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 (2

nd 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.

http://laws.justice.gc.ca/en/C-8.5/text.html

http://www.neb.gc.ca/energy/ngma96.pdf


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: [email protected]

mailto:[email protected]


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 National Energy Board, supra note 5, p. 17.

http://www.neb.gc.ca/about/ar/2000/ar2000.pdf

http://www.geo.ucalgary.ca/NatGasCan/intro.htm


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.

http://www.neb.gc.ca/energy/emagdel.pdf



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

National Energy Board, supra note 5, p. 12. 22

National Energy Board, supra note 11, p. vii. 23

Ibid.

http://www.eia.doe.gov/oiaf/servicerpt/naturalgas/pdf/oiaf00102.pdf


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


Ibid.

http://www.fin.gov.nt.ca/pipeline/A_Comparison_of_Natural_Gas_Pipleine_Options_for_the_North1.pdf


http://tabla.geo.ucalgary.ca/NatGasCan/opipaper.pdf


“[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.

http://www.neb.gc.ca/energy/emadp00.pdf


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


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.)

http://www.eea-inc.com/compass/co0800a.pdf


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 141oW

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

http://www.dfait-maeci.gc.ca/foreignp/agenda2003/pdfs/dfait-e.pdf


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.

http://www.icj-cij.org/icjwww/idecisions/isummaries/icigmsummary820120.htm

http://www.icj-cij.org/icjwww/idecisions/isummaries/icigmsummary820120.htm


“[…] 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.

http://laws.justice.gc.ca/en/C-7.8/22527.html




(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.

http://www.boundary-dispute.ca/


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.

http://laws.justice.gc.ca/en/const/


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


[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


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.

http://laws.justice.gc.ca/en/I-5/64916.html


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

Delgamuukw v. British Columbia, supra note 116, par. 122. 129


Delgamuukw v. British Columbia, supra note 116, par. 122.

http://laws.justice.gc.ca/en/const/



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

R. H., Bartlett, supra note 103, p. 15.

http://members.eisa.com/~ec086636/native_claims.htm


“[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).

http://www.penr.bcit.ca/petrotech/OffshoerHydrocarbonreport.pdf


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

http://laws.justice.gc.ca/en/T-7/C.R.C.-c.1518/163513.html


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

P., Cameron, supra note 144, p. 17.

http://www.ainc-inac.gc.ca/oil/Pdf/report00.PDF


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


K., W., Dam, supra note 157, p. 33. 163

K., Sinding, supra note 148, p. 19.


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



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


Ibid. 171


K., W., Dam, supra note 157, p. 33.


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.


4.2 Licence Terms and Conditions

4.2.1 Duration of the Licence

As Professor Peter Cameron comments:

“[t]he lead-time between initial award and actual production (if any) will be longer in frontier

areas, particularly deep water areas (i.e. over 600 feet deep). As a result, the conventional

duration of a licence, with an initial period of, say, five to six years, might seem too brief to

attract investment. A longer period would obviously make the acreage more attractive to the oil

companies, but it would also increase the risk that they might approach exploration with

insufficient haste as far as government is concerned.”177

According to Section 26(2) of the Canada Petroleum Resources Act, the general rule is

that the term of an exploration licence shall not exceed nine years from the effective date of the

licence and shall not be extended or renewed. However, this rule is subject to various

exceptions. For instance, Section 27(1) establishes that:

“[w]here, prior to the expiration of the term of an exploration licence, the drilling of any well has

been commenced on any frontier lands to which the exploration licence applies, the exploration

licence continues in force while the drilling of that well is being pursued diligently and for so

long thereafter as may be necessary to determine the existence of a significant discovery based

on the results of that well”

Therefore, it could be concluded that despite the rigidity of the general rule, the overall

law that applies is appropriate for frontier area conditions.178

4.2.2 Size of Area

Experts have suggested that increasing the size of acreage blocks put for licensing could

help in attracting investment to an area. Indeed,

“An individual firm will attempt to obtain a reasonable spread of acreage in order to be

represented in the different types of ‘play’ which may emerge. A ‘play’ is a geographically

defined areal trend where current evidence suggests there are prospects of finding hydrocarbons

in commercial quantity.”179

It could therefore be recommended that Canadian licensing authorities examine whether

larger licensing blocks have attracted greater work commitments in past call for bids. Perhaps a

trend will appear in the light of the above suggestion. If not, licensing authorities can test the

177


The rule is the same under the Canada-Newfoundland Agreement (Sections 69 and 70), and the

Canada-Nova Scotia Agreement (Sections 72 and 73). 179

P., Cameron, supra note 144, p. 177.


above theory in future licensing rounds. From a company perspective, larger licence blocks will

definitely reduce the ‘risks’ of having to enter into compulsory unitization agreements.180

180

Section 38, Canada Oil and Gas Operations Act, R.S.C. 1985, c. O-7; Basically, if a gas reservoir

underlies two separate licence blocks, the concerned licensees may be ordered by the Oil and Gas

Committee to enter into a compulsory unit agreement aiming for the development of the deposit as if it

was beneath one single licence unit. This is done to prevent waste and competitive drilling.


CHAPTER IV: FISCAL PROSPECTIVITY

1. IMPORTANCE OF THE ISSUE

The importance of the fiscal terms imposed cannot be underestimated. As one author

notes:

“Taxation can play a decisive role in the promotion of investments into petroleum exploration

and production […] If tailored properly fiscal terms are able to achieve the dual objective of

collecting an adequate share of the economic benefit generated by the oil industry for the

government while encouraging the exploration of new fields.”181

The Canadian taxation regime is complex since the Canadian Constitution Act of 1867

confers taxation powers to both Federal182

and Provincial183

levels of government.

A description of the Canadian fiscal system in relation to gas would justify the writing of entire

volumes. The presented study does not have as a purpose the detailed scrutiny of the Canadian

fiscal legislation but rather, the general consideration of the characteristics sought by investors

in a fiscal system.

2. ATTRACTIVENESS OF BACK-ENDED FISCAL TERMS

The fact that the gas industry is characterized by high costs that must be paid from the

outset of the project, as it will be demonstrated later in the body of this paper, justifies more

back-ended fiscal provisions. Basically, what back-ended provisions imply is a lower

government take during the initial stage of petroleum exploration, development and production.

Back-ended provisions have the advantage of enhancing the investors’ net present valuation of

the potential rewards of an investment.184

“Governments should be willing to accept low revenues early in a mineral [or petroleum] venture

(i.e. low taxes, royalties, etc.) in exchange for higher ones later on and conversely for the

company. The net result should be that the company reduces risk by getting its money early and

also achieves a higher rate of return, and the government gets more total revenue in the long run

plus longer life from the project, sustained employments, and other sustained benefits.”185

181

M., A., Garcia Schreck, supra note 3, p. 2. 182

Section 91(3), Constitution Act, 1867. 183

Sections 92(2) and 92A(4), Constitution Act, 1867. 184

M., A., Garcia Schreck, supra note 3, p. 25.


Due to the long-term nature of investment in the gas industry, investors will seek legal,

political and monetary stability for the duration of their venture. To create stronger incentives

for long-duration investments, host governments should provide enough guarantees and

assurances of fiscal stability. For example, even though historically, the UK’s fiscal regime has

been lenient in comparison with most other petroleum producing countries, international oil

companies exploiting the North Sea still perceived the system as uncertain and believed that the

state of things would turn against their interests.186

Attracting investment therefore implies a

psychological element that must be satisfied.187

Long-term investment also necessitates equity in the design of a fiscal system. For

instance, longer capital depreciation write-off periods will impact the economics of long-term

projects by pulling forward tax payments and increasing the level of borrowings.188

It should be noted that the hosting government might either tax the oil companies as if

they were part of any other sector of the economy or they could establish a distinct taxation

system strictly for petroleum revenues. The licensees may be imposed in accordance to one or

both of these systems.

3. ROYALTIES

Royalty poses different disadvantages to both companies and the host government.

From the point of view of the companies, royalties are a typical example of front-ended

fiscal mechanisms, since they are payable since the start of production. Here, a given amount of

185

H. E., Johansen, et al., supra note 47, pp. 34-35. 186


“To protect against increased taxation following contract execution, it is quite common to include a

stabilization clause in the contract fixing the income tax rate for the life of the contract. Such clauses

prohibit increases in the effective tax rate prevailing at the time of contract execution and provide that

any subsequent changes in the taxation level will be non- discriminatory, imposed by the host country

equally upon all industries, or determined in consultation with the company, with a view to preserving

the anticipated return on capital.”, See D. G., Ebner, supra note 144, p. 713. 188

Industry Science Resources (ISR), LNG Action Agenda 2000, October 2000, p. 32, Visited on April 8,

2001, http://www.isr.gov.au/resources/lng/actionagenda.pdf

http://www.isr.gov.au/resources/lng/actionagenda.pdf


royalty will have more impact than the same amount in income tax on notions such as the

internal rate of return or on the net present value.189

From the point of view of the government, one disadvantage with royalties, and it

applies to royalty bidding as well, is that royalties may lead to premature abandonment, what is

sometimes referred to as ‘high-grading’. Indeed, since royalties are a form of excise tax, costs

are not subtracted from revenues when calculating royalties. For a licensee, royalties constitute a

marginal cost. As production costs increase towards the end of the life of a field, the addition of

a royalty cost to the licensee might render the production unprofitable.190

One solution would be to establish a system of sliding scale royalties. A sliding scale

royalty will vary depending on the size of the field. A larger field will have to pay higher

royalties than a smaller one. One problem with this ‘solution’ is that larger fields may have

higher development costs. For instance, a large field may be situated in deeper water or perhaps

on a risky terrain. Moreover, large fields will often necessitate the construction of pipelines,

contrarily to small fields, which could be very well served with tanker loading. Pipeline

construction is a large expense that must take place early in the life of a field, whereas tanker-

loading costs may be spread out over the life of a field.

In summary, even when sliding scale royalties are introduced, such as in the Netherlands

and Norway, these may still fail to prevent early abandonment of a field.191

As a correction, we

suggest a sliding scale royalty that decreases in accordance with the total remaining recoverable

reserves.

In respect to Crown lands, Section 55(1) of the Petroleum Resources Act stipulates that:

“[t]here are hereby reserved to Her Majesty in right of Canada, and each holder of a share in a

production licence is liable for and shall pay, in accordance with the regulations, such royalties

as may be prescribed, at the rates prescribed, in respect of petroleum produced from frontier

lands and in respect of the periods prescribed.”

189


On the issue of ‘high-grading’, please refer to K., Brewer, et al, Economic Approaches to

Nonrenewable Resource Taxation, 11 J. Nat. Resources & Envtl. L. 175 (1996), p. 180.


Enabled by the above Section, Section 3 of the Frontier Lands Petroleum Royalty

Regulations192

establishes a royalty rate on the following basis:

“The prescribed royalty payable to Her Majesty under subsection 55(1) of the Act by each

interest holder is

(a) in respect of petroleum produced from project lands in a month preceding the month of

payout193

(i) beginning with the first production month and ending with the eighteenth production month,

one per cent of the gross revenues of the interest holder from that petroleum,

(ii) beginning with the nineteenth production month and ending with the thirty-sixth production

month, two per cent of the gross revenues of the interest holder from that petroleum,

(iii) beginning with the thirty-seventh production month and ending with the fifty-fourth

production month, three per cent of the gross revenues of the interest holder from that petroleum,

(iv) beginning with the fifty-fifth production month and ending with the seventy-second

production month, four per cent of the gross revenues of the interest holder from that petroleum,

and

(v) beginning with the seventy-third production month and ending with the last production

month preceding the month of payout, five per cent of the gross revenues of the interest holder

from that petroleum, or

(b) in respect of petroleum produced from project lands in the month of payout or any month

thereafter, the greater of

(i) thirty per cent of the net revenues of the interest holder from that petroleum, and

(ii) five per cent of the gross revenues of the interest holder from that petroleum

less

(c) a credit equal to the lesser of

(i) the amount of the investment royalty credit balance of the interest holder in respect of the

month in which payment of the prescribed royalty is due, and

(ii) the amount calculated for that interest holder under paragraph (a) or (b).

(2) For the purpose of calculating the prescribed royalty referred to in subsection (1), the

petroleum produced from project lands shall be measured at the point of production.”

In essence, the Federal royalty rate is established on a sliding-scale basis, prior to the

month of payout, the point where “the cumulative adjusted gross revenues of the interest holder

in relation to the project are equal to or greater than the adjusted cumulative cost base”. After

which, it follows a fixed rate.

The Federal legislation imposes what is known as an ad-valorem royalty, based on the

value of the hydrocarbons sold. This allows the government to benefit from changes to the price

191

Ibid. 192

Frontier Lands Petroleum Royalty Regulations, SOR/92-26, http://laws.justice.gc.ca/en/C-8.5/SOR-

92-26/37540.html 193

As defined in Section 2 of the Frontier Lands Petroleum Royalty Regulations, “month of payout of an

interest holder of a production licence in relation to a project means the first month in respect of which

http://laws.justice.gc.ca/en/C-8.5/SOR-92-26/37540.html



of gas and increase its tax revenues in times of rising prices. This approach also allows

government revenues keep pace with inflation.194

One criticism however would be that the Federal fiscal regime does not vary with

production, as it is done in Alberta or Saskatchewan.195

This may lead, as it has been remarked

above, to the early shutdown of fields when production costs become too high in comparison to

revenues. One proposed solution would be to establish an allowance for wells producing below

a certain threshold.

Canada should also consider substituting its royalty rate for a fiscal measure such as the

resource rent tax (RRT). The RRT, sometimes referred to as the additional profit tax, may be

defined as a tax that is only payable once positive cash flows in a project have fully offset

negative cash flows plus an interest fixed at the threshold rate of return.196

What is nice about RRTs is that they are back-ended and allow investors to earn a

specified rate of return and recover their initial capital investment before the tax becomes

imposed. If the threshold rate of return is set slightly above the investors’ discount rate then

investment will be encouraged even more.197

Certainly, RRTs do not guarantee revenues the way royalties do and are more difficult

for civil servants to administer. Certainly also, RRTs may theoretically discourage the

improvement of efficiency. However, investors are pleased under a system in which the

government carries a share of the exploitation and development risks. Also, as Marcial Alberto

Garcia Schreck notes:

the cumulative adjusted gross revenues of the interest holder in relation to the project are equal to or

greater than the adjusted cumulative cost base of the interest holder in relation to the project.” 194

J. M., Otto, Legal Approaches to Assessing Mineral Royalties, in J. M., Otto, Taxation of Mineral

Enterprises, p. 133. 195

Alberta Resources Development, Oil and Gas Fiscal Regimes of the Western Canadian

Provinces and Territories, June 1999, p. 20, Visited on August 6, 2001,

http://www.resdev.gov.ab.ca/room/keypubs/images/fisreg.pdf 196

P., Daniel, Evaluating State Participation in Mineral Projects: Equity, Infrastructure and Taxation, in

J. M., Otto, supra note 194, p. 177. 197


http://www.resdev.gov.ab.ca/room/keypubs/images/fisreg.pdf


“If the project is successful the present value the government will receive will typically be higher

under a RRT based system than under a bonus or royalty system. In a sense the government will

receive higher revenues as a reward for accepting more risk.”198

4. INCOME TAXES

An income tax will be calculated according to profits. Therefore, the costs will be

deducted from the revenues. For the licensee, one advantage of being faced with income taxes,

instead of for example higher royalty rates, is that the income taxes will only have to be paid

many years after the investment is made. Since a dollar spent tomorrow has less value than a

dollar spent today this is of great importance to the petroleum companies, especially since the

amounts in question are often in terms of hundreds of millions of dollars.199

Income taxes, just like royalties, can lead to the early abandonment of marginal fields.

According to Professor Dam, this is particularly possible when the tax applied on oil production

is higher than that applied on other sectors of the economy.200

Section 123(1) of the Income Tax Act sets the basic Federal income tax rate. According

to this Section,

“[t]he tax payable under this Part for a taxation year by a corporation on its taxable income or

taxable income earned in Canada, as the case may be, […] for the year is, except where

otherwise provided, 38% of its amount taxable for the year.”

A company licensed on Provincial territory may benefit from tax abatement, in accordance with

the terms of Section 124(1) of the Income Tax Act.

“There may be deducted from the tax otherwise payable by a corporation under this Part for a

taxation year an amount equal to 10% of the corporation's taxable income earned in the year in a

province.”

Additionally, the Federal legislation imposes a corporate surtax. Indeed, according to Section

123.2,

198

Ibid. 199

Ibid., pp. 135-136. Please see also, P., Cameron, supra note 144, p. 11. 200

Ibid., p. 137.


“There shall be added to the tax otherwise payable under this Part for each taxation year

by a corporation […] an amount equal to 4% of the amount”.

It should be noted that in accordance with Section 181.1(1) of the Income Tax Act, a

large corporations tax is levied under the following terms:

“Every corporation shall pay a tax under this Part for each taxation year equal to 0.225% of the

amount, if any, by which

(a) its taxable capital employed in Canada for the year

exceeds

(b) its capital deduction for the year.”

5. DEDUCTIONS AND WRITE-OFFS

To the above rules, various deductions are allowed. According to Section 66(1) of the

Income Tax Act, exploration and operating expenses may be expensed. However, according to

Section 18(1)(m) of the Income Tax Act, no deductions can be made in respect of royalty.

As established in Schedule II and Section 1100 of the Income Tax Regulations, certain

investments costs can be recovered on the following basis:201

- Development drilling costs are depreciated up to 30 per cent on a declining balance basis;

- Capital costs are depreciated at 20-25% a year;

- Property or lease acquisition costs (including bonuses and rentals) are written off at 10% on a

declining balance basis;

- Pipelines are depreciated 4% straight-line.

Investors prefer faster write-off periods for their expenses and assets. This renders the

fiscal burden more favorable in terms of payback period and increases the net present valuation

of a project’s returns.202

Additionally, it could be remarked that:

201

See also Canada’s Petroleum Law – June 2000, in HIS Energy Group, World Petroleum Laws. 202



“[…] the quicker the recovery is made the more advantageous it will be for the investor in that it

will limit it’s risk of having funds exposed in a foreign jurisdiction and will allow a quicker

redeployment of capital in other projects.”203

Therefore, reducing depreciation periods even further could provide the industry with

stronger incentives for investment. Even if this would mean lower tax revenues for the Federal

government, higher investment levels will achieve, in return, greater rates of economic growth

and reduced unemployment rates.

Section 1210(1) of the Income Tax Regulations establishes, in the same way, a resource

allowance that can offset the Federal tax. The resource allowance is fixed at a rate of 25 per cent

of gross revenue less operating costs and depreciation of development capital. Historically,

“[t]he resource allowance came into effect in 1976 […] It was viewed as a better way of

recognizing that provinces impose mining [and petroleum] taxes and/or royalties and to take that

fact into account, within reasonable limits, in determining taxable income. In addition, the

resource allowance was designed to offer more incentives to those who explore and develop in

Canada and to impose a greater tax liability on those who do not.”204

6. OBSERVATIONS

According to analysts, the above rules are not too onerous for the petroleum companies.

The Canadian fiscal regime has been described as “complicated but fair”.205

It has also been

described as a stable system. Indeed, no major changes have been made at the Federal level

203

United Nations, Mineral Taxation and Investment: Selected Papers, presented in the International

Seminar on Mining Taxation, (Montreal, Quebec, Canadian Institute of Mining, Metallurgy and

Petroleum (CIM), the United Nations and the Department of Economic & Social Development (DESD),

September 30-October 4, 1991), p. 25. 204

Department of Finance, Canada, Tax Expenditure: Notes to the Estimates / Projections, 2000, p. 71,

Visited on August 21, 2001, http://www.fin.gc.ca/taxep/2000/taxexpnot00_e.pdf 205

In comparison with other fiscal systems, analysts have rated the Canadian fiscal prospectivity as a one

star (very tough) to three stars system (average) depending on the province or territory. P., Van Meurs,

World Fiscal Systems for Oil, pp. 153-204.

http://www.fin.gc.ca/taxep/2000/taxexpnot00_e.pdf


since 1987 and, at the Provincial level, only minor adjustments have been made to harmonize

with Federal tax rules.206

The system of accelerated write-offs provided acts as a good incentive since costs can be

deducted early enough so that taxes will be applied only when it is clear that a project will be

profitable.207

However, as a criticism, one could reproach that depletion allowances have been phased

out.

“Prior to 1990, taxpayers were entitled to earn an extra deduction of up to 33 1 /3 per cent of

most exploration and development expenses or the costs of assets related to new mines [or fields]

or major expansions. The deductions for earned depletion are generally limited to 25 per cent of

the taxpayer’s annual resource profits, although mining [or petroleum] exploration depletion can

be deducted against non-resource income.”208

206

Natural Resources Canada, Lessons from Canadian Mineral Taxation: An International Context, in

the International Seminar on Mining Legislation, (Porto, Portugal, United Nations Economic

Commission for Europe, March 13-14, 1997), p. 39. 207

Department of Finance, supra note 204, p. 75. 208

Ibid., p. 72.


CHAPTER V: GEOPOLITICAL PROSPECTIVITY

1. CANADA: A DEREGULATED GAS MARKET

Before describing the events that specifically marked the evolution of Canadian gas

markets towards gas liberalization, it is important to portray the typical mechanisms used by any

gas industry to achieve this goal. This will be the focus of the following sections.

1.1 Development Stages of a Gas Industry: The Pre-Competition Phase

The gas industry has been for a long time the perfect example of natural monopolies.

This is explained by the high infrastructure costs and the desire of States to regulate through

ownership.

“A gas transportation system involves huge sums of investment and little or no salvage value, in

general pipelines are protected by appreciable barriers to entry and face high barriers to exit.

Therefore, once established, a pipeline is often in a good position to exercise market power. In

some government’s view this in itself is an argument for regulatory supervision.” 209

According to the analysts, competition is generally introduced late in the development of

a gas industry, only in the stage of ‘transition towards maturity’.210

In this stage, where, for

instance, the European Union would be situated as it is today, natural gas has been able to

penetrate all profitable segments of the market and now authorities are under national and

foreign pressure to break-up monopolies. Interestingly, for most western countries, liberalisation

has been on the agenda since the mid-1970s not only in the energy sector but in various other

sectors as well. The justification behind this tendency is that competition leads firms to greater

economic efficiency and the lowering of prices so they reflect the cost of supply. Furthermore,

politicians perceive monopoly in gas transmission as an obstacle to inter-regional trade.211

Therefore, an alternative model must substitute the monopoly model in order to achieve

gas-to-gas competition. The literature has identified different competitive models that can be

adopted. These models will be examined in the next point. 212

209

International Energy Agency, Natural Gas Transportation: Organisation and Regulation, p. 69. 210

J., Estrada, et al., The Development of European Gas Markets, pp. 19-31. 211

International Energy Agency, Natural Gas Distribution: Focus on Western Europe, p. 22. 212

Ibid., pp. 21-22.


1.2 The Main Competitive Market Models

As it is clearly demonstrated in the North American experience, gas-to-gas competition

must inevitably be introduced through some government intervention to protect new entrants

and to break up natural monopolies. There are mainly two models that policy-makers may adopt

to achieve gas-to-gas competition: pipeline-to-pipeline competition or mandatory third party

access (TPA). These two models have different degrees of market opening and different levels

of competitive pressure.213

1.2.1 Pipeline-to-Pipeline Competition

Under the first alternative, liberalisation can be achieved through the introduction of

pipeline-to-pipeline competition. Here, new transmission companies are allowed to build

competing pipelines to those already in place. The threat of new pipeline construction is

believed to help limit prices and excess profits, even when prices are not directly regulated. This

model has been adopted to a certain extent in Germany, where Wingas competes between

Ruhrgas for gas sales to the industry.214

This first suggested model has suffered heavy criticism on the grounds that the already

established gas pipelines will enjoy initial economic advantages. Indeed, not only their

infrastructure has been partially or totally amortized but they also count on the required gas

supplies to maximize pipeline use.215

Further, it is feared that this model will simply lead to a duopoly instead of a monopoly

or to an oligopoly instead of a duopoly. In fact, as demand grows, the situation between the

pipelines may become that of complementarity instead of a competitive one.216

213

International Energy Agency, supra note 48, p. 21. 214


J., Estrada, et al., supra note 210, p. 25. 216

Ibid.


1.2.2 Mandatory Third Party Access

The second competitive model, mandatory TPA, can be either directed solely at the

transmission system or it can cover part or all of the regional and local distribution system as

well.217

Under the first possibility, there is competition in the wholesale and bulk markets. TPA

is non-discriminatory. Transportation services are unbundled from gas sales activities. Shippers,

which may include producers, traders and end-users may use the pipeline grids upon payment

for the use of the system. The required charges may be regulated or left to negotiations.218

Under the second hypothesis, mandatory TPA is expanded to the retail level to cover

distribution networks. Here, there is no price control on gas sales. Transportation and gas sales

are unbundled at all levels. Moreover, all end-users are free to select their supplier. Presently,

only the United Kingdom has achieved this level of competition. As a matter of fact, such

competition in retail is not fully implemented in the United States and Canada since it is not

available to small-scale end-users.219

1.3 The Canadian Gas Liberalisation Experience

In the 1970s, the entire Canadian gas chain was highly monopolized and prices were

regulated on a cost-plus basis by the NEB and by Provincial regulatory bodies. The liberalized

Canadian gas industry as it is today is the outcome of interesting events. Indeed, in the late

1970s and early 1980s, TransCanada Pipelines, which had the monopoly over gas purchasing

and transmission, took the decision to significantly increase export prices to the United States.

Inadvertently, this decision coincided with a ‘gas bubble’ in the United States. As a result,

TransCanada Pipelines was faced with the impossibility to lift minimum gas volumes it

committed to lift under long-term take-or-pay contracts.220

As a reaction, and recognizing the

need of establishing a market-driven policy, on October 31, 1985, the Governments of Canada,

217



Ibid., p. 22. 220

Ibid., pp. 76-77.


British Columbia, Alberta and Saskatchewan signed the Agreement on Natural Gas Markets and

Prices, sometimes referred to as the “Halloween Agreement”.221

As a result of the Agreement, in 1986, wellhead gas prices were decontrolled222

and

mandatory open access to high-pressure transmission pipelines was introduced. Gas high-

pressure transmission monopolies such as TransCanada were required to unbundle and create

affiliates for their marketing activities. These rules were extended to local distribution

companies in the late 1980s.223

At the present time, the NEB may make orders with respect to all matters relating to

traffic, tolls or tariffs.224

A company cannot charge any toll unless, it has been previously

specified in a tariff that has been filed with the NEB and is in effect; or approved by an order of

the NEB.225

Two provisions in particular govern the nature of tolls. First of all:

“All tolls shall be just and reasonable, and shall always, under substantially similar

circumstances and conditions with respect to all traffic of the same description carried over the

same route, be charged equally to all persons at the same rate.”226

Second of all,

“A company shall not make any unjust discrimination in tolls, service or facilities against any

person or locality.”227

The NEB plays a central role in ensuring the observance of the above provisions. For

example:

“The Board may determine, as questions of fact, whether or not traffic is or has been carried

under substantially similar circumstances and conditions referred to in section 62, whether in any

case a company has or has not complied with the provisions of that section, and whether there

has, in any case, been unjust discrimination within the meaning of section 67.”228

221

J. H. Farrel, and P. F., Forshay, Competition Versus Regulation: reform of Energy Regulation in North

America, 12:4 JENRL 385, p. 387. See also National Energy Board, supra note 50, p. 1. 222

Just as an illustration of the effects of deregulation, wellhead gas prices fell by 40 percent between

1985 and 1987; See National Energy Board, supra note 53, p. vi. 223

Ibid., p. 77. 224





Section 63, National Energy Board Act.


1.4 Implications of North American Liberalization

Through a very similar series of events, the United States has achieved the same level of

gas-to-gas competition as in Canada.229

This leads to the following remarks:

- New players may enter the markets, at any level of the gas chain.

- Once a new company has entered the Canadian market, it can pierce, from one single point,

many different markets either in Canada or the United States.

As an illustration to the above statements, prospective gas producers in Canada may

directly sale their gas to American industrial users. Here, the gas sold can be delivered through

the pipeline network of a third party to the sales contract. Therefore, investment in gas assets

does not imply the ownership of large costly infrastructure anymore and can accommodate small

budgets.

2. INCREASING NORTH AMERICAN GAS DEMAND

2.1 Current Export Levels and Export Points

In 2000, Canadian exports reached a record of 100 bcm (3.5 tcf).230

This is an increase of

four percent from 1998 and about 23 percent from 1995. One main reason behind this growth is

the enlargement of pipeline capacity to the United States at the year-end of 1998.231

Canadian gas exports in 2000 were distributed in the following way: 37 percent to the

Midwest, 28 percent to the Northeast, 19 percent to California, 14 percent to the Pacific

Northwest, and one percent to the Mountain region.232

229

In the United States, the introduction of competition in the natural gas industry started in the 1970s,

when industrial consumers were given the opportunity to choose their gas suppliers. The market was

further liberalized in 1986 when FERC introduced open access to pipeline networks. Later, in 1992,

pipeline companies were required to unbundle their transportation, storage and sales services; See E.,

Lask, US: Still in Transformation, Petroleum Economist 23 (2000), p. 23. 230

In 2000, revenue from Canadian natural gas exports rose by 73 percent to C$ 19 billion. See, National

Energy Board, supra note 5, p. 18. 231

National Energy Board, 1999 Annual Report, March 17, 2000, pp. 15-16, Visited on August 23, 2001,

http://www.neb.gc.ca/about/ar/1999/ar1999.pdf 232

National Energy Board, supra note 5, p. 18.



If compared with the 1998 exports distribution, the 2000 and even the 1999 figures

clearly show that Canadian producers have been able to benefit from increased pipeline capacity

to divert some of their sales towards higher-priced markets of the United States such as the

Midwest and the Northeast.233

As it was discussed earlier, analysts are denoting the formation of a supply shortfall.

“Natural Gas is getting the most attention. Some claim that the future of North American gas

supply lies in Canada's northern territories. That may be true, but it will not help this winter.

American demand is growing so steadily that even if Canada's gas exports increase 50

percent this decade, as forecast, Canada will only be pacing American growth. Over this decade,

American consumption of natural gas is expected to increase by about 50 percent, to 33 trillion

cubic feet a year. For electricity generation alone, it is expected to double. The hitch is that

American natural gas production has declined by about 5 percent since 1998.”234

As a consequence of this tight supply/demand balance235

, natural gas prices have

increased dramatically in 2000 and remain until today significantly high.236

In Alberta, average

spot prices at the wellhead have actually increased over 50 percent between 1999 and 2000.237

The EEA projects that,

“[…] upward pressure on gas prices should abate in 2002 as the impact of gas supplies

developed in response to the high prices is felt. After 2002, EEA projects that deliverability

utilization will continue to remain above 98 percent, as gas demand growth, largely a result of

sustained increases in gas use by power generators, will press gas supply. Given the continuation

of high deliverability utilization, EEA projects an average Henry Hub price of over

$2.80/MMBtu for the remainder of the decade. The price in the later years of the decade,

although high, is below the 2000-2001 price because of lower oil product prices.”238

2.2 Regulatory Requirements for Exports

Canadian exporters of natural gas must satisfy the requirements of both Provincial and

Federal regulatory agencies. The powers of each level of government are clearly enunciated in

the Canadian Constitution Act, 1867. The Provinces have jurisdiction over natural resources,

production and transportation facilities located on their territories. A prospective exporter must

233


G., Hazell, Communications for a Sustainable Future, University of Colorado at Boulder, Natural

Gas, June 22, 2000, Visited on August 19, 2001,

http://csf.colorado.edu/forums/longwaves/jun00/msg00361.html 235

It should be noted that high oil prices also had an influence. 236

Please refer to Annex J. 237

W. J., Simpson, Canadian Shortfall Looms, 67:5 Petroleum Economist 21 (2000), p. 21. 238

Energy and Environmental Analysis Inc., supra note 60, p. 6.

http://csf.colorado.edu/forums/longwaves/jun00/msg00361.html


obtain the approval of the Province concerned before being able to remove gas from its

borders.239

Conversely, the Federal level of government is responsible for extra-Provincial

undertakings, which are of national interest. In view of that, the Federal level holds regulatory

powers over inter-Provincial and international trade and commerce and consequently inter-

Provincial and international gas240

pipelines241

. In addition to Provincial requirements, a

prospective exporter must also obtain a Federal export licence from the NEB, in conformity with

section 116 of the National Energy Board Act.242

According to Section 117(1) of the National

Energy Board Act:

“Subject to the regulations, the Board may, on such terms and conditions as it may impose, issue

licences for the exportation or importation of oil or gas.”

Before issuing an export licence, the NEB can take into account all considerations that

appear to it to be relevant and shall, in accordance with Section 118(a) of National Energy

Board Act:

“satisfy itself that the quantity of oil or gas to be exported does not exceed the surplus remaining

after due allowance has been made for the reasonably foreseeable requirements for use in Canada

having regard to the trends in the discovery of oil or gas in Canada.”

239

E. E., Smith, et al., International Petroleum Transactions, Second Edition, p. 929; Also, according to

Section 92(a)(2) of the Constitution Act, 1867, “[i]n each province, the legislature may make laws in

relation to the export from the province to another part of Canada of the primary production from non-

renewable natural resources and forestry resources in the province and the production from facilities in

the province for the generation of electrical energy, but such laws may not authorize or provide for

discrimination in prices or in supplies exported to another part of Canada.” 240

Section 2, National Energy Board Act defines gas as meaning:

“(a) any hydrocarbon or mixture of hydrocarbons that, at a temperature of 15°C and a pressure of

101.325 kPa, is in a gaseous state, or

(b) any substance designated as a gas product by regulations made under section 130”. 241

Section 2, National Energy Board Act defines pipelines as being: “" means a line that is used or to be

used for the transmission of oil, gas or any other commodity and that connects a province with any other

province or provinces or extends beyond the limits of a province or the offshore area as defined in

section 123, and includes all branches, extensions, tanks, reservoirs, storage facilities, pumps, racks,

compressors, loading facilities, interstation systems of communication by telephone, telegraph or radio

and real and personal property and works connected therewith, but does not include a sewer or water

pipeline that is used or proposed to be used solely for municipal purposes”. 242

E. E., Smith, et al., supra note 239, p. 930.


5.2.3 Natural Gas Consumption By Sector

In North America, natural gas has a significant market share as an energy source. As a

matter of fact, it accounts for 29 percent and 24 percent of Canadian and US energy

consumption respectively.243

Natural gas consumption is expected to grow by 2.3 percent

annually from 1999 to 2020 (to 34.7 trillion cubic feet). This is faster growth than for any other

fuel source.244

Unquestionably, the sector that is gaining the most publicity at the present moment and

certainly for the coming years is the gas-fired power generation sector. Gas-fired generation

(including industrial cogeneration) is expected to grow from a 15 percent share of generation in

1999 and a 16 percent share in 2000 to a 36 percent share in 2020.245

Some of the main reasons

behind this growth is the fact that gas-fired plants have major cost of building, time of building

and environmental advantages over conventional oil or coal plants. Indeed,

“[g]as turbine plants have […] no emissions of sulfur and negligible emissions of particulates.

Nitrogen oxide emissions can be cut by 90 percent and carbon dioxide by 60 percent […] In the

future, this technology could spur utilities to convert hundreds of aging coal plants into gas-

burning combined-cycle plants.”246

The market at the moment is such that turbine manufacturers cannot keep up with gas

turbine demand. The three largest US manufacturers, General Electric, ABB and Siemens-

Westinghouse, are actually booked in North America through to 2002.247

The EEA projects that gas demand for power generation will more than double from

over 3,500 bcf in 1999 to over 7,100 in 2010.248

This figure takes into account-anticipated

improvements in consumption efficiency.

When it comes to residential heating, currently 70 per cent of the new homes built in the

United States are heated with natural gas. This means that natural gas now heats 52 per cent of

243


Energy Information Administration, supra note 19, p. 31. 245

Ibid., p. 32. See Annex K. 246

C., Flavin, and N., Lenseen, Power Surge: A Guide to the Coming Energy Revolution, p. 100. 247

Anonymous, Dash for Gas Creates Turbine Queues Among US Generators, 10:17 WGI 2, p. 2. 248

Energy and Environmental Analysis Inc., supra note 60, p. 18.


the American housing stock.249

The EEA projects that residential gas demand in the United

States will grow at an annual rate of 1.6 percent from 4,800 bcf in 1999 to around 5,700 bcf in

2010.250

3. BENEFITS UNDER THE NAFTA

3.1 History of the NAFTA

The Canada-United States Free Trade Agreement (FTA) signed on January 2, 1988 by

President Reagan and Prime Minister Mulroney was the ancestor of the North American Free

Trade Agreement (NAFTA) and constituted a base for negotiations. The objectives of the FTA

were to eliminate barriers to trade in goods and services and to facilitate conditions of fair

competition between the two countries.

The NAFTA was signed by Canada, the United States and Mexico on December 17,

1992 and entered into force on January 1, 1994. In an article published in 1994, one scholar

observed that:

“[t]he current inward focus of the European Community suggests that, at least for the short term,

a party interested in promoting free trade will have greater success in a venue other than Europe.

It raises concern for non-European trading countries that is more insular and less open to free

trade than has been true in the past. Hence, the establishment of a free trade area on the North

American continent that is roughly equivalent to the countries of the European Community and

the European Free Trade Area in population and gross national product has great appeal.”251

The NAFTA was established pursuant to Article XXIV of the General Agreement on

Tariffs and Trade252

(GATT).253

The parties to the NAFTA specifically affirm their rights and

obligations under the GATT.254

Indeed, the Preamble of the NAFTA clearly states that one of

the objectives sought by the parties to the agreement is to:

“[…] [b]uild on their respective rights and obligations under the General Agreement on Tariffs

and Trade and other multilateral and bilateral instruments of cooperation.”

249

M., Vickerman, Riding the Natural Gas Roller Coaster, 1:2 Petroleum and Natural Gas Watch (2000). 250

Energy and Environmental Analysis Inc., supra note 60, p. 19. 251

E. E., Smith, and D. P., Cluchey, GATT, NAFTA and the Trade in Energy: A US Perspective, 12:1

JENRL 26 (1994), p. 31. 252

General Agreement on Tariffs and Trade, 55 U.N.T.S. 194, T.I.A.S. No. 1700. 253

Section 101, NAFTA. 254

Section 103(a), NAFTA.


However, in the event of any inconsistency between the NAFTA and such other agreements, the

NAFTA shall prevail to the extent of the inconsistency.255

The objectives of the NAFTA, as established in Section 104, are:

“(a) eliminate barriers to trade in, and facilitate the cross-border movement of, goods and

services between the territories of the Parties;

(b) promote conditions of fair competition in the free trade area;

(c) increase substantially investment opportunities in the territories of the Parties;

(d) provide adequate and effective protection and enforcement of intellectual property rights in

each Party's territory;

(e) create effective procedures for the implementation and application of this Agreement, for its

joint administration and for the resolution of disputes; and

(f) establish a framework for further trilateral, regional and multilateral cooperation to expand

and enhance the benefits of this Agreement.”

According to observers,

“NAFTA created the world’s largest and potentially richest free trade market, with nearly 370

million consumers and $7 trillion in annual transactions.”256

3.2 The Energy Sections of the NAFTA

Contained in its Part II on ‘Trade in Goods’, the NAFTA contains a Chapter of nine

articles specifically dedicated to “Energy and Basic Petrochemicals”.257

In accordance with

Annex 602.3, Mexico can reserve to itself the exploration, exploitation and transportation of

natural gas activities, including investment in such activities. The reason behind this reservation

is that the Mexican Constitution prohibits foreign ownership of oil and gas resources.258

Moreover, according to Paragraph 1 of Section 601, the Parties “confirm their full respect for

their Constitutions”.

255

The NAFTA prevails unless otherwise provided in the NAFTA. Section 103(b), NAFTA. See T. R.,

Wilson, Trade Rules: Ethyl Corporation v. Canada (NAFTA Chapter 11) Part II: Are Fears Founded?, 6

NAFTA: L. & Bus. Rev. Am. 205, p. 205. 256

E. E., Smith, et al., supra note 239, p. 940. 257

Chapter 6, Sections 601 to 609, NAFTA. These are essentially based on the Sections contained in

Chapter 9 of the FTA.


Section 603(2) of the NAFTA makes a reference to obligations previously contracted by

the Parties. It states that:

“[t]he Parties understand that the provisions of the GATT incorporated in paragraph 1 prohibit,

in any circumstances in which any other form of quantitative restriction is prohibited, minimum

or maximum export price requirements and, except as permitted in enforcement of

countervailing and antidumping orders and undertakings, minimum or maximum import price

requirements.”

Section 606, the heart of the Energy Chapter, summarizes well the obligations of the

Parties. According this Section,

“1. [t]he Parties recognize that energy regulatory measures are subject to the disciplines of:

(a) national treatment, as provided in Article 301;

(b) import and export restrictions, as provided in Article 603; and

(c) export taxes, as provided in Article 604.

2. Each Party shall seek to ensure that in the application of any energy regulatory measure,

energy regulatory bodies within its territory avoid disruption of contractual relationships to the

maximum extent practicable, and provide for orderly and equitable implementation appropriate

to such measures.”

The NAFTA contains restrictions to the general obligation not to disrupt trade. These

restrictions are contained in Sections 605 and 607 of the NAFTA. The examination of these

restrictions deserves a study of their own. Suffice to say that these restrictions are extremely

restrictive259

and that they have been heavily criticized by Canadian academics.

“The precise meaning and application of these provisions have become quite contentious, as

there are conflicting opinions as to what exemptions are left open to Canada in the event of an

energy shortage. What is clear, however, is that Canada has undertaken unprecedented

obligations to supply oil and other energy products to the United States even when Canada is

itself experiencing a shortage.”260

258

See J., Jiménez, The Great Impact of NAFTA in the Energy Sector: A Mexican Perspective, 18:2

JENRL 160 (2000). 259

The restrictions in Section 605 of the NAFTA are even more restrictive than those established in the

GATT. Indeed, Section 605 starts by declaring that: “a Party may adopt or maintain a restriction

otherwise justified under Article XI:2(a) or XX(g), (i) or (j) of the GATT with respect to the export of an

energy or basic petrochemical good to the territory of another Party, only if […]”. Therefore, even if a

restriction is justified by the GATT, it may be prohibited by the NAFTA. 260

A. M., Godin, Canada’s International Obligations to Provide Energy Under the EIP, GATT, and

NAFTA, 1 Great Plains Nat. Resources J. 45 (1996), p. 60. For example, according to Section 605(c) of

the NAFTA, a party can impose a restriction only if this “[…] does not require the disruption of normal

channels of supply to that other Party or normal proportions among specific energy or basic


It is obvious that the energy provisions of the FTA were negotiated by Canada with a

priority placed on security of markets and by the United States with a priority placed on security

of supply. The resulting high emphasis on free trade falls to the advantage of investors, since

their trade relations are exceptionally well protected.261

3.3 Investment

3.3.1 NAFTA Provisions Governing Investment

The investment provisions of the NAFTA are contained in Chapter 11 of the Agreement.

The NAFTA imposes on its Parties national treatment262

, most-favored-nation treatment263

, and

minimum treatment264

requirements in regards to investment. Section 1106 of the NAFTA lists a

series of requirements or commitments that Parties to the NAFTA cannot impose on foreign

investors on their territory. Section 1109 imposes on parties the obligation not to interfere with

transfers in regards to investment on their territory. Parties must ensure that privately or

publicly-owned monopolies or state enterprises that they maintain or establish act in a manner

that is not inconsistent with the Investment Chapter.265

Actually, the NAFTA also establishes a dispute settlement mechanism to assure “equal

treatment among investors of the Parties in accordance with the principle of international

reciprocity and due process before an impartial tribunal”.266

Hence, a priori, foreign investment

in Canadian territory is protected, under the GATT and the NAFTA, creating a feeling of overall

trade stability.

3.3.2 Investment Opportunities

In a Petroleum Economist article entitled US Giants Hungry for Canadian Gas Assets, it

has been noted that:

petrochemical goods supplied to that other Party, such as, for example, between crude oil and refined

products and among different categories of crude oil and of refined products.” 261

Ibid., p. 58. 262




Sections 1502(3) and 1503(2), NAFTA. 266

Sections 1115 to 1138.2, NAFTA.


“A hunger for Canadian natural gas assets has attracted a horde of carnivores, many of them US

energy giants such as Conoco, Duke Energy, Unocal and Hunt Oil, which are leading in a wave

of American companies across the 49th parallel. They prey cover the full range of western

Canada’s gas producers, many of them seen to be faltering, despite record cash flows this year

and the first signs of recovering share values.” 267

The same article remarks that of the C$11.1bn in merger & acquisitions transactions in

Canada in 1999, large US based companies represented 35 per cent.268

In the second quarter of

1998, gas-driven deals have accounted for as much as 70 per cent of Canadian acquisitions, up

15 per cent from the previous quarter.269

Examples of US acquisitions would include that of

Norcern Energy by Union Pacific Resources Group Inc. in March 1998. The deal was done at a

price tag of $3.5 billion and has concentrated 2.8-bcf/d of production capacity in one pair of

hands. One may also cite Southern Minerals’s $65 million takeover, also in 1998, of Neutrino

Resources along with its estimated 37.4-bcf of gas reserves.270

It is mainly in periods of bullish gas prices and weak Canadian currency value that

Canadian assets become most attractive. In other words, there are periods were there is a price

differential between Canadian and US assets. In the recent past, especially at the end of 1997,

Canadian firms being hit with high debt-to-equity ratios, sometimes reaching as high as 41 per

cent, have advantaged US investors. These US investors have therefore had plenty of open

opportunities and turning to hostile takeovers was not needed to achieve objectives. In fact,

many large Canadian companies such as Gulf Canada, PetroCanada, and Renaissance Energy

have been auctioning properties in the hope of raising cash flow.271

One project that has long been under active consideration by investors is to build a gas

liquefaction terminal and allow Canada to make its first steps as an LNG supplier. The startup of

an LNG project in Canada is extremely risky but at the same time, may prove to be extremely

profitable to project sponsors and to the Canadian industry as a whole.

267

Anonymous, US Giants Hungry for Canadian Gas Assets, 67:5 Petroleum Economist 22 (2000), p.

22. 268

Ibid., p. 22. 269

Anonymous, Canada Hosts Spate of US Upstream Takeovers, 9:17 WGI 2 (1998), p. 2. 270

Ibid., p. 3.


The next section will describe the LNG industry as it stands today and will list the

problems it faces. The proposed project in Canada will then be presented and evaluated,

according to pertinent realities.

4. POSSIBILITY OF BECOMING AN LNG SUPPLIER

The prospects for the growth of the world’s LNG markets are promising. LNG has been

growing at an average rate of approximately 6.7 per cent since 1990. Between 1995 and 1996,

growth actually increased by 12.4 per cent. These numbers are mainly owed to the larger market

share natural gas is gaining due to its technical and environmental advantages. Experts predict

that world LNG trade could increase from the current level of about 82 million tones to 160

million tones by the year 2010.272

It is important to understand what the capital costs of LNG projects can represent in

practice.

“The cost of field development, liquefaction, plant and harbor facilities, which is always the LNG

supplier’s responsibility, depends largely on location and the operating environment, however

capital requirements can run above 5 billion dollars.

The buyer generally has the responsibility to make arrangements for acquiring new LNG tankers

and, assuming an electric utility, for construction of both a receiving terminal and power plant,

together these can add from 5 to 10 billion dollars to the overall costs.”273

Therefore, the costs of a new LNG venture ranges from 10 to 20 billion dollars.274

At this point, before examining the feasibility of an LNG project in Canada, the

following section will describe the problems faced by the LNG industry in general.

271

Ibid. 272

Industry Science Resources (ISR), LNG, Visited on April 8, 2001,

http://www.isr.gov.au/agendas/Sectors/lng 273

International Energy Outlook, Natural Gas, January 1997, Visited on November 26, 2000,

http://www.seninte.upc.es/Interno/Energia/gas.html; Please see also, T. P., Ehrahrt, LNG Enters the New

Millennium, presented to the Seminar on Oil and Gas in the Next Millennium, (International Bar

Association, May 20, 1997), p. 13. 274


http://www.isr.gov.au/agendas/Sectors/lng

http://www.seninte.upc.es/Interno/Energia/gas.html


4.1 Problems with LNG Exports in General

4.1.2 Transportation Costs

It is important to note that there are fundamental differences between the oil and gas

industries. First of all, it is much more expensive to transport gas than oil. In the case of LNG, it

has to be liquefied before transportation at a temperature of minus 160 degrees in ships.275

These

operations are actually cheaper than long distance pipeline transportation. Therefore, if the price

of gas is low, the final consumer price might be unable to cover the price of the production and

transportation of gas.276

On the other hand, transportation experts are predicting a serious shortage of gas carriers.

Makato Iwata, general manager of Mitsui OSK Lines’s liquefied gas carrier division, the

world’s largest operator of LNG tankers foresees a shortfall of 27 tankers by the year 2005.277

Recently, towards June 1999, RasGas had difficulty in booking a tanker for its LNG

sales.278

It appeared that out of nearly 90 LNG tankers that exist worldwide, only four were not

booked on long-term supply contracts. This shortage actually placed constraints on LNG spot

sales by Middle East producers Qatargas, RasGas and Adgas.279

In response, Qatar and Oman

complexes both ordered more than 20 new ships, presently being built in Japan and Korea.280

As

for the new complexes in Trinidad and Nigeria, they have decided to use second hand vessels,

some of which should have already left the Asian LNG trade.281

Actually, it is interesting to note

that the price of a newly built tanker fell in price to around $190 million in 1998 from a $250

peak in 1992.282

275

Anonymous, Analyzing the Outlook for LNG Costs and Prices, 17:11 IPF 1 (1994), p. 2. 276

Ibid. Please see also, J. T., Jensen, Gas Supplies for the World Market, 15 The Energy Journal 237, p.

238-239. 277

Anonymous, Suez Canal Seeks Rise in LNG Traffic to Europe, 10:6 WGI 4 (1999), p. 4. 278

Anonymous, LNG Spot Market Finds Customers, Lacks Tankers, 38:26 PIW 3 (1999), p. 3. 279

Ibid. 280

Anonymous, Middle East Challenges Asia LNG Suppliers, 21 AGR 2 (1999), p. 3. 281

Ibid. 282



Iwata suggested five ways to reducing transportation costs: swapping spare capacity,

standardizing vessel sizes, extending their lifetime to possibly 35 years, innovative financing,

and improved technology.283

However, transportation costs are believed according to some

experts to remain high for at least another five years.284

4.1.2 Inflexible Contractual Obligations

LNG trade is thought to be extremely inflexible. The sponsors of an LNG project will

need to take many precautions in order to guarantee a return on their investment. For instance,

since LNG projects are characterized as being capital intensive, long-term supply contracts often

have to be secured prior to the commencement of construction. These contracts need to be

signed with buyers that are financially sound and reliable. Very often, it will be government-

owned company or large creditworthy gas and electricity utilities.

Another example of inflexibility is the indexation of gas prices to oil. This indexation

represents a difficult investment risk to both the buyer and the seller since they cannot estimate

accurately the extent of their obligations. Inevitably also, low oil prices will mean less profit to

LNG Middle East suppliers. Not surprisingly, Sheikh Yamani, in a speech delivered to the

Institute of Petroleum in London on November 1999, described the price of oil as the greatest

uncertainty the LNG suppliers face.285

The President and Chief Executive of Kogas, Kap Soo Han, summarized the inflexibility

of gas sales contracts in the following statement made in a recent conference in Bali, Indonesia:

“It is my belief that current long-term LNG sales and purchase contracts, based on take-or-pay

conditions, can not accommodate these rapidly developing market needs…LNG contracts with

exporters will have to be more flexible particularly in regard to contract periods, quantities and

pricing. The current pricing formula which is linked to crude oil prices, needs to be changed to be

more market-driven. The downward quantity tolerance should be expanded from the current level

of 5-10% to the level of 15-20% to help LNG buyers effectively deal with increased uncertainty of

demand.”286

283

Ibid. 284

Anonymous, supra note 280, p.3. 285

Anonymous, Low Oil prices Test LNG Industry, 21 AGR 20 (1999), p. 21. 286

Anonymous, Industry Restructuring Sparks Call for LNG price cuts and Flexible Contracts, 29 AGR 2

(1999), pp. 3, 6.


4.1.3 The Weather Problem and Insufficient Storage Facilities

A third problem with LNG trading is the weather factor. Indeed, weather is an important

aspect to consider since warm weather decreases considerably the demand for gas. As a matter

of fact, global warming will be more and more of an issue in the years to come. In 1999, Europe

has witnessed its thermometers reach record temperatures. For instance, most of the UK has

experienced spring-like temperatures in January 1999. It had actually some of the warmest

temperatures since records began 120 years. As a result, just between December 24, 1998 and

January 3, 1999, national demand fell to about 59.7 per cent of peak.287

On the other hand, storage capacity of the importing countries is growing more and more

insufficient with demand growth.288

If we take the example of an LNG importing country hit by

warm weather and suffering from a lack of storage capacity, it would most probably have over-

committed itself. In this scenario, a take-or-pay clause, if existent, would most probably have to

be exercised. The problem for LNG suppliers is when there is no take-or-pay clause in the

contract. LNG suppliers take more risk in countries where there is insufficient storage capacity.

In Europe, storage capacity is lacking, especially in countries such as Spain, Portugal and even

the UK. One reason behind this inadequate infrastructure is the high construction costs of new

storage. Mobile Europe Gas’ Vice President, Donald Woods, says it can cost up to $800 million

to build a new 2 bcm site.289

However, it is important to understand that producers too cannot neglect the importance

of adequate storage. For instance, Indonesia’s state Pertamina, was faced with a shortage of

storage facility due to the 1998 reduced Korean LNG consumption, despite its 10 storage tanks

of a total 28 mcf capacity.290

In 2000, the EEA projected that around 10 bcf of new gas storage

is required in Canada to maintain the reliability of the national gas delivery system. According

to the EEA, the trend is towards increasing utilization and seasonal price spreads. Consequently,

287

Anonymous, Warmest January Day keeps Prices Low, 10:1 WGI 4 (1999), p. 4. Please see also,

Anonymous, Gasunie’s 1998 Sales Hit by Warm Weather, 10:1 WGI 5 (1999), p.5. 288

Anonymous, Storage Capacity Fails to Grow in Europe’s New Competitive Markets, 8:18 WGI 6

(1997), p. 6. 289

Ibid. 290

Anonymous, Korea Cuts Spot Deals; May Defer Long-Term Deals, 9:1 WGI 1 (1998), p. 1.


this will increase the value of storage capacity. 291

Therefore, regardless of the fact that Canada

would be interested in becoming an LNG exporter, there is already a shortage of storage

capacity that needs to be resolved. Actually, shortage in storage capacity is even a greater

problem in the United States. Indeed, according to analysts:

"If summer weather is hot, particularly in the eastern third of the U.S., we could see gas storage

withdrawals occurring in the summer months. If this does not happen this coming summer, it

will almost certainly occur a year later. And once gas withdrawals begin in the summer, the U.S.

has one winter left before we have run our storage system dry. Once this occurs, we will be

forced to relegate natural gas to a seasonal use."292

4.2 The Feasibility of an LNG Project in Canada

Geographically, an LNG Project in Canada is only possible either on the Eastern Coast,

in one of the Maritime Provinces, or on the Western Coast, in British Columbia. For many

years, a project in British Columbia has been under active consideration and remains on the

drawing board today. The project, known as PAC-RIM, would be located in Prince Rupert and

would have a capacity of 3.5 mt/y.293

According to estimates, PAC-RIM is believed to cost $924

million.294

It has been reported that PAC-RIM is intended to serve markets in Asia, and more

specifically in Korea. Independent analysts have qualified PAC-RIM as a “marginally

attractive” project.295

According to their findings,

“[t]he main reasons for the attractiveness of the project are the quick ramp-up speed, the

relatively low cost of liquefaction, the low cost of the pipeline and the availability of

considerable infrastructure.”296

Technically speaking, Canada has all the requirements to build a liquefaction plant. It

has adequate reserves297

, a stable economy and financially sound investors. However, it could be

feared that if Canada engages in the LNG industry, it may become unable to meet its NAFTA

291

Energy and Environmental Analysis Inc., supra note 60, p. 7. 292

M., Vickerman, supra note 249. 293

The United States is considering a neighbouring project in the Alaska North Slope area. See P., Van

Meurs, supra note 205, pp. 419-420 294

Ibid., p. 316. 295

Ibid. 296

Ibid. 297

According to experts, typical LNG projects developed in the 1990s deliver around 7 million tones per

annum (mtpa), requiring a feed of over 1 bcf/d of natural gas. This means that, over a typical 20-year

supply contract, the gas reserves to maintain productivity need to be over 9 tcf, taking into account the

gas that needs to stay in the reservoir to maintain pressure. See A.R., Flower, LNG Project Feasibility, in


obligations. Indeed, under the NAFTA, Canada cannot restrict its levels of exports to one of its

NAFTA partners if this in operation reduces:

“the proportion of the total export shipments of the specific energy or basic petrochemical good

made available to that other Party relative to the total supply of that good of the Party

maintaining the restriction as compared to the proportion prevailing in the most recent 36-month

period for which data are available prior to the imposition of the measure, or in such other

representative period on which the Parties may agree.”298

Put differently, Canada cannot reduce its level of exports below the average levels of

exports of the last 36 months. It is difficult for Canada to enter the LNG industry without

contravening with this obligation. At the present time, Canada does not have the resources to

export LNG to Korea without reducing its levels of natural gas exports to the United States.

Actually, even if Canada were already an LNG player, it would have to examine whether it is in

breach of its NAFTA obligations before signing any new long-term LNG sales contract.

Despite this fact, it should be noted that competition in the LNG business is fierce. As a

matter of fact, the competition is already up and running and closing contracts. Due to their

proximity, already established Asian, Australian and Middle East LNG projects are probably

better able to supply their Asian neighbours at lower costs. LNG from Canada will only

penetrate the Asian market if it can be offered at competitive prices or if Asian suppliers stop

satisfying consumer demand.

Interestingly, Canadian LNG’s most fierce competitors will be located within Asia itself.

Upstream exploration is very active in Asia and giant finds may lead to new Asian LNG

facilities. Even more threatening for Canadian LNG is a proposed plan for a regional pipeline

network. The realisation of such a scheme would greatly jeopardize Canada’s potential share in

the Asian market. It is even fair to say that it will reduce LNG’s market share altogether.299

Actually, in the present time, gas pipeline options are numerous and include Myanmar, Gulf of

Thailand, and even Exxon’s Natuna structure.300

G. B., Greenwald, Liquified Natural Gas: Developing and Financing International Energy Projects , p.

79. 298

Section 605(a), NAFTA. 299

Anonymous, Mideast LNG Fights to Keep Asian Window Open, 7:13 WGI 1 (1996), p. 9. 300

Ibid.


Similarly, possible extension of existing Asian LNG facilities is another worry for

Canada. Such extended facilities will probably have, through lower prices, the upper hand on

new grassroots projects. Actually, this advantage would hold even against new grassroots

projects within Asia itself.301

Another worry that deserves consideration is the fact that Asia, as history demonstrates,

may become economically unstable. Indeed, between early 1997 to approximately mid-1999,

Asia was hit with an economic crisis that weakened its currencies by 20% to 30%.302

If we take

the South Korean example in 1998, it’s GDP growth was faced with a 5.8% contraction in that

year.303

In addition, energy demand had a contraction of 8.1%, with a reduced LNG

consumption of 3.8%. Actually, LNG imports to South Korea fell by a significant 9%, to10.58

mt.304

Not surprisingly, Kogas had to cancel 15 cargoes from Indonesia’s Pertamina for 1998,

amounting to about 600,000 tons.305

Equally, Kogas also had to cancel a 1-mt spot deal with

Abu Dhabi.306

4.3 Recommendations

By the time a Canadian LNG project comes onstream and by the time dedicated tankers

are built, the world would be shaped with new realities related to gas and energy as a whole.

“The overall proposed LNG capacity for grassroots plants and expansion of existing plants are

excessive compared with the forecast growth in [Asian] regional gas demand […] The likely

LNG oversupply is poised to change the structure of the industry and will possibly have lasting

impacts on future LNG trade and implications for future contracts in the region.”307

Canada must be extremely cautious in weighing the risks and the rewards of entering the

LNG business. Even if PAC-RIM never materializes, the consolation is that Canada should be

able to sell all of its production on North American markets. Interestingly, the gas shortage in

North America is such that, in 1999, LNG imports to the United States have nearly doubled

301




Anonymous, 1998 – The Year of Negative Growth, 10:3 WGI 1 (1999), p. 1. 305

Anonymous, Korea Cuts Spot Deals; May Defer Long-Term Deals, supra note 270, p. 1. 306

Anonymous, Asian LNG Producers Rein Back Output, 9:7 WGI 10 (1998), p. 10. 307

F., Fesharaki, Asian Demand Growth Driving Global Gas Trade Outlook, 98:20 OGJ 68 (2000), p.73.


from the previous year. In 2000, the trend continued with a growth of 35 percent from 1999 to a

total of 220 bcm.308

These LNG imports constituted arbitrage opportunities, where the price of imported gas

in LNG form was cheaper or simply competitive with the local market price. Needless to say,

these imports were contracted on a spot basis309

and might have been sold at a loss for the seller.

If the price of gas goes down enough, LNG imports to the United States are not justified,

assuming they are purchased at their just price. If North America can increase its production

enough, perhaps that prices will indeed decrease. This is a foreseeable scenario, especially once

Mexico becomes in position to export. Indeed, the national Mexican oil company, PEMEX,

predicts that Mexico will become a net exporter in 2005, once the Burgos Basin in the northeast

of Mexico is developed.310

308

The LNG imported to the United States in 2000, came from eight different suppliers. By order of

importance, these were: Trinidad and Tobago (99 bcm), Qatar (46 bcm), Algeria (44 bcm), Nigeria (13

bcm), Oman (10 bcm), Australia (6 bcm), Indonesia (3 bcm) United Arab Emirates (3 bcm). See Energy

Information Administration, supra note 20, p. 12. 309

With the exception of Algeria that delivered primarily under long-term arrangements. The buyer in

this contract probably anticipates that gas prices will remain high; Ibid. 310

E. E., Smith, et al., supra note 239, p. 915.


CHAPTER VI: CONCLUSION

Experts have been predicting for almost a decade the formation of a shortfall in North

American gas supply. The first symptoms of this shortfall have already been felt with the

record-high prices in 1999 and 2000. Obviously, there is a strong pressure on the industry for

the increase of production. Inevitably, it has become necessary to develop the resource potential

of frontier areas. This implies higher costs and higher risks for investors.

Unquestionably, attracting investors to explore and exploit Canada’s frontier is not an

evident task to do for policy-makers. This is especially true at this point of time, where

petroleum companies can ‘just go elsewhere’.

The aim of this paper was to examine broadly Canada’s prospectivity from an

investment point of view. This exercise allows Canadian petroleum authorities to see where

emphasis should be placed in improving the overall investment climate in Canada. The

conclusions of this study could be summarized as follows:

First of all, from a technical point of view, Canada is believed to hold large quantities of

gas resources. Extracting this gas can however be extremely costly, especially due to

unfavorable weather and complex terrain structure (e.g. rocky mountains, deep offshore, etc.).

Also from a technical point of view, there are often important distances between

resource basins and markets. Even though there is already a solid North American pipeline grid,

new infrastructure often needs to be built in order to reach intended markets.

Second of all, from a legal point of view, moratoriums on new licences are often placed,

decreasing as a result the deliverability potential of natural gas. Moratoriums have been placed

and continue to be placed due to the high occurrence of boundary disputes in Canada. Two

disputes are still pending. The first one, at an international level, is between Canada and the

United States over offshore areas in the Beaufort Sea. The second one, at an intra-national level,


is between the Provinces of Nova Scotia and Newfoundland over portions of their offshore

areas.

The Nova Scotia/Newfoundland dispute should be resolved when the arbitration decision

on the issue is rendered around May 2002. In contrast, there are no promising signs for the

resolution of the Canada/United States dispute. It is pressing to achieve an agreement on the

disputed area, especially with the industry’s strong interest in the region. If Canada and the

United States do not expect to achieve a delineation shortly, then they should at least consider

negotiating a joint development arrangement.

Moratoriums on new licences have also been placed due to Native claims on certain

areas. Canada must therefore develop its resources while reconciling Aboriginal rights over

land. The issue of Native rights creates a climate of uncertainty over the authority of the Federal

government to issue licences over certain areas. Attracting investment in frontier areas hence,

implies good relationships with Native groups. The Federal government must continue in trying

to achieve agreements with individual communities. Likewise, the Supreme Court of Canada

must be prompt in its response to ambiguities over the precise scope of such concepts as Native

title. Initiatives, such as the recent one made by Justice Antonio Lamer in Delgamuukw, are

precious to the industry and it is hoped that the present trend will continue with future

compositions of the Supreme Court.

Also from a legal point of view, licensing rules are central to Canada’s investment

prospectivity. There have been numerous controversies over which one, between the auction and

the discretionary methods of award, is most efficient. This paper concludes that the auction

system, as adopted by Canada, seems perfectly capable of conciliating the interests of both host

countries and petroleum companies. This mechanism is objective, transparent and able to

incorporate practically any condition envisaged. Additionally, it relieves petroleum companies

from the fear of excessive economic rent ‘recapture’ methods.


Also on the topic of licensing, petroleum experts have advanced that increasing licence

duration and licence block size could provide incentives for investment. The validity of these

opinions is definitely worth testing in future calls for bids.

Third of all, from a fiscal point of view, terms can be made more generous for the

promotion of investment and the development of frontier areas. The options for policy-makers

are numerous. Essentially, it comes down to either providing more ‘back-ended’ provisions, by

reducing initial government take, or even reducing overall take as a whole. Just as an example,

this study proposes the reduction of part of the royalty burden in favor of a system such as the

resource rent tax. Under this replacement system, tax only becomes imposed once negative cash

flows have been offset. Another example of fiscal incentives could be to further accelerate the

recovery of deductible costs in order to hasten the payback period of projects.

Fourth of all, from a geopolitical point of view, the Canadian gas industry benefits from

a highly integrated and liberalized North American market. A Canadian gas producer can sell

production directly to industrial end-users without having to own any transportation

infrastructure. Gas sales contracts and investment in gas assets are further facilitated by various

contracted international agreements, mainly the NAFTA and the GATT. Investors in Canada

benefit from a strong emphasis put on free trade and there are numerous restrictions on the

capacity of governments to interfere with their trading activities.

Under the same geopolitical prospectivity title, this study has also considered the

feasibility of an LNG project in Canada. The examination of the question revealed a number of

potential ‘sticks in the wheel’. Amongst other things, Canada is bound by a rigid supply

obligation under the NAFTA. For the time being, it is unlikely that Canada can enter the LNG

industry without disrupting its levels of exports to its NAFTA partners. Therefore, political

interference in the project constitutes an important foreseeable risk, sufficient to discourage

investment in the project. Besides that fact, Asia, the main target of Canadian LNG, represents

important transportation distances and therefore non-negligible added costs. Various

competitors, benefiting from proximity, are probably able to supply Asian markets with a price

advantage.


Finally, the reader should retain that investment in Canadian assets is a case-by-case

decision. The general issues presented in this study might not all be relevant when considering a

particular investment. For example, depending on the area under consideration, an interested

investor may or may not be concerned with the issue of Native claims or the issue of boundary

disputes.

Nevertheless, the issues presented demonstrate that any decision to invest will require

the prior examination of a multitude of correlated and uncorrelated parameters, of different

importance and potential effects. The issues presented also demonstrate that the promotion of

gas investment is not only in the hands of Canadian petroleum authorities, but also in the hands

of the Department of Foreign Affairs, the Department of Finance, the Department of Indian and

Northern Affairs, etc. A solid promotional strategy therefore requires the successful

coordination of various different bodies and players at both Federal and Provincial levels.


ANNEXES


Annex A

Future Potential of the WCSB

Reproduced from Woronuk, R. H., Canadian Gas Potential Committee, Canadian Gas Supply:

Going Up? Or Down?, p.3, http://tabla.geo.ucalgary.ca/NatGasCan/opipaper.pdf



Annex B

Typical Gas Well Drilling Costs By WCSB Area

Reproduced from National Energy Board, Short-term Natural Gas Deliverability from the

Western Canada Sedimentary Basin: 2000-2002, December 2000, p. 44, Visited on March 8,

2001, http://www.neb.gc.ca/energy/emagdel.pdf



Annex C

Alaska - Canadian & US Markets Proposed Routes

Anonymous, Why Alaska-Lowe 48 Pipeline is Suddenly a ‘This-Decade Project’, December

2000, Gas Matters, p. 13.


Annex D

Offshore Atlantic: Gas Discovery Areas

Woods, T. J., Canadian Prospects Push Toward 30-tcf North American Natural Gas Market,

99:4 OGJ 64, p. 68.


Annex E

Canadian and US Natural Gas Pipelines

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



Annex F

Canada/United States Beauford Sea Boundary Claims

H. E., Johansen, et al., Mineral Resource Development: Geopolitics, Economics and Policy, p.

58


Annex G

Georges Bank Boundary Drawn by International Court of Justice

H. E., Johansen, et al., Mineral Resource Development: Geopolitics, Economics and Policy, p.

60


Annex H

The Canada/France Boundary as Delineated by the Arbitration Court

Reproduced from 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), p. 1148.


Annex I

The Nova Scotia/Newfoundland Disputed Boundary

Reproduced from Nova Scotia Petroleum Directorate, Map PD 2000-2B


Annex J

Alberta Natural Gas Prices – AECO/NIT

($/Gigajoule)

Reproduced from National Energy Board, 2000 Annual Report, March 17, 2001, p. 16, Last

Visited on July 30, 2001, http://www.neb.gc.ca/about/ar/2000/ar2000.pdf



Annex K

Gas-Fired Capacity Additions (US Example)

Reproduced from Energy and Environmental Analysis Inc., Gas Market Compass, Overview for

the Basic Outlook, August 8, 2000, Visited on March 7, 2001,




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Northwest Territories, Department of Finance, Norman Wells Regional Map, Visited on March

8, 2001, http://www.fin.gov.nt.ca/pipeline/Norman_Wells_Regional _Map.pdf

Northwest Territories, Department of Finance, Sedimentary Basins of the NWT and Yukon,

Visited on March 8, 2001,

http://www.fin.gov.nt.ca/pipeline/Sedimentary_Basins_of_the_NWT_and_Yukon.pdf

Northwest Territories, Department of Finance, Pre-1990 Wells Drilled, Visited on March 8,

2001, http://www.fin.gov.nt.ca/pipeline/Pre_1990_Wells_Drilled.pdf

Northwest Territories, Department of Finance, Post-1989 Wells Drilled, Visited on March 8,

2001, http://www.fin.gov.nt.ca/pipeline/Post_1989_Wells_Drilled.pdf

Simpson, E. L., Aboriginal Claims in Canada: A Chronology, Visited on March 8, 2001,

http://www.ualberta.ca/~esimpson/claims/chronology.htm

Stevens, P., Natural Gas: The Fuel of the Next Century, 6:3 CEPMLP EJ, Visited on December

1, 2000, http://www.dundee.ac.uk/cepmlp/journal/html/vol6-3.html

Watkins, G. C., Atlantic Institute for Market Studies, Atlantic Petroleum Royalties: Fair Deal or

Raw Deal?, June 2001, Visited on August 21, 2001,

http://www.aims.ca/Publications/royalties.pdf

Weick, E., Native Claims, Visited on March 8, 2001,


Woronuk, R. H., Canadian Gas Potential Committee, Canadian Gas Supply: Going Up? Or

Down?, Visited on March 7, 2001, http://tabla.geo.ucalgary.ca/NatGasCan/opipaper.pdf

Woronuk, R. H., Canadian Gas Potential Committee, Supply as a Function of Endowment,

Visited on March 7, 2001, http://tabla.geo.ucalgary.ca/NatGasCan/ceripaper.pdf

http://www.fin.gov.nt.ca/pipeline/Geophysical_Development_in_the_NWT.pdf

http://www.fin.gov.nt.ca/pipeline/Native_Land_Claims_and_Petroleum_Lease_Boundaries.pdf

http://www.fin.gov.nt.ca/pipeline/Natural_Gas_transportation_Options.pdf

http://www.fin.gov.nt.ca/pipeline/Norman_Wells_Regional%20_Map.pdf

http://www.fin.gov.nt.ca/pipeline/Sedimentary_Basins_of_the_NWT_and_Yukon.pdf

http://www.fin.gov.nt.ca/pipeline/Pre_1990_Wells_Drilled.pdf

http://www.fin.gov.nt.ca/pipeline/Post_1989_Wells_Drilled.pdf

http://www.ualberta.ca/~esimpson/claims/chronology.htm

http://www.dundee.ac.uk/cepmlp/journal/html/vol6-3.html

http://www.aims.ca/Publications/royalties.pdf



http://tabla.geo.ucalgary.ca/NatGasCan/ceripaper.pdf


2.4 Conferences

Conference Papers, presented in the Seminar Liquified Natural Gas: The Process of Project

Development, (Saint Andrews, Scotland, Centre for Energy, Petroleum and Mineral Law and

Policy, September 18-19, 1997).

Ehrahrt, T. P., LNG Enters the New Millennium, presented to the International Bar Association

Seminar on Oil and Gas in the Next Millennium, May 20, 1997.

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 , (Calgary, Alberta, National Energy Board, April 19, 2000).

Documents

Zaid Mahayni - 2001 CEPMLP LLM Dissertation