‘buy local’ policy: rule-
making and enforcement.167
A ‘buy local’ policy may either be found within the body of the licence or in external
statutory rules. Such a policy may take various forms. Under one possibility, the licensee may
be obliged to buy local supplies when they are competitive with foreign suppliers.168
Another
possibility would be to impose a tariff on imported foreign supplies.169
164
165
166
Ibid.
167
Ibid., p. 23.
168
E.g. Section 45 (3)(d) of the Canada-Nova Scotia Agreement: “consideration shall be given to
services provided from within the Province and to goods manufactured in the Province, where those
services and goods are competitive in terms of fair market price, quality and delivery”; or Section 45
(3)(b) also of the Canada-Nova Scotia Agreement: “[…] individuals resident in the Province shall be
given first consideration for training and employment in the work program for which the plan was
submitted and any collective agreement entered into by the corporation or other body submitting the plan

Scholars have expressed many doubts on the efficiency of ‘buy local’ obligations. In
some cases, local suppliers, of either goods or services, may just be unable to supply the
minimal level of quality required by the government or the licensee. In such case, an exemption
could be justified. The problem now is: who is in position to grant an exemption? Should the
host government create a special administrative body to monitor purchasing decisions? Indeed,
it could be very difficult to enforce ‘buy local’ policies. Certainly, the text of the licence or the
statutory rule containing the ‘buy local’ policy cannot be specific enough to enumerate all
possible scenarios that may arise in practice.170
Is the discretionary method really this much more capable to implement a ‘buy local’
policy? Nothing keeps governments running under the auction approach from specifying before
the start of the bidding that the winner must carry a “buy local’ policy. Host governments may
also, as it is done in Canada, enact such a policy in a statutory rule (private or public). It might
seem unattractive to the industry but nonetheless it is possible.
4.1.3.5 Limitation on the Entry of Foreign Oil Companies
The limitation of the entry of foreign oil companies is thought to be best achieved under
the discretionary method of allocation. It has especially been an objective among the North Sea
countries. As Professor Peter Cameron notes:
“It is not simply a desire to avoid having profits flow out of the country at some future date. A
government will probably wish to give its domestic industry a stake […] or let its domestic
concerns learn on the backs of foreign oil companies e.g. through joint ventures.”171
Here again, under the auction approach, all that is required to achieve the same result is to
draft the appropriate conditions on bidder qualifications. Therefore, one could exclude from
bidding eligibility all corporations that are not locally incorporated.172
For example, in Canada,
the Federal Minister of Natural Resources cannot grant an oil or gas lease to a corporation
and an organization of employees respecting terms and conditions of employment in the offshore area
shall contain provisions consistent with this paragraph.”
169
170
Ibid.
171
172

incorporated outside of Canada.173
Moreover, to be able to hold a lease, at least 50 per cent of
the issued shares of the corporation must be owned by persons who are Canadian citizens or by
corporations whose shares “are listed on a recognized Canadian stock exchange and that
Canadians will have an opportunity of participating in the financing and ownership of the
corporation”.174
4.1.4 Method of Award: Recommendations
The auction mechanism may incorporate discretionary conditions that allow
governments to benefit from the ‘best of both worlds’. For instance, nothing keeps a host
government from conducting an auction on the condition that the winner adopts a ‘buy local’
policy. Similarly, the host government can limit participation in bidding only to small or
medium sized companies.
Under the auction system, governments can still maintain a reasonable level of control
after the award of the licence. Actually, since the auction approach allows for the capture of
economic rent from the outset of the licence, the undesirable effects of recapture methods are
avoided to a certain extent.
Even when it comes to acreage on which little information is available or acreage in
frontier areas, the auction mechanism through its royalty bidding option may still be an
advisable solution. It effectively ‘spares’ companies from the risk of losing money both on the
award of the licence and the exploration of the acreage.
As an example of the rewards of the auction approach in Canada, in 1999, firms bid over
$72.5 million in work commitments for four parcels in the Mackenzie Delta region.175
According to the Northwest Territories Department of Finance:
“This is a significant amount of work commitment and represents renewed interest in the area.”176
173
Section 54(2)(b), Canada Oil and Gas Land Regulations.
174
Section 54(2)(c), Canada Oil and Gas Land Regulations.
175
L.,Coad, et al., supra note 31, p. 23.
176
Ibid.

Zaid Mahayni - 2001 CEPMLP LLM Dissertation

Zaid Mahayni - 2001 CEPMLP LLM Dissertation

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Viewers also liked

Viewers also liked (11)

Similar to Zaid Mahayni - 2001 CEPMLP LLM Dissertation

Similar to Zaid Mahayni - 2001 CEPMLP LLM Dissertation (20)

Zaid Mahayni - 2001 CEPMLP LLM Dissertation