Technical considerations: Implementing the decision Environmental and Introduction

Technical considerations: Implementing the decision Environmental and Introduction
Technical considerations:
Implementing the decision
Chapter 1
Chapter 2
Chapter 3
Environmental and
socio-economic matters Introduction
6
Regulatory review process 18
1.1 The project
6
2.1 Role of the National Energy Board 18
1.2 Project description
8
2.2 The “public interest”
19
3.1 Joint Review Panel process
26
1.2.1 Niglintgak field 8
2.3 Coordination of review process
20
3.2 Consult to modify process
27
1.2.2 Taglu field
9
1.2.3 Parsons Lake field
9
22
3.3Environmental matters
discussed in final argument
28
1.2.4 Mackenzie Gathering System
9
2.4National Energy Board
hearing process
26
2.4.1 Overview
22
3.3.1 Cumulative effects and
upstream impacts
28
22
22
3.3.2 End use of gas and
downstream impacts 31
3.3.3 Air quality issues and
greenhouse gas emissions 32
1.2.5 Mackenzie Valley Pipeline
10
1.2.6 Construction schedule
11
2.4.2 Events leading up
to the oral hearing
14
2.4.3 Oral hearing
1.3.1 Project environment
14
1.3.2 Social, cultural and
economic setting
16
2.4.4 National Energy Board Act
subsection 15(1)
Member’s report
23
2.4.5 Consult to modify process
and final argument
3.3.4 Impacts of climate change
on the project 35
23
3.3.5 Wildlife and species at risk
37
1.3 Project setting
3.3.6 Environmental Protection Plans 40
3.3.7 National Energy Board’s role
in enforcing recommendations
directed to others
42
3.4Socio-economic matters discussed
in final argument
1249_NEB_MGP_Vol2_Text_ENG.indd 1
44
3.4.1 Socio-Economic Agreement
44
3.4.2 Employment and training
44
3.4.3 Impacts to harvesters, land
and resources
46
3.4.4 Project reporting
47
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2 Mackenzie Gas Project
Chapter 4
Development fields
Chapter 6
48
112
4.1 The reservoirs 49
6.1 Overview of facilities
4.2 Niglintgak
50
6.2 Assessment of engineering issues 113
4.2.1 Design of the
Niglintgak facilities 50
4.2.2 Development plan issues 53
4.3 Taglu 67
4.3.1 Design of the Taglu facilities 67
4.3.2 Development plan issues 70
4.4 Parsons Lake 81
6.3 Overall design strategy
112
6.3.3 Stress-based and
strain-based design
114
6.3.4 System design
and configuration
121
7.2 Economic setting
160
6.4 Specific design issues
128
7.3 Supply
161
7.4 Markets/demand
164
7.5 Transportation contracts
167
85
6.4.2 Geohazards 128
6.4.3 Pipeline operating
temperatures 131
6.4.4 Pipeline materials
133
5.2 General route and facilities
site selection
95
5.2.1 General route selection–
Mackenzie Valley Pipeline and
Mackenzie Gathering System
95
5.2.2 Facilities site selection 97
5.2.3 Community and
government input into
route/site selection 97
6.4.5 Joining – welding and
non-destructive examination 134
7.1 Public convenience and necessity 160
7.5.1 Mackenzie Valley Pipeline
167
7.5.2 Mackenzie Gathering System 167
7.6 Financing
168
137
6.4.8 Watercourse crossings 140
6.4.9 Pipeline control systems
and leak detection
145
6.4.10 Settlement of backfill
146
6.4.11Right of way protection
during construction
8.1 Regulation of tolls, tariffs
and access
170
147
8.2 Mackenzie Valley Pipeline
171
148
8.2.1 Timing of decision on
toll and tariff matters
171
8.2.2 Method of economic
regulation
172
8.2.3 Cost of capital
173
8.2.4 Depreciation
176
6.5 Other technical considerations
148
6.5.3 Pressure testing
151
108
6.5.4 Support infrastructure 151
5.5.1 Land ownership in the
Mackenzie Gas Project area
108
6.5.5 Northern logistics
and construction
152
5.5.2 The Proponents’ land
acquisition approach
109
5.5 Land acquisition
160
6.4.7 Slopes
6.5.2 Air emissions 5.4 Land use planning considerations 104
Economic feasibility
137
148
101
Chapter 7
6.4.6 Seismic design 6.5.1 Overview
5.3 General land requirements
159
114
4.4.2 Development plan issues 94
6.8 Other requirements
specific to the Mackenzie
Gathering System
6.3.2 Cost estimate
128
5.1 Introduction
158
113
6.4.1 Overview
94
6.7 Emergency response
6.3.1 Design process
82
Routing and land matters
155
113
4.4.1 Design of the Parsons Lake
facilities Chapter 5
1249_NEB_MGP_Vol2_Text_ENG.indd 2
Facilities
6.6 Preliminary plans for integrity
monitoring and surveillance
Chapter 8
Toll, tariff and
access provisions
170
8.2.5 Tolling methods (zonal versus
volume distance tolling)
177
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3
8.2.6 Open access
179
8.2.7 Term-related toll differential
184
8.2.8 Lateral policy
184
8.2.9 Service to northern
communities
185
8.2.10Codes of conduct
188
8.2.11 Tolls and tariff task force
190
8.3 Mackenzie Gathering System
191
8.3.1 Overview
8.3.2 The need for economic
regulation on the Mackenzie
Gathering System
191
8.3.5 Code of Conduct
201
9.4Participation by parties
in our hearing process
201
9.5Consideration of
Aboriginal concerns
202
9.2.1 Overview
197
9.2.2 Consultation for the Mackenzie
Gathering System and
Mackenzie Valley Pipeline 197
9.2.3 Consultation for
the development fields 199
9.2.4 Consultation with
government 200
1249_NEB_MGP_Vol2_Text_ENG.indd 3
226
G Mr. Rowland J. Harrison’s
subsection 15(1) report
234
H National Energy Board’s letter to Joint
Review Panel regarding modifications
235
I Concordance table
238
J Joint Review Panel’s response
to NEB’s consult to modify process
246
K Conditions for the
Mackenzie Valley Pipeline
248
L Miscellaneous Order for Mackenzie
Valley Pipeline Tolls and Tariff
265
MConditions for the Mackenzie
Gathering System 268
N Miscellaneous Order for Mackenzie
Gathering System Tolls
285
Chapter 10
National Energy Board
lifespan regulation
208
10.1.2Monitoring and enforcement 209
197
D Development field reservoirs:
characteristics and exploration history
203
209
9.2 The Proponents’
consultation program 223
9.5.2 Concerns raised
in our hearing
10.1.1The application stage
196
C Summary of events
232
195
9.1 Introduction 220
F Authorization MO-13-2004
208
196
B Recital and appearances
E Conversion factors and energy content 231
194
Consultation
219
202
10.1Regulation under
the National Energy Board Act
Chapter 9
A List of Issues for Hearing GH-1-2004
9.5.1 Accommodation
by the Proponents
191
8.3.3 Proposed method for setting
Mackenzie Gathering System
fees (excluding the natural
gas liquids pipeline)
192
8.3.4 Proposed method for tolls
on the natural gas
liquids pipeline
Appendices
9.3 Participation by parties
in the Joint Review Panel
hearing process 10.1.3Abandonment
211
10.2Economic regulation
213
10.3Regulation, monitoring and
enforcement under the Canada
Oil and Gas Operations Act
214
Chapter 11
Disposition
216
O Conditions for the Shell Canada Limited
(Shell) Development Plan for
the Niglintgak field
287
P Conditions for the Imperial Oil
Resources Limited (IORL)
Development Plan for the Taglu field
295
Q Conditions for the ConocoPhillips
Canada (North) Limited (ConocoPhillips)
Development Plan for the
Parsons Lake field
303
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4 Mackenzie Gas Project • Volume 2: Implementing the decision
Fig. 4-10 Design height for top of Taglu
List of Figures
Fig. 1-1
Overall project map
Fig. 1-2
Development fields and
upstream gathering pipeline
Fig. 1-3
Fig. 1-4
7
Fig. 4-11 Drilling waste disposal
Fig. 6-13 Anticipated right of way
73
Fig. 4-12 Parsons Lake production facilities 81
8
Fig. 4-13 Parsons Lake field map
83
Fig. 4-14 Commercial discovery declaration
11
area and significant discovery
licences for Parsons Lake field
as of 2006
12
Fig. 5-1
Typical right of way cross-sections 102
Fig. 1-5
Proposed construction spreads
13
Fig. 5-2
Fig. 1-6
Permafrost regions
15
Typical land requirements at
an open-cut watercourse crossing 103
Fig. 1-7
Land claim regions
of the Mackenzie Valley
Fig. 2-2
Fig. 2-3
Process timeline for review
of Mackenzie Gas Project
National Energy Board
and Joint Review Panel
coordinated hearing schedule 16
21
24
Fig. 4-1
Development fields
48
Fig. 4-2
Natural gas supply
49
Fig. 4-3
Natural gas liquids supply
49
Fig. 4-4
Niglintgak production facilities 51
Fig. 4-5
Niglintgak field map
52
Fig. 4-6
Commercial discovery declaration
area and significant discovery
licences for Niglintgak as of 2006
53
Niglintgak substructure
design height
59
Fig. 4-8
Taglu production facilities
67
Fig. 4-9
Taglu field map
68
Fig. 4-7
Engineering design process
113
Fig. 6-2
Frost heave
116
Fig. 6-3
Thaw settlement
117
Fig. 6-4
Mackenzie Gathering System
121
Fig. 6-5
Mackenzie Valley Pipeline
design capacity
125
Temperature profiles for
configurations with one
and three compressor stations
132
Temperature profiles for various
compressor configurations
132
Thermosiphon and wood chips
used as surface insulation
138
Watercourse crossing –
open trench
140
Fig. 6-6
Communities where our
information sessions and
public hearings were held
86
Fig. 6-1
22
Fig. 6-7
Fig. 6-8
Fig. 6-9
settlement for different
clearing techniques
147
Fig. 7-1
Natural gas resources
161
Fig. 7-2
Capacity forecasts
163
Fig. 7-3
Supply basins and sub basins
163
Fig. 7-4
Angevine report – projected
future gas supply and demand
165
Existing export pipeline corridors
from the Western Canada
Sedimentary Basin
166
Proposed toll zones for the
Mackenzie Valley Pipeline
177
Fig. 8-2
Community gas pipeline
186
Fig. 8-3
JP-05 / JP 95 fee comparison 193
80
Proposed construction schedule
for Mackenzie Gathering System
and Mackenzie Valley Pipeline
Fig. 2-1
1249_NEB_MGP_Vol2_Text_ENG.indd 4
Mackenzie Valley Pipeline
and natural gas liquids pipeline well pad and facility foundations Fig. 7-5
Fig. 8-1
Fig. 10-1 Regulation by the
Fig. D-1
National Energy Board
throughout a project’s lifespan
209
A NW-SE cross-section of
the Niglintgak reservoir and
proposed initial well locations
228
Fig. 6-10 Watercourse crossing –
isolated method
Fig. 6-11 Diversion berms and ditch plugs
141
142
Fig. 6-12 Watercourse crossing –
horizontal directional drill
using backreaming method
143
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5
Table 7-3 WCSB export pipeline capacity
List of Tables
Table 1-1 Potentially affected communities and projected gas flows
17
Table 2-1 Initial events in the coordinated
review process
21
23
49
Table 4-2 Niglintgak construction
highlights schedule
50
Table 4-3 Taglu construction
highlights schedule
69
Table 4-4 Parsons Lake construction
highlights schedule 82
Table 5-1 Refinements to
the preliminary route
Table 5-3 Land requirements by use
99
101
Table 6-1 Project expenditures 2007 update 114
Table 6-2 Regional climate-warming rates
selected by the Proponents
Table 6-4 Line pipe specifications
133
167
168
proposed return on equity capital
for the Mackenzie Valley Pipeline 173
Table 8-2 Comparison of 2005 returns
on equity capital
174
Table 8-3 Estimated capital costs for
metering and related facilities
by community
187
Table 8-4 Estimated cost of service
Table 9-1 Changes to project design
187
203
Table 10-1Principles for the end state
of land post-retirement
213
Table D-1 Gas characteristics for
the development fields 226
227
Table D-3 Reservoir model results for
Table D-4 Taglu exploration history 162
228
Table D-5 Reservoir model results for
the Taglu field 156
Table 7-1 Comparison of available
natural gas supply forecasts
167
Significant Discovery Licence 019 227
125
Table 6-5 Proponents’ preliminary plans
for monitoring and surveillance
of owner-shippers
Table D-2 Niglintgak exploration history 119
Table 6-3 Mackenzie Valley Pipeline
design parameters
Table 7-5 Contracted volumes by shipper
to northern communities
98
Table 5-2 Project changes filed
in November 2005
on Mackenzie Valley Pipeline
Table 8-1 Mackenzie Explorer Group’s
Table 4-1 Recoverable volumes of natural
gas in the development fields Table 7-4 Contracted and available capacity
Table 7-6 Predevelopment interests
Table 2-2 Key events in the National Energy
Board hearing process
166
229
Table D-6 Parsons Lake exploration history 229
Table D-7 Reservoir model results
for Parsons Lake
229
Table 7-2 Eagle Plains basin
resource estimates
1249_NEB_MGP_Vol2_Text_ENG.indd 5
163
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Chapter 1
Introduction
1.1 The project
The Mackenzie Gas Project is a proposal to produce and transport natural gas and natural gas
liquids from the three largest discovered onshore natural gas fields in the Mackenzie Delta area.
Natural gas from the Niglintgak, Taglu and Parsons Lake fields would travel via the Mackenzie Valley
Pipeline from Inuvik, Northwest Territories, to northwestern Alberta and on to southern markets.
Natural gas liquids would be separated from the natural gas at a gas processing facility near Inuvik
(Inuvik Area Facility) and transported via a smaller pipeline to Norman Wells, Northwest Territories,
where it would connect to the existing Enbridge Pipelines (NW) Inc. Norman Wells Pipeline
(see Figure 1-1).
In October 2004 the National Energy Board
• the 1195.8 kilometre long Mackenzie Valley
received the following applications for the
Pipeline, including three compressor stations,
construction and operation of the Mackenzie
a heater station and associated pipeline
Gas Project:
facilities to transport natural gas from the
• the development of three natural gas
Inuvik Area Facility to northwestern Alberta,
fields — Niglintgak, Taglu and Parsons Lake
applied for under section 52 of the National
development fields — applied for under
Energy Board Act. This pipeline would
section 5.1 of the Canada Oil and Gas
connect with the existing NOVA Gas
Operations Act;
Transmission Ltd. system in Alberta; and
• the Mackenzie Gathering System, including
• an order, pursuant to Part IV of the National
189.2 kilometres of upstream gathering
Energy Board Act, approving the toll and
pipelines, the Inuvik Area Facility, and a
tariff principles that are to apply to service
457.2 kilometre natural gas liquids pipeline
on the Mackenzie Valley Pipeline.
from the Inuvik Area Facility to Norman Wells,
all applied for under paragraph 5(1)(b) of
the Canada Oil and Gas Operations Act;
1249_NEB_MGP_Vol2_Text_ENG.indd 6
12/6/10 11:01:20 AM
Chapter 1: Introduction 7
Did you know?
Pipelines in the North
The Mackenzie Valley Pipeline is designed to
transport approximately 34.3 Mm3/d (1.2 Bcf/d)
of natural gas with three compressor stations
in operation.
If the Mackenzie Gas Project proceeds it would be by
built the Norman Wells Pipeline from Norman Wells
far the largest pipeline system to be constructed and
to Zama, Alberta. Several natural gas pipelines have been
operated in Canada’s North, although it would not
built from southern Yukon and the Northwest Territories
be the first. The Canol Pipeline, built during World War II,
into British Columbia and Alberta in the last half century
moved crude oil from Norman Wells to Whitehorse,
and, in the late 1990s, the Ikhil Pipeline was built to supply
and in the mid-1980s, Enbridge Pipelines (NW) Inc.
Inuvik with natural gas.
Taglu
Mackenzie
Bay
Amundsen Gulf
KP Mackenzie Valley Pipeline
kilometre post
Tuktoyaktuk
Future facility site
Proposed pipeline route
Inuvik
The proponents of the Mackenzie Gas Project
Proposed Alberta pipeline route
KP-0
Aklavik
Inuvik Area
Facility
are Imperial Oil Resources Ventures Limited,
Mackenzie Valley Aboriginal Pipeline Limited
Partnership, Imperial Oil Resources Limited,
ConocoPhillips Canada (North) Limited,
Canada Limited as managing partner of Shell
District boundary
INUVIALUIT
SETTLEMENT REGION
Regional boundary
Production field
Fort McPherson
Tsiigehtchic
100
GWICH'IN
SETTLEMENT
AREA
0
100
SAHTU SETTLEMENT AREA
K'AHSHO GOT'INE DISTRICT
Little Chicago
Loon River North
future compressor
station
Colville Lake
N o r t h w e s t Te r r i t o r i e s
Fort Good Hope
KP-275
Nunavut
N u n a v u t
Canada Energy, (collectively, the Proponents).
The capital cost of the Mackenzie Gas Project
is estimated at $16.2 billion (2006$). It is
50
Kilometres
Conoco Phillips Northern Partnership,
ExxonMobil Canada Properties and Shell
Overall project map
Facility site
Parsons Lake
Niglintgak
Figure 1-1
Norman Wells
Enbridge interconnect
facility
planned to be in operation by the end of 2018,
Yu k o n
Déline
KP-457
Great Bear River
compressor station
based on the start of construction in late 2014.
DÉLINE DISTRICT
Great Bear
Lake
KP-540
Tulita
SAHTU SETTLEMENT AREA
TULITA DISTRICT
TLI CHO
REGION
Wrigley
KP-808
Rae
River Between Two
Mountains future
compressor station
Yellowknife
DEH CHO
REGION
Fort Simpson
Great Slave
Lake
Jean Marie River
Fort Providence
Nahanni Butte
Trout River future
heater station
KP-1098
Saamba K’e
Fort Liard (Trout
Lake)
British Columbia
1249_NEB_MGP_Vol2_Text_ENG.indd 7
KP-1196
Kakisa
Hay River
Enterprise
Interconnect facility
(located in Alberta)
DENE THA’ FIRST NATION A l b e r t a
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8 Mackenzie Gas Project • Volume 2: Implementing the decision
Figure 1-2
Kugmallit Bay
Development fields
Kendall Island
Bird Sanctuary
and upstream
Tuktoyaktuk
gathering pipeline
1.2.1 Niglintgak field
Shell Canada Limited (Shell) applied for approval
Richards Island
Taglu
1.2 Project description
of a Development Plan under section 5.1
Kittigazuit
Bay
of the Canada Oil and Gas Operations Act
for the Niglintgak field on 20 October 2004.
el
nn
The Niglintgak Significant Discovery Licence
East Ch
Yaya Lakes
Camp Farewell
a
Niglintgak
SDL019 is located about 120 kilometres northwest
of Inuvik and 85 kilometres west of Tuktoyaktuk
and lies within Kendall Island Bird Sanctuary
Bar C
Tununuk Point
in the Mackenzie Delta (see Figure 1-2).
Parsons Lake
The proposed production facilities include:
• six to twelve production wells located
on three well pads;
M
ie
nz
ke
ac
• a system of above-ground flow lines;
River
South pad future
facility site
• a gas conditioning facility located
in the Kumak Channel;
Storm Hills
Pigging facility
• a disposal well; and
• infrastructure including an emergency
shelter and helipads.
Construction is planned over four winter
seasons from 2014 to 2018 with operations
Proposed or alternative airstrip
to commence in 2018 and continue for
Gas conditioning facility
about 25 years. The initial capital expenditure
Gathering pipelines route
Liquids pipeline and gas pipeline route
Inuvik Area Facility
Significant discovery licence area
20
10
0
$800 million (2006$).
20
Kilometres
for drilling and facilities is expected to be
Inuvik
Aklavik
1249_NEB_MGP_Vol2_Text_ENG.indd 8
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Chapter 1: Introduction 9
1.2.2 Taglu field
Imperial Oil Resources Limited applied for
approval of a Development Plan under section
5.1 of the Canada Oil and Gas Operations Act
for the Taglu field on 7 October 2004.
Construction is planned to take place from 2014
Construction is planned to take place from 2014
to 2018 with operations commencing in 2018.
to 2018 with operations commencing in 2018
The estimated initial capital expenditure for
and expected to continue for 25 or 30 years.
developing the field is $1,750 million (2006$)
The estimated initial cost for developing
with an additional $800 million for future
the field is $1,200 million (2006$) with an
compression and infill wells.
additional $350 million for future compression
The Taglu Significant Discovery Licence SDL063
and infill wells.
is located about 120 kilometres northwest of
1.2.3 Parsons Lake field
Inuvik and 70 kilometres west of Tuktoyaktuk
ConocoPhillips Canada (North) Limited applied
1.2.4 Mackenzie Gathering System
in the Mackenzie Delta (see Figure 1-2).
on behalf of itself and ExxonMobil Canada
Imperial Oil Resources Ventures Limited applied
Properties for approval of a Development Plan
on behalf of itself, Shell Canada Limited,
pursuant to section 5.1 of the Canada Oil and
ConocoPhillips Canada (North) Limited, and
Gas Operations Act for the Parsons Lake field
ExxonMobil Canada Properties for authorization
on 7 October 2004.
under paragraph 5(1)(b) of the Canada Oil
The proposed production facilities include:
• up to 15 production wells drilled
from a single pad;
• one or two disposal wells;
• a gas conditioning facility;
The Parsons Lake Significant Discovery
• associated infrastructure including
Licences SDL032 and SDL030 are located about
and Gas Operations Act for the Mackenzie
Gathering System on 7 October 2006.
70 kilometres north of Inuvik and 55 kilometres
The Mackenzie Gathering System includes:
• a barge landing site;
southwest of Tuktoyaktuk, to the east of the
• approximately 190 kilometres of NPS 16,
• an airstrip and helicopter pad;
Mackenzie Delta on Tuktoyaktuk Peninsula
NPS 18, NPS 26 and NPS 32 gathering
• buildings; and
(see Figure 1-2).
pipelines to transport production from
pads and foundations;
• a water treatment system.
The proposed production facilities include:
• a north pad with 9 to 19 production wells;
• disposal wells and a gas conditioning facility;
Did you know?
• a south pad with three to seven
production wells;
Nominal pipes size (NPS)
Nominal pipe size (NPS) is a set of standard pipe
• flow lines; and
diameters used for pressure piping in North America
• support infrastructure including
measured in inches.
Approximate conversions to SI (metric) for the pipes
in this project are as follows:
Nominal pipe size
natural gas fields to the Inuvik Area Facility;
• the Inuvik Area Facility, which would process
production from the three development fields;
• an approximately 457 kilometre long NPS 10
natural gas liquids pipeline from the Inuvik
Area Facility to Norman Wells; and
• block valves, pigging facilities, and meter
stations for the upstream gathering pipelines
and the natural gas liquids pipeline.
Approximate pipe
diameter
NPS 10
250 mm
NPS 16
400 mm
NPS 18
450 mm
NPS 26
650 mm
NPS 30
750 mm
NPS 32
800 mm
1249_NEB_MGP_Vol2_Text_ENG.indd 9
an all-weather airstrip.
the Niglintgak, Taglu and Parsons Lake
12/6/10 11:01:27 AM
10 Mackenzie Gas Project • Volume 2: Implementing the decision
On 12 October 2007 MGM Energy Corp.
executed a Capacity Request Agreement
indicating its intent to become either an
owner in the Mackenzie gas gathering and
processing facilities or to contract for firm
capacity in the facilities for an identified
volume of 5.66 Mm3/d (200 MMcf/d). A supply
of 2.83 Mm /d (100 MMcf/d) from a field
3
1.2.5 Mackenzie Valley Pipeline
Imperial Oil Resources Ventures Limited applied
on behalf of itself, Mackenzie Valley Aboriginal
Pipeline Limited Partnership, Shell Canada
Limited, ConocoPhillips Canada (North) Limited,
and ExxonMobil Canada Properties for a
certificate of public convenience and necessity
• the Trout Lake heater station to be
installed when additional shipping
commitments are received;
• a meter station located at the Inuvik
Area Facility; and
• a pig receiver and block valve just south of
the Alberta-Northwest Territories boundary.
pursuant to section 52 of the National Energy
As applied for, the Mackenzie Valley Pipeline
Board Act and an order pursuant to Part IV
has a design capacity of 27.3 Mm3/d
of the National Energy Board Act approving
(964 MMcf/d) with one compressor station
the toll and tariff principles that would apply to
and 34.3 Mm3/d (1.2 Bcf/d) with three
the Mackenzie Valley Pipeline (see Figure 1‑3).
compressors and one heater station in
Subsequently, ConocoPhillips Canada (North)
operation. The design capacity is expandable
MGM Energy Corp. was the only third-party
Limited’s interests in the Mackenzie Valley
to 49.8 Mm3/d (1.8 Bcf/d) with a total
shipper to make a volume commitment to
Pipeline were transferred to ConocoPhillips
of 14 compressor stations in operation.
the Mackenzie Gas Project during the course
Northern Partnership.
The Proponents propose initially to construct
known as MGM East would be delivered to
a receipt point located at Taglu, and a supply
of 2.83 Mm3/d (100 MMcf/d) from a field
known as MGM West would be delivered
to a receipt point located at Niglintgak.
of the proceedings. MGM Energy Corp.
did not make a capacity request for space
on the Mackenzie Valley Pipeline.
The Mackenzie Valley Pipeline includes:
• approximately 1196 kilometres of buried
NPS 30 pipeline from the Inuvik Area Facility
The Mackenzie Gathering System would have
to a point of interconnection with the NOVA
the capacity to deliver about 30.9 Mm3/d
Gas Transmission Ltd. system just south of
(1.1 Bcf/d) of gas to the Mackenzie Valley
the Alberta-Northwest Territories boundary;
Pipeline and to transport about 4000 m3/d
• three compressor stations, one at Great Bear
(25,200 Bbl/d) of natural gas liquids from
River to be installed initially and two others
the Inuvik Area Facility to Norman Wells.
at Loon River North and River Between Two
The approximate capital cost of the Mackenzie
Mountains to be installed when additional
Gathering System is $3,500 million (2006$).
shipping commitments are received;
a single compressor station and no heater
station. The approximate capital cost of
the Mackenzie Valley Pipeline is $7,050 million
(2006$) with one compressor station at
the Great Bear River. The Loon River North
and River Between Two Mountains compressor
stations and the Trout Lake heater station would
add approximately $800 million to the capital
cost. The Mackenzie Valley Pipeline is scheduled
to be in service in 2018.
It is scheduled to be in service in 2018.
1249_NEB_MGP_Vol2_Text_ENG.indd 10
12/6/10 11:01:27 AM
Chapter 1: Introduction 11
1.2.6 Construction schedule
Mackenzie
Bay
Taglu
The Proponents indicated that the earliest
they would make their final decision on whether
or not to proceed with the Mackenzie Gas
Project would be at the end of 2013, subject
Amundsen Gulf
Future facility site
Pipeline and natural
Gathering pipelines route
gas liquids pipeline
Liquids pipeline and gas pipeline route
KP-0
Aklavik
Mackenzie Valley
Facility site
Inuvik
to regulatory approval and receipt of required
permits. Should the project proceed as
kilometre post
Parsons Lake
Niglintgak
Figure 1-3
KP Mackenzie Valley Pipeline
Tuktoyaktuk
Gas pipeline route
Inuvik Area
Facility
Proposed Alberta pipeline route
Regional boundary
Fort McPherson
Tsiigehtchic
Production field
100
proposed, the detailed design and construction
50
0
100
Kilometres
phases of the pipeline and related facilities
would commence by 2014 and would be
expected to continue into 2018. It would
be during this phase that the project activities
Loon River North
future compressor
station
Colville Lake
Northwest Territories
Fort Good Hope
KP-275
Nunavut
would have the greatest interaction with
Great Bear
Lake
the northern communities and the natural
environment. The Proponents submitted
that this phase of the project would also
Norman Wells
Enbridge interconnect
facility
see the completion of the following activities
Great Bear River
compressor station
in the project area:
• field investigation and testing programs
Déline
KP-457
KP-540
Tulita
Yukon
to provide data for detailed design;
• procuring and mobilizing materials,
Wrigley
equipment, goods and services;
• ongoing consultation with the northern
communities;
KP-808
Rae
River Between Two
Mountains future
compressor station
Yellowknife
• developing and constructing infrastructure
Fort Simpson
support, such as borrow sites;
• drilling and completing wells at
the development fields; and
Fort Providence
Trout River
KP-1098
• constructing production facilities and
flow lines at the development fields.
Saamba K’e
Fort Liard (Trout
Lake)
British Columbia
1249_NEB_MGP_Vol2_Text_ENG.indd 11
Great Slave
Lake
Jean Marie River
Nahanni Butte
KP-1196
Kakisa
Hay River
Enterprise
Interconnect facility
(located in Alberta)
Alberta
12/6/10 11:01:32 AM
12 Mackenzie Gas Project • Volume 2: Implementing the decision
The winter months (mid-October to late
staging and fuel storage sites). The winter
preparation, a subsequent winter season for
April) would be the primary time for pipeline
of 2014 -2015 would see the first sections
construction of the pipeline and a third winter
construction activities. The summer months
of the pipeline right of way surveyed, cleared
season for final clean-up. Work would occur
(May to October) would be used for mobilizing
and graded and further development of borrow
sequentially (clearing crews would be followed
equipment, materials and fuel to the sites to
sites, staging and tank sites, barge landing
by pipeline installation and clean-up crews)
support the winter construction. Infrastructure
sites and the main construction camps. The
proceeding in one direction along the spread
development and facility fabrication and
Proponents expect these activities to extend
with minor exceptions at some locations
construction are anticipated to proceed year
into the summer of 2015. During the summer
due to weather, construction camp locations
round. A schedule proposed by the Proponents
of 2015, pipeline materials, equipment, camps
or watercourse crossings.
is provided in Figure 1-4.
and fuel would be mobilized to site for the first
pipe laying season in the winter of 2015-2016.
Onsite activities are proposed to commence
Figure 1-4
Proposed construction
schedule for
Mackenzie Gathering
System and Mackenzie
Valley Pipeline
Clearing activities and horizontal directionally
drilled water course crossings are expected
in early summer 2014 with site preparation
The Proponents propose to divide construction
to be completed on all spreads in the first two
and initial development of some construction
of the pipeline into 12 construction spreads (see
winter construction seasons. Commissioning
support infrastructure (barge landing facilities,
Figure 1‑5). Each spread is expected
and start-up activities would be scheduled
small construction camps, borrow sites, material
to require an initial winter season for site
to commence in 2018 after the final
Regulatory,
consultation,
environmental and
socio-economic
Ongoing community consultations & communication
Environmental & socio-economic monitoring
Winter access & summer barge seasons
Infrastructure and
logistics
Borrow sites
Barge landing sites & camp installations
Initial facilities
Site civil works
Module fabrication
Module delivery to site
Installation & hookup
Pipelines
Right of way clearing
Pipeline installation
Testing,
commissioning and
reclamation
Commissioning & start up
Site reclamation
Winter access
Mackenzie barge season
1249_NEB_MGP_Vol2_Text_ENG.indd 12
Project activities
Project summer activities, where practical
2019
2018
2017
2016
2015
Year
2014
Demobilization
Proponent site specific activities
12/6/10 11:01:33 AM
Chapter 1: Introduction 13
season of pipeline installation. Reclamation
and demobilization of camps, equipment
and materials are expected to extend into
the fall of 2019.
Construction of the station facilities (Inuvik
Area Facility, metering facility and Great Bear
River Compressor Station) is proposed to
Mackenzie
Bay
Amundsen Gulf
Spread D1
55km
kilometre post
Spread D2
67km
Inuvik
Aklavik
Gathering pipelines route
Inuvik Area
Facility
Liquids pipeline and gas pipeline route
Gas pipeline route
KP-0
Proposed Alberta pipeline route
Fort McPherson
Tsiigehtchic
Spread D3
120km
Regional boundary
Construction spreads
Production field
100
KP-275
Fort Good Hope
Nunavut
Spread C2
140km
N u n a v u t
Great Bear
Lake
summer of 2016. Construction of the facility
Enbridge interconnect
facility
KP-457
Spread C1
142km
Déline
Norman Wells
Tulita
KP-540
Great Bear River
compressor station
to the facility sites to finalize assembly in the
winter of 2017-2018. The Proponents anticipate
concluding facility construction in the summer
100
Colville Lake
N o r t h w e s t Te r r i t o r i e s
drilled and installed during the winter and
Proponents anticipate mobilizing the modules
0
Kilometres
Loon River North future
compressor station
pile foundations for the facilities would be
modules would occur off site and the
50
Spread C3
134km
survey, clearing and grading of the facility sites.
summer. The Proponents submitted that the
spreads
Future facility site
commence in the winter of 2014-2015 with
Gravel pads would be installed the following
Proposed construction
Facility site
Spread D2
26km
Spread D1
41km
Figure 1-5
KP Mackenzie Valley Pipeline
Tuktoyaktuk
Spread B3
140km
Yu k o n
of 2018.
Spread B2
120km
River Between Two
Mountains future
compressor station
Wrigley
KP-808
Spread B1
120km
Rae
Yellowknife
Fort Simpson
Spread A3
110km
Trout River future
heater station
Fort Liard
British Columbia
1249_NEB_MGP_Vol2_Text_ENG.indd 13
Great Slave
Lake
Jean Marie River
Nahanni Butte
Spread A1
85km
KP-1098
Trout Lake
KP-1196
Fort Providence
Kakisa
Spread A2
85km
Hay River
Enterprise
Interconnect facility
(located in Alberta)
Alberta
12/6/10 11:01:38 AM
14 Mackenzie Gas Project • Volume 2: Implementing the decision
Did you know?
Definitions
Permafrost – soil or rock that remains at
1.3 Project setting
1.3.1 Project environment
northern pike, longnose sucker, slimy sculpin
and lake chub. Wildlife populations found in
The Mackenzie Delta is located above the
the project area include grizzly bear, polar bear,
Arctic Circle and is approximately 14 250 square
barren-ground and woodland caribou, moose,
beneath more than 90 percent of land area.
kilometres in area; more than twice the size
marten, lynx, beaver, beluga whale, bowhead
Taliks may exist beneath river channels, lakes
of Prince Edward Island. The Mackenzie Delta
whale, ringed seal, and many bird species.
and in other localized areas.
is the outlet of the Mackenzie River, which flows
On the northeast tip of the Mackenzie Delta,
Extensive discontinuous permafrost – permafrost
for approximately 1800 kilometres from Great
still more than 2000 kilometres from the
Slave Lake in the Northwest Territories to the
North Pole, lies Kendall Island Bird Sanctuary.
or below 0ºC for at least two consecutive years.
Continuous permafrost – permafrost occurs
occurs beneath 65 to 90 percent of land area.
Intermediate discontinuous permafrost –
Beaufort Sea. The Mackenzie River is Canada’s
The Sanctuary is home to more than 90 species
of land area.
longest, and one of the world’s largest, river
of birds, including the lesser snow geese,
Sporadic discontinuous permafrost – permafrost
systems. Along its route, the Mackenzie River
the tundra swan and other migratory birds.
occurs beneath 10 to 35 percent of land area.
picks up and carries a large amount of silt
Isolated patches of permafrost – permafrost
that settles out in the Mackenzie Delta,
permafrost occurs beneath 35 to 65 percent
occurs beneath less than 10 percent of land area.
Talik – a pocket of unfrozen ground in a permafrost
area, often beneath a lake or river.
Muskeg – a bog or peatland typically containing
forming an extensive network of channels,
islands, lakes and ponds. The Canadian North
has more lakes than the rest of the world
Sphagnum moss, willows and stunted black spruce
combined and more than 25,000 of them
trees. Muskeg can reach depths of 30 metres or more
are in the Mackenzie Delta.
and is a significant impediment to transportation
and construction during the summer.
1249_NEB_MGP_Vol2_Text_ENG.indd 14
41 species of fish, including Arctic grayling,
Permafrost lies beneath much of the project
area. The Niglintgak and Taglu fields are
located in areas of discontinuous permafrost
in the Mackenzie Delta (see Figure 1-6). The
Parsons Lake field is located on higher ground
to the east of the Mackenzie Delta, where the
permafrost is continuous. North of the Inuvik
The proposed Mackenzie Gas Project stretches
Area Facility, the upstream gathering pipelines
over 1000 kilometres from the Mackenzie Delta
would be buried for the most part in continuous
to northwestern Alberta and generally follows
permafrost. South of the Inuvik Area Facility,
the Mackenzie Valley. The rivers and lakes of the
the Mackenzie Valley Pipeline and natural gas
region, including the Mackenzie Delta, support
liquids pipeline would leave the continuous
12/6/10 11:01:38 AM
Chapter 1: Introduction 15
permafrost zone and enter the discontinuous
permafrost zone. South of Fort Simpson
the Mackenzie Valley Pipeline would enter
the sporadic permafrost zone.
Taglu
Mackenzie
Bay
Amundsen Gulf
kilometre post
Future facility site
Gathering pipelines route
Inuvik
The soil in the Mackenzie Delta region is thinly
Liquids pipeline and gas pipeline route
KP-0
Aklavik
layered and formed from river deposits of silt,
sand and gravel. The delta’s low-lying
Gas pipeline route
Inuvik Area
Facility
Proposed Alberta pipeline route
Regional boundary
Fort McPherson
Tsiigehtchic
Production field
Continuous permafrost
geography exposes both the Niglintgak and
Extensive discontinuous permafrost
Taglu fields to regular flooding and occasional
Intermediate discontinuous permafrost
Sporadic discontinuous permafrost
storm surges from the Beaufort Sea.
Most of the land along the pipeline route is
Permafrost regions
Facility site
Parsons Lake
Niglintgak
Figure 1-6
KP Mackenzie Valley Pipeline
Tuktoyaktuk
Loon River North
future compressor
station
Isolated patches of permafrost
KP-275 Colville Lake
N o r t h w e s t Te r r i t o r i e s
Fort Good Hope
100
50
0
100N u n a v u t
Kilometres
flat and covered with muskeg, except for
N u n a v u t
a few areas with rolling hills and other features.
Great Bear
Lake
The Mackenzie Gas Project would cross more
than 600 watercourses that vary from small,
Norman Wells
Enbridge interconnect
facility
seasonal streams to large rivers. The vegetation
KP-457
Great Bear River
compressor station
along the route changes from the treeless
KP-540
Déline
Tulita
tundra in the Mackenzie Delta to the boreal
forest in Alberta. Large areas of forest in the
Yu k o n
Mackenzie Valley have burned in recent years.
Wrigley
Rare plants and uncommon vegetation types
are found throughout the region. Some plants
are used for traditional purposes, such as food,
medicine, ceremonies or materials.
KP-808
Rae
River Between Two
Mountains future
compressor station
Yellowknife
Fort Simpson
Great Slave
Lake
Jean Marie River
Fort Providence
Nahanni Butte
Trout River future
heater station
KP-1098
Saamba K’e
Fort Liard (Trout
Lake)
British Columbia
1249_NEB_MGP_Vol2_Text_ENG.indd 15
KP-1196
Kakisa
Hay River
Enterprise
Interconnect facility
(located in Alberta)
Alberta
12/6/10 11:01:43 AM
16 Mackenzie Gas Project • Volume 2: Implementing the decision
Figure 1-7
Mackenzie
Bay
1.3.2 Social, cultural and
Amundsen Gulf
Tuktoyaktuk
Land claim regions
economic setting
Proposed pipeline route
Proposed Alberta pipeline route
of the Mackenzie Valley
District boundary
Regional boundary
100
Inuvik
Aklavik
50
0
100
in the Northwest Territories and in northwestern
Alberta that could be affected by the Mackenzie
Kilometres
INUVIALUIT
SETTLEMENT REGION
The Proponents identified up to 32 communities
Gas Project (see Table 1-1). The 26 communities
Fort McPherson
Tsiigehtchic
in the Northwest Territories are home to
GWICH'IN
SETTLEMENT
AREA
about 35,000 residents and are found in
SAHTU SETTLEMENT AREA
K'AHSHO GOT'INE DISTRICT
four regions — Inuvialuit Settlement Region,
Gwich’in Settlement Area, Sahtu Settlement
Colville Lake
N o r t h w e s t Te r r i t o r i e s
Fort Good Hope
Nunavut
Area, and the Dehcho Region. The six
communities in northwestern Alberta are
N u n a v u t
home to about 7,000 residents and are located
Norman Wells
DÉLINE DISTRICT
Great Bear
Lake
in the Dene Tha’ First Nation region.
The population in the four regions of the
Déline
Northwest Territories in the Mackenzie Delta
Tulita
and along the Mackenzie Valley where the
Yu k o n
Mackenzie Gas Project would be built is about
TLI CHO
REGION
SAHTU SETTLEMENT AREA
TULITA DISTRICT
12,000. More than 75 percent of these people
are Aboriginal. Most live in communities smaller
than 1,000 people. About half of the total
Wrigley
Northwest Territories population and about
Rae
40 percent of the northwestern Alberta
Yellowknife
DEH CHO
REGION
Great Slave
Lake
Jean Marie River
Nahanni Butte
Fort Providence
Kakisa
Saamba K’e
Fort Liard (Trout
Lake)
British Columbia
1249_NEB_MGP_Vol2_Text_ENG.indd 16
population is Aboriginal.
Fort Simpson
Hay River
Enterprise
Saskatchewan
DENE THA’ FIRST NATION A l b e r t a
12/6/10 11:01:49 AM
Chapter 1: Introduction 17
In the project area, some land claims have
been settled. The first was the Inuvialuit Final
Area
Region
Community
Northwest Territories
Inuvialuit Settlement Region
Aklavik
Tuktoyaktuk
Holman
Paulatuk
Sachs Harbour
Agreement in 1984. In 1992, the Gwich’in
signed an agreement that established
the Gwich’in Settlement Area. In 1994 the
Sahtu Dene and Metis Land Claim Settlement
Gwich’in Settlement
Inuvik
Fort McPherson
Tsiigehtchic
Sahtu Settlement Area
Norman Wells
Fort Good Hope
Deline
Tulita
Colville Lake
Dehcho Region
Fort Simpson
Fort Providence
Fort Liard
Wrigley
Nahanni Butte
Trout Lake
Jean Marie River
Kakisa
Hay River Reserve
West Point Reserve
Industrial and commercial centres
Yellowknife
Hay River
Enterprise
Dene Tha’ First Nation
Chateh
Meander River
Bushe River
Industrial and commercial centres
High Level
Rainbow Lake
Zama City
Act came into effect. There are ongoing
negotiations with the Dehcho (see Figure 1-7).
The cost of living is higher in more northern
communities due to their distance from the
source of supply for basic goods. Based on a
2000 survey, the cost of living in the Mackenzie
Delta was 25 percent to 115 percent higher
than in Edmonton, Alberta, depending on the
remoteness of the community. Country foods
such as caribou and moose are a large part of
the diet for many Aboriginal people. Traditional
gathering and harvesting supplement earned
incomes and help offset the high cost of living.
In most communities, government-related
Northwestern Alberta
employment is the largest and most stable
economic influence.
1249_NEB_MGP_Vol2_Text_ENG.indd 17
Table 1-1
Potentially affected
communities
12/6/10 11:01:50 AM
Chapter 2
Regulatory review process
2.1 Role of the National Energy Board
The National Energy Board regulates safety, security, environmental and economic matters
throughout a pipeline project’s lifespan. The National Energy Board has developed regulations
and guidelines for the safety, security and protection of people, the environment and property.
For example, pipelines regulated under the National Energy Board Act must be designed in
accordance with the National Energy Board’s Onshore Pipeline Regulations, 1999 and the latest
versions of relevant design codes, including the Canadian Standards Association Z662, Oil and Gas
Pipeline Systems. Pipelines must also be operated in accordance with all other regulations under
the National Energy Board Act, such as the Toll Information Regulations and Gas Pipeline Uniform
Accounting Regulations. Facilities regulated under the Canada Oil and Gas Operations Act must
be designed and operated in accordance with their own set of regulations.
1249_NEB_MGP_Vol2_Text_ENG.indd 18
The National Energy Board’s role as regulator
As well as regulating the physical facilities,
is to oversee that safety and environmental
the National Energy Board oversees the
issues associated with construction, operation
economic aspects of a proposed project.
and abandonment of regulated facilities are
Pipeline development in Canada may occur
identified and managed by the owners of
in a competitive market but often occurs
these facilities. The National Energy Board
in a monopoly or near-monopoly situation.
satisfies itself that a facility’s design and
The National Energy Board’s authority for
proposed operations would result in a project
economic regulation of pipelines is intended
that is safe, reliable and environmentally
to ensure that the prices set for transporting
responsible before it is approved.
the gas, the costs that are incurred by
12/6/10 11:01:51 AM
Chapter 2: Regulatory review process 19
the pipeline proponents and the returns to
the pipeline owners are similar to those that
would occur if the market were competitive.
2.2 The “public interest”
We must decide whether Canadian society
would be better or worse off if the project
Before submitting an application to the National
is approved. The National Energy Board Act
Energy Board, companies must ensure that the
requires us to consider any public interest
proposed project would comply with existing
that may be affected by granting or refusing
statutory and regulatory requirements.
the application. To determine if a project is in
Once an application is received, the National
Energy Board typically reviews the proposed
project to:
• assess the application from economic,
the public interest, we consider the potential
benefits it could bring to Canadians and the
burdens it could place on Canadians.
In doing so, we examine engineering, economic,
engineering, safety, environment and
environmental and socio-economic factors.
lands perspectives;
In particular, we assessed:
• ensure that regulated companies have
notified and consulted with landowners,
Aboriginal peoples, and other affected
parties;
• determine how best to provide opportunities
for affected people and other stakeholders to
provide their input on the proposed project;
and
• determine whether, with specific mitigation
measures and other conditions, the project
would be in the public interest.
• the proposed engineering design —
whether or not the facilities will be safe;
• the economics of the proposed project —
is there sufficient supply and demand,
will other parties have access to the facilities;
are the tolls and tariffs reasonable;
• the effect the proposed project will have
To ensure that we heard a wide range
of views from an informed and engaged
public, we carried out activities to encourage
meaningful participation in the review process
for the Mackenzie Gas Project by all potentially
affected people. These activities were designed
with the following objectives:
• to share information in a timely manner
with the public about the National Energy
Board’s process;
• to design a process that generally reflects
the public’s needs and expectations;
• to design a process that takes into account
Northerners’ experiences and expectations;
and
• to ensure that the hearing process provides
an opportunity to people from all walks
of life to participate fully and in a manner
in which they felt comfortable.
If the National Energy Board determines
that a project is in the public interest, its role
on the environment, as well as the effect
as a regulator would continue through the
the environment will have on the project —
construction, operation and abandonment
the environment includes the physical,
phases of the project.
social and cultural setting where the facilities
would be built; and
• the effect the proposed project would
have on individuals, groups, communities
and societies.
1249_NEB_MGP_Vol2_Text_ENG.indd 19
12/6/10 11:01:51 AM
20 Mackenzie Gas Project • Volume 2: Implementing the decision
Did you know?
Contributing partners to the Cooperation Plan
Boards and agencies with mandatory public
hearing processes:
• Mackenzie Valley Land and Water Board;
• Mackenzie Valley Environmental Impact
Review Board;
Energy Board authorized Mr. Harrison
of review process
under subsection 15(1) of the National
Energy Board Act to report and make
A renewed interest in developing northern
gas resources emerged in 2000. The many
agencies that would be affected by a pipeline
proposal realized that there would be
recommendations on social, cultural,
economic and environmental matters
pertaining to the Mackenzie Gas Project.
• Gwich’in Land and Water Board;
substantial duplication and overlap of public
As contemplated in the Cooperation
• Sahtu Land and Water Board;
review processes if each agency worked alone.
Plan our hearing process was coordinated
• Northwest Territories Water Board;
Beginning in the fall of 2000 the heads of
with the Environmental Impact Review
• Canadian Environmental Assessment Agency;
these agencies met to explore means of
of the Mackenzie Gas Project by the Joint
• National Energy Board; and
working cooperatively to minimize duplication
Review Panel. The Joint Review Panel Report
• Environmental Impact Review Board for
and overlap. In June 2002, the agencies signed
and Mr. Harrison’s subsection 15(1) report
the Cooperation Plan for the Environmental
were taken into account in our public
Impact Assessment and Regulatory Review
interest determination.
the Inuvialuit Settlement Region.
Other agencies with a direct interest in Environmental
Impact Statement and regulatory matters:
• Joint Secretariat for the Inuvialuit
Settlement Region;
• Environmental Impact Screening Committee
for the Inuvialuit Settlement Region;
of a Northern Gas Pipeline Project through
the Northwest Territories (Cooperation Plan).
The Cooperation Plan provided a framework
for a joint environmental impact assessment
The filings made with the National Energy
Board and the Mackenzie Valley Land and
Water Board initiated the regulatory and
• Inuvialuit Game Council;
process that met the requirements of the
environmental review processes (see Table 2-1).
• Inuvialuit Land Administration;
Inuvialuit Final Agreement, the Mackenzie
The Agreement issued on 22 April 2004 set out
• Inuvialuit Land Administration Commission; and
Valley Resource Management Act and the
details for the environmental impact assessment
Canadian Environmental Assessment Act.
by a Joint Review Panel, the coordination of
Mr. Rowland J. Harrison, Q.C. of the National
hearings between regulatory agencies and the
Energy Board was appointed as a member
maintenance of a public registry. It also set out
of the Joint Review Panel for the Mackenzie
the role of the Northern Gas Project Secretariat,
Gas Project (Joint Review Panel). To assist
which provided logistical, communications,
the National Energy Board in meeting its
information management, administrative and
environmental requirements, the National
technical support throughout the review process.
• Indian and Northern Affairs Canada.
Observers:
• Nominee of the Dehcho First Nation to
the Mackenzie Valley Land and Water Board;
• Government of the Northwest Territories; and
• Government of Yukon.
1249_NEB_MGP_Vol2_Text_ENG.indd 20
2.3 Coordination
12/6/10 11:01:51 AM
Chapter 2: Regulatory review process 21
Table 2-1
Initial events in the coordinated review process
Date
Event
18 June 2003
Preliminary information package filed by the Proponents of the Mackenzie Gas Project
with the National Energy Board.
21 July 2003
An application for a Type A Land Use Permit and Type B Water Licence for the
Camsell Bend Development filed with the Mackenzie Valley Land and Water Board.
This triggered the environmental review process.
21 August 2003
Mackenzie Gas Project referred by the Minister of the Environment to a Joint Review
Panel under the Canadian Environmental Assessment Act.
22 April 2004
Agreement for the Coordination of the Regulatory Review of the Mackenzie Gas Project
signed by the parties.
July/August 2004
Agreement for an Environmental Review of the Mackenzie Gas Project signed by
the Chair of the Mackenzie Valley Environmental Impact Review Board, Chair of the
Inuvialuit Game Council, and Federal Minister of the Environment.
Figure 2-1
Process timeline
for review of
Companies
indicate interest
in northern gas
Companies
conduct public
consultation
Companies file
preliminary
information
package
Companies
file project
applications
Companies
ready to start
public hearings
Companies file
project update
Mackenzie Gas Project
2000
2001
Agency heads
begin cooperation
discussions
1249_NEB_MGP_Vol2_Text_ENG.indd 21
2002
Cooperation
Plan released
2003
2004
2005
Joint Review
Panel established
2006
Public
hearings
begin
2007
2008
2009
2010
Joint Review Panel report released
Public hearings end
NEB decision released
12/6/10 11:01:51 AM
22 Mackenzie Gas Project • Volume 2: Implementing the decision
2.4 National Energy Board
(Appendix A – List of issues) by way of Order
Yellowknife, Fort Good Hope and Fort Simpson.
hearing process
AO-1-GH-1-2004, dated 23 November 2005,
The purpose of the conference was two-fold: to
to address concerns about tolls, access, tariff
provide information on our hearing process and
2.4.1 Overview
provisions and dispute mechanisms related to
the National Energy Board’s role throughout the
The National Energy Board received the
the Mackenzie Gathering System. Key events
lifespan of a pipeline; and to hear participants’
applications for the Mackenzie Gas Project
in our hearing process are shown in Table 2-2
views on shaping certain parts of the hearing
in October 2004. Following an initial review
and Appendix C – Summary of events.
process to meet their needs.
2.4.2 Events leading up to
2.4.3 Oral hearing
the oral hearing
By letter of 23 November 2005 the Proponents
with the Joint Review Panel’s hearing sessions
Throughout 2005, we continued our
indicated that they were ready to start the
(see Figure 2-2).
examination of the applications, which included
public hearings. We released our hearing
we decided to hold a hearing and issued
Hearing Order GH-1-2004 on 24 November
2004. Our hearing sessions were coordinated
the exchange of several rounds of information
schedule on 20 December 2005. The scheduled
Hearing Order GH-1-2004 initially contained a
requests and the submission of evidence
evidentiary portion of the oral hearing started
list of 12 issues for discussion in the hearing
by participants. Also throughout 2005, the
in Inuvik on 25 January 2006 and ended back
related to the National Energy Board’s mandate
National Energy Board, the Joint Review Panel
in Inuvik on 14 December 2006. The evidentiary
pursuant to the National Energy Board Act
and the Northern Gas Project Secretariat held
hearing involved the questioning of witnesses
and the Canada Oil and Gas Operations Act.
information sessions in northern communities
for the Proponents and intervenors on their
We focused on engineering, safety and
near the pipeline route to explain their roles and
filed evidence and the presentation of oral
economic matters in our hearing, whereas the
to provide information on the National Energy
statements by members of the communities.
Joint Review Panel focused on environmental,
Board and Joint Review Panel hearing processes.
We held hearing sessions on 47 days in 15
cultural, and socio-economic matters. Following
We held a pre-hearing planning conference
communities in the Northwest Territories
the receipt of comments from intervenors,
between 5 and 13 December 2005 in Inuvik,
and Northern Alberta throughout 2006.
Issue 13 was added to the list of issues
Figure 2-2
National Energy Board
and Joint Review Panel
Write report
Hearings
Translate & publish
Joint Review
Panel
coordinated hearing
schedule
Final argument
Adjourn
Prepare and translate report
2011
2010
2009
2008
2007
Conditions1
2006
Year
Adjourn
Hearings
National
Energy Board
1. Written comment process on NEB response to Joint Review Panel recommendations,
including proposed conditions. Addresses NEB role with respect to “consult to modify”aspect
of Mackenzie Valley Resource Management Act.
1249_NEB_MGP_Vol2_Text_ENG.indd 22
12/6/10 11:01:51 AM
Chapter 2: Regulatory review process 23
On 7 April 2006 Mackenzie Explorer Group
Mackenzie Explorer Group subsequently
to examine the updated evidence that was filed
filed a motion with us for an order that,
appealed our decision. The appeal was heard
by the Proponents, the Government of Canada
when constructed and placed into service,
by the Federal Court of Appeal on 23 October
Crown Consultation Unit and other intervenors.
the Mackenzie Gathering System and the
2007 and dismissed on 22 April 2008.
This brought the evidentiary portion of
Mackenzie Valley Pipeline will be a single
pipeline subject to regulation under Part IV
of the National Energy Board Act and that
the Proponents prepare, file and serve the toll
principles and the tariff(s) for this single pipeline
In early 2007, the Proponents filed updates
the hearing to a total of 50 days.
to the applications and on 10 and 11 October
2.4.4 National Energy Board Act
2007 we held an oral hearing session in
subsection 15(1) Member’s report
Yellowknife to examine the updated evidence.
Mr. Rowland J. Harrison, Q.C., the National
for approval under Part IV of the National
In March 2010 we provided an opportunity
Energy Board Member appointed to the
Energy Board Act. An oral hearing was held in
for parties to file updated evidence and on
Joint Review Panel, was authorized under
Yellowknife on 2 June 2006. On 10 July 2006
28 March 2010 a hearing session was held in
subsection 15(1) of the National Energy Board
we denied Mackenzie Explorer Group’s motion.
Yellowknife to allow parties the opportunity
Act to report and make recommendations
to the National Energy Board on matters
identified in the Environmental Impact
Statement Terms of Reference for the
Table 2-2
Key events in the National Energy Board hearing process
Mackenzie Gas Project under Authorization
MO-13-2004 dated 15 October 2004 (see
Date
Event
November 2004 to
December 2005
Information sessions and technical review
5 to 13 December 2005
Pre-hearing Planning Conference in Inuvik, Yellowknife, Fort Good Hope,
and Fort Simpson
issued on 30 December 2009. In it he adopted
25 January 2006 to
14 December 2006
National Energy Board hearing sessions in 15 Northern communities
of fulfilling the requirements of his National
2 June 2006
Mackenzie Explorers Group motion heard in Yellowknife
10 July 2006
Ruling on Mackenzie Explorers Group motion
5 February 2007
Proposed conditions initially issued for comment
10 and 11 October 2007
Hearing in Yellowknife to examine updated evidence
2.4.5 Consult to modify process
14 December 2007
Federal government enacted changes to the Canada Oil and Gas Operations
Act, granting the National Energy Board the power to regulate tolls, tariffs
and access on COGOA pipelines.
and final argument
Federal Court of Appeal dismissed Mackenzie Explorer Group’s appeal, noting
but not basing their decision on the fact that changes to the Canada Oil
and Gas Operations Act had resolved Mackenzie Explorer Group’s concerns.
on 30 December 2009, following which we
22 April 2008
Mr. Harrison’s subsection 15(1) report was
30 December 2009
Joint Review Panel Report issued
30 December 2009
Mr. Harrison’s subsection 15(1) Report issued
Jan. to Mar. 2010
Consult to modify process
28 March 2010
Hearing in Yellowknife to examine updated evidence
12 to 22 April 2010
Final argument in Yellowknife and Inuvik
1249_NEB_MGP_Vol2_Text_ENG.indd 23
Appendix F – Authorization MO-13-2004).
the Joint Review Panel Report for the purposes
Energy Board obligation (see Appendix G –
Mr. Rowland J. Harrison’s Subsection 15(1)
Report).
The Joint Review Panel Report was issued
conducted a “consult to modify” process
under section 137 and subsection 141(6) of
the Mackenzie Valley Resource Management
Act. By letter dated 9 March 2010, parties
to both the National Energy Board hearing
and the Joint Review Panel hearing were
invited to comment on Joint Review Panel’s
12/6/10 11:01:51 AM
24 Mackenzie Gas Project • Volume 2: Implementing the decision
Figure 2-3
Mackenzie
Bay
recommended measures that were directed
Amundsen Gulf
Hearings and information sessions
Tuktoyaktuk
Communities where
Information sessions
Proposed pipeline route
our information sessions
Proposed Alberta pipeline route
and public hearings
were held
District boundary
Inuvik
INUVIALUIT
SETTLEMENT REGION
Production field
100
50
0
100
GWICH'IN
SETTLEMENT
AREA
proposed modifications to the recommended
which were cross-referenced to the Joint Review
Panel’s recommended measures by way of
Kilometres
Fort McPherson
Tsiigehtchic
comments from 30 parties, and then made
measures in the form of proposed conditions,
Regional boundary
Aklavik
to the National Energy Board. We received
a concordance table. These were presented
SAHTU SETTLEMENT AREA
K'AHSHO GOT'INE DISTRICT
to the Joint Review Panel for its comment and
for the comment of parties in the final argument
Colville Lake
N o r t h w e s t Te r r i t o r i e s
Fort Good Hope
Nunavut
phase of our hearing (see Section 3.2, Consult
to modify process). We received a letter from
N uon
n a31
v u
t
the Joint Review Panel
March
2010
Norman Wells
DÉLINE DISTRICT
responding to our proposed conditions.
Great Bear
Lake
We resumed our hearing 12 April 2010 in
Déline
Yellowknife to hear final argument. Our hearing
Tulita
ended on 22 April 2010 in Inuvik after a total
of 58 hearing days.
Yu k o n
SAHTU SETTLEMENT AREA
TULITA DISTRICT
Meander River, AB
In addition to the evidence obtained through
TLI CHO
REGION
our hearing process, we also considered the
Wrigley
Joint Review Panel Report, Mr. Harrison’s
High Level, AB
subsection 15(1) report, the comments received
in the consult to modify process, the
Yellowknife
Alberta
DEH CHO
REGION
Fort Simpson
Hay River
Jean Marie River
Nahanni Butte
Saamba K’e
Fort Liard (Trout
Lake)
British Columbia
West Point
Great Slave
First Nation
Lake
K’atlodeeche
Fort Providence First Nation
(Hay River Reserve)
Kakisa
Enterprise
Governments of Canada & of the Northwest
Territories Final Response to the Joint Review
Panel Report for the Proposed Mackenzie Gas
Project and the comments on that response
before making our regulatory decisions with
respect to the Mackenzie Gas Project. We
Saskatchewan
have adopted the Joint Review Panel’s
DENE THA’ FIRST NATION A l b e r t a
recommendations directed to us, as modified,
and they have been included in the conditions
to the approvals granted for the Mackenzie Gas
Project. The National Energy Board will monitor
and enforce the implementation of the
conditions in the approvals.
1249_NEB_MGP_Vol2_Text_ENG.indd 24
12/6/10 11:01:56 AM
Chapter 2: Regulatory review process 25
Did you know?
2004
Northern Gas Project Secretariat
Inuvik, NT (Nov. 15)
Norman Wells, NT (Nov. 16)
The parties responsible for the environmental impact
Leading up to the beginning of public hearings in late
Yellowknife, NT (Nov. 17)
assessment and regulatory review of the Mackenzie
January 2006, the Northern Gas Project Secretariat
Gas Project agreed through the Cooperation Plan
coordinated information sessions with the National
Fort Simpson, NT (Nov. 23)
to coordinate and harmonize their review and public
Energy Board and Joint Review Panel to explain
hearing processes for the Mackenzie Gas Project.
the review process and to present up-to-date
The parties determined that their review could most
information about how the public could participate.
effectively be implemented through the services
In addition to organizing formal public information
of a secretariat to support and coordinate the public
sessions, the Northern Gas Project Secretariat
hearing processes, including all aspects related
conducted several informal visits to the communities
to public involvement.
along the project route to assist community leaders
The Northern Gas Project Secretariat was established
High Level, AB (Dec. 13)
Enterprise, NT (Dec. 14)
2005
Hay River, NT (Jan. 13)
Tulita, NT (Feb. 8)
Fort Good Hope, NT (Feb. 9)
Inuvik, NT (Feb. 28)
Norman Wells, NT (Mar. 1)
in their preparations for the public hearing process.
Yellowknife, NT (Mar. 3)
in 2003 to assist in coordinating the regulatory review
The Northern Gas Project Secretariat published
and environmental assessment of the Mackenzie Gas
an electronic monthly newsletter in English plain
Meander River, AB (Mar. 9)
Project. An Executive Committee of Chairs, supported
language: The Review – your link to the review
Fort Simpson, NT (Mar. 10)
by the Northern Gas Project Secretariat, provided the
of the Mackenzie Gas Project. The goal of the
Aklavik, NT (Mar. 15)
forum through which all involved parties could present
newsletter was to bring the most up-to-date
Wrigley, NT (Mar. 16)
their positions and requirements and where cooperative
information on the project to community decision-
Tuktoyaktuk, NT (Mar. 23)
and harmonized approaches would be developed while
makers and leadership in an easy-to-understand,
respecting the need for the review processes to be
electronic format. Throughout the hearing process the
conducted independently. The committee comprised
Northern Gas Project Secretariat maintained offices in
the Sitting Chairs of the Joint Review Panel, the NEB
Yellowknife, Inuvik, Norman Wells and Fort Simpson.
Panel, the Mackenzie Land and Water Board and the
Northwest Territories Water Board.
Saamba K'e (Trout Lake), NT (Oct. 12)
Jean Marie River, NT (Oct. 13)
Colville Lake, NT (Oct. 19)
Tsiigehtchic, NT (Oct. 20)
A list of public information sessions held by the
Inuvik, NT (Elders’ session) (Oct 20)
Northern Gas Project Secretariat, the Joint Review
West Point First Nation, NT (Nov. 2)
Panel and the National Energy Board follows.
Ft. Liard, NT (Nov. 14)
Nahanni Butte, NT (Nov. 15)
Fort Providence, NT (Nov. 21)
Kakisa, NT (Nov. 24)
Déline, NT (Nov. 25)
Fort McPherson, NT (Nov. 29)
Tsiigehtchic, NT (Nov. 30)
2006
1249_NEB_MGP_Vol2_Text_ENG.indd 25
K’atlodeeche First Nation
(Hay River Reserve), NT (Jan. 19)
12/6/10 11:01:57 AM
Chapter 3
Environmental and
socio-economic matters
3.1 Joint Review Panel process
In August 2003, the federal Minister of the Environment referred the Mackenzie Gas Project
to a Joint Review Panel under the Canadian Environmental Assessment Act. In January 2004,
the Inuvialuit Environmental Impact Screening Committee, under the Western Arctic Claim:
The Inuvialuit Final Agreement, made the decision to refer the project to the review panel process.
On 20 April 2004, the Mackenzie Valley Environmental Impact Review Board announced that it
had decided to refer the project to an environmental impact review. In May 2004, the Minister
of Indian Affairs and Northern Development Canada gave his approval for the Mackenzie Valley
Environmental Impact Review Board to enter into an agreement to establish a joint review panel.
An Agreement for an Environmental Impact Review of the Mackenzie Gas Project was released on
9 August 2004. This agreement created the Joint Review Panel, set out its mandate and established
the Scope of the Environmental Impact Review, including the factors to be considered in the review.
Under the Joint Review Panel Agreement,
As set out in the Joint Review Panel Agreement,
the signatory agencies issued the Environmental
the Joint Review Panel was also required to
Impact Statement Terms of Reference for
have regard to “the protection of the existing
the Mackenzie Gas Project in August 2004.
and future social, cultural and economic
The Terms of Reference contained guidelines
well-being of residents and communities”,
for the preparation of an Environmental Impact
in addition to its consideration of environmental
Statement for the Mackenzie Gas Project,
matters. The social, cultural and economic
including the nature and scope of the issues
concerns that were raised with the Joint Review
that the Proponents needed to address. The
Panel included:
Environmental Impact Statement served as
• resource harvesting;
a basis for the Joint Review Panel’s review
• land use;
and evaluation of the potential impacts of the
• cultural heritage;
Mackenzie Gas Project on the environment.
• infrastructure and services; and
• economic, social and cultural impacts.
1249_NEB_MGP_Vol2_Text_ENG.indd 26
12/6/10 11:01:58 AM
Chapter 3: Environmental and socio-economic matters 27
Our hearing focused on safety, engineering
to provide comments on recommendations
conditions because they were duplicative of the
and economic issues, but comments received
within the National Energy Board’s mandate
requirements of statutes and regulations or of
during the consult to modify process and final
according to the following schedule:
the mandate of other regulatory authorities;
required the National Energy Board to delegate
argument also included a number of social,
cultural and economic issues and concerns. 28 January 2010
On 2 September 2004 the federal Minister of
Environment appointed Mr. Rowland J. Harrison,
11 February 2010
Parties to both hearings
sent comments to us, the
Proponents and other parties
18 February 2010
The Proponents sent reply
comments to us and parties
to both hearings
Q.C., a member of the National Energy Board,
as one of the seven members comprising the
Joint Review Panel. On 15 October 2004, the
National Energy Board authorized Mr. Harrison
9 March 2010
to report and make recommendations to us in
our consideration of the Mackenzie Gas Project.
On 30 December 2009 the Joint Review
Panel issued its report and Mr. Harrison
The Proponents sent
comments to us and parties
to both hearings
29 March 2010
action by various federal and territorial
we provided a separate administrative
governments and agencies.
process to gather comments for use by
recommendations of the Joint Review Panel
or, after consulting with the Joint Review Panel,
adopt the recommendations with modifications
or reject them.
other federal and territorial government
have not rejected any of the Panel’s
recommendations that are directed
proposed by the NEB are primarily
the implementation of those
recommendations conforms to
established NEB protocols and
procedures, operational requirements
and other statutes and regulations.
departments and agencies.
A copy of the letter is included in Appendix J.
In a letter dated 9 March 2010, attached as
The summary of the Joint Review Panel’s
Appendix H, we proposed modifications to the
recommendations directed to the National
Joint Review Panel recommendations that were
Energy Board and references to our associated
directed to us and listed our proposed
conditions can be found in the Concordance
conditions, many of which were designed to
Table in Appendix I.
address the Joint Review Panel recommendations
as modified. We indicated that the proposed
modifications preserved the intent of the
On 6 January 2010, we established a process to
recommendations and were made to clarify
consult on the Joint Review Panel recommenda-
desired end results and timing for
tions. Parties to both our hearing and the
implementation. We also stated that some
Joint Review Panel hearing were invited
recommendations were not included as
1249_NEB_MGP_Vol2_Text_ENG.indd 27
The Joint Review Panel concluded that:
for the purpose of ensuring that
of the National Energy Board’s mandate,
designated regulatory agency to adopt the
proposed modifications on 29 March 2010.
to the NEB and that the modifications
were addressed to us. The remainder required
require the National Energy Board as a
The Joint Review Panel responded to the
The Joint Review Panel
responded to our proposed
modifications
For recommendations that fell outside
Mackenzie Valley Resource Management Act
the present applications.
the NEB Proposed Conditions
contained 176 recommendations, 85 of which
Subsection 141(6) and section 137 of the
operational matters; or fell outside the scope of
We drafted proposed
modifications and provided
them to the Joint Review
Panel for written response
adopted it as his report to us. The report
3.2 Consult to modify process
its authority to others; related to internal
12/6/10 11:01:58 AM
28 Mackenzie Gas Project • Volume 2: Implementing the decision
3.3 Environmental matters
decision for the Mackenzie Gas Project.
The Sierra Club of Canada countered this by
discussed in final argument
The Proponents stated that:
reaffirming what was heard before the Joint
In keeping with the purposes of establishing
from an environmental assessment
the Joint Review Process, we relied on the Joint
perspective, the issue in any event
Review Panel Report for the environmental and
isn’t whether the Proponents believe
socio-economic assessment of the Mackenzie
that the addition of future facilities
Gas Project. Matters arising from the Joint
is reasonably foreseeable. The issue
Review Panel Report were raised in final
is whether there is sufficient detail about
argument. These matters were:
future facilities to allow for a meaningful
• cumulative effects and upstream impacts;
assessment of their effects to be made,
• end use of gas and downstream impacts;
which in this case there clearly is not.
• air quality issues and greenhouse
gas emissions;
of development that follows a pipeline going
into a frontier area and that the commonality
between the Sproule Associates Limited and
Gilbert Laustsen Jung Associates Ltd. supply
studies shows likely locations of future
development, therefore future development is
neither hypothetical nor fanciful. World Wildlife
Fund Canada submitted that the Joint Review
Panel appropriately exercised its discretion
The Proponents submitted that future induced
as to what it regards as reasonably foreseeable
development should not be included in the
projects. Both the Sierra Club of Canada and
• impacts of climate change on the project;
cumulative effects assessment in the first place
World Wildlife Fund Canada submitted that
• wildlife and species at risk;
because it is contrary to the law and contrary
we should not revisit the Joint Review Panel’s
• environmental protection plans; and,
to environmental assessment guidance. For this
conclusion on the importance of induced
• National Energy Board’s role in enforcing
same reason, the National Energy Board should
development for sustainability, but rely on
not include conditions about such developments
the Joint Review Panel’s conclusions and
in the Mackenzie Gas Project decision. The
recommendations in light of the delegation
Proponents then concluded that the National
of the social and environmental review to it.
recommendations directed at others.
3.3.1 Cumulative effects and
upstream impacts
To address the potential effects of the project
as filed and the potential cumulative effects of
future developments, the Joint Review Panel
directed recommendations to us, governments,
and regulatory agencies and authorities. The
1249_NEB_MGP_Vol2_Text_ENG.indd 28
Review Panel: that there is a typical sequence
Energy Board must not include those Joint
Review Panel recommendations related to
future facilities in the environmental assessment
decision for the Mackenzie Gas Project,
and that the National Energy Board:
Related views were presented on the linkage
between future induced developments and
sustainability and its relevance to our decision.
The Proponents submitted that the basis for
the Joint Review Panel’s sustainability conclusion
Joint Review Panel concluded that, subject to
should make a decision to permit
on page 585 of the Joint Review Panel Report is
the full implementation of its recommendations,
the Mackenzie Gas Project to proceed,
flawed because the Joint Review Panel actually
the project is not likely to have significant
subject to the implementation of the
assessed future development for which little
adverse environmental effects. The Proponents
mitigative and remedial measures and
is known, instead of assessing the Mackenzie
submitted that this conclusion is unsustainable
follow-up programs as proposed in the
Gas Project itself. The Sierra Club of Canada
because it was inappropriate for the Joint
NEB letters dated March 9 2010, on the
submitted that specialist advisors to the Joint
Review Panel to tie its recommendations
basis that the Mackenzie Gas Project is
Review Panel emphasized the importance of
related to speculative or hypothetical future
not likely to cause significant adverse
considering induced development before being
developments to the environmental assessment
environmental effects.
able to determine sustainability. The Sierra Club
12/6/10 11:01:58 AM
Chapter 3: Environmental and socio-economic matters 29
of Canada also proposed that it is incumbent on
and limits of acceptable change. The Sierra
fund to take place. The Mackenzie Valley
the National Energy Board to take on the idea
Club of Canada urged us to make sure that
Aboriginal Pipeline Limited Partnership
of sustainability as part of its own processes.
the recommendations from the Joint Review
(Aboriginal Pipeline Group), representing
Panel to control cumulative impacts from
members of the Inuvialuit, Gwich’in and Sahtu,
induced development are put in place before
submitted that care must be taken so that the
the project goes ahead.
project is not burdened with unreasonable
Parties also stated their concerns to us
about how cumulative effects of future
development would be managed. The Joint
Review Panel Report presented a number of
The Inuvialuit Regional Corporation
recommendations related to future development
submitted that:
directed to us and to government authorities.
Alternatives North submitted that Northerners
do not want to see the same pattern of
hydrocarbon development that happened in
Alberta, and that it is unacceptable that each
development be assessed separately at different
times without adequate up-front consideration
of cumulative effects. World Wildlife Fund
Canada supported the principle of Conservation
First, submitting that this means anticipating
cumulative effects and induced development
and sequencing up front certain conservation
expectations. It objected to the Joint Review
Panel’s recommendations which would freeze
future development, and did not believe that
While we do not support the extent
was their mandate in the first place. The
to which the Joint Review Panel report
Aboriginal Pipeline Group added that:
recommends additional assessment
procedures throughout this expansion
process, we nevertheless appreciate, in
principle, the need to ensure the future
development of our region’s hydrocarbon
resources does not occur at a scale and
We have protected our land for
thousands of years. We are proud
of this land given to us by the Creator
to provide for us. We will continue
to use our land wisely.
pace that will endanger our natural
The Sierra Club of Canada submitted that
environment and overwhelm the social
imposing conditions related to future projects
fabric of our communities.
does not fetter the discretion of future
panels. The Sierra Club of Canada submitted
accomplishments while Northerners still have
The Inuvialuit Regional Corporation stated that
a chance to do so. The Sierra Club of Canada
the Inuvialuit have worked in close partnership
expressed the need for up-front controls
with government departments and agencies,
on the pace and scale of upstream-induced
with co-management boards, and with other
development. The Sierra Club of Canada
Aboriginal groups to identify both the
must actually be implemented. Dehcho First
supported the Joint Review Panel’s position
anticipated impact of these developments and
Nations submitted their concerns that we did
that mitigation must occur up front, in
the measures that should be taken to either
not understand the spirit and intent of many
a proactive manner, not as each individual
mitigate or to manage them. The Inuvialuit
recommendations such as those involving
development project is proposed. It suggested
Regional Corporation would like to see us direct
future projects that are not currently before us.
that we consider a number of up-front
the government to provide the necessary
Dehcho First Nations suggested adjusting the
strategies proposed by the Joint Review Panel,
financial resources to allow initiatives such as
timing of Joint Review Panel recommendations
such as the federal government’s completion of
the Beaufort Sea Strategic Regional Plan of
related to future projects so they apply to
species recovery strategies, interim withdrawals
Action, the Beaufort Regional Environmental
this project instead. The Proponents submitted
to support a network of protected areas,
Assessment process and the impact planning
that future development, be it new gas fields
and land use planning to incorporate thresholds
in advance of the Mackenzie Gas Project impact
or a pipeline expansion, would be subject
1249_NEB_MGP_Vol2_Text_ENG.indd 29
that, under the Canadian Environmental
Assessment Act and Mackenzie Valley Resource
Management Act, mitigation measures relied
upon to conclude that a project can go ahead
12/6/10 11:01:58 AM
30 Mackenzie Gas Project • Volume 2: Implementing the decision
to the intense scrutiny of the regulatory process,
Views of the Board
including scrutiny by the National Energy Board.
The matter of cumulative effects and
The Joint Review Panel’s response to our
upstream impacts was heard in full before
proposed modifications to the recommendations
the Joint Review Panel. We rely on their
stated that, where we noted that a relevant
methodology and conclusions.
Joint Review Panel recommendation is:
In response to the concerns raised regarding
in decision-making and project oversight in
order to minimize environmental impacts
now and in the future.
People at the hearing were concerned
about the future. While views differed
in the details, common threads included
[o]utside the scope of the Mackenzie Gas
the need for up-front planning and the
Project (MGP) applications as it involves
National Energy Board’s jurisdiction over
future application(s), [t]he Joint Review
future projects, we continue to rely on
Panel does not understand this notation
the Joint Review Panel’s assessment to
to be a rejection by the NEB of the
identify mitigation measures appropriate
relevant recommendation. The relevant
for addressing cumulative effects of future
Joint Review Panel recommendations
development. We believe that our approach
stand and the Panel expects that they
to implementing mitigation measures
would, accordingly, be considered
related to future development at the
We ask that you consider not only
by the NEB in the specific context
time of application for that development
the need to ensure the protection
of any future applications.
maintains the spirit and intent of the
of our environment, but also the
Joint Review Panel recommendations while
provision of economic opportunity
adhering to the principles of natural justice
to our residents and the social
and procedural fairness for future projects.
integrity of our communities.
The Sierra Club of Canada held the position
that it is relevant that the National Energy Board
has jurisdiction over approving future induced
developments, but that does not take away
from the Joint Review Panel’s assertions that
this work needs to be done up front. According
to the Sierra Club of Canada, rights issuances
and exploration in the area will increase, and
this is not within the National Energy Board’s
purview. The Sierra Club of Canada submitted
that they would agree with the Joint Review
Panel’s response interpreted as the Joint Review
Panel agrees that once preparatory work is
done, then future applications can be dealt
with one at a time because the necessary
preparatory work is complete.
1249_NEB_MGP_Vol2_Text_ENG.indd 30
Energy Board will continue to play its role
The National Energy Board will consider
all relevant evidence at the time of future
applications, including cumulative impacts
the integration of the land, the economy
and the people; the importance of
future generations; and community
self-reliance. We listened to these views
and incorporated them into our public
interest determination. We heard from
the Inuvialuit Regional Corporation:
We also heard from the Dehcho Elders
and Harvesters:
on the environment, and will make
We’re talking about the future of our
decisions in the public interest. The Joint
children and we need to make sure
Review Panel agrees that this procedural
that things are going to be better for
modification does not mean that we
our children in the long future and
are rejecting the Joint Review Panel’s
we don’t want anything sitting wrong
recommendations directed at future
for our children in the future.
projects. The Joint Review Panel stated
that they expect that [cumulative effects]
would be considered by the National
Energy Board in the specific context
of any future applications. The National
The Aboriginal Pipeline Group stated
that they “need to regain socio-economic
self-sufficiency for our people today and
for our future generations.”
12/6/10 11:01:59 AM
Chapter 3: Environmental and socio-economic matters 31
The National Energy Board will continue to
According to the Proponents, the Mackenzie
When the National Energy Board is asked
listen to Northerners through its lifespan
Gas Project would deliver gas into the Alberta
to consider the impacts of downstream
regulatory oversight and accompany them
pipeline system where it would be commingled
facilities, it looks for a direct connection
in the pursuit of a sustainable energy
with other gas supplies and sold into markets
between these downstream facilities
future. Achieving sustainable outcomes will
throughout Canada and the United States.
and the project under consideration.
be a product of many parties including
The Proponents submitted that there is no direct
It is not possible to identify any particular
government authorities, communities,
connection between the Mackenzie Gas Project
downstream facility that would use the gas
industry, and the Canadian public, that
facilities and a specific facility where gas will
transported by the Mackenzie Gas Project.
all support different pieces of the picture.
be burned, thus it is not relevant to our decision
The gas would be transported through the
for us to consider the environmental effects of
TransCanada Alberta System to markets
the combustion of Mackenzie gas at all facilities
in southern Canada and elsewhere in
across North America where the gas could be
North America. Where that gas would
burned. The Sierra Club of Canada countered
Parties brought forward concerns in final
be delivered depends on future gas sales
that since the location of greenhouse gas
argument related to the downstream impacts
contracts and it is not possible at this time
emissions is irrelevant to their impacts, it is
of the project and the end use of Mackenzie
to determine what portion, if any, would
not logical to ignore end use impacts for the
gas. The Sierra Club of Canada and France
be consumed in Alberta or in which sectors
reason that the location of end use is unknown.
of the North America economy over the
3.3.2 End use of gas and
downstream impacts
Benoît expressed concern that the gas from the
Mackenzie Gas Project was intended for use in
the oil sands where it would significantly increase
greenhouse gas emissions. The Sierra Club
of Canada submitted that, short of carbon
neutrality, the Mackenzie Gas Project could
contribute to a sustainable energy future if
the gas is used wisely by displacing more
carbon-intensive fuels. The Sierra Club of Canada
proposed a National Energy Board certificate
life of the pipeline. No specific markets
Views of the Board
or consumers can be directly linked to
Mackenzie gas would enter the North
the Mackenzie Valley Pipeline and the
American market, where it would augment
operation of downstream facilities is
other supplies of natural gas. The end
not contingent upon receiving Mackenzie
use of this gas would be determined
gas. Because there is no direct connection
by competitive markets operating within
between the Mackenzie Valley Pipeline
a public policy framework. The Joint Review
and any particular downstream facility,
Panel Report concluded that:
the environmental effects arising from
the operation of downstream facilities
condition which would delay ‘leave to open’
mandating carbon neutrality
for the pipeline until satisfactory implementation
and intervening in the market
of Joint Review Panel recommendations 8-8
to specify preferred end uses for
and 8-9. These recommendations were directed
natural gas cannot be resolved on
Nevertheless, we believe that augmenting
at the federal government to implement
a project-by-project basis through
the Canadian supply of natural gas,
initiatives to manage greenhouse gas emissions
the environmental assessment
a relatively clean-burning and efficient
(8-8) and to direct natural gas to ‘wise’
process, but must be addressed by
fuel source, is of benefit to the Canadian
end-use applications (8-9). Ecology North also
governments through comprehensive
public. Greater gas supply in the market
recommended the National Energy Board support
climate change strategies.
increases the potential that fuels with
do not appear to us to be relevant to
the applications before us.
these Joint Review Panel recommendations.
1249_NEB_MGP_Vol2_Text_ENG.indd 31
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32 Mackenzie Gas Project • Volume 2: Implementing the decision
higher greenhouse gas outputs would
environment, and while impacts are not
sulphur dioxide; nitrous oxides; ozone; carbon
be preferentially displaced. Global energy
predicted to exceed relevant standards
monoxide; carbon dioxide; volatile organic
demand is independent of whether
and guidelines, participants invoked
compounds; particulate matter; and compounds
the “keep clean areas clean” principle;
that include sulphates and nitrates, together
Mackenzie gas comes on stream or not.
Since natural gas is relatively low in
called potential acid input. Carbon dioxide,
greenhouse gas output per unit of
of the Northwest Territories recommended
methane and nitrous oxides are compounds
energy produced, overall emissions
the use of best available technology to
that have the potential to collect in the
would tend to be lower than the
minimize emissions, while the Proponents
atmosphere and influence global temperatures
alternative where other carbon-based
countered that they would use best practical
(greenhouse gases). Air quality impacts
energy sources would be used.
technology, which is “technology that
can be local to regional in the case of particulate
considers safety, engineering requirements,
matter and sulphur dioxide, or global
3.3.3 Air quality issues and
cost and environment, to reduce operational
in the case of greenhouse gases.
greenhouse gas emissions
emissions”; and
Air quality issues
Air quality in the North is considered to be of
high quality and Northerners are very concerned
• the project’s air emissions would require
appropriate monitoring during the
construction and operation phases.
Specific discussion regarding air quality issues
including emissions for the three gas fields
is included in Chapter 4, Development fields.
Further specific discussion on air emissions
that it remains that way. Both Environment
The Joint Review Panel noted that the National
pertaining to facility design is found in
Canada and the Proponents agreed that existing
Energy Board would be the prime regulator
Chapter 6, Facilities.
air quality in the proposed project area is good
of air emissions from the project and that
and, along with other government regulators,
Environment Canada and the Government of
emphasized the need to “keep clean areas
the Northwest Territories would play advisory
clean.” This principle requires new industrial
roles. The Joint Review Panel recognized
development to be “planned, constructed
the National Energy Board’s expertise and
and operated in a manner that minimizes
experience in regulating interprovincial aspects
the degradation of air quality in these areas.”
of the oil, gas and electric utility industries,
Air quality issues for the project included project
emissions for the pipeline and development
fields, monitoring, and greenhouse gases in
the context of monitoring climate change.
These are aligned with the issues identified
including environmental matters. The Joint
Review Panel also recognized the extensive
environmental and local knowledge that
Environment Canada and the Government
of the Northwest Territories can provide.
The Joint Review Panel report indicated that
the Proponents’ baseline information was
compiled from historical data and results
of air quality monitoring that was carried
out over one year near the communities of
Inuvik and Norman Wells, and periodically
at the Parsons Lake and Taglu gas fields. The
Proponents’ monitoring data and other sources
indicated that background concentrations of
air contaminants are generally below detection
levels or applicable guidelines. The one
exception that is not below detection levels
in the Joint Review Panel report. In its view
Air emissions can be related to the project-
is ozone; relatively high background levels
the key air quality issues included:
specific effects of construction, operations,
were monitored in Inuvik and Norman Wells.
• the project would be a long-term source
and waste incineration. Specific components
The Proponents indicated that elevated
of air emissions for the project might include:
ozone levels at high latitudes in the northern
of new air emissions in a generally pristine
1249_NEB_MGP_Vol2_Text_ENG.indd 32
• Environment Canada and the Government
12/6/10 11:01:59 AM
Chapter 3: Environmental and socio-economic matters 33
hemisphere are thought to result from the
Greenhouse gas emissions arising from
minimizing upstream greenhouse gas emissions
intrusion of stratospheric ozone. The Proponents
the project include carbon dioxide, methane
associated with the project.
stated that all ground-level concentrations
and nitrous oxides with each compound having
of compounds released by the project during
a different climate change potential. During
operations at the gas fields, the Inuvik Area
operation, the project would emit greenhouse
Facility, and compressor and heater station
gases from burning natural gas at combustion
sites would increase, but would be below
related sources such as compressors and
those outlined in applicable federal and
methane gas released through normal
territorial guidelines at all locations in the
venting procedures and minor leaks (fugitive
production area and along the pipeline corridor.
emissions). Further specific discussion on air
Environment Canada recommended that
the Proponents design and implement suitable
emissions pertaining to facility design is found
in Chapter 6, Facilities.
Sierra Club of Canada submitted that we need
to specify an actual target and it is not enough
to just leave it up to the Proponents. Sierra Club
of Canada indicated that the target should
at least match the general recommended target
in Joint Review Panel recommendation 8‑8.
Views of the Board
We understand the importance of clean
air in the North and that air quality must
air quality monitoring programs with its
In the Joint Review Panel’s view, Environment
help. Environment Canada focused its
Canada is responsible for the design and
recommendations on pollution prevention
implementation of ongoing climate monitoring
and the use of best available technology
in the region, the analysis of the data and
and best management practices to minimize
the assessment of potential impacts. The
the degradation of air quality. Further discussion
Proponents’ responsibility should be limited
around application of these principles may
to providing relevant site-specific monitoring
be found in Chapter 6, Facilities.
information to Environment Canada and
The Dehcho Elders and Harvesters indicated
ensuring that their operations and maintenance
that the project needs to be designed to
program takes into account any changes
minimize air quality impacts, with monitoring
beyond that currently predicted.
plans in place to verify the predicted emissions
Alternatives North submitted that the National
quality. We are committed to working
and impacts. Corrective action needs to be
Energy Board and the Government of Canada
collaboratively with Environment Canada
taken quickly to avoid impacts upon the land
have a public interest mandate that requires
and the Government of the Northwest
and wildlife from degraded air quality.
consideration of greenhouse gas emissions.
Territories to protect air quality in
Greenhouse gas emissions
Ecology North deemed that high project-specific
Parties were concerned about the impacts
standards for greenhouse gas emissions,
of the project on climate change, especially
based on a robust and strong definition of
in light of Canada’s international efforts under
the United Nations Framework Convention
on Climate Change and the Kyoto Protocol.
1249_NEB_MGP_Vol2_Text_ENG.indd 33
be considered in a cumulative manner.
We also recognize the need to minimize
greenhouse gas emissions resulting from
the project. The Joint Review Panel directed
several recommendations to us relating
to air quality and air emissions. We have
addressed air issues through several
conditions for the Mackenzie Gas Project.
These conditions are focused on the
Proponents taking appropriate measures
to minimize air emissions and address air
the North, recognizing the extensive
environmental and local knowledge
that these agencies can provide.
best available technology and accompanied
Conditions 11, 12 and 13 address
by penalties in the cases where they do not
technologies for reducing emissions,
meet those project standards or targets, would
incorporation of best management
provide the best possible protection in terms of
practices and best available technologies,
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34 Mackenzie Gas Project • Volume 2: Implementing the decision
and facility design. Condition 12 requires
as presented in the Environmental
Monitoring is required by the National
the submission of a report evaluating
Protection Plan (EPP) and environmental
Energy Board under Section 39 of the
incinerator emissions from camps and
alignment sheets and that work is
Onshore Pipeline Regulations, 1999.
station facilities. Technologies and practices
in compliance with environmental
(“A company shall develop a monitoring
must be reflected in the waste management
regulations; and
and surveillance program for the protection
plans required by Conditions 16 and 59.
of the pipeline, the public and the
Condition 67 requires the Proponents
resulting from project-environment
environment.”) A monitoring program may:
to minimize and reduce emissions from
interactions and evaluate the
•• identify any issues or potential concerns
flaring. Further specific discussion for
effectiveness of approved mitigation
these conditions regarding air emissions
measures. This is further discussed
pertaining to facility design is found in
in section 3.3.6, Environmental
Chapter 6, Facilities.
Protection Plans.
that may compromise the protection
of the environment;
•• include methods for developing
measures to prevent or mitigate
the impact of the identified issues;
Air quality monitoring is part of
The National Energy Board promotes
comprehensive environmental monitoring
goal-oriented environmental management
under an environmental management
and monitoring. This means the National
system. Through environmental
Energy Board tends to require a desired
management, systems are established
end result and the proponent may choose
additional mitigative measures as
to address the effects of the project on
the means of achieving that result provided
necessary; and
the environment and of the environment
the means are acceptable to the National
on the project, with the overall goal of
Energy Board. A proponent is expected
for adaptation of successful mitigation
minimizing negative impacts. Adaptive
to implement Environmental Protection
to future pipeline projects.
management is a systematic process
and Monitoring and Surveillance
for continually improving management
Programs which include protection of
practices by learning from their outcomes.
the environment as one of the main goals.
Environmental monitoring is an important
The Onshore Pipeline Regulations, 1999
collected data such as air quality or
part of environmental management that
require the proponent to implement an
emissions data. Monitoring may include
directly supports adaptive management by
Environmental Protection Program which
any relevant environmental practices
observing and evaluating the effects that
must include monitoring and adaptive
(e.g., vegetation establishment, water
occur, then changing or adding mitigative
management. (Section 48: “A company shall
quality sampling, waste disposal).
measures, as appropriate, to limit or reverse
develop and implement an environmental
the environmental effects. Environmental
protection program to anticipate, prevent,
monitoring can include:
mitigate and manage conditions which
•• compliance monitoring, to verify that all
have a potential to adversely affect
environmental mitigation is implemented
1249_NEB_MGP_Vol2_Text_ENG.indd 34
•• effects monitoring, to assess the effects
the environment.”)
•• provide for continued monitoring of
sites to evaluate success of mitigative
measures undertaken;
•• provide a system for implementing
•• provide a feedback system that allows
Monitoring programs may have specific
goals and targets and could include
methods for evaluating and interpreting
Responsibilities of the National Energy
Board regarding monitoring include:
•• conducting environmental inspections
of facilities, verifying compliance with
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Chapter 3: Environmental and socio-economic matters 35
terms and conditions, and assessing
with other government agencies, location
employee training, monitoring, public
the effectiveness of mitigation;
and selection methods of monitoring sites,
communication, waste management and
and complaint response. Condition 16
required consultation with Environment
verifying reclamation and maintenance of
includes the requirement for monitoring
Canada and the Government of the
the project site to acceptable standards; and
incinerator emissions.
Northwest Territories. With these
•• monitoring ongoing operation and
•• conducting environmental audits,
evaluating environmental management
systems and environmental programs.
A commitment to continuous improvement,
outlined in Joint Review Panel
recommendation 8-6, is expected to be
conditions, we find it acceptable for
the Proponents to develop greenhouse
gas targets for the project consistent
with the use of best management practices
The National Energy Board generally
a component of the Air Quality Monitoring
requires the filing of environmental
Program required by Condition 15. We
post-construction monitoring reports
are of the view that the commitment to
as a condition of an authorization.
continuous improvement is not limited to
The Filing Manual provides guidance for
greenhouse gas emissions but should apply
3.3.4 Impacts of climate change
companies on the content of environmental
to all discharges to the environment, which
on the project
post-construction monitoring reports.
in this case is the atmosphere. Condition 15
Warming of the global and regional climate
The information in monitoring reports
also covers the requirements for methods
could raise sea levels and affect weather
should include:
and locations of monitoring.
patterns. The Niglintgak and Taglu fields
•• confirmation of proper implementation
of mitigation and reclamation
measures used;
•• identification of the outstanding
environmental issues; and
•• discussion of the company’s plans for
how outstanding issues will be resolved.
Condition 13 requires the Proponents to file
a report outlining the use of best available
technology for station facility construction.
Selection of best available technology is
the most significant factor in determining
achievable air emissions targets.
Condition 59 outlines the requirements
and in consultation with appropriate
government agencies.
are located in the low-lying Mackenzie Delta
near the Beaufort Sea. We heard concerns
that seasonal flooding and storm surges could
affect these facilities during the life of the
project. The companies provided evidence that
the facilities would be high enough to protect
them from storm surges and flooding even if
sea levels were to rise. Parsons Lake is located
We have addressed the monitoring of
for an Environmental Protection Program.
air emissions through several conditions.
The condition requires the Proponents
Condition 3 requires the Proponents to
to submit policies, practices and procedures
submit for approval an Environmental
for management of air emissions including
Protection Plan prior to pre-construction
maximum proposed greenhouse gas targets
The Sierra Club of Canada was concerned about
activities which includes monitoring of
and reduction strategies for air emissions
the lack of peer-reviewed research publications
activities for this stage of the project.
including particulate matter, NOx and
on the effects of climate change, specifically for
Condition 15 outlines expectations for
greenhouse gases. Condition 59 also
the Mackenzie Delta over the 30 year lifespan
an Air Quality Monitoring Program and
addresses other matters from the Joint
that was used by Shell in the design of the
includes the requirement for consultation
Review Panel recommendations including
Niglintgak facilities. The Sierra Club of Canada
1249_NEB_MGP_Vol2_Text_ENG.indd 35
on higher ground and further from the sea,
so its facilities would be less exposed to possible
effects of climate change.
12/6/10 11:01:59 AM
36 Mackenzie Gas Project • Volume 2: Implementing the decision
stated that from a design perspective, there is
the upper limit temperature scenarios
Further specific discussion on climate change
uncertainty regarding the effects of climate
to ensure that the safety margin
regarding project design is found in Chapter 4,
change on the permafrost, the rise in sea level
built into the project design is
Development fields and Chapter 6, Facilities.
and the degree of flooding. The Sierra Club of
adequate to cover the range of
Canada referred to the Arctic Climate Impact
future temperature conditions
Assessment prepared by the International Arctic
including their variability extremes.
Science Committee. The Arctic Climate Impact
We are satisfied with the Proponents’
The Joint Review Panel was generally satisfied
climate change estimates used in the
that the Proponents had taken climate change
design. Given the uncertainty regarding
into account in their design. Nevertheless
climate change predictions, a prudent step
the Joint Review Panel recommended that the
would be to assess the design using upper
National Energy Board add a condition which
The Proponents said that climate change would
limit temperature scenarios as suggested
would require the Proponents to file final design
be considered further in detailed engineering
by the Joint Review Panel. As the name
plans that incorporated further analysis of
design, where required, such as for well pads,
implies, upper limit temperature scenarios
the impacts of climate change on permafrost
pipelines, facilities, and the right of way.
would be less likely to occur than what has
and terrain stability over the design life
Other possible impacts of climate change,
been used by the Proponents for the design
of the project and post-abandonment. The
such as landform changes and groundwater
of the project. Condition 6 requires the
Joint Review Panel was of the view that this
flows, would be handled through monitoring
Proponents to submit a report which
analysis should be conducted for a series of
and mitigation. Overall, the Proponents
includes an analysis of the impacts of
representative locations, conditions and terrain
indicated that their designs were sufficiently
climate change and variability on
types and should incorporate climate variability,
conservative to address potential climate
permafrost and terrain stability for a series
in particular, upper limit temperature scenarios
change and variability.
of representative locations and conditions
to account for the range of future temperature
using potential upper limit temperature
Environment Canada indicated that interactions
conditions, including variability and extremes,
scenarios which may occur along the
of climate variability and climate change would
and the impact of this variability on stream
pipeline. The analysis is to include potential
likely be a more significant environmental
flow regimes. The Joint Review Panel added
impact on slope and water course crossing
stressor on Project components over the
that the results should be incorporated
design. We have not specified how the
anticipated lifespan of the project of about
into monitoring, mitigation and adaptive
study should be structured. We are of the
25 years than currently acknowledged by the
management plans. The Joint Review Panel
view that, as part of this study, government
Proponents. Therefore, appropriate assessment,
thought that this analysis should be provided
departments such as Environment Canada,
monitoring and mitigation approaches must
to other appropriate regulators in sufficient
Indian and Northern Affairs Canada and
be incorporated into the project’s design,
time for review and to provide input to
Natural Resources Canada should be
maintenance, contingency plans and
the National Energy Board.
consulted to benefit from their expertise.
Indian and Northern Affairs Canada suggested
Conditions N8, T7 and P8 require the
in final argument that the Proponents should
Proponents to provide final detailed
climate change modeling employed
demonstrate how upper limit temperature
design information which incorporates an
by the Proponents properly incorporate
scenarios have been considered in their design.
analysis of the impacts of climate change
Assessment states that the Arctic is experiencing
the most rapid and severe climate change on
earth, including the disappearance of Arctic sea
ice which allows higher waves and storm surges.
decommissioning plans. Environment Canada
also recommended that, prior to construction:
1249_NEB_MGP_Vol2_Text_ENG.indd 36
Views of the Board
12/6/10 11:01:59 AM
Chapter 3: Environmental and socio-economic matters 37
and variability on permafrost and terrain
Habitat disruption and sensory disturbance
stability for each facility using potential
Parties to our hearing restated in final
upper limit temperature scenarios which
argument their concerns about habitat
may occur during the operational life of the
disruption and sensory disturbance to wildlife.
project. The Proponents will also provide
information about how upper limit
temperature scenarios may impact
precipitation, rise in sea level, storm surges,
ice floes and flood levels, and watercourse
crossing designs. We are of the view that
government departments such as
•• use of insulation and sound-suppression
that would occur from work on the pipeline.
•• minimizing the use of flares and lighting;
and wildlife habitat must be minimized as much
•• preventative maintenance to minimize
as possible for all animals, including those that
hibernate and live underground. They stated:
breeding and birthing areas and
from their expertise for the field design.
migration routes of all animals in
the clearing of the land for the right
of way, facilities and activities must
3.3.5 Wildlife and species at risk
be minimized and, in some cases,
Throughout final argument, parties reaffirmed
avoided by choosing an alternative
the importance of wildlife to the people
pipeline route or facility location.
emotional, and spiritual health, as well
as providing our economic base for long
before the last ice age.
equipment;
They submitted that disturbance of wildlife
Canada should be consulted to benefit
and plants to provide for our physical,
measures to reduce wildlife disturbance
concerned about the disruption to wildlife
the destruction of winter feeding,
We have depended on the wildlife
already committed to some mitigation
and habitat disruption. These include:
Affairs Canada and Natural Resources
The Dehcho stated:
We heard that the Proponents have
The Dehcho Elders and Harvesters were
Environment Canada, Indian and Northern
of the North and to Canada as a whole.
Views of the Board
unplanned activities; and
•• altered design of laterals to allow for
passage by caribou and harvesters.
It is our view that with the Proponents’
commitments and with the additional
requirements specified in Conditions 29
through 36 and similar Conditions on
the approvals for the three development
plans, disturbance to wildlife and their
habitats will be minimized. We require
They also confirmed that the pipeline corridor
the Proponents to submit for approval
must not be a barrier to wildlife movement.
Wildlife Protection and Management
Sensory disturbance such as noise and vibration
were of concern to the Dehcho Elders and
Harvesters. They submitted that noise and
vibration pollution from the Enbridge pipeline
Plans that include pre-construction
wildlife surveys, detailed descriptions
of mitigation measures and how these
will be implemented, and protocols for
affected animal migration and fish runs and
monitoring and adaptive management.
The Sierra Club of Canada submitted that
that proper studies need to be undertaken
Among the mitigation measures
species at risk are of national interest and that
to determine the sensitivities of all fish and
the Proponents must submit are the
biodiversity loss is a pressing global problem.
wildlife to the sounds and vibrations generated
scheduling of activities to minimize
by pipeline operation and how these affect
wildlife disturbance, procedures to avoid
Parties presented three outstanding concerns
their behaviour patterns, migrations and
denning areas, measures to avoid sensory
with respect to wildlife and species at risk:
other activities. The project design should
disturbance, and measures to minimize
• habitat disruption and sensory disturbance;
then be changed as required to ensure that its
impacts of vehicle and air traffic on
• woodland caribou; and
operation has no effect on wildlife behaviour.
wildlife. Annual den surveys and mitigation
• conditions regarding species at risk.
1249_NEB_MGP_Vol2_Text_ENG.indd 37
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38 Mackenzie Gas Project • Volume 2: Implementing the decision
measures to avoid dens must also be
appropriate action to adaptively manage
that we had not taken full consideration
completed and filed with the Government
the situation. We heard from the Dehcho
of Joint Review Panel recommendation 10-4
of the Northwest Territories and wildlife
Elders and Harvesters that, “we need to
in our proposed conditions.
management boards.
work together and closely and to make sure
We require the Proponents to submit
Wildlife Protection and Management
Plans prior to filing the detailed route.
Any adjustments to the detailed route
that would minimize impacts to wildlife
populations or their habitat will be
evaluated and completed at the design
stage. The National Energy Board will assess
the effectiveness of Wildlife Protection
and Management Plans and will monitor
their implementation. The National Energy
Board will conduct compliance monitoring
throughout the lifespan of the project and
will require all commitments to be satisfied.
We also require that the Wildlife Protection
and Management Plans be developed in
consultation with wildlife management
1249_NEB_MGP_Vol2_Text_ENG.indd 38
that everything is safe”. We plan to do so.
The Sierra Club of Canada, Alternatives North,
Jean Marie River First Nation and the Sambaa K’e
Dene Band submitted that the woodland caribou
Woodland caribou
recovery strategy and action plan must be
Canada’s Species at Risk Act requires the
finalized and approved under the Species at Risk
Minister of the Environment to put in place
Act as a prerequisite to the development of a
a recovery strategy and action plan for listed
Wildlife Protection and Management Plan for
wildlife species, which includes boreal woodland
woodland caribou and in advance of National
caribou. This has not yet been completed.
Energy Board final authorizations. Jean Marie
The Sierra Club of Canada submitted that
River First Nation also submitted that required
since legal obligations under the Species at Risk
mitigation measures include avoidance of critical
Act have not been fulfilled, the environmental
overwintering habitat for woodland caribou.
assessment is not complete because the Joint
The proposed Mackenzie Valley Pipeline corridor
Review Panel has accordingly been unable
is home to over-wintering woodland caribou,
to determine the significance of impacts on
traditionally harvested by the Sambaa K’e Dene
species at risk such as woodland caribou.
Band members. The Sambaa K’e Dene Band field
The Proponents submitted that the Joint Review
and literature research carried out over a period
Panel made recommendations to address
of three years, consistent with other woodland
the uncertainty about the significance of the
caribou research, indicates that these animals
boards, the territorial government and
impacts the project might have on woodland
are most vulnerable to industrial development
Environment Canada. We ask for evidence
caribou, including recommendation 10-4.
during the late winter months — January through
of this consultation to be provided with
Recommendation 10-4 states that a further
March — which is precisely when Mackenzie Gas
the Proponents’ submission. Through this,
assessment of the impacts that the project is
Project activities will be occurring. The Sierra
we are satisfied that agencies with expert
predicted to have on species listed on Schedule 1
Club of Canada argued that consideration of
knowledge on wildlife management in
of the Species at Risk Act (listed species) should
the impacts on these key species at risk was
the North will have input into the Plans.
take place once the Proponents have greater
meant to be conducted in public hearings,
We believe that Condition 28 regarding
certainty about the location of project facilities.
either before the Joint Review Panel or before
the hiring of local residents as monitors
It also states that surveys and impact
the National Energy Board, and that this public
will also assist local residents to identify
assessments for listed species must
process was being omitted from the proposed
any areas where mitigation measures
be carried out after recovery strategies
National Energy Board conditions.
are not working. The National Energy
and action plans have been completed.
Board can direct the Proponents to take
The Sambaa K’e Dene Band submitted
12/6/10 11:01:59 AM
Chapter 3: Environmental and socio-economic matters 39
Views of the Board
We acknowledge the importance of
woodland caribou to the people of the
North and of species at risk to Canadian
and additional knowledge becomes
minimized. When the recovery strategies
available. Mitigation measures to be
and action plans are finalized, the
described by the Proponents include:
Proponents are required to update their
•• the timing and dates of project activities
Wildlife Protection and Management Plans
biodiversity. We believe that our Conditions
to avoid conflict with caribou movement
accordingly. However, we expect that such
29 and 30 capture the intent of the Joint
or sensitive feeding and calving time;
modifications to plans will be minimal since
Review Panel recommendations related
•• measures to limit predator travel along
consultation with the parties responsible for
to woodland caribou protection and
right of ways;
developing the recovery strategy and action
management, and are within the National
•• access management; and
plan is required throughout.
Energy Board’s abilities to effectively assess,
•• measures to avoid or minimize
We recognize that without a recovery
manage, and enforce.
Mitigation measures must be developed
linear disturbance, effects of
strategy for woodland caribou in effect
habitat fragmentation, and barriers
at this time, critical habitat has not yet been
to movement.
established as defined under the Species
by the Proponents in consultation with
Environment Canada — the same agency
responsible for completing the woodland
caribou recovery strategy and action
plans under the Species at Risk Act.
We expect that through this consultation,
the Protection and Management Plan
for woodland caribou will be informed
by the same research that is going into
the development of the recovery strategy
and action plans.
These mitigation requirements were
at Risk Act although research is in progress.
derived directly from Joint Review Panel
However, Condition 29 requires Wildlife
recommendations 10-1, 10-4 and 10-16,
Protection and Management Plans to be
which had been recommended to
the Joint Review Panel by the Government
of the Northwest Territories who are
involved in the preparation of woodland
caribou recovery strategies. We have also
stipulated that the Wildlife Protection
and Management plans be developed in
consultation with Environment Canada, the
filed for approval by the National Energy
Board prior to decisions being made
on the detailed route. In the case that
the recovery strategy and action plan for
woodland caribou remain incomplete
at this time, we expect that additional
science-based and traditional knowledge
will be available to inform the detailed
route in avoiding critical habitat to
Conditions 29 and 30 require the
Government of the Northwest Territories,
Proponents to conduct pre-construction
and wildlife management boards. Based on
surveys and submit, for National Energy
comments received by parties on the Joint
Board approval, updated impact
Review Panel recommendations, we also
assessments, specific mitigation measures,
included specific consultation requirements
protocols for monitoring and adaptive
with the Dehcho Boreal Caribou Working
management, and provisions for updating
Group. Between the combined efforts of
We are of the mind that, with the
the Wildlife Protection and Management
the Proponents and these authorities we
application of the mitigation measures
Plan for woodland caribou as recovery
believe that potential adverse impacts of
proposed in Conditions 29 and 30,
strategies and action plans are effected
the project on woodland caribou will be
developed in consultation with federal,
1249_NEB_MGP_Vol2_Text_ENG.indd 39
the extent possible. The knowledge
of the Dehcho Boreal Caribou Working
Group should be a valuable tool
for the Proponents in identifying
and protecting critical habitat.
12/6/10 11:01:59 AM
40 Mackenzie Gas Project • Volume 2: Implementing the decision
territorial and Aboriginal government
authorities and approved by the National
Energy Board prior to filing of the detailed
pipeline route, impacts of the project
on woodland caribou can be minimized.
Views of the Board
concerns included impacts to the environment
We agree that pre-construction surveys
such as air quality, aesthetic impacts, and noise.
are not required for species at risk for
which recovery is not feasible at this time,
and modified our Conditions 29, N22, T21
and P21 accordingly. We expect that any
The Dehcho raised specific concerns regarding
project specific environmental monitoring
requirements, protection of water resources,
and minimizing invasive plant introduction.
Species at risk
incidental observations of individuals will
The National Energy Board adds a requirement
Environment Canada submitted that the draft
still be reported as per part (a) of these
to facility approval documents for a company to
conditions circulated by the National Energy
conditions. We also agree with Environment
develop and file for approval an Environmental
Board may unduly impose survey requirements
Canada’s clarification regarding newly listed
for those species at risk where the Minister of
Protection Plan. The Environmental Protection
species at risk. We expect that the Wildlife
Environment has determined that its recovery
Plan is a document that guides environmental
Protection and Management Plans will
is not feasible at this time, such as the Eskimo
oversight for the duration of a project and
address all known species at risk current
typically includes elements such as environmental
at the time of Plan submission.
mitigation measures, reclamation and
curlew. Environment Canada also clarified that
the requirements for listed species described in
re-vegetation. The Environmental Protection
Conditions 29, N22, T21 and P21 should apply
With respect to the survey area for
to all species at risk added to Schedule 1 of the
yellow rail and western toad, it is our
Species at Risk Act at the time the Proponents
view that Condition 34 as proposed
file their Wildlife Protection and Management
addresses Environment Canada’s concern.
The Environmental Protection Plan is an
Plans with the National Energy Board, not only
Condition 34 requires evidence of
important tool that is used to communicate
to those listed species assessed during the Joint
consultation with Environment Canada
the environmental procedures and mitigation
Review Panel hearings.
and the Government of the Northwest
measures to the Proponent’s field personnel
Territories when preparing the surveys
and construction or operation contractors.
and proposing mitigation and monitoring
The purpose of the Environmental Protection
measures specific to those species. Any
Plan is to document and communicate all
discrepancies regarding survey area may
the project-specific environmental protection
be addressed by the Proponents and the
measures or mitigation committed to by
appropriate management authorities
the Proponent in a clear and user-friendly
through this consultation.
document. It is a way to ensure the Proponent
Environment Canada submitted that Condition
34 be amended so that the survey area for
yellow rail and western toad be based on the
latest information on the species. Environment
Canada stated that in some cases, the
Committee on the Status of Endangered
Species in Canada reports may not include the
Plans are an important element of our regulatory
approach to environmental protection.
will honour all the environmental commitments
most up-to-date information, and management
authorities for the species may have more
3.3.6 Environmental Protection Plans
current information on species range.
Concerns regarding protection of the land
were raised during final argument. These
that were made during the hearing process.
It also helps to outline clear lines of responsibility
and accountability for the company.
During review of the Environmental Protection
Plan, the National Energy Board verifies that
1249_NEB_MGP_Vol2_Text_ENG.indd 40
12/6/10 11:01:59 AM
Chapter 3: Environmental and socio-economic matters 41
all relevant mitigation and environmental
environmental practices and procedures,
Valley Pipeline and Mackenzie Gathering
commitments are included. The Proponents
making criteria-based decisions, and how
System. As the project begins the operational
use the Environmental Protection Plan to
to confirm compliance;
phase the Environmental Protection Program
communicate environmental commitments to its
contractors and mandatory language is used to
facilitate compliance. There is flexibility for the
• requirements of permits by other regulators
with regulatory responsibilities for the project;
• evidence of consultation with other regulatory
(Section 48 of the Onshore Pipeline Regulations,
1999) will apply. Prior to any drilling or
construction activity relating to a Development
Proponent in developing the overall content of
agencies that confirms satisfaction of
Plan Application, authorizations under
the Environmental Protection Plan. Other plans
proposed environmental mitigation;
paragraph 5(1)(b) of the Canada Oil and Gas
such as the Waste Management Plan, Wildlife
Protection and Management Plan, and Heritage
Resources Plan may be incorporated into the
Environmental Protection Plan as specific chapters
to make it more encompassing for field staff.
The Environmental Protection Plan typically
addresses the following:
• specific goals for protecting environmental
and socio-economic elements identified as
important (air, vegetation, soils, permafrost,
native plants, access management, wetlands,
water resources, mitigating noise and
• frequency and scheduling of monitoring
activities;
• schedule of expected reporting to
the National Energy Board on the progress
and success of the mitigation measures
implemented;
• inclusion for adaptive management, which
allows for appropriate means to evaluate
and amend issues that may arise during
project operations; and
• effective means of reporting issues that
may arise and reporting structures.
aesthetic impacts, preventing weeds and
The Environmental Protection Plan incorporates
invasive species, and reclamation);
the environmental alignment sheets. References
• practices and procedures that can be
implemented to meet these goals;
• criteria for evaluating the success of practices
and procedures, particularly for reclamation
and any new mitigation measures;
• incorporation of flexibility by covering options
to the Environmental Protection Plan are
for an authorization under paragraph 5(1)(b).
Each of the Proponents will submit their
own specific Environmental Protection Plan
for the applications and may file several plans
depending on timing of construction, the type
of activity, and site specific considerations.
Alternatives North requested that the
Conditions N11, T10, and P10 which deal with
Environmental Protection Plans for Kendall
Island Bird Sanctuary and Fish Island be filed
with the National Energy Board for approval.
requirements of all regulatory agencies.
Protection Plan is consistent with National
Energy Board goal-oriented regulation.
regarding which practices and procedures to
An Environmental Protection Plan must be
implement and under what circumstances;
submitted to the National Energy Board for
1249_NEB_MGP_Vol2_Text_ENG.indd 41
shall provide an Environmental Protection Plan
is a comprehensive document that includes
that may be used;
responsibilities for carrying out
Production Regulations states that an operator
sheets. The Environmental Protection Plan
The requirement for an Environmental
• assignment of accountabilities and
of the Canada Oil and Gas Drilling and
also incorporated into these alignment
for environmental practices and procedures
• criteria by which decisions will be made
Operations Act would be required. Section 6
approval prior to pre-construction activities
and pipe-laying operations for the Mackenzie
12/6/10 11:01:59 AM
42 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
Required Environmental Protection
to recommend a project if and only if it is in
We listened to the issues raised about the
Plans also address Joint Review Panel
the public interest. They added that the Joint
land, water resources, invasive species and
recommendation 6-4, Construction and
Review Panel felt compelled to underline that
other biophysical components. Through
Operation Plan for the Kendall Island Bird
the full suite of recommendations were needed
appropriate environmental management
Sanctuary and Fish Island.
to make the project sustainable. The Sierra
and planning we believe that these matters
Conditions N11, T10, and P10 address
can be appropriately addressed during
all stages of the project. We are committed
to protection of the environment and will
ensure measures are in place to address
potential environmental impacts. A key
component of this includes adherence
to our conditions and Environmental
Protection Plans required by Conditions 3,
38, N11, T10 and P10.
Environmental Protection Plan requirements regarding the Development Plan
Applications. The National Energy Board
will assess future applications for authorizations for work or activity at the anchor
fields along with the accompanying
Environmental Protection Plan. Environmental mitigation during construction and
operation for Fish Island will be addressed
We will ensure that Environmental
through Section 39 and 48 of the Onshore
Protection Plans for the project are
Pipeline Regulations and will also be
enforceable; that commitments made
addressed in the specific Environmental
during the hearing are included; that
Protection Plans.
appropriate field practices are incorporated;
and that routine field amendments are
addressed. The Environmental Protection
Plans will facilitate environmental regulatory
oversight for the project because they
1249_NEB_MGP_Vol2_Text_ENG.indd 42
Club of Canada submitted that we are leaving
critical sustainability issues to others such
as governments because almost all those
recommendations intended to control
the pace and scale of upstream development
and those intended to ensure sustainability in
relation to the end use of gas are not reflected
in the National Energy Board’s proposed
conditions. Alternatively, the Gwich’in Tribal
Council submitted that not all of the Panel’s
recommendations need to be accepted before
the project can proceed; that matters best left
to government policy should not be addressed
by the recommendations; and that the
completion of third-party actions should not
be a pre-condition to project advancement.
3.3.7 National Energy Board’s role
in enforcing recommendations directed
to others
Some parties had confidence in the ability
of Northern agencies to protect the land.
The Inuvialuit Regional Corporation stated:
will incorporate all the environmental
During final argument, parties submitted
protection requirements in one document
that the National Energy Board has a
for each portion of the project. The
responsibility as “key gatekeeper” on this
Environmental Protection Plans provide
file to ensure that all Joint Review Panel
a basis for working collaboratively with
recommendations are fulfilled. World Wildlife
other Northern agencies. We will monitor
Fund Canada submitted that the National
and inspect all aspects of the project and
Energy Board must address the broader
the Environmental Protection Plans will be
roster of Joint Review Panel recommendations,
Over the past 25 years, the Inuvialuit
utilized as a document to verify compliance.
including those directed to government
have gained a high level of confidence
authorities, because they fall within the
in the ability of these organizations and
National Energy Board’s fundamental mandate
individuals to collectively provide for the
Much of the responsibility for the health
of our environment is held collectively by
the organizations and co-management
bodies established under our land claim
agreement and by the residents of every
Inuvialuit community.
12/6/10 11:01:59 AM
Chapter 3: Environmental and socio-economic matters 43
ongoing health of the environment and
the National Energy Board has determined in a
After making its regulatory decisions,
wildlife across the Inuvialuit Settlement
public process that governments have met their
the National Energy Board collaborates
Region while allowing the orderly
commitments. Canadian Parks and Wilderness
with others to protect wildlife, water, air
conduct of development and
Society suggested other assurances such
and vegetation from potential
other commercial activities.
as timelines, land withdrawals, funding
negative impacts resulting from
requirements, or checklist tracking. World
project development.
As we look forward to the future
development of the resource within
our region, we do so in the comfort
that our organizational structures
have both the skills and the experience
to maintain a responsible and objective
balance between the health of our
Wildlife Fund Canada requested we state that
this project is only in the public interest if all
the Joint Review Panel’s recommendations are
implemented. World Wildlife Fund Canada
cited an example in which another regulator,
the Natural Resources Conservation Board,
Our responsibility begins with making
the public interest determination. The
question central to our public interest
determination is whether Northerners
and other Canadians would be better
or worse off if the Mackenzie Gas Project
chose to make an approval come into effect
is approved. This question is answered
economic opportunity to the residents
upon the completion by government of a
in Volume 1, Respecting all voices:
of our communities.
statutory order creating a wildland recreation
Our journey to a decision.
environment and the provisions of
area. World Wildlife Fund Canada suggested
Other parties expressed concern that Joint
Review Panel recommendations directed
to other authorities would not be met.
The Sierra Club of Canada submitted that
we must set conditions that provide reasonable
assurance that all of the Joint Review Panel’s
recommendations will be implemented, or say
no to the project at this time. The Canadian
Parks and Wilderness Society submitted that
we should consider conditions that provide a
greater level of certainty that recommendations
outside the National Energy Board’s mandate
are fulfilled. The Sierra Club of Canada and
Canadian Parks and Wilderness Society gave
examples of ways in which we could ensure
compliance. The Sierra Club of Canada
that we could, if we chose, take on a similar
sequencing consideration and stipulate the
order in which things happened, even where
those things are not immediately within
the National Energy Board’s purview. Parties
were afforded a further opportunity to
comment on these and related matters upon
receipt of the government response. In general,
parties were concerned about the adequacy of
the government response and either proposed
strengthened conditions or took the view that,
given this response, the project is not in the
public interest.
Views of the Board
The public interest determination takes into
account benefits and impacts of the project
on the land, the people, the economy, and
safety and technical concerns. The review
and hearing of environmental and socioeconomic impacts was conducted by
the Joint Review Panel, whose assessment
helped inform our determination. In order
to make a decision that the project is in
the public interest, we had to be assured
that environmental impacts could be
minimized and that high standards for
environmental protection will be maintained throughout the project life. The
National Energy Board has within its
abilities three important regulatory tools
suggested a two-part approach in which we
The National Energy Board has considerable
to achieve this. The National Energy Board’s
first weigh the government response to evaluate
responsibility with respect to the Mackenzie
authority allows us to condition, enforce
whether the response commits to substantial
Gas Project. Fourteen federal and territorial
and conduct compliance monitoring for
implementation of the Joint Review Panel’s
agencies, departments and regulatory
a number of requirements related to
recommendations, then we add a condition
boards also have a role in managing
environmental protection, which include
that the certificate does not take effect until
environmental aspects of the project.
many recommendations of the Joint Review
1249_NEB_MGP_Vol2_Text_ENG.indd 43
12/6/10 11:01:59 AM
44 Mackenzie Gas Project • Volume 2: Implementing the decision
Panel. The National Energy Board is
and to assess the impacts of future related
opportunities and mitigate negative impacts
responsible for lifespan regulation of
developments, we believe that a clear
arising from the Mackenzie Gas Project for
the project. The National Energy Board
public interest determination can be made
Northwest Territories residents. The Socio-
also has jurisdiction over the assessment of
at this stage without the ultimate reliance
Economic Agreement includes measures
new applications for future developments.
on third-party action. We remain committed
to address employment and training, social
In addition, northern agencies and federal
to collaboration with other authorities to
and cultural well-being, business, net effects
authorities have responsibilities related
protect wildlife, water, air and vegetation.
on government, monitoring, reporting and
to monitoring the project and managing
the effects. We regard these responsibilities
as complementary to the National Energy
Board’s responsibilities, and the National
Energy Board is committed to working
in collaboration with others to support an
effective and efficient regulatory scheme.
adaptive management.
3.4 Socio-economic matters
The Government of the Northwest Territories
discussed in final argument
requested that we ensure compliance by the
3.4.1 Socio-Economic Agreement
Economic Agreement by requiring adherence to
The Government of the Northwest Territories
the Socio-Economic Agreement as a condition
stated that the Mackenzie Gas Project is crucial
of approval.
It is our view that conditions contingent
to the socio-economic future of the Northwest
upon third-party actions would unduly
Territories, and has the potential to:
leave both Northerners and the
Proponents in a state of uncertainty
transform the Territories from
about whether and when the project
a region dependent on the support
could proceed. We heard that people need
and contributions from the rest of
certainty and time to make appropriate
Canada to a self-sufficient Territory.
preparations for development. These
preparations include training workers,
resolving outstanding land issues, developing job and business opportunities, and
conducting detailed permitting by land
and water boards, among others. Since we
feel that a high standard of environmental
protection will be met through the National
1249_NEB_MGP_Vol2_Text_ENG.indd 44
Proponents with the terms outlined in the Socio-
Views of the Board
The commitments set out in the SocioEconomic Agreement provide important
measures for addressing the socio-economic
impacts and optimizing the benefits of the
Mackenzie Gas Project. Enforcement is best
The Government of the Northwest Territories
left to the parties to the agreement and
also noted that the Mackenzie Gas Project is
we see no value in attaching a condition to
expected to impact the well-being of residents
the Certificate requiring the implementation
and communities in the Northwest Territories,
of the agreement.
and that a socio-economic agreement for the
Mackenzie Gas Project was therefore a critical
component of the project.
3.4.2 Employment and training
The Dehcho Elders and Harvesters Councils
Energy Board’s regulatory authority to
To address concerns of mutual interest,
stated that the Proponents and government
enforce those Joint Review Panel recom-
the Proponents and the Government of the
should provide Dehcho communities with
mendations directed to us, to enforce
Northwest Territories signed the Socio-Economic
educational and training opportunities,
those commitments made by the Proponents
Agreement for the Mackenzie Gas Project in
to help mitigate impacts and enhance benefits
during our hearing and the Joint Review
2007. The Agreement outlines commitments
of the project. The Dehcho Elders and Harvesters
Panel hearing over the project’s lifespan,
that are intended to optimize beneficial
Councils stated this should include educational
12/6/10 11:02:00 AM
Chapter 3: Environmental and socio-economic matters 45
upgrading, safety courses, survival training,
To achieve this, the Dehcho Elders and
Views of the Board
as well as information and scholarships for
Harvesters Councils recommended the
We recognize the potential benefits,
careers as forest rangers, fisheries officers, game
establishment of a Dehcho Mackenzie Gas
wardens, and park rangers. The Dehcho Elders
as well as the potentially undesired
Project monitoring agency to oversee, observe
and Harvesters Councils and the Liidlii Kue First
and protect land, wildlife and habitat during
Nation also stated that Canada needs to fulfill
the planning, construction and reclamation
the original terms of the Mackenzie Gas Project
of the project. The Sambaa K’e Dene Band
Impacts Fund by limiting it to the Aboriginal
also requested that the Proponents or Canada
communities and regions along the pipeline
provide funding to the Sambaa K’e Dene
corridor, and to make the first phase of funding
Band for an independent environmental
immediately available. The Dehcho Elders
monitoring program during and for a period
and Harvesters Councils and the Liidlii Kue
following construction.
First Nation also suggested that some of the
effects, that employment generated by
the Mackenzie Gas Project can bring to
communities. A number of our conditions
and the Proponents’ commitments
address these effects. Condition 28 requires
the Proponents to provide information
to the National Energy Board related to
the hiring of local residents as monitors
to carry out compliance and environmental
Mackenzie Gas Project Impacts Fund be used
Concerns were also raised about training
impact monitoring for the Mackenzie Gas
for wilderness, language and cultural programs.
for Mackenzie Gas Project personnel, which
Project. In addition, Condition 29 requires
the Dehcho Elders and Harvesters Councils
the Proponents to prepare and submit
stated should include cultural awareness
to the National Energy Board a number
training, seminars and workshops, as well
of Wildlife Protection and Management
as participation in on-land activities with
Plans that will address general wildlife
Dehcho Elders and harvesters.
and species-specific protection, and will
The Dehcho Elders and Harvesters Councils
also stated ongoing training, information
sessions and workshops in Dehcho communities
for follow-up and monitoring programs are
needed. The Dehcho Elders and Harvesters
include details on protocols for monitoring
Councils further stated that Dehcho communities
The Government of Yukon requested that we
should be provided with financial and logistical
adopt Joint Review Panel recommendations
support to allow them to hire their own
15-7 and 15-8, relating to the inclusion of the
dedicated Mackenzie Gas Project environmental
Yukon in the Proponents’ Human Resources and
monitors, who would report directly to the
Employment Database for the Mackenzie Gas
Dehcho communities. The Dehcho Elders and
Project, and designating Whitehorse as a
The Socio-Economic Agreement for
Harvesters Councils stated that management,
point-of-hire. Alternatives North requested that
the Mackenzie Gas Project details the
monitoring and follow-up programs for the
the requirement for a communications plan as
measures and commitments that are
project must include the direct involvement
part of the Proponents’ diversity plan originally
intended to minimize the socio-economic
of the Dehcho, to ensure that the needs and
included in recommendation 15-9 of the Joint
impacts of the project and enhance
interests of Dehcho communities are represented
Review Panel be included in our conditions.
benefits. Section 2 of the Socio-Economic
and protected, and that such programs must
Northern Pipeline Projects Ltd. recommended
Agreement outlines the employment,
fully incorporate Dene knowledge.
that contact between closed camp worker
training and hiring commitments made by
populations and local people should be planned
the Proponents, including hiring priorities,
and minimal.
points of hire for the Mackenzie Gas
1249_NEB_MGP_Vol2_Text_ENG.indd 45
and adaptive management, in addition
to Conditions 3 and 38 which require
Environmental Protection Plans for
the Mackenzie Gas Project.
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46 Mackenzie Gas Project • Volume 2: Implementing the decision
Project, employment requirements and
With respect to the Government of Yukon’s
To address compensation concerns, the Liidlii
policies, human resources development,
request for us to adopt Joint Review Panel
Kue First Nation requested that we require the
and the services and support for employ-
recommendations 15-7 and 15‑8, we note
Proponents to enter into a benefits agreement
ment, education and training that will
the Government of Yukon confirmed that
with the Liidlii Kue First Nation and the Dehcho
be provided by the Government of
these recommendations were consistent
First Nations as a condition of approval.
the Northwest Territories. Section 3 of
with, if not specifically contemplated by, the
The Liidlii Kue First Nation further requested
the Socio-Economic Agreement outlines
Proponents’ written commitments to the
that the agreement include funds to allow
the commitments of the Proponents
Government of Yukon, and we are
the Liidlii Kue First Nation to establish and
for promoting cultural preservation and
therefore confident these issues will be
maintain a monitoring program throughout
understanding. These include the provision
addressed. We are similarly confident that
the life of the project in their territory.
of cultural sensitivity and cross-cultural
the existing requirements for monitoring
awareness training for all project workers,
and reporting systems contained in
and supporting cultural activities such
Conditions 23, N28, T27 and P27 will
as community‑based traditional lifestyle
sufficiently address communications needs
initiatives, traditional harvesting and
related to the Proponents’ diversity plans,
the promotion of traditional culture and
and no additional requirements to these
positive relationships with communities.
conditions are needed.
We believe these measures, commitments
stated that research is required on the
traditional Dehcho economy and the impact
the project will have on physical, cultural
and spiritual health and well‑being. The Dehcho
Elders and Harvesters Councils also requested
that routing and siting of all project facilities
avoid burial and sacred sites, and that
and programs will adequately address
3.4.3 Impacts to harvesters, land
work along water courses be conducted
employment and training needs,
and resources
in a ceremonial manner with the involvement
and concerns relating to monitoring
The Dehcho Elders and Harvesters Councils,
of the Dehcho. To address concerns regarding
and cultural protection.
the Sambaa K’e Dene Band and the Liidlii
compensation for resources, the Dehcho
Kue First Nation raised a number of concerns
Elders and Harvesters Councils requested that
regarding potential impacts on harvesters,
Dehcho harvesters be covered by a Harvesters
land and resources in the Dehcho Region.
Compensation Agreement before the project
The Sambaa K’e Dene Band stated its opposition
is allowed to proceed, and that compensation
to the development of borrow pits within
be provided for the value of all timber stands
the K’eotsee (Trainor Lake) watershed.
cleared on the right of way.
community interactions as contained in
The Sambaa K’e Dene Band also requested
Finally, the Dehcho Elders and Harvesters
Conditions 24, 25 and 26 will provide for
that harvester compensation be addressed
Councils requested that the project be designed
planned and limited interactions between
through a consultation agreement with Canada
and built in a manner that minimizes the
the Mackenzie Gas Project workforce
and the Proponents, through the conclusion
aesthetic impacts upon people and wildlife,
and local communities, and will minimize
of the Dehcho Process, or through the
and that Dehcho communities be involved
potential negative interactions.
conclusion of an Impact Benefits Agreement.
in the development of a granular management
Regarding the recommendation by
Northern Pipeline Projects Ltd. related to
work camps, we believe the requirements
for closed work camps and the preparation
by the Proponents of plans to monitor
and minimize adverse effects of worker-
1249_NEB_MGP_Vol2_Text_ENG.indd 46
The Dehcho Elders and Harvesters Councils
12/6/10 11:02:00 AM
Chapter 3: Environmental and socio-economic matters 47
plan for the project. The Dehcho Elders
the Proponents have made to address
and Harvesters Councils expressed the
harvester compensation.
desire of Dehcho communities to work
with the Proponents to identify alternative
sources of granular material, and that Dehcho
communities, not Canada, be the recipients
of any granular royalties.
3.4.4 Project reporting
Alternatives North requested that we commit
For matters relating to granular resources,
to a full public registry for all Mackenzie Gas
we will continue to rely on the authority
Project applications and follow-up to ensure
of northern regulatory bodies and federal
transparency and accountability. They further
departments. For concerns over borrow
suggested the public registries of the Mackenzie
pits and participation in management plans
Valley Environmental Impact Review Board and
raised by the Sambaa K’e Dene Band and
the Mackenzie Valley Land and Water Board
Views of the Board
the Dehcho First Nations, the Mackenzie
could serve as models.
We recognize the importance of
Valley Land and Water Board has regulatory
harvesting to the economy of the
oversight for permitting activities related
Views of the Board
Northwest Territories, as well as its
to granular resource extraction in the
We are committed to the open, transparent
socio-economic and cultural importance
Mackenzie Valley. In response to concerns
sharing of information with all those who
for Aboriginal communities. In response
over impacts to burial or sacred sites and
have an interest in the Mackenzie Gas
to the concerns of the Dehcho Elders
aesthetic impacts raised by the Dehcho
Project, including the northern institutions
and Harvesters Councils regarding timber
Elders and Harvesters Councils, Condition 21
and federal departments with whom we
resources, Condition 75 for the Mackenzie
requires the Proponents to submit to
will continue to work cooperatively as
Valley Pipeline will require the Proponents
the National Energy Board their Heritage
the project proceeds. Subject to statutory
to notify and consult with Aboriginal and
Resources Management Plan, as reviewed
limitations, we will continue to make
municipal authorities regarding community
by the Prince of Wales Northern Heritage
information about the project publicly
use of merchantable timber cleared along
Centre. The mitigation measures committed
available on our repository. For all projects
the right of way. With respect to harvester
to by the Proponents, as detailed in
regulated by the National Energy Board
compensation, the report of the Joint
their Environmental Impact Statement,
that have proceeded to construction, our
Review Panel summarized the commitments
will adequately address aesthetic and
public repository includes submissions
made by the Proponents to provide
visual impacts.
made by proponents relating to their
compensation to harvesters. The Proponents
compliance with certificate conditions,
committed to providing compensation
as well as responses to these submissions
to harvesters in accordance with the terms
by the National Energy Board.
of the Inuvialuit Final Agreement, and
the Comprehensive Land Claim Agreements
for the Gwich’in and Sahtu Settlement
Areas. They also committed to providing
compensation to Dehcho harvesters on
terms similar to these final agreements.
We are satisfied with the commitments
1249_NEB_MGP_Vol2_Text_ENG.indd 47
12/6/10 11:02:00 AM
Chapter 4
Development fields
Kugmallit Bay
Kendall Island
Bird Sanctuary
Tuktoyaktuk
Richards Island
Taglu
Kittigazuit
Bay
el
nn
East Ch
Yaya Lakes
Camp Farewell
a
Niglintgak
Bar C
Tununuk Point
Parsons Lake
M
ie
nz
ke
ac
River
South pad future
facility site
Storm Hills
Pigging facility
Proposed or alternative airstrip
Gas conditioning facility
Gathering pipelines route
Liquids pipeline and gas pipeline route
Inuvik Area Facility
Significant discovery licence area
20
10
0
20
Kilometres
Inuvik
Aklavik
Figure 4-1 Development fields
1249_NEB_MGP_Vol2_Text_ENG.indd 48
12/6/10 11:02:03 AM
Chapter 4: Development fields 49
4.1 The reservoirs
The Mackenzie Gas Project is anchored on
the production of natural gas from three
development fields near the edge of the
Mackenzie Delta. These three fields—
Niglintgak, Taglu and Parsons Lake—would
Development Field Reservoirs: Characteristics
sales gas, with level production for 12 years,
and Exploration History provides additional
following which production would decline until
information on the field reservoirs and
the reservoirs are depleted (see Figure 4-2).
exploration history.
Natural gas liquids production would begin
Total supply from the anchor fields is projected
to be
Volume 2 Figure3 4.11
Mm /d (0.850
about
24 production
Sales gas
from Bcf/d)
anchorof
fields
at 1756 m3/d (11,050 Bbl/d) and would
immediately decline (see Figure 4‑3).
produce about 172 Gm (6.1 Tcf) of sweet
3
natural gas (see Table 4-1). This is enough
30
gas to heat one million average Canadian
testing of exploratory wells and delineation
0.25
5
wells. Results from surveys and tests provide
technical information on the sub-surface rock
0
Year
Billions of cubic feet/day
10
0
25
dimensional seismic surveys and drilling and
0.5
20
activities such as two dimensional and three
15
15
found and the boundaries identified through
10
natural gas. Typically, oil and gas reservoirs are
0.75
20
5
Each field consists of reservoirs of trapped
Natural gas supply
25
Millions of cubic metres/day
homes for almost fifty years.
Figure 4-2
1.0
and the trapped gas. Computer models use
this information to predict the best locations
to put production wells for the most efficient
method of extracting the gas. Appendix D –
Taglu
Parsons Lake
Volume Niglintgak
2 Figure 4.12
Liquids production from anchor fields
Figure 4-3
12.6
2000
Table 4-1
in the development fields
Field
Niglintgak
Recoverable volumes of natural gas
27 Gm3 (0.95 Tcf)
Taglu
81 Gm3 (2.8 Tcf)
Parsons Lake
64 Gm3 (2.3 Tcf)
Cubic metres/day
Recoverable volumes of natural gas
1500
9.4
1000
6.3
500
3.1
0
25
20
15
10
5
0
Year
Thousands of barrels/day
Natural gas liquids supply
Parsons Lake
Taglu
Niglintgak production is negligible on this scale, i.e., 7 m3/d
1249_NEB_MGP_Vol2_Text_ENG.indd 49
12/6/10 11:02:03 AM
50 Mackenzie Gas Project • Volume 2: Implementing the decision
4.2 Niglintgak
4.2.1 Design of the Niglintgak facilities
The proposed production facilities include:
Wells and well pads
• six to twelve production wells located
All drilling would be conducted from three well
pads (north, central and south) which would
on three well pads;
Niglintgak is the westernmost of three natural
• a system of above-ground flow lines;
lie along the shoreline of the Mackenzie River’s
gas fields associated with the project and
• a gas conditioning facility located
Middle Channel (see Figure 4-5). Each well
is the starting point of the proposed Mackenzie
in the Kumak Channel;
Gathering System. Located entirely within
• a disposal well; and
Kendall Island Bird Sanctuary, Niglintgak is
• infrastructure including an emergency
approximately 120 kilometres northwest of
pad would be built of steel decking and
elevated on steel piles.
shelter and helipads.
From these pads, Shell plans to initially drill six
production wells. Once production begins and
Inuvik and 85 kilometres west of Tuktoyaktuk.
Shell proposes to start construction by barging
more is learned about the reservoir, as many as
Shell Canada Limited (Shell) is the Proponent
supplies and equipment to Camp Farewell
six contingent wells may be needed to optimize
for a Development Plan for the Niglintgak field
(refer to Figure 4-1) during late summer 2014
natural gas recovery. Shell also indicated that
under the Canada Oil and Gas Operations Act.
in preparation for winter work. Production
some wells may require commingled production
Development of the field is estimated to cost
is scheduled to start in the summer of 2018.
in order to recover gas with a minimal well
$800 million with an estimated annual average
Highlights of the proposed construction and
count. Commingled production is production
operations and maintenance expenditure of
drilling activities are shown in Table 4-2.
of oil and gas from more than one pool or zone
$10 million per year for the period 2019 to
through a common well-bore without separate
2023. Construction is planned over four winter
measurement of the production from each pool
seasons from 2014 to 2018 with production
or zone.
operations to commence in 2018 and continue
Flow lines and water disposal well
for about 25 years.
After the natural gas is extracted from the
reservoir, it would be transported along 10
1249_NEB_MGP_Vol2_Text_ENG.indd 50
Table 4-2
kilometres of insulated above-ground flow
Niglintgak construction highlights schedule
lines to a gas conditioning facility, where
Activity
Season and year
Barge supplies and equipment into Camp Farewell
Late summer 2014
Start constructing well pad pilings, flow line pilings and well pad decking
Winter 2014/15
Option to commence drilling at south well pad
Winter 2014/15
Dredge gas conditioning facility transportation route, if required
Summer 2015
Construct flow lines including horizontal directional drill
Winter 2015/16
Excavate gas conditioning facility set-down site and prepare foundation
Winter 2016/17
Transport gas conditioning facility to set-down location
Summer 2017
Complete drilling and completion program and demobilize
Winter 2017/18
Start up operations and production
Summer 2018
the gas would be separated from any liquid
hydrocarbons and water. Water that has been
removed would be sent to a disposal well
on the south well pad. The flow lines would
be elevated at least 2.2 metres above ground
on vertical supports.
12/6/10 11:02:03 AM
Chapter 4: Development fields 51
Figure 4-4
Niglintgak production
facilities
Gas conditioning facility
Shell’s proposed gas conditioning facility would
be prefabricated and housed on a lightweight,
• inject hydrocarbon liquids into the sales gas
line; and
• chill and meter the sales gas before it is
Kumak Channel. The current design calls for a
barge with a 1.5 metre draft that stretches 50
metres across and 150 metres in length, which
ice-strengthened steel barge. The gas
pumped into the buried lateral pipeline which
is slightly larger than a soccer field. Once
conditioning facility, designed for a maximum
connects to the Mackenzie Gathering System.
the barge reaches its final location, it would
capacity of 4.3 Mm3/d (150 MMcf/d) consists
of several production modules designed to:
• separate the gas from free water and
hydrocarbon liquids;
• inject produced water into a disposal well;
• compress and dehydrate the gas;
1249_NEB_MGP_Vol2_Text_ENG.indd 51
Shell plans to tow the gas conditioning facility
be installed onto steel-pile foundations.
barge through the Beaufort Sea and into Little
Kumak Channel in the Mackenzie Delta, where
it would be set down on the Kumak Channel
flood plain at a location north of the Little
12/6/10 11:02:04 AM
52 Mackenzie Gas Project • Volume 2: Implementing the decision
Barging
mitigate these concerns. Impacts on water
Camp Farewell
The gas conditioning facility would be
quality during transportation are not expected
Camp Farewell, which includes an airstrip,
transported by barge through the Beaufort Sea
to be significant as no dredging is anticipated.
an equipment laydown area, a barge landing
and up the Mackenzie River. In summer, beluga
Shell’s preferred route to the set-down location
whales, bowhead whales and ringed seals all
runs through the previously dredged Kittigazuit
make the southeast Beaufort Sea home.
Bay (location shown on Figure 4-1), which is
There is the possibility that personnel would
part of an existing shipping lane. This would
encounter groups of marine mammals; however,
eliminate the need to dredge the shallow waters
encounters are anticipated to be short term.
at the mouth of the Mackenzie River. Shell plans
Measures such as reducing vessel speeds,
to perform bathymetry and if required, conduct
using an onboard mammal monitor to watch
additional dredging on the transportation route.
for aggregations of bowheads, and redirecting
Proposed production facilities for the Niglintgak
vessels to avoid whales could be used to
site and fuel storage facilities, would be used
to support drilling and construction activities
at Niglintgak. The camp is Shell’s staging
and storage facility within Kendall Island Bird
Sanctuary and has operated to support northern
exploration and drilling activities since the late
1960s. It is located 15 kilometres southeast of
the Niglintgak field and provides accommodation
for 35 workers and support staff.
field (see Figure 4-4) are described opposite.
VOL 2 FIG 4-W/G-2 NIGLINTGAK FACILITIES SITE PLAN
Chevron
C-21
Figure 4-5
Niglintgak field map
J-30
sla
North well pad
nd
Bi
rd
Sa
nc
M
tu
id
ar
dl
y
e
Niglintgak
Island
Shell
H-30
Ch
an
Niglintgak gas
conditioning facility
A-30
ne
l
Shell
M-19
nel
lI
han
al
ak C
nd
Kum
Ke
3M-19
2M-19
G-19
Little Kumak
Channel
Shell
B-19
O-08
Central well pad
Shell
E-58
C-08
P-2 (A1-A6)
Shell
C-58
Bottom hole location
Abandoned wells (surface locations)
South well pad
Gathering pipelines route
Horizontal directional drilled crossing
Flow line
Significant discovery licence area
0
M
ac
ke
nz
ie
Ri
ve
r
1
Kilometres
1249_NEB_MGP_Vol2_Text_ENG.indd 52
12/6/10 11:02:04 AM
Chapter 4: Development fields 53
Views of the Board
4.2.2 Development plan issues
We are satisfied with the general
During the hearing, we heard the
approach, conceptual design and plan
following related to the development
proposed by Shell for the Niglintgak field.
of the Niglintgak field:
We note that when Shell drills and produces
• matters raised by adjacent rights holders;
gas from its wells, new geological and
• geographic and design issues related
reservoir data will be acquired that will
to permafrost, subsidence, flood
determine if additional faulting and
protection and climate change;
compartmentalization exists and whether
any contingent wells would be required.
Condition N18 requires Shell to submit
to the National Energy Board an updated
resource management plan within
18 months after production commences
or prior to the drilling of contingent wells.
• air quality issues and greenhouse
gas emissions;
• activity and facility noise levels and
The reservoir is in the poorly consolidated
Reindeer Sands geological formation and
consists of several separate zones resulting
from subsurface faulting. To fully recover
the gas in the reservoir, Shell proposes a total
of six to twelve wells on the three well pads.
These sites were selected because the land has
been disturbed by previous drilling activity.
Most of the activity would take place on the
north pad where Shell plans to initially drill four
gas wells. Initially, one gas well would be drilled
environmental footprint in Kendall Island
on the central pad, and the south pad would
Bird Sanctuary; and
contain both a gas well and a water disposal
• management of spoils from dredging
operations.
well. To reach the gas reserves, Shell plans to
directionally drill under the Mackenzie River.
The shallow depth of the reservoir will limit
We consider Shell’s conceptual plan
Matters raised by adjacent rights holders
requiring commingled production in
On 3 November 2004, the National Energy
some wells in order to optimize gas
Board issued a declaration of Commercial
recovery with a minimal well count to
Discovery (CDD) for the Niglintgak field, which
be acceptable. The National Energy Board
includes land held and operated by several
Figure 4-6
will consider commingled production
different parties. Shell is the sole interest holder
Commercial discovery declaration area and significant
on an individual well basis during drilling
of Significant Discovery Licence SDL019, which
and production operations in accordance
encompasses most of the field (see Figure 4-6).
with section 66 of the Canada Oil and Gas
A Significant Discovery Licence interest holder
Drilling and Production Regulations.
has the right to drill wells and, in the future,
Condition N31 stipulates that the approval
of the Development Plan for the Niglintgak
discovery licences for Niglintgak as of 2006
52
51
obtain production rights for subsurface oil
and gas resources.
field under subsection 5.1(4) of the
Shell’s plans for developing the field are based
Canada Oil and Gas Operations Act is
on the results of reservoir modeling. Shell’s
subject to the Minister of Indian Affairs
models show a reservoir that is smaller and
and Northern Development Canada
relatively shallow in comparison to the other
providing confirmation that Shell has
two fields—the gas reserves lie only about
satisfactorily met the Benefits Plan
1000 metres below the surface—and much
requirements of section 5.2 of the
of the reserves lie underneath the Mackenzie
Canada Oil and Gas Operations Act.
River and its tributaries.
1249_NEB_MGP_Vol2_Text_ENG.indd 53
the length of these directionally drilled wells.
42
32
22
Chevron Mosbacher
41 Talisman
31
21
SDL-016
12
2
52
42
11
1
51
41
Crown land
69º20’
60
50
40
30
20
10
60
50
59
49
39
29
19
9
59
49
48
38
28
18
8
58
48
57
47
37
27
17
7
57
47
56
46
36
26
16
6
56
46
58
BP Chevron
EL-394
Shell
SDL-019
135º15’
EL-394
SDL-019
SDL-016
CDD Outline
12/6/10 11:02:05 AM
54 Mackenzie Gas Project • Volume 2: Implementing the decision
To the north of Significant Discovery Licence
discussion around unitization. Shell believes
area3 intended to provide adjacent interest
SDL019 lies the Significant Discovery Licence
the only way Mosbacher and Chevron can prove
holders the opportunity to develop wells on
SDL016 land held by Mosbacher Operating Ltd.
the extent of gas reserves under their land is
their lands. Shell indicated that the 250 metre
(Mosbacher), Talisman Energy Inc., and Chevron
by drilling their own wells. This could be assisted
off-target area is appropriate, but requested
Canada Resources (Chevron) which is also the
by allowing Chevron and Mosbacher access to
a variance in accordance with the 2009 Draft
operator for these lands. To the south, east
Shell’s well pads so that they may directionally
Spacing Requirements in order to allow
and west of Shell’s land, is Exploration Licence
drill wells onto their lands. According to Shell,
for the optimum location of some wells.
EL394 held by Chevron and BP Canada Energy
their proposed well pads could be adjusted
Company with Chevron being the operator.
to accommodate additional drilling activities,
1
Chevron and Mosbacher, as interest holders
for lands adjacent to the Niglintgak field are
concerned that Shell’s proposed development
would drain their gas resources. Mosbacher
and Chevron would prefer to develop the
agreeable financial arrangement. If Chevron
and Mosbacher choose to drill wells from
Shell’s well pads, the pads could be extended
by 15 metres for each additional well.
Mosbacher indicated that the proposed
Niglintgak Development Plan was sub-optimal
with respect to minimizing waste and
referenced sections 18 and 19 of the Canada Oil
and Gas Operations Act. In the absence of joint
development, both Chevron and Mosbacher
Niglintgak field in collaboration with Shell,
According to Shell’s estimates, the maximum
submitted to us that Shell should not be granted
either by unitization or by providing third-party
horizontal reach for wells in the Niglintgak
a variance in accordance with the 2009 Draft
access to common facilities.
Field is approximately 1.3 to 1.5 kilometres.
Spacing Requirements for Significant Discovery
Chevron and Mosbacher could potentially
Licence SDL019 as this would exacerbate
drill a well from Shell’s north and central
drainage of gas from their lands.
A unitization agreement would allow parties
to jointly develop the field in exchange for a
predetermined share of the end product. Shell
is opposed to a unitization agreement. Shell
also stated that no order for unitization to
prevent waste under section 38 of the Canada
Oil and Gas Operations Act is required as there
would be no waste. Shell argued that Chevron
and Mosbacher, like Shell, have rights to drill
wells and develop their lands, but unlike Shell,
1249_NEB_MGP_Vol2_Text_ENG.indd 54
provided all parties could reach a mutually
In final argument, both Chevron and
well pads into their adjacent lands. If an
arrangement is reached during the design
Chevron asked us to consider a condition that
phase, Shell would consider modifying its
would require field development to take into
facilities, including installing additional river
consideration the area needs when designing
crossings and enlarging flow line structural
and sizing facilities. Chevron also asked for
supports for future expansion and meeting
a condition restricting well density to no more
additional fuel gas and power supply
than one well per spacing unit for all Shell lands.
requirements for well pads.
The third condition requested by Chevron would
require Shell to provide a one grid unit set-back
Chevron and Mosbacher have chosen not to
Typically when gas fields are developed, wells
exercise those rights. In Shell’s opinion, the
are positioned according to an established
Chevron and Mosbacher lands lie on the outer
grid of “spacing units”, such as that set out
fringes of the reservoir and there is not enough
in the National Energy Board’s 2009 Draft
Mosbacher suggested a condition that would
information about Chevron’s and Mosbacher’s
Spacing Requirements2. The 2009 Draft Spacing
direct Shell to include all land in Significant
potential gas reserves to conduct meaningful
Requirements establish a 250 metre off-target
Discovery Licence SDL016 within the commercial
[1] Exploration Licence EL394 has expired and Production
Licence PL25 was issued on 17 September 2008 for
sections 17, 28 and 39. The current representative interest
holder of Production Licence PL25 is MGM Energy Corp.
[2] The 2009 Draft Spacing Requirements were issued
on 31 December 2009 and replaced the Draft Spacing
Unit Regulations.
[3] The 250 metre off-target area replaces the
one grid unit set-back outlined in the Draft Spacing
Unit Regulations.
between Significant Discovery Licence SDL019
and lands of differing ownership.
12/6/10 11:02:05 AM
Chapter 4: Development fields 55
discovery declaration area as part of the
Chevon and Mosbacher drill wells on their
requiring field development to take into
Niglintgak Development Plan. Secondly,
lands to demonstrate productivity before
consideration the area needs when
Mosbacher asked for a condition requiring Shell
serious discussions could occur on joint
designing and sizing facilities.
to fully explore joint production arrangements
development or unitization of the
with other interested parties. The third condition
Niglintgak field. In this regard, Condition
requested by Mosbacher would have Shell
N2 requires the Niglintgak north, central
make available drilling pad space on reasonable
and south well pads to be designed so
commercial terms to allow Mosbacher and
each may be expanded to allow for the
other interested parties the opportunity to drill
drilling of at least one well by third parties.
additional wells on a timely basis.
If the parties involved are able to work
In the absence of joint development
arrangements, we are of the view that
the 2009 Draft Spacing Requirements are
appropriate and provide an approach that
balances the optimization of gas recovery
with the protection of the correlative rights
of adjacent land interest holders. Condition
out commercial terms including timing,
Views of the Board
N19 requires Shell to comply with the
the condition would provide Chevron
2009 Draft Spacing Requirements. We
We are of the view that if the interest
and Mosbacher the opportunity to drill
are not persuaded by Chevron to require
holders of the adjacent lands wish to
directional wells to delineate the field on
a one grid unit set-back between Significant
develop their lands a joint and collaborative
their lands with a minimal environmental
Discovery Licence SDL019 and lands of
approach to the development of the
footprint in Kendall Island Bird Sanctuary.
differing ownership. We consider the
Niglintgak field would be advantageous
to all parties involved. The benefits would
include a minimal duplication of facilities
and a minimal environmental footprint
within Kendall Island Bird Sanctuary.
It is also our view that joint development
is best obtained through voluntarily
commercial negotiations and agreements
between the parties involved. We note that
the compulsory unitization4 provisions in
the Canada Oil and Gas Operations Act
require participation from Shell as it holds a
large portion of the lands comprising the
Niglintgak commercial discovery declaration
area. Shell has stated that it requires that
As there currently is no joint production
arrangement between the interest holders
of Significant Discovery Licence SDL016
and Shell, we are of the view that there is
1249_NEB_MGP_Vol2_Text_ENG.indd 55
to be appropriate noting that it is consistent
with set-backs used in Alberta, British
Columbia, Saskatchewan and Yukon.
no basis for Mosbacher’s condition directing
The 2009 Draft Spacing Requirements set
Shell to include all sections of land in
a limit of one producing well in spacing
Significant Discovery Licence SDL016 within
units adjacent to lands of differing
the commercial discovery declaration area
ownership, but for spacing units not
as part of the Niglintgak Development Plan.
adjacent to lands of differing ownership,
As noted, the first step that needs to be
there is no off-target area and more than
taken to commence meaningful discussions
one producing well is permitted5. Therefore,
on joint production arrangements is the
we are not persuaded by Chevron to restrict
drilling of wells by Chevron and Mosbacher.
well density to no more than one well per
Without wells on their lands, adjacent
spacing unit for all Shell lands.
interest holders cannot make volume
commitments with respect to third party
[4] Compulsory unitization, sections 39 to 47 of the
Canada Oil and Gas Operations Act came into force on
31 July 2010. Compulsory unitization requires one or
more working interest owners who are parties to a unit
agreement and a unit operating agreement and own in
the aggregate sixty-five percent or more of the working
interests in a unit area to apply for a unitization order with
respect to the agreements.
250 metre off-target area for gas wells
access to Shell’s facilities. Therefore, we are
not persuaded to include the Mosbacher
condition requiring Shell to fully explore
joint production arrangements with other
interested parties or the Chevron condition
[5] Part IV of the 2009 Draft Spacing Requirements.
12/6/10 11:02:05 AM
56 Mackenzie Gas Project • Volume 2: Implementing the decision
According to the 2009 Draft Spacing
Geographic and design issues
Requirements, Shell would not need
Permafrost
a variance for the proposed preliminary
The Niglintgak field is located within a zone
well locations. Any future application
of intermediate discontinuous permafrost. Well
for a variance would be considered by
operations could produce not only warm natural
obstacles without requiring a trench and with
the National Energy Board at that time
gas, but also circulate other warm liquids, such
minimal disruption to the surface. A drill rig is used
and would be assessed in accordance
as reservoir and drilling fluids, which could thaw
with the 2009 Draft Spacing Requirements,
the permafrost. Thawing of the permafrost may
The passage is reamed out to an appropriate size
or any orders dealing with spacing that may
alter the landscape.
and the pipe or utility is then pulled through.
supersede it.
To reduce disturbance to the permafrost,
We are of the view that the proposed
Shell proposes to space the wells a minimum
production scheme is appropriate for a
of 15 metres apart, and implement a number
conventional gas field such as Niglintgak.
of other mitigative measures to reduce thawing
With Condition N19 in place requiring
of the permafrost by warm fluids from well
compliance with the 2009 Draft Spacing
operations. In addition, the well pads would
Requirements, interest holders of
be constructed on a raised steel deck, and
Significant Discovery Licence SDL016
6
and Production Licence PL25 have the
opportunity to drill wells and develop
their lands. We do not consider there
to be sufficient grounds to find that the
Niglintgak Development Plan is suboptimal
in terms of minimizing waste , as suggested
7
by Chevron and Mosbacher.
the flow lines would be insulated and elevated.
Did you know?
Horizontal directional drill
A method for installing pipelines or other utilities
beneath rivers, streams, channels, roads and other
to bore an underground passage for the pipeline
or utility with a directionally controlled drill head.
The location of the gas conditioning facility
requires the flow lines from the north and
central pads to cross the Kumak Channel,
a distance of approximately one kilometre.
A feasibility assessment for a horizontal
directional drill indicated that ice-rich, thawunstable permafrost effectively surrounds
the Kumak Channel, but concluded the
One reason Shell chose the proposed set-down
location for the gas conditioning facility is
that the site is underlain by permafrost, which
provides several options for excavation of the
area. Shell’s preferred approach is a combination
crossing may be successfully constructed
with the application of mitigative measures,
such as using chilled drilling fluids, to prevent
permafrost thaw.
of winter mechanical excavation and summer
Shell’s alternative to the horizontal directional
dredging. Once the gas conditioning facility
drill would be a trenched flow line crossing
is in place, the site would be dammed off and
about 900 metres downstream of the proposed
drained to isolate it from the channel to allow
horizontal directional drill crossing bordering
the permafrost layer to re-establish naturally.
the Little Kumak Channel.
[6] The lands comprising Significant Discovery Licence
SDL016 are eligible for a production licence as those lands
were included in the NEB’s commercial discovery declaration dated 16 September 2004.
[7] Waste as defined in section 18 of the Canada Oil and
Gas Operations Act.
1249_NEB_MGP_Vol2_Text_ENG.indd 56
12/6/10 11:02:05 AM
Chapter 4: Development fields 57
Views of the Board
We are satisfied with Shell’s general
approach to addressing permafrost integrity
for the Niglintgak development. We note
that because warm fluids get circulated up
and down the wellbore during drilling and
production operations, it is important for
crossing and the contingent open cut
Joint Review Panel Report recommendation
crossing; a monitoring program of
6-10 asked us to require Shell to file with the
slope stability, scour, drainage impedance
National Energy Board a program to monitor
and erosion issues for the crossing; and
subsidence and flooding due to hydrocarbon
evidence of consultation with other
extraction for the Niglintgak field. In a letter
appropriate regulators and government
dated 28 January 2010 responding to the
departments.
Joint Review Panel Report recommendations
the Proponents submitted to us that
safety and environmental protection reasons
Subsidence
recommendation 6-10 be rejected as our
The reservoir for the Niglintgak field is located in
proposed Condition 7 (dated 5 February 2007)
the Reindeer Sands Formation, formed 60
for the Niglintgak field was sufficient. In
million years ago in the Early Tertiary Period.
the Proponents’ view, it was unlikely to be
When natural gas from the Niglintgak field is
technically feasible to monitor flooding due
extracted from the poorly consolidated Reindeer
to hydrocarbon extraction since it would be
Sands Formation, the sands may become more
very difficult to differentiate flooding due to
We are of the view that Shell’s preliminary
tightly packed and the surface could settle.
hydrocarbon extraction from natural flooding.
horizontal directional drill design is
This phenomenon is called subsidence. With
The Proponents said that flooding at Niglintgak
satisfactory. We note that horizontal
this subsidence, the Niglintgak field, which
is a natural and annual occurrence.
directional drill design has been used only
is located within the active Mackenzie Delta
In argument, Environment Canada suggested
once in permafrost areas and that this
floodplain, may be more prone to flooding. The
the following revisions to the condition:
increases the potential for unforeseen issues
low lying terrain of Niglintgak Island presently
during installation. We agree with the use
experiences annual spring floods as snow melt
of temperature controlled drilling muds
raises water levels in lakes, rivers and their
for the horizontal directional drill crossing.
tributaries throughout the Mackenzie Delta.
When this is not possible, the alternative
Shell predicts a maximum subsidence of 0.45
use of freezing temperature depressants
metres at the surface over the centre of the
in order to differentiate project-induced
has potential undesirable long term impacts
reservoir, which correlates with the centre of
subsidence from natural changes in ground
on slope stability and their use as an option
the Middle Channel, and predicts subsidence
that the permafrost thaw bulbs around
wellbores do not coalesce. Condition N3
requires the interwell spacing on Niglintgak
well pads to be no less than 15 metres unless
Shell utilizes mitigation measures approved
by the National Energy Board.
• clarify and enhance consultation;
• include the monitoring of flooding due
to subsidence in order to determine
the loss of nesting habitat;
• include monitoring of reservoir compaction
elevation; and
in horizontal directional drill must be
of 0.15 metres at the set-down location of the
carefully considered before implementation.
gas conditioning facility. Shell has indicated that
technology at the time including airborne
Condition N7 requires Shell to provide:
it is considering using global positioning system
and remote sensing techniques.
a hazard analysis and contingency plan for
targets on each of the well sites, the gas
the proposed horizontal directional drill
conditioning facility, on flow lines and
crossing; detailed final design drawings for
at a number of benchmark locations to
the proposed horizontal directional drill
monitor subsidence.
1249_NEB_MGP_Vol2_Text_ENG.indd 57
• allow the use of the most appropriate
Shell responded in argument by proposing the
condition include the terms “best management
practices” and “best available technology” in
regards to monitoring.
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58 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
We are of the view that it will be important
to monitor and confirm Shell’s estimates of
subsidence due to hydrocarbon extraction
because the Niglintgak field is located
inside Kendall Island Bird Sanctuary and
is one of the first proposed developments
in the Mackenzie Delta where subsidence
We agree with Environment Canada
Flood protection and climate change
that the condition should allow for the
Shell’s approach to flood protection was to
use of the most appropriate technology
estimate a maximum value for subsidence due
at the time. This is similar to Shell’s
to gas extraction and add factors such as the
suggestion to use the terms “best
maximum predicted flood level, rising sea levels
management practices” and “best available
due to climate change, an increased severity of
technology” in the condition. Condition N4
storm surges, permafrost thaw, and maximum
has been amended to reflect this.
wave height. These factors were all taken into
due to gas extraction is predicted to occur.
We agree with Environment Canada’s
Condition N4 requires Shell to submit
suggestion to clarify and enhance
a program to measure and monitor
consultation and Condition N4 has been
accumulated subsidence and to monitor
revised in this regard.
consideration when developing the preliminary
design for the well pads, flow lines and the
barge-based gas conditioning facilities. Shell
determined that permafrost thaw subsidence
on areas vulnerable to flooding was much
flooding for the life of the field.
smaller, by an order of magnitude, than
Environment Canada indicated monitoring
subsidence from gas extraction and, therefore,
of reservoir compaction was needed to
permafrost thaw subsidence was not significant.
differentiate project-induced subsidence
Subsidence at the original set-down location
from natural changes in ground elevation.
of the gas conditioning facility was predicted
Condition N4 requires that elevation
to be 0.15 metres. A substructure design
benchmarks be located outside of the
height of 5.75 metres was determined for
projected gas-extraction-subsidence-area.
the gas conditioning facility, which included
We believe that these elevation benchmarks
consideration of subsidence, foundation
will act as control or reference points to
settlement, maximum flood level, rise in
provide data to estimate natural subsidence.
sea level, storm surge, wave crest and a
We are not persuaded that monitoring
freeboard of 0.3 metres as additional protection
of reservoir compaction is necessary.
(see Figure 4-7). The well pads would be set
between 3 and 4 metres above grade and
the flow lines would be elevated a minimum
of 2.2 metres above grade.
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Chapter 4: Development fields 59
Shell believes that it has used a conservative
stated that from a design perspective, there
These documents contain extensive analysis of
approach to estimate the effect of thawing
is uncertainty regarding the effects of climate
all the parameters that could influence sea level
permafrost in its determination of the design
change on the permafrost, the rise in sea level
rise from climate change. Shell noted that the
height of its facilities. Should the waters of
and the degree of flooding. The Sierra Club of
change in the annual average mean sea level,
the Mackenzie River ever threaten the facilities,
Canada referred to the Arctic Climate Impact
recorded at Tuktoyaktuk between 1971 and
some modification to the facilities and flow
Assessment prepared by the International Arctic
2005 indicates that sea level changes are at
lines would be considered. This could include:
Science Committee. The Arctic Climate Impact
a low level (less than 0.1 metres over 35 years).
• increasing the height of the equipment
Assessment states that the Arctic is experiencing
Shell believes previously mentioned research
the most rapid and severe climate change on
and Environment Canada data endorses its
earth, including the disappearance of Arctic sea
view that the direct impact of sea level rise over
on flow lines and certain well site
ice which allows higher waves and storm surges.
30 years should not exceed 0.1 metres, but that
equipment, such as tanks;
Shell indicated that the direct impact of sea
an increase in the magnitude of storm surges
level rise over 30 years should not exceed
needs to be considered. Shell indicated that it
0.1 metre This was based on research from the
will look at whatever evidence and information
platforms and flow lines;
• increasing the number of restraint points
• installing a flood barrier around
the plant perimeter at deck level;
• increasing the depth of the substructure
United States Environmental Protection Agency
is available, and if it leads to a different
and raising the elevation of the plant
(September 1995) and the Intergovernmental
conclusion, Shell would need to increase design
on the gas conditioning facilities; and
Panel on Climate Change in 2001.
margins and would do that. Facility designs
• installing ice barriers.
Warming of the global and regional climate
Figure 4-7
could raise sea levels and affect weather
0.2m wave crest elevation
patterns. The Niglintgak field is located in the
low-lying Mackenzie Delta near the Beaufort
0.3m increase in severity
of storm surge
Sea. We heard concerns that seasonal flooding
0.1m sea level rise
Niglintgak substructure
design height
and storm surges could affect these facilities
during the life of the project. Shell provided
evidence that the facilities would be high
0.3m
0.6m
enough to protect them from storm surges
Freeboard
Environmental changes + waves
Maximum predicted flood level
and flooding even if sea levels rise.
The Sierra Club of Canada was concerned about
the lack of peer-reviewed research publications
2.2m
Average water level at
installation site (Aug - Sept)
on the effects of climate change, specifically
1.7m
1.5m minimum draft + 0.2m tolerance
span that was used by Shell in the design of the
0.3m
Foundation tolerance
Niglintgak facilities. The Sierra Club of Canada
0.5m
Foundation settlement
0.15m
Extraction generated subsidence
for the Mackenzie Delta over the 30 year life
Design
substructure
height
5.75m
Note: based on preliminary design information
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60 Mackenzie Gas Project • Volume 2: Implementing the decision
will include adaptive management and future
Views of the Board
Air quality issues
mitigations, where appropriate.
We are satisfied with Shell’s climate change
Air quality in the North is considered to be of
The Joint Review Panel was generally satisfied
estimates used in the design. Given the
high quality and Northerners are very concerned
that Shell had taken climate change into
uncertainty regarding climate change
that it remains that way. Both Environment
account in its design. Nevertheless the Joint
predictions and the vintage of studies and
Canada and the Proponents agreed that existing
Review Panel recommended that the National
data used by Shell, a prudent step would
air quality in the proposed project area is good
Energy Board add a condition to the certificate
be to assess the design using upper limit
and, along with other government regulators,
which would require Shell to file final design
temperature scenarios as suggested by the
emphasized the need to “keep clean areas
plans that incorporate further design analysis
Joint Review Panel. As the name implies,
clean.” This principle requires new industrial
of the impacts of climate change on permafrost
upper limit temperature scenarios would
development to be “planned, constructed and
and terrain stability over the design life of
be less likely to occur than what has been
operated in a manner that minimizes the
the project and post-abandonment. The Joint
used by Shell for the design of the project.
degradation of air quality in these areas.”
Review Panel was of the view that this analysis
Condition N8 requires Shell to provide
Air quality issues for the project included project
should be conducted for a series of representa-
final detailed design information that
emissions for the pipeline and development
tive locations, conditions and terrain types
incorporates an analysis of the impacts of
fields, monitoring, and greenhouse gases in
and should incorporate climate variability, in
climate change and variability on
the context of monitoring climate change.
particular, upper limit temperature scenarios
permafrost and terrain stability for the
The Joint Review Panel noted that the National
to account for the range of future temperature
Niglintgak facility using potential upper
Energy Board would be the prime regulator
conditions, including variability and extremes,
limit temperature scenarios which may
of air emissions from the project and that
and the impact of this variability on stream flow
occur during the operational life of the
Environment Canada and the Government
regimes. The Joint Review Panel added that the
facilities. Shell will also provide information
of the Northwest Territories would play advisory
results should be incorporated into monitoring,
about how upper limit temperature
roles. The Joint Review Panel recognized
mitigation and adaptive management plans.
scenarios may impact precipitation, rise
the National Energy Board’s expertise and
The Joint Review Panel thought that this
in sea level, storm surges, ice floes and
experience in regulating interprovincial aspects
analysis should be provided to other appropriate
flood levels, and watercourse crossing
of the oil, gas and electric utility industries,
regulators in sufficient time for review and to
designs. We are of the view that
including environmental matters. The Joint
provide input to the National Energy Board.
government departments such as
Review Panel also recognized the extensive
Environment Canada, Indian and Northern
environmental and local knowledge that
Affairs Canada and Natural Resources
Environment Canada and the Government
Canada should be consulted to benefit
of the Northwest Territories can provide.
Indian and Northern Affairs Canada suggested
in final argument that the Proponents should
demonstrate how upper limit temperature
scenarios have been considered in their design.
Further specific discussion on climate
change regarding project design is found in
Chapter 6.
from their expertise for the field design.
Air emissions can be related to the projectspecific effects of construction, operations,
and waste incineration. Air quality impacts
can be local to regional in the case of particulate
matter and sulphur dioxide, or global in
1249_NEB_MGP_Vol2_Text_ENG.indd 60
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Chapter 4: Development fields 61
the case of greenhouse gases. Emissions would
Environment Canada recommended that
Alternatives North submitted that the National
occur during the construction phase through
the Proponents design and implement suitable
Energy Board and the Government of Canada
intermittent flaring during well testing at
air quality monitoring programs with its
have a public interest mandate that requires
the Niglintgak field.
help. Environment Canada focused its
consideration of greenhouse gas emissions.
Further specific details pertaining to emissions
for the pipeline are discussed in Chapter 3 and
discussion on air emissions pertaining to facility
design is found in Chapter 6.
The Joint Review Panel report indicated that the
Proponents’ baseline information was compiled
from historical data and results of air quality
monitoring that was carried out over one year
near the communities of Inuvik and Norman
Wells, and periodically at the Parsons Lake and
Taglu gas fields. The Proponents’ monitoring
data and other sources indicated that background concentrations of air contaminants are
recommendations on pollution prevention
and the use of best available technology and
best management practices to minimize the
degradation of air quality. Further discussion
around application of these principles may be
found in Chapter 6.
Ecology North deemed that high project-specific
standards for greenhouse gas emissions based
on a robust and strong definition of best
available technology and accompanied by
penalties in the cases where they do not meet
those project standards or targets, would
The Dehcho Elders and Harvesters indicated that
provide the best possible protection in terms of
the project needs to be designed to minimize air
minimizing upstream greenhouse gas emissions
quality impacts, with monitoring plans in place
associated with the project.
to verify the predicted emissions and impacts.
Corrective action needs to be taken quickly to
avoid impacts upon the land and wildlife from
degraded air quality.
Sierra Club of Canada submitted that we need
to specify an actual target and it is not enough
to just leave it up to the Proponents. Sierra Club
of Canada indicated that the target should at
generally below detection levels or applicable
Greenhouse gas emissions
least match the general recommended target
guidelines. The one exception that is not
Parties were concerned about the impacts
in Joint Review Panel recommendation 8-8.
below detection levels is ozone; relatively high
of the project on climate change, especially
background levels were monitored in Inuvik and
in light of Canada’s international efforts under
Norman Wells. The Proponents indicated that
the United Nations Framework Convention
elevated ozone levels at high latitudes in the
on Climate Change and the Kyoto Protocol.
northern hemisphere are thought to result
from the intrusion of stratospheric ozone.
The Proponents stated that all ground-level
concentrations of compounds released by
the project during operations at the gas fields,
the Inuvik Area Facility, and compressor and
heater station sites would increase, but would
be below those outlined in applicable federal
and territorial guidelines at all locations in the
production area and along the pipeline corridor.
1249_NEB_MGP_Vol2_Text_ENG.indd 61
Views of the Board
We understand the importance of clean air
in the North and that air quality must be
Greenhouse gas emissions arising from the
considered in a cumulative manner. We also
project include carbon dioxide, methane and
recognize the need to minimize greenhouse
nitrous oxides with each compound having
gas emissions resulting from the project.
a different climate change potential. During
The Joint Review Panel directed several
operation, the project would emit greenhouse
recommendations to us relating to
gases from burning natural gas at combustion
air quality and air emissions. We have
related sources such as compressors and
addressed air issues through several
methane gas released through normal
conditions for the Mackenzie Gas Project.
venting procedures and minor leaks (fugitive
These conditions are focused on the
emissions). Further specific discussion on air
Proponents taking appropriate measures
emissions pertaining to facility design is found
to minimize air emissions and address air
in Chapter 6.
quality. We are committed to working
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62 Mackenzie Gas Project • Volume 2: Implementing the decision
collaboratively with Environment Canada
Environmental monitoring is an important
and the Government of the Northwest
part of environmental management that
Territories to protect air quality in
directly supports adaptive management by
the North, recognizing the extensive
observing and evaluating the effects that
environmental and local knowledge
occur, then changing or adding mitigative
for adaptation of successful mitigation
that these agencies can provide.
measures as appropriate to limit or reverse
to future pipeline projects.
Conditions N14 and N16 address
technologies for reducing emissions,
incorporation of best management
practices and best available technologies,
and facility design. Condition N15 requires
the submission of a report evaluating
incinerator emissions from camps and
station facilities and technologies and
practices must be reflected in the waste
the environmental effects. Environmental
monitoring can include:
•• compliance monitoring, to verify that all
environmental mitigation is implemented
as presented in the Environmental
Protection Plan and environmental
alignment sheets and that work is in
compliance with environmental
regulations; and
•• effects monitoring, to assess the effects
additional mitigative measures as
necessary; and
•• provide a feedback system that allows
Monitoring programs may have specific
goals and targets and could include
methods for evaluating and interpreting
collected data such as air quality or
emissions data. Monitoring may include
any relevant environmental practices
(e.g., vegetation establishment, water
quality sampling, waste disposal).
Responsibilities of the National Energy
management plans required by Condition
resulting from project-environment
Board regarding monitoring include:
N12. Condition N17 requires Shell to
interactions and evaluate the effectiveness
•• conducting environmental inspections
minimize and reduce emissions from
of approved mitigation measures.
of facilities, verifying compliance with
flaring. Further specific discussion for
This is further discussed in section 3.3.6.
terms and conditions, and assessing
these conditions regarding air emissions
pertaining to facility design is found
in Chapter 6.
Shell is expected to implement
Environmental Protection and Monitoring
and Surveillance Programs which include
Air quality monitoring is part of
protection of the environment as one of
comprehensive environmental monitoring
the main goals. A monitoring program may:
under an environmental management
•• identify any issues or potential concerns
system. Through environmental
that may compromise the protection
management, systems are established
of the environment;
to address effects of the project on the
•• include methods for developing measures
the effectiveness of mitigation;
•• monitoring ongoing operation, verifying
reclamation and maintenance of the
project site to acceptable standards; and
•• conducting environmental audits,
evaluating environmental management
systems and environmental programs.
We generally require the filing of environmental post-construction monitoring
environment and of the environment
to prevent or mitigate the impact of
reports as a condition of an authorization.
on the project, with the overall goal of
the identified issues;
The information in monitoring reports
minimizing negative impacts. Adaptive
•• provide for continued monitoring of
management is a systematic process for
sites to evaluate success of mitigative
continually improving management
measures undertaken;
practices by learning from their outcomes.
1249_NEB_MGP_Vol2_Text_ENG.indd 62
•• provide a system for implementing
should include:
•• confirmation of proper implementation
of mitigation and reclamation
measures used;
12/6/10 11:02:05 AM
Chapter 4: Development fields 63
•• identification of the outstanding
proposed greenhouse gas targets and
Kendall Island Bird Sanctuary
reduction strategies for air emissions
Kendall Island Bird Sanctuary was established
including particulate matter, NOx and
in 1961 and is the only protected area in
greenhouse gases. Condition N11 also
the Mackenzie Delta. It is one of the most
addresses other matters from the Joint
significant wetland complexes in North America
Review Panel recommendations including
and the deltaic landscape of the Niglintgak field
employee training, monitoring, public
is a haven for the more than 90 species of birds
communication, and required consultation
that migrate to the region annually. The 623
with Environment Canada and the
square kilometre Kendall Island Bird Sanctuary
Government of the Northwest Territories.
provides critical habitat for thousands of
A commitment to continuous improvement,
With these conditions, we find it acceptable
songbirds, waterfowl and shore birds that
outlined in Joint Review Panel recommen-
for the Proponents to develop greenhouse
use the area for breeding and staging. Kendall
dation 8-6, is expected to be a component
gas targets for the project consistent
Island Bird Sanctuary has been identified
of an operator’s management system
with use of best management practices
pursuant to paragraph 5(2)(b) of the
and in consultation with appropriate
Canada Oil and Gas Drilling and Production
government agencies.
environmental issues; and
•• discussion of the company’s plans for
how outstanding issues will be resolved.
Condition N11 requires Shell to submit
an Environmental Protection Plan which
includes monitoring of activities. Condition
N15 includes the requirement for
monitoring incinerator emissions.
as a Key Habitat Site which is defined as an
area that supports at least one percent of the
national population of a migratory bird species
Regulations. This is addressed in Condition
for any portion of its annual cycle. Kendall Island
N11. We are of the view that the commit-
Bird Sanctuary is considered by Environment
ment to continuous improvement is
Canada to be an important component of
not limited to greenhouse gas emissions
Canada’s effort to conserve biodiversity. Under
but should apply to all discharges to the
environment, which in this case is the
atmosphere. Condition N11 also covers
the requirements for methods and
locations of monitoring.
the Migratory Birds Sanctuary Regulations,
Environment Canada has authority over surface
developments in Kendall Island Bird Sanctuary
and has established a limit of one percent
or 600 hectares as the allowable surface
Condition N16 requires the Proponents
disturbance in the Sanctuary for all oil and
to file a report outlining the use of best
gas activities. As a result, Environment Canada
available technology for station facility
encourages project design considerations that
construction. Selection of best available
result in the least possible long-term impact on
technology is the most significant factor
habitat. To reduce impacts on migratory birds,
in determining achievable air emissions
Environment Canada has indicated that it may
targets. Condition N11 outlines the
restrict or apply special conditions to activities
requirements for an Environmental
such as construction, operation, monitoring
Protection Plan. The condition requires
and decommissioning in Kendall Island Bird
the Proponents to submit maximum
Sanctuary during the period between May
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64 Mackenzie Gas Project • Volume 2: Implementing the decision
through October when the Sanctuary is
if an area is “pristine”—a pure, natural area
Shell plans to schedule activities to avoid critical
occupied by birds. Furthermore, Environment
that might have dwellings but no industrial
migratory bird nesting periods where practical.
Canada has indicated its preference for
presence. Environment Canada recommends
Because the Niglintgak field is relatively shallow
Shell to construct above-ground flow lines
continuous noise emissions, as measured from
at 1000 metres, drilling times can be reduced
within Kendall Island Bird Sanctuary. In final
the fence line of the facility, not exceed Alberta’s
compared to Taglu and Parsons Lake. Shell
argument Shell indicated it is committed
Energy Resources Conservation Board Directive
is proposing a winter-only drilling program,
to using above-ground flow lines to reduce
038 “best practices” permissible sound levels
and completions for most wells during winter
surface disturbance.
during the period from 10 May to 30 September
months over three to four consecutive years.
when migratory birds are present in the
However, two well completions are proposed
Sanctuary because Kendall Island Bird Sanctuary
by Shell in the intervening summer seasons.
is considered a pristine area.
Other construction activities such as barging,
Activity and facility noise levels
The Niglintgak anchor field is located in
Kendall Island Bird Sanctuary which is a federally
protected area managed for the conservation
of migratory birds and protection of habitat for
northern-breeding birds. Shell holds Significant
Shell has indicated the primary noise generation
sources at the Niglintgak facilities such as
compressors, power generation equipment
bathymetric work, dredging, transporting and
setting of the gas conditioning facility would
also occur in summer.
and aerial coolers, will be designed so that
Both the Proponents and Environment Canada
the resulting sound levels will be below the
shared the view that requirements for noise
maximum permissible noise levels provided
regulation in Kendall Island Bird Sanctuary, both
in Alberta’s Energy Resources Conservation
for the National Energy Board and migratory
Board Directive 038. The Proponents agree with
bird sanctuary requirements, can only be
Environment Canada that the appropriateness,
finalized after detailed engineering and design
both technically and economically, of the
work is completed, after the noise impact
proposed regulatory requirement will be further
analysis is prepared, and after discussions
informed when detailed design progresses and
between the parties. Environment Canada
before finalizing Environment Canada permit
will continue to work with the National Energy
conditions. For facilities in Kendall Island Bird
Board, Proponents and other regulators on
Sanctuary, the Proponents will continue to
issues related to noise in Kendall Island Bird
evaluate and apply noise mitigation options
Sanctuary. Shell indicated that it is committed
beyond those required to meet the “business
to adhering to requirements in Alberta’s Energy
Alberta’s Energy Resources Conservation Board
as usual” interpretation of Alberta’s Energy
Resources Conservation Board Directive 038, as
Directive 038 indicates a recommended noise
Resources Conservation Board Directive 038,
well as continuing evaluation of noise mitigation
target for remote areas even if no human
provided these are practical. Shell is expected
through detailed engineering and planning in
residences are present. This is considered the
to provide detailed engineering and noise
order to arrive at practical solutions to concerns
“business as usual” requirement. The Directive
modeling results to Environment Canada.
raised by Environment Canada.
Discovery Licence SDL019 that grants it
subsurface oil and gas rights. Environment
Canada has regulatory authority for activities
within Kendall Island Bird Sanctuary, and
will issue permit conditions governing noise
emissions from development under the
Migratory Bird Sanctuary Regulations.
Environment Canada and the Proponent
have both agreed to follow Alberta’s Energy
Resources Conservation Board Directive 038
for noise regulation. There is currently no
legislation or standard in the Northwest
Territories governing noise emissions.
has provisions to change the typical target
when there are unique circumstances, including
1249_NEB_MGP_Vol2_Text_ENG.indd 64
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Chapter 4: Development fields 65
Views of the Board
Overall footprint
within Kendall Island Bird Sanctuary if it were to
We agree with Environment Canada that
Shell’s preliminary design anticipates less than
result in the permanent loss of habitat. The best
regulating impacts of noise in a nationally
ten hectares of total new disturbance within
placement for these materials will be finalized
protected bird sanctuary requires special
Kendall Island Bird Sanctuary. This new
by Shell after discussions with regulators and
consideration and application of best
disturbance includes the entire gas conditioning
stakeholders, including Environment Canada,
practices and the use of best available
facility, the three well pads, the above-ground
to reduce the impact on local wildlife.
technology with the intent of “continuous
flow lines and modifications to the pre-existing
improvement of pipeline safety and
Camp Farewell and a stockpile site.
environmental protection”. Condition N9
To prepare a level set-down site for the gas
drilled well locations and would incorporate
applies to regulating noise in the
conditioning facility, up to 50 000 cubic metres
as much of the previously disturbed land as
Niglintgak field and is intended to minimize
of silt, mud and other material would need to
feasible. Shell also plans to augment the steel
disturbance from facilities inside Kendall
be excavated. The majority of material would
pads with temporary ice pads for the drilling
be removed in the winter and, if required, some
equipment. The ice pads would not leave a
minor dredging or the removal of mud from the
permanent footprint once drilling is complete.
Island Bird Sanctuary. The Condition
requires meeting Alberta’s Energy Resources
Conservation Board Directive 038 “business
as usual” standard with allowance for
achieving the more stringent standard that
Environment Canada recommended to the
Joint Review Panel and the Joint Review
Panel accepted. There is flexibility built in
to the condition to adjust the standard as
informed by final detailed engineering, an
channel floor would occur the following summer.
One reason Shell chose the proposed location
for the gas conditioning facility is that the site is
underlain by permafrost, which provides several
To reduce the level of permanent disturbance,
Shell plans to locate the well pads at previously
Access to the field would be by winter road or
helicopter from Camp Farewell. Shell does not
propose permanent access.
options for excavation of the area. Shell’s
In addition to the permanent footprint, Shell
preferred approach is a combination of winter
estimates a 17.5 hectare temporary footprint
mechanical excavation and summer dredging.
or land disturbed during the construction
of ice pads and an ice road.
independently verified noise impact analysis
Shell reduced the scope of dredging and
report, and continued consultation for final
made design modifications to avoid or reduce
The disposal of drilling waste is not permitted
determination of the fence line, which is
dredging in the delta area. As a result, the gas
within the Sanctuary, so Shell’s initial plan was
the measurement base for a distance-based
conditioning facility barge draught was reduced
to dispose of these drill cuttings in a sump
regulatory standard.
from 1.9 to 1.5 metres, the location was moved
located outside of Kendall Island Bird Sanctuary.
outside of Little Kumak Channel, and Shell
However, Shell has since adopted its alternative
committed to schedule its dredging activities
method which is to transport the cuttings out of
to avoid impacts on the beluga harvest.
the Northwest Territories to an approved landfill
Shell’s current plan is to deposit the excavated
1249_NEB_MGP_Vol2_Text_ENG.indd 65
in Alberta or British Columbia.
material adjacent to the gas conditioning
In developing its Development Plan Application,
facility site within Kendall Island Bird Sanctuary.
Shell met with a variety of stakeholders including
Environment Canada indicated that it would not
Aboriginal peoples and other Northerners,
allow placement of the excavated stockpile
various government representatives, communities
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66 Mackenzie Gas Project • Volume 2: Implementing the decision
and oil and gas companies. Information from
conditioning facility at Niglintgak describe the
Views of the Board
these discussions was used to develop and
potential impacts associated with dredging, and
We have considered the various comments
refine Shell’s plans. Examples of community-
include spoil management and the site-specific
regarding Condition N10 and the condition
driven design changes to the Niglintgak Project
mitigation measures to address adverse impacts.
has been amended to require a dredging
To address Joint Review Panel Report
spoil management plan, to clarify
recommendation 9-9 regarding dredging
requirements for consultation and to
and excavation of the set-down location for
adjust the timing so it is no longer linked
the barge-based gas conditioning facility,
to construction of the well pads. The
we proposed Condition N10 on 9 March 2010.
best placement of dredging materials will
During final argument, Environment Canada
be finalized by Shell after consultation
Dredging activities will occur within Kendall
suggested that the condition be expanded to
with regulators and stakeholders, including
Island Bird Sanctuary and Environment Canada
require a dredging spoil management plan.
Environment Canada, to reduce the impact
will not permit the spoil to be placed on
Environment Canada and a number of other
on local wildlife. Environment Canada has
undisturbed terrestrial habitat within Kendall
parties indicated that consultation needed to be
authority over activities in Kendall Island
Island Bird Sanctuary. Environment Canada
defined or clarified. Shell asked that the timing
Bird Sanctuary under the regulations.
requested that we require that Shell’s plan for
of the condition be adjusted so that the dredging
excavation and dredging at the site of the gas
plan is not linked to well pad construction.
were discussed during final argument and
include reducing overall footprint by locating
drilling sites at pre-disturbed locations,
preferentially scheduling drilling and construction
activities in the winter and using above-ground
flow lines to reduce surface disturbance.
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Chapter 4: Development fields 67
4.3 Taglu
4.3.1 Design of the Taglu facilities
The Taglu field is 120 kilometres northwest of
Bird Sanctuary, a key habitat site for local
Inuvik and 70 kilometres west of Tuktoyaktuk
shore birds and waterfowl. The Taglu field is
close to the Beaufort Sea. A single development
found within the same geological formation
The Taglu field lies above the Arctic Circle
site is proposed near the middle of the field,
as the Niglintgak field—the Reindeer
near the northern edge of the Mackenzie Delta.
close to the confluence of the Kuluarpak
Sands, a formation that is known to be
Currently the largest onshore gas field ever
and Harry channels (see Figure 4-8).
poorly consolidated.
discovered in the Mackenzie Delta, it is
estimated that Taglu contains nearly three
trillion cubic feet of recoverable natural gas—
enough to fuel all the gas-heated homes in
Canada for three years.
The reservoir reaches under Richards Island
and, like the proposed Niglintgak field fifteen
kilometres to the southwest, much of the
reservoir stretches underneath Kendall Island
Figure 4-8
Taglu production
facilities
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68 Mackenzie Gas Project • Volume 2: Implementing the decision
Imperial Oil Resources Limited (Imperial) filed
The well pad and the gas conditioning facility
in the summer of 2018. An overview of the
a Development Plan for the Taglu field under
would be located adjacent to each other
construction schedule is provided in Table 4-3.
section 5.1 of the Canada Oil and Gas
(see Figure 4-9).
Operations Act. The proposed production
facilities include:
• up to 15 production wells drilled from
a single pad;
• one or two disposal wells;
• a gas conditioning facility;
• associated infrastructure including
Wells and well pads
Construction is planned to take place from 2014
Imperial plans to directionally drill 10 to
to 2018 with operations commencing in 2018.
15 production wells and one or two disposal
The cost for developing the field is estimated
wells from a single well pad. Figure 4‑9 shows
to be $2,550 million with an estimated average
the plan view of 11 potential locations of
operations and maintenance expenditure of
production wells and the preliminary locations
$26 million per year for the period 2019 to 2023.
of two disposal wells. This well pad would
be located near the centre of the reservoir
Imperial proposes to start constructing
pads and foundations;
• a barge landing site;
winter roads and moving equipment onto
• an airstrip and helicopter pad;
the site in 2014. Drilling would start in the
• buildings; and
winter of 2016/17 with production beginning
• a water treatment system.
just inside the east boundary of Kendall Island
Bird Sanctuary. Once production begins and
additional reservoir data becomes available,
Imperial may shift the current locations of
its contingent wells to optimize production
Ka
ng
uk
Big Lake
nd
a
F-04
Ke
D-54
Ch
l an
k Channel
rry
l
ne
lua
rpa
l l Is
an
Ch
Ku
Kimialuk Lake
I-53
deck supported by steel piles. Gravel for the well
H-43
L-53
pad and other facilities will come from existing
N-42
O-32
Taglu lateral
borrow sites at Yaya Lakes (see Figure 4-1).
Flow lines
O-52 M-42
I-42
Niglintgak lateral
commingled production.
with a matted and fluid sealed surface or a steel
K-43
H-53
shows that some wells would incorporate
The well pad would be either gravel filled
B-54
D-43: Taglu well pad and
gas conditioning facility
Imperial’s depletion plan for the Taglu field
Ha
Taglu field map
pad facilities on elevated pile foundations.
el
Figure 4-9
ann
d Bi
rd S a
nctuary
of the field. Imperial plans to build its well
The wellheads would be located beneath
the surface of the well pad in a long cellar.
This cellar would provide personnel with easy
access to any well for drilling or servicing with
a conventional rig and provides a heated space
for the flow lines and other support systems.
Proposed airstrip
Bottom hole location
Gathering pipelines route
Significant discovery licence area
1
0.5
0
Kilometres
1
Gas would travel above ground on a pipe rack
via insulated and heat-traced flow lines to a
manifold facility and on to the gas conditioning
facility. The manifold facility would direct
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Chapter 4: Development fields 69
the flow from each well to either a production
to the flare system in a safe and controlled
• control room;
line for processing or a line for testing.
manner, when required.
• office and administration buildings;
Gas conditioning facility
The average daily design capacity for the Taglu
Reservoir fluids would be processed at the gas
gas conditioning facility would be 12.6 Mm3/d
conditioning facility to remove free water and
(445 MMcf/d). The facility would be designed
natural gas liquids and to dehydrate and chill the
to handle a peak maximum design capacity of
gas to meet the specifications of the gathering
14.5 Mm3/d (510 MMcf/d), about 15 percent
Barging
pipeline. Although the gas would not need
above average daily rates, to accommodate
Currently, Imperial plans to enter the East
to be compressed initially, the facility would be
scheduled maintenance and production
Channel of the Mackenzie River through
designed so that it could do so if compression
downtime among the development fields.
Kittigazuit Bay, where there is a historical
were needed. Natural gas liquids and gas
volumes would be measured and transported
to the gathering system and produced water
would be injected about one kilometre below
the surface into the disposal well.
• domestic water system;
• sewage treatment system;
• storage; and
• telecommunication facilities.
shipping channel. Vessel movement through
Infrastructure
The following infrastructure would be provided
to support construction, operations and
maintenance activities and to access the site:
• pads and foundations;
Kittigazuit Bay, which is part of the Kugmallit
Bay 1A Beluga Management Zone, would
be scheduled in August following prime
beluga whale activity in the area. Preliminary
engineering indicates dredging is not required
Imperial would install a safety system in the
• barge landing site;
gas conditioning facility for blowdown and
• airstrip and helicopter pad;
pressure relief to lower the gas conditioning
• roads;
facility pressure and to direct hydrocarbon fluids
• living quarters;
in Kittigazuit Bay to successfully transport these
modules (see Figure 4-1).
Third-party use and future expansion
The Taglu production facilities are designed
to produce and process the Taglu volumes
predicted for the Taglu field, however, the
gas conditioning facility could accommodate
or be expanded to accept additional production
volumes. This would depend on the timing and
Table 4-3
volume of the additional gas, the gas properties,
Taglu construction highlights schedule
and acceptable commercial arrangements.
Activity
Season and year
The well pad may also be extended, but at this
Construct winter roads, gas conditioning facility pad, drilling pad and airstrip
Winter 2014/15
point, Imperial does not have a need to extend
Compact gravel pads and transport construction equipment, materials and fuel
Summer 2015
the well pad.
Construct the dock and complete construction of gravel pads for gas conditioning
facility, drilling pad and completions
Winter 2015/16
Barge and install small gas conditioning facility modules
Summer 2016
Begin drilling program
Winter 2016/17
Barge and install large gas conditioning facility modules
Summer 2017
Begin well completions
Winter 2017/18
Startup operations and production
Summer 2018
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70 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
We find Imperial’s general approach,
conceptual design and plan proposed for the
Taglu field to be satisfactory. We note that
new geological and reservoir data acquired
during drilling and production will be
used by Imperial to determine if additional
faulting and compartmentalization exists
and whether any contingent wells would
be required. Condition T17 requires
that Imperial file an updated resource
management plan with the National Energy
Board within 18 months after production
commences or prior to the drilling of
contingent wells.
Condition T18 requires Imperial to comply
with the 2009 Draft Spacing Requirements
in order to protect the correlative rights
of any adjacent subsurface rights holders.
Imperial’s preliminary production well
locations for the Taglu field comply with the
2009 Draft Spacing Requirements.
We are of the view that Imperial’s
conceptual plan whereby some wells
would utilize commingled production
to achieve maximum gas recovery
is acceptable. Commingled production
is production of oil and gas from more
than one pool or zone through a common
well-bore without separate measurement
of the production from each pool or zone.
The National Energy Board will consider
commingled production on an individual
well basis during drilling and production
operations in accordance with section 66
of the Canada Oil and Gas Drilling and
Production Regulations.
Condition T30 stipulates that the approval
of the Development Plan for the Taglu
Field under subsection 5.1(4) of the
Canada Oil and Gas Operations Act is
subject to the Minister of Indian Affairs and
Northern Development Canada providing
confirmation that Imperial has satisfactorily
4.3.2 Development plan issues
During the hearing, Imperial discussed the
following issues associated with developing
the Taglu field:
• design issues related to permafrost,
subsidence, flood protection
and climate change;
• air quality issues and greenhouse
gas emissions;
• activity and facility noise levels and
environmental footprint in Kendall Island
Bird Sanctuary; and
• management of spoil from
dredging operations.
The design of the development field facilities
is linked to the physical environment.
The Taglu field is located in an active delta
floodplain, with permafrost under parts of
the proposed development. Facility locations
are periodically flooded and the effects of
flooding are a safety and facility design priority.
met the Benefits Plan requirements of
Permafrost and design issues
section 5.2 of the Canada Oil and Gas
The Taglu field is located within a zone of
Operations Act.
intermediate discontinuous permafrost. As with
the Niglintgak field, if the permafrost thaws, the
landscape may be permanently altered. Imperial
has proposed using a number of different types
of design techniques to prevent the permafrost
from thawing beneath its production facilities.
One of these methods would be to separate
each well by 18 metres. This interwell spacing
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Chapter 4: Development fields 71
is similar to the 15 metres Shell has adopted for
Subsidence
Joint Review Panel Report recommendation
its wells in Niglintgak. As previously mentioned,
The Taglu reservoir is within the same
6-10 asked us to require Imperial to file with
wellheads and flow lines would be located
geological formation as the Niglintgak reservoir,
the National Energy Board a program to monitor
in a heated “cellar” below the well pad.
the Reindeer Sands Formation. This formation
subsidence and flooding due to hydrocarbon
To preserve the permafrost, Imperial plans
of poorly consolidated sands from the Early
extraction for the Taglu field. In a letter dated
to include an active refrigeration system with
Tertiary Period is nearly 60 million years old.
28 January 2010 responding to the Joint Review
the wellbore conductor in their wellsite facility.
As with Niglintgak, these sands could crumble
Panel Report recommendations the Proponents
This system keeps the permafrost from melting
and partially collapse, or subside, as gas is
submitted to us that recommendation 6-10
by chilling the ground below the wellsite,
withdrawn from the field.
be rejected as our proposed Condition 7
to about 37 metres deep, during drilling
Imperial estimates the maximum amount
and production. Well pad facilities and flow
of subsidence resulting from gas extraction
lines would be constructed on elevated pile
would range from 0.20 to 0.42 metres. The
foundations to prevent permafrost damage
deepest subsidence would be a low drainage
and to avoid seasonal floods during operations.
area to the north of the proposed Taglu gas
conditioning facility towards Big Lake. Imperial
Views of the Board
indicated that the predicted subsidence would
We are satisfied with Imperial’s approach
not materially change the drainage patterns
to addressing permafrost integrity with
respect to the Taglu development. We note
through those wellbores during drilling
effect was estimated by Imperial to be much
and production. Condition T2 requires
smaller, by an order of magnitude, compared to
the interwell spacing on the well pad to
extraction-induced subsidence described above.
reasons that the permafrost thaw bulbs
around wellbores do not coalesce.
1249_NEB_MGP_Vol2_Text_ENG.indd 71
would be very difficult to differentiate flooding
due to hydrocarbon extraction from natural
flooding. The Proponents said that flooding
at Taglu is a natural and annual occurrence.
the following revisions to the condition:
thaws as a result of climate change. This
for safety and environmental protection
flooding due to hydrocarbon extraction since it
dish” would be formed.
well pad and that warm fluids would flow
the National Energy Board. It is important
unlikely to be technically feasible to monitor
In argument, Environment Canada suggested
Subsidence may also occur if the permafrost
utilizes mitigation measures approved by
was sufficient. In the Proponents’ view, it was
within the affected area and no “subsidence
that all Taglu wells would be located on one
be no less than 15 metres unless Imperial
(dated 5 February 2007) for the Taglu field
• clarify and enhance consultation;
• include the monitoring of flooding due
to subsidence in order to determine
the loss of nesting habitat;
• include monitoring of reservoir compaction
in order to differentiate project-induced
Imperial is considering using a three-dimensional
subsidence from natural changes in ground
global positioning system survey method to
elevation; and
monitor and measure accumulated ground
• allow the use of the most appropriate
subsidence on the Taglu facilities. Details of such
technology at the time including airborne
a program are still being assessed by Imperial.
and remote sensing techniques.
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72 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
We are of the view that it will be important
to monitor and confirm Imperial’s estimates
of subsidence due to hydrocarbon extraction
because the Taglu field is located inside
We agree with Environment Canada that
Climate change and flood protection
the condition should allow for the use
The Taglu reservoir is found under low lying
of the most appropriate technology at
terrain with a mean elevation of 1.5 to
the time. Condition T3 has been amended
1.7 metres above sea level. Imperial expects
to reflect this.
the site to be periodically flooded during spring
Kendall Island Bird Sanctuary and is one
We agree with Environment Canada’s
of the first proposed developments in the
suggestion to clarify and enhance
Mackenzie Delta where subsidence due to
consultation and Condition T3 has been
gas extraction is predicted to occur. Condition
revised in this regard.
runoff and later in the season by storm surges
from the nearby Beaufort Sea. As a result,
Imperial considered the following factors
in the design height of the Taglu pad:
T3 requires Imperial to submit a program
• maximum flood level;
to measure and monitor accumulated
• maximum wave height;
subsidence and to monitor flooding for the
• rise in sea level; and
life of the field.
• surface effect of gas extraction induced
Environment Canada indicated monitoring
subsidence on flood depth.
of reservoir compaction was needed to
These factors and a safety margin of 0.2 metres
differentiate project-induced subsidence
were used by Imperial to design a well pad
from natural changes in ground elevation.
and facility foundation height of 3.1 metres
Condition T3 requires that elevation
(see Figure 4-10).
benchmarks be located outside of the
projected gas-extraction-subsidence-area.
We believe that these elevation benchmarks
will act as control or reference points to
provide data to estimate natural subsidence. We are not persuaded that monitoring of reservoir compaction is necessary.
Imperial plans to monitor the facilities and
implement adaptive management and
contingency plans as needed. If Imperial’s design
height is too low, it is possible to accommodate
higher water levels by adding earthen fill
material to certain areas of the site to protect
them from flooding. In addition, select pilemounted facilities, such as modules and flow
lines, could be raised if flooding becomes
a problem. Furthermore, protective measures,
such as bumper posts or strengthened pipe
supports could be used to protect those parts
of the Taglu facility that would be at risk
from ice floes.
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Chapter 4: Development fields 73
Although there would be a risk that flood levels
of peer-reviewed research publications on
should incorporate climate variability, in
during the 30 year operating life of the Taglu
the effects of climate change, specifically
particular, upper limit temperature scenarios
field could exceed the design height, Imperial
for the Mackenzie Delta over the 30 year life
to account for the range of future temperature
considers this risk to be relatively low. However,
span that was used by Imperial in the design
conditions, including variability and extremes,
if water levels reach an extreme height, it would
of the Taglu field facilities. The Sierra Club of
and the impact of this variability on stream
be possible to shut down production. Onsite
Canada stated that in designing infrastructure
flow regimes. The Joint Review Panel added
activity could cease and some or all personnel
in the Mackenzie Delta there is uncertainty
that the results should be incorporated
would be removed from the site.
as to the effects of climate change, including
into monitoring, mitigation and adaptive
the effects on the permafrost, the rise in sea
management plans. The Joint Review Panel
could raise sea levels and affect weather
level and the degree of flooding.
thought that further design analysis should
patterns. The Taglu field is located in the
The Joint Review Panel was generally satisfied
low-lying Mackenzie Delta near the Beaufort
that Imperial had taken climate change into
Sea. We heard concerns that seasonal flooding
account in its design. Nevertheless the Joint
and storm surges could affect the facilities
Review Panel recommended that the National
The Taglu field would produce natural gas
Energy Board add a condition to the certificate
from relatively shallow underground formations.
which would require Imperial to file final design
As the natural gas is removed, the ground
plans that incorporate further analysis of the
could settle by up to almost half a metre due to
impacts of climate change on permafrost and
the removal of natural gas. This possibility was
terrain stability over the design life of the project
taken into account in the design of the facilities.
and post-abandonment. The Joint Review
Imperial also indicates that climate change
Panel was of the view that this analysis should
is implicit in the way it completed its modeling
As with the Niglintgak field, the Sierra Club
be conducted for a series of representative
for the facility and pipeline design specifically;
of Canada was concerned about the lack
locations, conditions and terrain types and
that is, trends in climate warming regionally
Warming of the global and regional climate
during the life of the project. The Taglu airstrip
could also be subject to flooding, but in that
event workers and equipment would be
brought to the site by helicopter. The companies
provided evidence that the facilities would be
high enough to protect them from storm surges
and flooding even if sea levels were to rise.
be provided to other appropriate regulators
in sufficient time for review and to provide
input to the National Energy Board.
have been incorporated into the modeling.
Figure 4-10
Indian and Northern Affairs Canada suggested
Design height for top of Taglu well pad and facility foundations
in final argument that the Proponents should
demonstrate how upper limit temperature
scenarios have been considered in their design.
Conceptual top of pad (estimated at 3.1m above grade)
0.7m
0.2m safety factor + 0.1m sea level change + 0.4m extraction induced subsidence
0.8m
Maximum wave
Estimated maximum flood level
Further specific discussion on climate
change regarding project design is found
Gravel
in Chapter 6.
1.6m
0.9m
Mean sea level (2003)
Tundra
Note: Preliminary design. Dimensions shown might be adjusted as design is developed.
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74 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
Air quality issues
can be local to regional in the case of
We are satisfied with Imperial’s climate
Air quality in the North is considered to be of
particulate matter and sulphur dioxide,
change rates used in the design. Given
high quality and Northerners are very concerned
or global in the case of greenhouse gases.
the uncertainty regarding climate change
that it remains that way. Both Environment
Emissions would occur during the construction
predictions and the vintage of any climate
Canada and the Proponents agreed that existing
phase through intermittent flaring during well
change studies or data used by Imperial,
air quality in the proposed project area is good
testing at the Taglu field.
a prudent step would be to assess the
and, along with other government regulators,
design using upper limit temperature
emphasized the need to “keep clean areas
scenarios as suggested by the Joint Review
clean.” This principle requires new industrial
Panel. As the name implies, upper limit
development to be “planned, constructed
temperature scenarios would be less likely
and operated in a manner that minimizes
to occur than what has been used by
the degradation of air quality in these areas.”
Imperial for the design of the project.
Air quality issues for the project included project
Condition T7 requires Imperial to provide
emissions for the pipeline and development
final detailed design information that
fields, monitoring, and greenhouse gases in
incorporates an analysis fo the impacts of
the context of monitoring climate change.
climate change and variability on
The Joint Review Panel noted that the National
permafrost and terrain stability for the
Energy Board would be the prime regulator
Taglu facility using potential upper limit
of air emissions from the project and that
temperature scenarios which may occur
Environment Canada and the Government of
during the operational life of the facilities.
the Northwest Territories would play advisory
Imperial will also provide information about
roles. The Joint Review Panel recognized
how upper limit temperature scenarios may
the National Energy Board’s expertise and
impact precipitation, rise in sea level, storm
experience in regulating interprovincial aspects
surges, ice floes and flood levels. We are of
of the oil, gas and electric utility industries,
the view that government departments such
as Environment Canada, Indian and
Northern Affairs Canada and Natural
Resources Canada should be consulted to
benefit from their expertise for the field
design.
including environmental matters. The Joint
Review Panel also recognized the extensive
environmental and local knowledge that
Environment Canada and the Government
of the Northwest Territories can provide.
Further specific details pertaining to emissions
for the pipeline are discussed in Chapter 3 and
discussion on air emissions pertaining to facility
design is found in Chapter 6.
The Joint Review Panel report indicated that the
Proponents’ baseline information was compiled
from historical data and results of air quality
monitoring that was carried out over one year
near the communities of Inuvik and Norman
Wells, and periodically at the Parsons Lake
and Taglu gas fields. The Proponents’
monitoring data and other sources indicated
that background concentrations of air
contaminants are generally below detection
levels or applicable guidelines. The one
exception that is not below detection levels
is ozone; relatively high background levels
were monitored in Inuvik and Norman Wells.
The Proponents indicated that elevated
ozone levels at high latitudes in the northern
hemisphere are thought to result from the
intrusion of stratospheric ozone. The Proponents
stated that all ground-level concentrations
of compounds released by the project during
Air emissions can be related to the project-
operations at the gas fields, the Inuvik Area
specific effects of construction, operations,
Facility, and compressor and heater station
and waste incineration. Air quality impacts
sites would increase, but would be below those
outlined in applicable federal and territorial
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Chapter 4: Development fields 75
guidelines at all locations in the production
through normal venting procedures and
addressed air issues through several
area and along the pipeline corridor.
minor leaks (fugitive emissions). Further
conditions for the Mackenzie Gas Project.
specific discussion on air emissions pertaining
These conditions are focused on the
to facility design is found in Chapter 6.
Proponents taking appropriate measures
Environment Canada recommended that
the Proponents design and implement
suitable air quality monitoring programs
Alternatives North submitted that the National
with its help. Environment Canada focused
Energy Board and the Government of Canada
its recommendations on pollution prevention
have a public interest mandate that requires
and the use of best available technology
consideration of greenhouse gas emissions.
and best management practices to minimize
the degradation of air quality. Further discussion
around application of these principles may
be found in Chapter 6.
collaboratively with Environment Canada
and the Government of the Northwest
Territories to protect air quality in
the North, recognizing the extensive
standards for greenhouse gas emissions based
environmental and local knowledge
on a robust and strong definition of best
that these agencies can provide.
available technology and accompanied by
penalties in the cases where they do not meet
that the project needs to be designed to
those project standards or targets, would
minimize air quality impacts, with monitoring
provide the best possible protection in terms
plans in place to verify the predicted emissions
of minimizing upstream greenhouse gas
and impacts. Corrective action needs to
emissions associated with the project.
land and wildlife from degraded air quality.
air quality. We are committed to working
Ecology North deemed that high project-specific
The Dehcho Elders and Harvesters indicated
be taken quickly to avoid impacts upon the
to minimize air emissions and address
Conditions T13 and T15 address
technologies for reducing emissions,
incorporation of best management
practices and best available technologies,
and facility design. Condition T14 requires
the submission of a report evaluating
Sierra Club of Canada submitted that we need
incinerator emissions from camps and
to specify an actual target and it is not enough
station facilities and technologies and
Greenhouse gas emissions
to just leave it up to the Proponents. Sierra Club
practices must be reflected in the waste
Parties were concerned about the impacts
of Canada indicated that the target should at
management plans required by Condition
of the project on climate change, especially
least match the general recommended target
T11. Condition T16 requires Imperial
in light of Canada’s international efforts under
in Joint Review Panel recommendation 8-8.
to minimize and reduce emissions from
the United Nations Framework Convention
flaring. Further specific discussion for
on Climate Change and the Kyoto Protocol.
Views of the Board
Greenhouse gas emissions arising from
We understand the importance of clean
the project include carbon dioxide, methane
air in the North and that air quality must be
and nitrous oxides with each compound
considered in a cumulative manner. We also
Air quality monitoring is part of
having a different climate change potential.
recognize the need to minimize greenhouse
comprehensive environmental monitoring
During operation, the project would emit
gas emissions resulting from the project.
under an environmental management
greenhouse gases from burning natural
The Joint Review Panel directed several
system. Through environmental
gas at combustion related sources such
recommendations to us relating to air
management, systems are established
as compressors and methane gas released
quality and air emissions. We have
to address effects of the project on
1249_NEB_MGP_Vol2_Text_ENG.indd 75
these conditions regarding air emissions
pertaining to facility design is found
in Chapter 6.
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76 Mackenzie Gas Project • Volume 2: Implementing the decision
the environment and of the environment
•• include methods for developing measures
We generally require the filing of
on the project, with the overall goal of
to prevent or mitigate the impact of
environmental post-construction
minimizing negative impacts. Adaptive
the identified issues;
monitoring reports as a condition of
management is a systematic process for
•• provide for continued monitoring of
an authorization. The information in
continually improving management
sites to evaluate success of mitigative
monitoring reports should include:
practices by learning from their outcomes.
measures undertaken;
•• confirmation of proper implementation
Environmental monitoring is an important
•• provide a system for implementing
part of environmental management that
additional mitigative measures as
directly supports adaptive management by
necessary; and
observing and evaluating the effects that
•• provide a feedback system that allows
occur, then changing or adding mitigative
for adaptation of successful mitigation
measures as appropriate to limit or reverse
to future pipeline projects.
the environmental effects. Environmental
monitoring can include:
•• compliance monitoring, to verify
that all environmental mitigation
is implemented as presented in the
Environmental Protection Plan and
environmental alignment sheets
and that work is in compliance with
environmental regulations; and
•• effects monitoring, to assess
Monitoring programs may have specific
goals and targets and could include
methods for evaluating and interpreting
collected data such as air quality or
emissions data. Monitoring may include
Environmental Protection and Monitoring
and Surveillance Programs which include
protection of the environment as one of
how outstanding issues will be resolved.
Condition T10 requires Imperial to
submit an Environmental Protection Plan
which includes monitoring of activities.
Condition T14 includes the requirement
for monitoring incinerator emissions.
improvement, outlined in Joint Review
quality sampling, waste disposal).
Panel recommendation in 8-6, is expected
Responsibilities of the National Energy
•• conducting environmental inspections
Imperial is expected to implement
environmental issues; and
•• discussion of the company’s plans for
(e.g., vegetation establishment, water
environment interactions and
This is further discussed in section 3.3.6.
•• identification of the outstanding
A commitment to continuous
Board regarding monitoring include:
approved mitigation measures.
measures used;
any relevant environmental practices
the effects resulting from projectevaluate the effectiveness of
of mitigation and reclamation
to be a component of an operator’s
Management system pursuant to
paragraph 5(2)(b) of the Canada Oil and
Gas Drilling and Production Regulations.
of facilities, verifying compliance with
This is addressed in Condition T10.
terms and conditions, and assessing
We are of the view that the commitment
the effectiveness of mitigation;
to continuous improvement is not limited
•• monitoring ongoing operation, verifying
to greenhouse gas emissions but should
reclamation and maintenance of the
apply to all discharges to the environment,
project site to acceptable standards; and
which in this case is the atmosphere.
•• conducting environmental audits,
the main goals. A monitoring program may:
evaluating environmental management
•• identify any issues or potential concerns
systems and environmental programs.
Condition T10 also covers the requirements
for methods and locations of monitoring.
that may compromise the protection
of the environment;
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Chapter 4: Development fields 77
Condition T15 requires the Proponents
Environmental footprint
The Imperial project management team will
to file a report outlining the use of best
in Kendall Island Bird Sanctuary
continue to look for opportunities to further
available technology for station facility
The proposed site of the Taglu development
reduce the footprint of the Taglu development
construction. Selection of best available
is located near the meeting of the Kuluarpak
in Kendall Island Bird Sanctuary. For example,
technology is the most significant factor
and Harry channels of the Mackenzie River,
Imperial will look at the use of existing disturbed
in determining achievable air emissions
and it lies within Kendall Island Bird Sanctuary.
space adjacent to the development site,
targets. Condition T10 outlines the
As discussed previously, Environment Canada
being the D‑43 well site pad and connecting
requirements for an Environmental
has regulatory authority over the surface
road. The project’s engineering team is also
Protection Plan. The condition requires
of the Sanctuary and has determined that
investigating the merits of using a wet gas
the Proponents to submit maximum
the maximum allowable surface disturbance
metering system instead of the test separator
proposed greenhouse gas targets and
related to all oil and gas activities within Kendall
system in an effort to reduce footprint. The
reduction strategies for air emissions
Island Bird Sanctuary should be no more than
project will also consider tankage requirements
including particulate matter, NOx and
one percent of the Sanctuary or 600 hectares.
for fuel needs, as there may be opportunities
greenhouse gases. Condition T10 also
Environment Canada expressed concern with
for offsite staging, as well as the fabrication
addresses other matters from the Joint
not only the size of the area being disturbed but
and construction of the gas conditioning
Review Panel recommendations including
also with Imperial’s plan for continuous drilling
facilities modules. Imperial hopes that by
employee training, monitoring, public
and year-round activity. The estimated total
implementing options such as these, the Taglu
communication, and required consultation
area of surface disturbance is approximately
footprint could be reduced by approximately
with Environment Canada and the
30 hectares, representing 0.05 percent of all
10 percent of the current footprint estimate.
Government of the Northwest Territories.
of Kendall Island Bird Sanctuary. All production
With these conditions, we find it acceptable
wells would be drilled from the same well
for the Proponents to develop greenhouse
pad using directional drilling techniques.
gas targets for the project consistent
This helps to reduce the overall footprint
with use of best management practices
of the development. The well pad is likely
and in consultation with appropriate
to be located just inside the eastern boundary
government agencies.
of Kendall Island Bird Sanctuary, just west
Activity and facility noise levels
The Taglu anchor field is located in Kendall
Island Bird Sanctuary which is a federally
protected area managed for the conservation
of migratory birds and protection of habitat
for northern-breeding birds. Imperial holds
of the existing D-43 well site (see Figure 4-9).
Significant Discovery Licence SDL063 that grants
The initial drilling program would occur
it subsurface oil and gas rights. Environment
uninterrupted for about 16 months, with
Canada has regulatory authority for activities
well completions to follow. Imperial is proposing
within Kendall Island Bird Sanctuary, and
a development plan which is flexible enough
may issue permit conditions governing
to accommodate contingencies that could
noise emissions from development under
arise during detailed design, construction
the Migratory Bird Sanctuary Regulations.
and operation of the Taglu field.
Environment Canada and Imperial have both
agreed to follow Alberta’s Energy Resources
Conservation Board Directive 038 for noise
1249_NEB_MGP_Vol2_Text_ENG.indd 77
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78 Mackenzie Gas Project • Volume 2: Implementing the decision
regulation. This provides a solid basis for noise
those required to meet Alberta’s Energy
Imperial indicated it is committed to adhering,
regulation that currently does not exist in
Resources Conservation Board Directive 38
at a minimum, to Alberta’s Energy Resources
the Northwest Territories, in other words, there
minimum standards provided that such options
Conservation Board Directive 038. Imperial
is currently no legislation or standard in the
are practical. Environment Canada is awaiting
recognized that operating facilities in Kendall
Northwest Territories governing noise emissions.
detailed engineering and noise modeling results
Island Bird Sanctuary requires additional
from Imperial.
consideration, and Imperial is committed
Alberta’s Energy Resources Conservation Board
to continuing evaluations of noise mitigation
Directive 038 indicates a recommended noise
Environment Canada has concerns with the level
target for remote areas even if no human
of noise associated with Imperial’s Taglu well
residences are present. This is considered
drilling operations while birds are present.
the “business as usual” requirement. The
to address concerns raised by Environment
Unlike Niglintgak, Imperial plans to drill
Directive has provisions to change the typical
Canada. As indicated in previous submissions,
in Taglu for 16 months starting in the winter
target when there are unique circumstances,
Imperial is committed to working with
of 2016 followed by year-round oil and gas
Environment Canada in reducing noise levels
including if an area is “pristine”—a pure, natural
activities. However, May to October is the
of production facilities in Kendall Island
area that might have dwellings but no industrial
time when birds are typically present in Kendall
Bird Sanctuary, and Imperial will endeavour
presence. Environment Canada is recommending
Island Bird Sanctuary and therefore sensitive
to reduce noise emissions beyond the
continuous noise emissions, as measured from
to disturbance. As a result, Environment Canada
requirements of Directive 038 where
the fence line of the facility, not exceed the
may restrict activity or access within Kendall
technically and economically possible.
Alberta’s Energy Resources Conservation Board
Island Bird Sanctuary during this period to
Directive 038 “best practices” permissible
protect bird habitat.
sound levels during the period from 10 May to
planning, in order to arrive at practical solutions
In final argument both the Proponents and
Environment Canada shared the view that
30 September when migratory birds are present
Imperial indicated that this would not meet
requirements for noise regulation in Kendall
in the Sanctuary because Kendall Island Bird
its need to service and access personnel
Island Bird Sanctuary, both for the National
Sanctuary is considered a pristine area.
year-round for drilling, construction and
Energy Board and migratory bird sanctuary
operational activity. On a related matter,
requirements, can only be finalized after detailed
Imperial stated it would consider scheduling
engineering and design work is completed, after
planned maintenance flaring outside
the noise impact analysis is prepared, and after
Imperial intends to design all equipment
at the Taglu gas conditioning facility so that
the resulting sound levels would be below
the maximum permissible noise levels provided
1249_NEB_MGP_Vol2_Text_ENG.indd 78
options through detailed engineering and
the migratory birds nesting season.
discussions between the parties. Environment
Canada will continue to work with the National
in Alberta’s Energy Resources Conservation
When we asked how operations would be
Energy Board, Proponents and other regulators
Board Directive 038. This would include primary
affected if drilling was restricted from May
on issues related to noise in Kendall Island
sources of noise generation such compressors,
to October, Imperial indicated it would have
Bird Sanctuary. Imperial indicated during final
power generation equipment and aerial
to reassess the entire design and execution plan
argument it is committed to adhering to
coolers. Environment Canada has also indicated
associated with the development. Environment
requirements in Alberta’s Energy Resources
that Imperial has committed to evaluating
Canada is continuing to have discussions
Conservation Board Directive 038, as well
and applying noise mitigation options beyond
with Imperial on this matter.
as continuing evaluation of noise mitigation
12/6/10 11:02:08 AM
Chapter 4: Development fields 79
through detailed engineering and planning
Overall footprint
approximately 50 kilometres south of
in order to arrive at practical solutions to
Many of the proposed facilities for the Taglu
the proposed Taglu site (see Figure 4-1).
concerns raised by Environment Canada.
field, such as the well pad, gas conditioning
facility, flow lines and air strip would be
Views of the Board
We agree with Environment Canada that
regulating impacts of noise in a nationally
protected bird sanctuary requires special
located inside the east boundary of Kendall
Island Bird Sanctuary. The total area of
permanent surface disturbance would be
approximately 30 hectares.
Imperial intends to build its facilities offsite,
in large modules, and ship them to Taglu
for assembly. Based on consultations with
area stakeholders, Imperial has identified
an opportunity to increase the size of offsite
fabricated modules, if the modules can be
consideration and application of best
During the project design phase, Imperial
successfully transported and installed at
practices and the use of best available
incorporated measures to reduce the overall
the site. Based on the construction execution
technology with the intent of “continuous
footprint for the proposed Taglu development by:
plan descriptions, the concept would reduce:
improvement of pipeline safety and
• locating a single well pad near the centre
• the footprint at Taglu within Kendall Island
environmental protection.” Condition T8
of the reservoir and using directional drilling
applies to regulating noise in the Taglu
techniques to drill all of the proposed wells
field and is intended to minimize
from one common well pad. This pad
disturbance from facilities inside Kendall
would be approximately 70 metres wide
Island Bird Sanctuary. The condition requires
by 300 metres in length with 15 metres
meeting the Alberta’s Energy Resources
of road access on both sides and would
Conservation Board Directive 038 “business
cause 100 metres of disturbance;
as usual” standard with allowance for
• locating the gas conditioning facility
achieving the more stringent standard that
adjacent to the well pad to eliminate
Environment Canada recommended to the
the need for a network of connecting roads;
Joint Review Panel, and the Joint Review
• accessing the site with river barges in the
Bird Sanctuary;
• some air traffic support at the site within
Kendall Island Bird Sanctuary; and
• barge traffic on the Mackenzie River.
Imperial also indicated that it considered building
a barge-based gas conditioning facility, like the
one planned for the Niglintgak field; however,
this did not reduce the overall footprint.
The proposed location of the Taglu airstrip
within Kendall Island Bird Sanctuary was a
Panel accepted. There is flexibility built in
summer and by winter road without adding
concern for Environment Canada, as it will
to adjust the standard as informed by final
a substantial number of additional access
occupy approximately seven or eight hectares.
engineering, an independently verified
noise impact analysis document, and final
determination of the fence line, which is
the measurement base for a distance-based
roads through Kendall Island Bird Sanctuary;
• locating the well pad and gas conditioning
facility on already disturbed land;
• using storage areas outside of Kendall Island
regulatory standard.
Bird Sanctuary for some tankage
We acknowledge the parallel permitting
requirements; and
process for Kendall Island Bird Sanctuary
• using staging areas outside of Kendall
Drilling waste in Taglu can be separated into
solids (drill cuttings) and liquids (reserve pit
fluids). Typically, these wastes are disposed
of in a sump. However, sumps are not
permitted in Kendall Island Bird Sanctuary.
Imperial plans to initially inject both solids
and support the need for consistency
Island Bird Sanctuary, such as Tununuk Point
and liquids into a dedicated disposal well
and clarity between Environment Canada
(Bar C) for drilling materials. Tununuk Point
and then, as drilling progresses, into the
and National Energy Board conditions.
is a previously disturbed lease area located
annuli of a previously drilled production well
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80 Mackenzie Gas Project • Volume 2: Implementing the decision
(see Figure 4-11). With this approach, Imperial
Imperial’s alternative method for the disposal
undisturbed terrestrial habitat within Kendall
would use the dedicated disposal well as
of drill cuttings would be to inject the reserve
Island Bird Sanctuary. Environment Canada
a backup if there are any issues with the
pit fluids into the well annuli and incinerate
requested that we require that Imperial’s plan
production well annuli. In addition, Imperial
the drill cuttings. The residual material from
for dredging the barge landing at the Taglu field
would have a temporary onsite storage area
incineration would be hauled to an approved
should describe the potential impacts associated
for drill cuttings in case of any equipment or
disposal facility.
with dredging, including spoil management and
disposal problems with either the production
well annuli or the dedicated disposal well.
The solids, or drill cuttings, represent about
20 percent of the total volume to be disposed of
in the wells. Before the solids can be injected
Insofar as air traffic operations are concerned,
as the Joint Review Panel noted:
Environment Canada and the Proponents
the success of the consultations between
assessed alternative means of accessing
the Proponents and Environment Canada.
the Taglu site and agreed that the
proposed Taglu airstrip would pose the
create a slurry. Injection of the cuttings is
least adverse effects.
injection pressure and fluid properties would be
monitored to verify that the reservoir is behaving
as predicted and unexpected fractures are not
Views of the Board
We accept Imperial’s conceptual plan to
planned as discrete “batch injection operations”
drilling programs. During injection operations,
to address adverse impacts. As discussed earlier,
this is a condition that should also refer to
into a well, they would be mixed with water to
for limited volume and discretely scheduled
the site-specific mitigation measures proposed
The Joint Review Panel similarly agreed that the
dispose drill cuttings by subsurface slurry
proposed airstrip was the best option. Imperial
injection as this avoids the use of sumps
will continue to consult with Environment
and would minimize the environmental
Canada in relation to the details of its proposed
footprint within Kendall Island Bird
air operations at Taglu.
Sanctuary. However, as down-hole slurry
occurring. Subsurface slurry injection of the scale
Dredging activities will occur within Kendall
and extent proposed by Imperial has not been
Island Bird Sanctuary and Environment Canada
practiced before in the Northwest Territories.
will not permit the spoil to be placed on
injection of this scale and extent has not
been utilized in the Mackenzie Delta
before, Condition T4 requires Imperial
to submit a drill cuttings slurry injection
management program. The National Energy
Board would assess such a program with
respect to subsurface containment as well
as safety, protection of the environment
Figure 4-11
Injection into a dedicated disposal well
Annular injection
Drilling waste disposal
Injection
through
annulus
Deep casing
the condition has been amended to require
a dredging spoil management plan and
Packer
Perforated
casing
Cement
regarding Condition T9 for dredging and
Tubing
Casing shoe
1249_NEB_MGP_Vol2_Text_ENG.indd 80
We have considered the various comments
Deep casing
Shallow casing
and conservation of resources.
to clarify requirements for consultation
with Environment Canada, Department of
Fisheries and Oceans, Indian and Northern
Affairs Canada and Transport Canada.
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Chapter 4: Development fields 81
4.4 Parsons Lake
The Parsons Lake field borders the Mackenzie
Delta to the east and is located 70 kilometres
north of Inuvik and 55 kilometres southwest
of Tuktoyaktuk on the Tuktoyaktuk Peninsula.
Unlike the neighbouring Niglintgak and Taglu
fields to the northwest, the Parsons Lake field
is not located within the Mackenzie Delta
or Kendall Island Bird Sanctuary.
ConocoPhillips Canada (North) Limited
The capital expenditures for development
(ConocoPhillips) has requested approval of a
of the Parsons Lake field are estimated to
Development Plan application for the Parsons
be $1,550 million with an estimated average
Lake field pursuant to section 5.1 of the Canada
operations and maintenance expenditure
Oil and Gas Operations Act. ConocoPhillips
of $25 million per year for the period 2019
and ExxonMobil Canada Properties (ExxonMobil)
to 2023.
propose to develop natural gas and natural
gas liquids from Parsons Lake and ship these
hydrocarbons with those from the Taglu and
Niglintgak fields via the Mackenzie Gathering
System to the Inuvik Area Facility.
The Parson’s Lake development (see Figure 4-12)
would include:
• construction of a north pad with nine to
nineteen production wells, two disposal wells,
and a gas conditioning facility;
Figure 4-12
Parsons Lake
production facilities
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82 Mackenzie Gas Project • Volume 2: Implementing the decision
• a south pad with three to seven production
wells;
• construction and operation of flow lines
from the south pad to the north pad; and
• supporting infrastructure, including an
all-weather airstrip.
and a 2.5 kilometre long all-weather road
Therefore, ConocoPhillips has identified three
connecting the airstrip to the main road.
possible sites for contingent satellite well
pads, each accommodating up to three wells.
Wells and well pads
Proposed phase one development would
include constructing well site facilities
at the north and south pads and up to three
ConocoPhillips would develop the contingent
wells if drilling and production operations
identify and locate faults that compartmentalize
the reservoir.
Construction is planned to take place from
contingent satellite well pads. The north pad
2014 to 2018 with production operations
would initially house up to nine production
ConocoPhillips’ Development Plan provides
commencing in 2018 and expected to continue
wells, one waste disposal well and one cuttings
preliminary bottomhole locations for nine
for 25 or 30 years.
injection well, with the possibility of up to ten
production wells, two contingent wells, one
contingent production wells.
cuttings injection well and one waste disposal
4.4.1 Design of the Parsons Lake facilities
well located on the north pad and for three
ConocoPhillips plans to transport and stage
Phase two, preliminary plans for 2024, includes
production wells and one contingent well from
construction equipment during the summer of
drilling three production wells and as many
the south pad (see Figure 4-13). All would be
2014 for winter activities. An overview of the
as four contingent production wells from
directionally drilled except for the cuttings
construction schedule is shown in Table 4-4.
the south pad.
injection well which would likely be a vertical
ConocoPhillips estimates 28 hectares would
ConocoPhillips believes that it may not be
be required for the development, including
able to reach parts of the Parsons Lake field
the north and south well pads, the airstrip,
by drilling only from the north or south pads.
well. The preliminary total vertical and measured
depth of these wells range from 1000 to
3150 metres and from 1000 to 4734 metres,
respectively. ConocoPhillips also provided
a commingled production strategy for Parsons
Lake in order to effectively and economically
deplete reservoir compartments.
1249_NEB_MGP_Vol2_Text_ENG.indd 82
Table 4-4
The north pad would be built on granular
Parsons Lake construction highlights schedule
material about 1.5 metres thick. The south
Activity
Season and year
Transport and stage construction equipment to delta staging location
Summer 2014
Begin construction of winter access road, begin development of borrow sites,
transport material to the north pad, all-weather access road and airstrip
Winter 2014/15
Construct and complete commissioning of airstrip
Summer 2016
Construct winter access road for heavy module transport, transport very large modules
and begin installing very large modules as part of the gas conditioning facility
Winter 2016/17
Commence drilling program at north pad
Winter 2016/17
Complete north pad drilling and testing program
Winter 2018/19
Start up the gas conditioning facility
Winter 2018
South pad drilling program, construction of the flow line from the south pad to
the north pad
Beyond 2019
pad and contingent satellite wells pads would
be built on ice pads and with only a small area
of granular material around the wellhead.
All well pads would include individual wellbores,
wellheads and wellhouses. Thermosiphons
would be installed to maintain the permafrost
below the pads.
12/6/10 11:02:09 AM
Chapter 4: Development fields 83
Flow lines
The gas dehydration unit is designed to
through the gathering system would be added
Once the natural gas and natural gas liquids
reduce the moisture content of the sales gas
in stages as the wellhead pressure declines.
have been extracted, they would flow through
to 6 mg/m and to neutralize any potential
above-ground flow lines from the wells to
for corrosion caused by the carbon dioxide in
the gas conditioning facility on the north pad.
the gas stream. ConocoPhillips’ design also
The 16 kilometre long flow line from the south
incorporates a relief and blowdown system,
to Tuktoyaktuk, and transported via winter road
pad would rest on piled metal supports at least
including flare stacks, to handle any emergency
to Parsons Lake. Once the modules were onsite,
2.2 metres above the ground, and run parallel
relief and flaring at the north and south pads.
they would be placed on steel piles and elevated
to the Parsons Lake lateral of the Mackenzie
Equipment to compress the gas so it would flow
about one to two metres above the gravel
3
Project facilities would be built from very large
modules constructed offsite, shipped by barge
Gathering System. Hydrocarbons from the
south pad would be metered and heated
before traveling to the north pad. The flow
Figure 4-13
lines would be insulated to keep temperatures
Parsons Lake field map
inside the flow lines between 30°C and 50°C.
This would help prevent the natural gas,
natural gas liquids and any produced water
from freezing and plugging the lines.
Production from any satellite well pads
Parsons Lake north pad and
gas conditioning facility
would be transported in insulated above-ground
I-11
D-21 E-11
D-20 M-20
N-10
F-30
J-19
L-09
K-29
B-19
M-58
O-28
flow lines to the north pad and the gas
conditioning facility.
Gas conditioning facility
The gas conditioning facility would be able
Parsons Lake
to handle a maximum volume of 9.0 Mm3/d
(324 MMcf/d). It would process the reservoir
fluids to meet the specifications of the gathering
E-54
system and would include components to:
J-44
E-43
• separate gas from free water and
hydrocarbon liquids (natural gas liquids);
P-41
South pad future
facility site
• compress and dehydrate the gas;
• chill and meter the hydrocarbons before
they enter the gathering system; and
• collect any water and send it to
Proposed or alternative airstrip
Gathering pipelines route
a disposal well.
Storm Hills
Pigging facility
Significant discovery licence area
10
5
0
10
Kilometres
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84 Mackenzie Gas Project • Volume 2: Implementing the decision
surface. Buildings installed on the gravel
would have lower concentrations of carbon
Views of the Board
pad would have insulated foundations,
dioxide. Blending would allow ConocoPhillips
We are of the view that the general
and thermosiphons.
to meet the Inuvik Area Facility’s carbon dioxide
approach and the conceptual design and
content specification.
plan outlined by ConocoPhillips for the
ConocoPhillips considered a number of
Winter transportation
Parsons Lake field are reasonable. We note
alternative configurations for production such
ConocoPhillips plans to move the seven
that ConocoPhillips will use new geological
as locating the main gas conditioning facility at
pre-assembled gas conditioning facility very
and reservoir data acquired from drilling
the south pad, housing only a minimal satellite
large modules from Tuktoyaktuk to Parsons
and production to determine if additional
facility on the north pad and using a flow line
Lake on a purpose-built heavy load ice road
faulting and compartmentalization exists
to transport gas from the north pad to the
the winter before commercial gas production
and whether any contingent wells would
south pad. However, this alternative would
begins. The proposed ice road would be
be required. In this regard, Condition P17
require a larger flow line than the current
specially prepared with a smooth ice surface
requests ConocoPhillips submit an updated
proposal and would be costlier.
and designed to accommodate the heavy-lift
resource management plan with the
trailers carrying the oversized and heavy gas
National Energy Board within 18 months
conditioning facility modules. Because of the
after production commences or prior
by ConocoPhillips was to construct gas
load’s size and weight, the road would need
to the drilling of contingent wells.
conditioning facilities at both north and
to about 20 metres wide with a 50 metre right
south pads. This would be costlier and
Condition P5 requires ConocoPhillips
of way, have a three percent gradient, contain
the north pad gas conditioning facility
to provide adequate gas sampling and
no tight curves and avoid frozen bodies of
would not be fully utilized.
analyses during drilling and production
water. The wide ice road would be completed
operations as the Parsons Lake field is
Because the Parsons Lake north pool contains
late in the season and likely used for six to
expected to have three to five percent
eight weeks. However, a shortened winter
carbon dioxide gas content.
Alternative production system
Another alternative configuration evaluated
about three percent carbon dioxide and the
south pool about five percent carbon dioxide,
ConocoPhillips evaluated whether removal
facilities for carbon dioxide would be required.
Four different options for removing carbon
1249_NEB_MGP_Vol2_Text_ENG.indd 84
season would mean significant delays to the
construction of the gas conditioning facility
We accept ConocoPhillips’ conceptual
if the ice road could not be used to transport
commingled production strategy to
all seven modules.
effectively deplete reservoir compartments.
The National Energy Board will consider
dioxide were studied, and costs for these
Furthermore, ConocoPhillips is proposing to
commingled production on an individual
options ranged from $80 to $100 million.
drill the south pool and satellite wells from ice
well basis during drilling and production
Rather than design the Parsons Lake facilities
pads. ConocoPhillips is aware that this drilling
operations in accordance with section 66
to extract the carbon dioxide, ConocoPhillips
schedule could be delayed by an unseasonably
of the Canada Oil and Gas Drilling and
chose to rely on blending the gas from Parsons
warm winter. If that happened, the wells would
Production Regulations.
Lake with gas from Niglintgak and Taglu that
not be drilled until the following winter.
12/6/10 11:02:11 AM
Chapter 4: Development fields 85
Condition P30 stipulates that the approval
of the Development Plan under for the
Parsons Lake field under subsection 5.1(4)
of the Canada Oil and Gas Operations Act is
subject to the Minister of Indian Affairs
and Northern Development Canada
providing confirmation that ConocoPhillips
has satisfactorily met the Benefits Plan
requirements of section 5.2 of the Canada
Oil and Gas Operations Act.
4.4.2 Development plan issues
During the hearing, the issues raised included:
• matters raised by adjacent rights holders;
• geographic and design issues related
to permafrost, climate change, subsidence
and flooding;
• air quality issues and greenhouse gas
emissions; and
• drill cuttings disposal.
Matters raised by adjacent rights holders
The National Energy Board issued a Declaration
of Commercial Discovery for the Parsons Lake
field on 16 September 2004 which included
lands held under Significant Discovery Licence
030, 032 and 062.
The Parsons Lake field is contained within
Significant Discovery Licences SDL030 and
SDL032. ConocoPhillips, the field operator,
holds 75 percent of the working interest
of these licences while ExxonMobil holds the
other 25 percent. Exploration Licence EL4068,
of which PetroCanada is the representative
interest holder, borders Significant Discovery
Licence SDL030 and SDL032 to the east and
south. Crown land lies to the north and west of
Significant Discovery Licence SDL032. Imperial9
is the registered interest holder and operator of
Significant Discovery Licence SDL062 located on
the northeast boundary with ConocoPhillips’
Significant Discovery Licence SDL032. Other
notable interest holders of Significant Discovery
Licence SDL062 include ExxonMobil Canada,
ConocoPhillips and Mosbacher. ExxonMobil
holds between four and eight percent interest
in the south, central and north segments
of Significant Discovery Licence SDL062.
ConocoPhillips holds approximately 1.2 percent
interest only in the central segment. Mosbacher
holds an average 3.1 percent interest in the
central and north segments (see Figure 4-14).
Mosbacher, which holds an interest in lands
adjacent to the Parsons Lake field, expressed
concern that the proposed development would
drain its gas resources. According to Mosbacher,
the Parsons Lake Development Plan should not
be approved because ConocoPhillips has failed
to present plans that would respect the rightful
economic interest of holders of adjacent lands.
Mosbacher indicated that, although its estimate
for gas-in-place for Significant Discovery Licence
SDL062 is small compared to the gas-in-place
for Significant Discovery Licences SDL030
and SDL032, it believes that approximately
5.4 percent of the total Parsons Lake original
gas-in-place lies under Significant Discovery
Licence SDL062. According to Mosbacher, the
volumes under Significant Discovery Licence
SDL062 are commercially producible. Mosbacher
stated that the one grid unit buffer offered by
ConocoPhillips would not adequately protect its
resource from being drained by ConocoPhillips’
operations on Significant Discovery Licences
SDL030 and SDL032. Without a unitization
agreement it is likely that the gas resource on
Significant Discovery Licence SDL062 would be
lost to the owners of Significant Discovery
[8] Exploration Licence EL406 was surrendered in 2007.
Licences SDL030 and SDL032.
[9] In Exhibit MOL-3I, Imperial Oil Resources Limited,
Imperial Oil Resources Ventures Limited and Imperial
appear to have been used interchangeably.
1249_NEB_MGP_Vol2_Text_ENG.indd 85
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86 Mackenzie Gas Project • Volume 2: Implementing the decision
133º45’
Figure 4-14
Commercial discovery
declaration area and
Mosbacher indicated that it sought cooperative
133º30’
negotiation between the parties. Since its efforts
28
18
8
58
48
38
28
18
8
58
48
38
28
27
17
7
57
47
37
27
17
7
57
47
37
27
26
16
6
56
46
36
26
16
6
56
46
36
26
in this regard were not successful, Mosbacher
asked us to direct ConocoPhillips to make
significant discovery
licences for Parsons Lake
field as of 2006
25
15
5
Crown land
55
45
35
25
15
5
Imperial et al
SDL-062
55
45
a comprehensive and compelling case that
resources from adjacent lands will not be
drained. Mosbacher stated that Imperial,
35
25
the operator of Significant Discovery Licence
SDL062, considered drilling a well, constructing
24
14
4
54
44
34
24
14
4
54
44
34
24
23
13
3
53
43
33
23
13
3
53
43
33
23
22
12
2
52
42
32
22
12
2
52
42
32
22
facilities and tying into the proposed Parsons
Lake development, but the stand-alone drilling
21
11
1
51
41
31
21
11
1
51
69º00’
30
20
10
60
50
40
30
20
10
60
project was not sufficiently robust to meet its
internal hurdle rates. Mosbacher stated it then
Petro-Canada
et al
41
31
21
EL-406
circulated an alternative cost-effective drilling
50
Licence SDL062. The scenario proposes a single
40
30
scenario based on the cooperative use of the
north pad by all partners of Significant Discovery
well with a horizontal reach10 of approximately
29
19
9
59
49
39
29
19
28
18
8
58
48
38
28
18
8
58
27
17
7
57
47
37
27
17
7
57
47
37
27
26
16
6
56
46
36
26
16
6
56
46
36
26
25
15
5
55
45
35
25
15
5
55
45
35
25
24
14
4
54
44
34
24
14
4
54
44
34
24
23
13
3
53
43
33
23
13
3
53
43
33
23
22
12
2
52
42
32
22
12
2
52
42
32
22
21
11
1
51
41
31
21
11
1
51
41
31
21
30
20
10
60
50
40
30
20
10
60
50
40
30
29
19
9
59
49
39
29
19
9
59
59
39
29
ConocoPhillips et al
SDL-032
9
59
59
39
ConocoPhillips
et al
48
38
SDL-030
29
7500 metres from the north pad into section 54
of Significant Discovery Licence SDL062 which
28
may be approaching the current theoretical
technical limit for the reservoir.
ConocoPhillips stated that Mosbacher has never
been prevented from doing work and drilling
wells like ConocoPhillips has done. No well has
been drilled in Significant Discovery Licence
SDL062 and ConocoPhillips believes there is a
great deal of uncertainty as to what resources
are included in Significant Discovery Licence
SDL062. ConocoPhillips stated that serious
Crown land
and meaningful discussions on unitization
cannot occur without a well. The gas
68º55’
SDL-032
1249_NEB_MGP_Vol2_Text_ENG.indd 86
SDL-030
SDL-062
EL-406
CDD Outline
[10] Mosbacher stated in the hearing that the
length of the drill was “7500 m reach measured depth
distance.” Measured depth is not horizontal reach,
but has been taken to mean horizontal reach because
the distance between the north pad and section 54
is approximately 7500 metres.
12/6/10 11:02:11 AM
Chapter 4: Development fields 87
conditioning facility is designed to process
Mosbacher submitted during final argument
Views of the Board
only the gas produced from the Parsons Lake
that the proposed Parsons Lake Development
We consider joint development of the
field and offers no spare capacity. Currently,
Plan was sub-optimal insofar as it does not
Parsons Lake field to be the desired
ConocoPhillips has no plans to expand the
address development of the whole field, and it
approach if the interest holders of
gas conditioning facility; however, the gas
encourages waste. In this regard, Mosbacher
Significant Discovery Licence SDL062 agree
conditioning facility could be upgraded to
referenced sections 18 and 19 of the Canada Oil
to develop their lands. This would avoid
accommodate third-party gas if the volume,
and Gas Operations Act. In the event there is no
duplication of facilities and would minimize
delivery conditions and gas composition were
joint development, Mosbacher requested that
the environmental footprint. It is also our
known before detailed engineering plans are
we reject ConocoPhillips’ applied-for spacing.
view that joint development should be
finalized. Upgrading would require expansion
Mosbacher asked us to consider a condition
attained voluntarily through commercial
of the pad size. In addition, ConocoPhillips
requiring ConocoPhillips to include all land in
negotiations and agreements between
would consider allowing a third-party to drill
Significant Discovery Licence SDL062 within the
the interested parties. We note that
a well from the north well pad as this pad was
commercial discovery declaration area as part
the compulsory unitization provisions in
designed to accommodate more wells than
of the Parsons Lake Development Plan. Another
the Canada Oil and Gas Operations Act
ConocoPhillips plans to drill. If Mosbacher were
condition requested by Mosbacher would
require participation from ConocoPhillips
to drill a well into Significant Discovery Licence
require ConocoPhillips to fully explore joint
as it holds a large portion of the lands
062 from the north pad and the well was
production arrangements with other interested
comprising the Parsons Lake commercial
determined to be commercial, the gas
parties. In addition, Mosbacher suggested
discovery declaration area. ConocoPhillips
conditioning facility may have to be upgraded.
a condition requiring ConocoPhillips to make
stated that the first step that needs to be
available drilling pad space on reasonable
taken to begin meaningful talk on joint
commercial terms to allow Mosbacher and
development or unitization is Mosbacher
other interested parties the opportunity to drill
proving the extent of field by drilling
additional wells on a timely basis.
a well on Significant Discovery Licence
ConocoPhillips requested approval for a variance
to the National Energy Board’s 2009 Draft
Spacing Requirements for Significant Discovery
Licences SDL030 and SDL032 to allow the
appropriate placement of wells to increase
SDL062. Condition P2 requires both the
gas recovery.
north and south well pads to be designed
for expansion allowing for the drilling
of at least one well by adjacent interest
holders. Contingent upon successful
discussions between ConocoPhillips and
Mosbacher to settle commercial terms
including timing, the condition would
provide Mosbacher the opportunity
to drill directional wells to delineate
the field on its lands with a minimal
environmental footprint.
1249_NEB_MGP_Vol2_Text_ENG.indd 87
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88 Mackenzie Gas Project • Volume 2: Implementing the decision
We consider there to be no basis for
lands of differing ownership for gas wells.
Geographic and design issues
a condition directing ConocoPhillips to
Alberta, British Columbia, Saskatchewan
Permafrost and climate change
include all sections of land in Significant
and Yukon utilize a similar set-back.
The Parsons Lake field lies within a zone
Discovery Licence SDL062 that are within
the commercial discovery declaration area
as part of the Parsons Lake Development
Plan since there is currently no joint
development agreement between the
interest holders of Significant Discovery
Licence SDL062 and ConocoPhillips and
ExxonMobil. As the critical action that
ConocoPhillips would not require a variance
for the proposed preliminary well locations
for the Parsons Lake field in accordance
with the 2009 Draft Spacing Requirements.
The 2009 Draft Spacing Requirements set a
limit of one producing well in spacing units
adjacent to lands of differing ownership,
but for spacing units not adjacent to lands
of continuous permafrost. The permafrost
thickness north and east of the lake ranges from
354 metres to 378 metres. Geotechnical drilling
on the north pad and adjacent areas in 2004
identified massive ground ice throughout the
north pad area. As with the other development
fields, development could thaw the permafrost
and significantly alter the northern landscape.
needs to occur before joint development
of differing ownership, there is no off-
ConocoPhillips plans to use a number of
discussions progress is that Mosbacher drills
target area and more than one producing
measures to preserve the permafrost. These
a well on its land, we are not persuaded to
well is permitted11. The National Energy
activities are divided into methods for protecting
include the condition sought by Mosbacher
Board will consider any future application
surface sites and methods for protecting the
requiring ConocoPhillips to fully explore
for a variance at that time and assess it in
permafrost during drilling and production.
joint production arrangements with other
accordance with the 2009 Draft Spacing
interested parties.
Requirements or any orders dealing with
We are of the view that the National Energy
spacing that may supersede it.
ConocoPhillips plans to insulate the ground
from heat sources, such as buildings and flow
lines using methods such as:
Board’s 2009 Draft Spacing Requirements
In our view, Mosbacher has not provided
are appropriate in the absence of joint
evidence to support a determination that
and the airstrip to provide thermal stability
development arrangements. The 2009
the proposed Parsons Lake Development
and protect against contact pressure caused
Draft Spacing Requirements are intended
Plan encourages waste. We consider
by vehicles. A layer of rigid insulation or
to provide a fair approach with respect
the proposed production scheme to be
geotextile may be incorporated in some
to the optimization of gas recovery and
appropriate for a conventional gas field
areas to further protect the permafrost;
the protection of the correlative rights of
such as Parsons Lake. With Condition P19
adjacent land interest holders. Condition
in place requiring compliance with
to elevate the buildings about 1.5 metres
P18 requires ConocoPhillips to comply with
the 2009 Draft Spacing Requirements,
above the gravel pads and allow for air flow
the 2009 Draft Spacing Requirements. The
Mosbacher has the opportunity to drill
between the building and the gravel pad;
2009 Draft Spacing Requirements establish
wells and develop lands in Significant
• using thermsiphons under any slab-on-grade
a 250 metre off-target area from adjacent
Discovery Licence SDL06212.
• piling 1.5 metres of gravel on all well pads
• using adfreeze-type steel pipe piles
foundations elevating and insulating the flow
lines, as mentioned in section 4.4.1; and
• where embankments are created,
[11] Part IV of the 2009 Draft Spacing Requirements.
[12] Those lands of Significant Discovery Licence SDL062
that were included in the National Energy Board’s
commercial discovery declaration dated 3 November 2004
are eligible for a production licence.
1249_NEB_MGP_Vol2_Text_ENG.indd 88
slopes would be angled to minimize
thaw degradation.
12/6/10 11:02:11 AM
Chapter 4: Development fields 89
Preservation of the permafrost at well sites
use a combination of wellbore insulation and
demonstrate how upper limit temperature
would be accomplished by:
thermosiphons it does not expect measurable
scenarios have been considered in their design.
• spacing all wells, including contingent
amounts of well permafrost thaw subsidence.
Further specific discussion on climate
wells, at least 25 metres apart. This exceeds
The north pad sits approximately 45 metres
the 15 metre interwell spacing suggested by
change regarding project design is found
above sea level and there is no evidence
the C-FER Technologies and EBA Engineering
in Chapter 6.
the site has been flooded. Accordingly, flooding
study of the effect of well spacing on
is not expected at the north pad or, similarly,
permafrost, which predicted the coalescence
the south pad.
of permafrost thaw bulbs in 20 years for wells
spaced at 10 metre intervals;
• installing thermosiphons close to each well;
• placing an insulated conductor about 24
metres down each well; and
• using cooled mud to drill the surface holes;
using permafrost cement for the conductor
Views of the Board
Warming of the global and regional climate
The Joint Review Panel was generally satisfied
could raise sea levels and affect weather
that ConocoPhillips had taken climate change
patterns. Parsons Lake is located on higher
into account in its design. Nevertheless the Joint
ground and further from the sea, so its
Review Panel recommended that the National
facilities would be less exposed to possible
Energy Board require ConocoPhillips to file final
effects of climate change.
design plans that incorporate further design
analysis of the impacts of climate change on
We are satisfied with ConocoPhillips’
permafrost and terrain stability over the design
general approach to addressing permafrost
life of the project and post-abandonment.
integrity with respect to the Parsons Lake
The Joint Review Panel was of the view that
development. As warm fluids will flow
By using these methods, ConocoPhillips expects
this analysis should be conducted for a series of
through those wellbores during drilling
heat loss from conduction and convection of
representative locations, conditions and terrain
and production operations, it is important
produced fluids would be reduced by at least
types and should incorporate climate variability,
for safety and environmental protection
90 percent compared to using conventional
in particular, upper limit temperature scenarios
reasons that the permafrost thaw bulbs
packer fluids.
to account for the range of future temperature
around wellbores do not coalesce.
The Sierra Club of Canada raised questions
conditions, including variability and extremes,
Condition P3 requires the interwell spacing
about the projections of temperature change
and the impact of this variability on stream flow
on the Parsons Lake well pads to be no
due to climate change over the life of the
regimes. The Joint Review Panel added that the
less than 15 metres unless ConocoPhillips
project used by ConocoPhillips in the design
results should be incorporated into monitoring,
utilizes mitigation measures approved
of the Parsons Lake field facilities.
mitigation and adaptive management plans.
by the National Energy Board.
and the surface casing on each well;
and using gelled diesel fuel in the tubing
or casing annulus for insulation.
ConocoPhillips evaluated the risk of surface
subsidence caused by the extraction of natural
gas and determined that no measurable
subsidence is expected because of the nature
The Joint Review Panel thought that this analysis
should be provided to other appropriate
regulators in sufficient time for review and to
provide input to the National Energy Board.
Condition P8 requires ConocoPhillips to
provide final detailed design information
which incorporates an analysis of the
impacts of climate change and variability on
of the reservoir and its depth (three kilometres).
Indian and Northern Affairs Canada suggested
permafrost and terrain stability for the
In addition, because ConocoPhillips plans to
in final argument that the Proponents should
Parsons Lake facility using potential upper
1249_NEB_MGP_Vol2_Text_ENG.indd 89
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90 Mackenzie Gas Project • Volume 2: Implementing the decision
limit temperature scenarios which may
the National Energy Board’s expertise and
and Norman Wells. The Proponents indicated
occur during the operational life of the
experience in regulating interprovincial aspects
that elevated ozone levels at high latitudes in
facilities. ConocoPhillips will also provide
of the oil, gas and electric utility industries,
the northern hemisphere are thought to result
information about how upper limit
including environmental matters. The Joint
from the intrusion of stratospheric ozone.
temperature scenarios may impact
Review Panel also recognized the extensive
The Proponents stated that all ground-level
precipitation and water levels of Parsons
environmental and local knowledge that
concentrations of compounds released by
Lake and other nearby lakes. We are of the
Environment Canada and the Government
the project during operations at the gas fields,
view that government departments such as
of the Northwest Territories can provide.
the Inuvik Area Facility, and compressor and
Environment Canada. Indian and Northern
Affairs Canada and Natural Resources
Canada should be consulted to benefit from
their expertise.
Air quality issues
Air quality in the North is considered to be of
high quality and Northerners are very concerned
that it remains that way. Both Environment
Canada and the Proponents agreed that existing
Air emissions can be related to the projectspecific effects of construction, operations,
and waste incineration. Air quality impacts
can be local to regional in the case of particulate
production area and along the pipeline corridor.
case of greenhouse gases. Emissions would
the Proponents design and implement suitable
occur during the construction phase through
air quality monitoring programs with its help.
intermittent flaring during well testing
Environment Canada focused its
at the Parsons Lake field.
recommendations on pollution prevention
and, along with other government regulators,
for the pipeline are discussed in Chapter 3 and
emphasized the need to “keep clean areas
discussion on air emissions pertaining to facility
clean.” This principle requires new industrial
design is found in Chapter 6.
degradation of air quality in these areas.”
and territorial guidelines at all locations in the
Environment Canada recommended that
Further specific details pertaining to emissions
operated in a manner that minimizes the
be below those outlined in applicable federal
matter and sulphur dioxide, or global in the
air quality in the proposed project area is good
development to be “planned, constructed and
heater station sites would increase, but would
The Joint Review Panel report indicated that the
Proponents’ baseline information was compiled
and the use of best available technology
and best management practices to minimize
the degradation of air quality. Further discussion
around application of these principles may
be found in Chapter 6.
The Dehcho Elders and Harvesters indicated that
the project needs to be designed to minimize air
from historical data and results of air quality
quality impacts, with monitoring plans in place
Air quality issues for the project included project
monitoring that was carried out over one year
to verify the predicted emissions and impacts.
emissions for the pipeline and development
near the communities of Inuvik and Norman
Corrective action needs to be taken quickly
fields, monitoring, and greenhouse gases in
Wells, and periodically at the Parsons Lake and
to avoid impacts upon the land and wildlife
the context of monitoring climate change.
Taglu gas fields. The Proponents’ monitoring
from degraded air quality.
The Joint Review Panel noted that the National
data and other sources indicated that back-
Energy Board would be the prime regulator
ground concentrations of air contaminants are
of air emissions from the project and that
generally below detection levels or applicable
Environment Canada and the Government
guidelines. The one exception that is not
of the Northwest Territories would play advisory
below detection levels is ozone; relatively high
roles. The Joint Review Panel recognized
background levels were monitored in Inuvik
Greenhouse gas emissions
Parties were concerned about the impacts
of the project on climate change, especially
in light of Canada’s international efforts under
the United Nations Framework Convention
on Climate Change and the Kyoto Protocol.
1249_NEB_MGP_Vol2_Text_ENG.indd 90
12/6/10 11:02:11 AM
Chapter 4: Development fields 91
Greenhouse gas emissions arising from the
project include carbon dioxide, methane and
nitrous oxides with each compound having
a different climate change potential. During
operation, the project would emit greenhouse
gases from burning natural gas at combustion
related sources such as compressors and
methane gas released through normal venting
procedures and minor leaks (fugitive emissions).
Further specific discussion on air emissions
pertaining to facility design is found in
Chapter 6.
Views of the Board
We understand the importance of clean
air in the North and that air quality must
discussion for these conditions regarding
air emissions pertaining to facility design
is found in Chapter 6.
be considered in a cumulative manner.
Air quality monitoring is part of
We also recognize the need to minimize
comprehensive environmental monitoring
greenhouse gas emissions resulting from
under an environmental management
the project. The Joint Review Panel directed
system. Through environmental
several recommendations to us relating
management, systems are established
to air quality and air emissions. We have
to address effects of the project on the
addressed air issues through several
environment and of the environment
conditions for the Mackenzie Gas Project.
on the project, with the overall goal of
These conditions are focused on the
minimizing negative impacts. Adaptive
Alternatives North submitted that the National
Proponents taking appropriate measures
management is a systematic process for
Energy Board and the Government of Canada
to minimize air emissions and address air
continually improving management
have a public interest mandate that requires
quality. We are committed to working
practices by learning from their outcomes.
consideration of greenhouse gas emissions.
collaboratively with Environment Canada
Ecology North deemed that high project-specific
and the Government of the Northwest
standards for greenhouse gas emissions
Territories to protect air quality in the
based on a robust and strong definition of
North, recognizing the extensive
best available technology and accompanied
environmental and local knowledge
by penalties in the cases where they do not
that these agencies can provide.
meet those project standards or targets, would
provide the best possible protection in terms of
minimizing upstream greenhouse gas emissions
associated with the project.
Environmental monitoring is an important
part of environmental management that
directly supports adaptive management by
observing and evaluating the effects that
occur, then changing or adding mitigative
measures as appropriate to limit or reverse
Conditions P13 and P14 address
the environmental effects. Environmental
technologies for reducing emissions,
monitoring can include:
incorporation of best management
•• compliance monitoring, to verify that all
practices and best available technologies,
environmental mitigation is implemented
Sierra Club of Canada submitted that we need
and facility design. Condition P14 requires
as presented in the Environmental
to specify an actual target and it is not enough
the submission of a report evaluating
Protection Plan and environmental
to just leave it up to the Proponents. Sierra Club
incinerator emissions from camps and
alignment sheets and that work is in
of Canada indicated that the target should at
station facilities and technologies and
compliance with environmental
least match the general recommended target
practices must be reflected in the waste
in Joint Review Panel recommendation 8-8.
management plans required by Condition
1249_NEB_MGP_Vol2_Text_ENG.indd 91
regulations; and
•• effects monitoring, to assess the effects
P11. Condition P16 requires the
resulting from project-environment
ConocoPhillips to minimize and reduce
interactions and evaluate the effectiveness
emissions from flaring. Further specific
of approved mitigation measures.
12/6/10 11:02:11 AM
92 Mackenzie Gas Project • Volume 2: Implementing the decision
This is further discussed in section 3.3.6.
ConocoPhillips is expected to implement
Environmental Protection and Monitoring
and Surveillance Programs which include
protection of the environment as one of
the main goals. A monitoring program may:
•• identify any issues or potential concerns
•• monitoring ongoing operation, verifying
to greenhouse gas emissions but should
apply to all discharges to the environment,
reclamation and maintenance of the
which in this case is the atmosphere.
project site to acceptable standards; and
Condition P10 also covers the requirements
•• conducting environmental audits,
evaluating environmental management
systems and environmental programs.
for methods and locations of monitoring.
Condition P15 requires the Proponents
to file a report outlining the use of best
that may compromise the protection
We generally require the filing of
available technology for station facility
of the environment;
environmental post-construction
construction. Selection of best available
monitoring reports as a condition
technology is the most significant factor
measures to prevent or mitigate
of an authorization. The information in
in determining achievable air emissions
the impact of the identified issues;
monitoring reports should include:
targets. Condition P10 outlines the
•• confirmation of proper implementation
requirements for an Environmental
•• include methods for developing
•• provide for continued monitoring
of sites to evaluate success of mitigative
of mitigation and reclamation
Protection Plan. The condition requires
measures undertaken;
measures used;
the Proponents to submit maximum
•• provide a system for implementing
additional mitigative measures
as necessary; and
•• provide a feedback system that allows
for adaptation of successful mitigation
•• identification of the outstanding
environmental issues; and
•• discussion of the company’s plans for
how outstanding issues will be resolved.
proposed greenhouse gas targets and
reduction strategies for air emissions
including particulate matter, NOx and
greenhouse gases. Condition P10 also
addresses other matters from the Joint
Condition P10 requires ConocoPhillips to
Review Panel recommendations including
submit an Environmental Protection Plan
Monitoring programs may have specific
employee training, monitoring, public
which includes monitoring of activities.
goals and targets and could include
communication, and required consultation
Condition P13 includes the requirement
methods for evaluating and interpreting
with Environment Canada and the
for monitoring incinerator emissions.
Government of the Northwest Territories.
A commitment to continuous
With these conditions, we find it acceptable
improvement, outlined in Joint Review
for the Proponents to develop greenhouse
Panel recommendation 8-6, is expected
gas targets for the project consistent
to be a component of an operator’s
with use of best management practices
Management system pursuant to
and in consultation with appropriate
Responsibilities of the National Energy
paragraph 5(2)(b) of the Canada Oil and
government agencies.
Board regarding monitoring include:
Gas Drilling and Production Regulations.
•• conducting environmental inspections
This is addressed in Condition P10.
to future pipeline projects.
collected data such as air quality or
emissions data. Monitoring may include
any relevant environmental practices
(e.g., vegetation establishment, water
quality sampling, waste disposal).
1249_NEB_MGP_Vol2_Text_ENG.indd 92
the effectiveness of mitigation;
of facilities, verifying compliance with
We are of the view that the commitment
terms and conditions, and assessing
to continuous improvement is not limited
12/6/10 11:02:11 AM
Chapter 4: Development fields 93
Drill cutting disposal
that it is appropriate for the Parsons Lake
Like the operators of the Taglu field,
production facility to follow Alberta’s Energy
ConocoPhillips plans to dispose of drill cuttings
Resources Conservation Board Directive 038
from the Parsons Lake field into a dedicated
“business as usual” Permissible Sound Level.
disposal well. Drill cuttings would be collected
and transported to the cuttings processing
station. At the station, the cuttings would
be mixed with water, milled and sheared to
create slurry. The slurry would then be pumped
into the proposed D-20 dedicated cuttings
disposal well (see Figure 4-13). Disposal would
usually be done in batches at low pump rates.
ConocoPhillips is planning a comprehensive
program of testing and monitoring of subsurface
containment during cuttings injection
operations. Annular cuttings injection may be
used as a back-up if ConocoPhillips was not able
to use the dedicated cuttings injection well.
Views of the Board
We are of the view that the conceptual
plan by ConocoPhillips to dispose its drill
cuttings by subsurface slurry injection is
satisfactory as it avoids the use of sumps
and minimizes the environmental footprint.
However, as down-hole slurry injection of
this scale and extent has not been utilized
in the Mackenzie Delta before, Condition
P4 requires ConocoPhillips to submit
a drill cuttings slurry injection management
program. The National Energy Board
would assess such a program with respect
As mentioned for Taglu, subsurface slurry
to subsurface containment as well as
injection has not been used in the Northwest
safety, protection of the environment
Territories at this scale before. If cuttings
and conservation of resources.
injection is not viable, ConocoPhillips’ alternative
method for the disposal of drill cuttings would
be to stabilize, store and subsequently transport
the cuttings to an approved disposal site.
Condition P9 requires meeting requirements
of Alberta’s Energy Resources Conservation
Board Directive 038 for noise regulation
and filing a post construction noise
Noise
assessment report 90 days following
The Parsons Lake anchor field is located outside
the start of operation.
of Kendall Island Bird Sanctuary. The physical
footprint of the facility, particularly the north
pad, is an area of relatively low numbers and
diversity of migratory birds compared to the
nearby Mackenzie Delta. ConocoPhillips believes
1249_NEB_MGP_Vol2_Text_ENG.indd 93
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Chapter 5
Routing and land matters
5.1 Introduction
The National Energy Board’s assessment of a pipeline application under the National Energy Board
Act includes consideration of the appropriateness of the general route of the proposed pipeline
and the general location of associated facilities, the amount of land required, and the proponent’s
land acquisition approach. If a certificate authorizing a project to be built along the general route
is issued, a further process determines the location of the specific or detailed route.
A different legislative scheme applies in relation
for the Mackenzie Gas Project. Our assessment
to facilities approved under the Canada Oil
may assist those departments and agencies in
and Gas Operations Act. Applications under
their consideration of the various applications
the Canada Oil and Gas Operations Act are
for land use, land rights acquisition, and
usually not filed with the National Energy Board
other approvals.
until the route has been established and all
required land rights for the project have
been secured. However neither the National
Energy Board Act nor the Canada Oil and Gas
Operations Act requires that all necessary
land rights be acquired prior to a company
submitting an application for a project.
Companies typically use surveys, land studies,
and other work such as selection criteria
and alternatives to identify, assess, and select
a proposed pipeline route and facility locations
when preparing pipeline applications under
both the National Energy Board Act and
the Canada Oil and Gas Operations Act.
Notwithstanding the differing legislative
Refinements are made through further
schemes and practices under the National
study and consultation with communities
Energy Board Act and the Canada Oil and Gas
and individuals which could be affected
Operations Act, we considered similar factors
by the project.
in our assessment of the proposed routes
for the Mackenzie Valley Pipeline and the
Mackenzie Gathering System.
In addition to the factors referred to above,
parties raised issues in respect of land use
plan requirements and the status of access
We recognize that federal and territorial
agreements. Each of these will be addressed
departments and agencies have responsibilities
in turn in this chapter.
in respect of land authorizations and permitting
1249_NEB_MGP_Vol2_Text_ENG.indd 94
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Chapter 5: Routing and land matters 95
5.2 General route and
facilities site selection
5.2.1 General route selection –
Mackenzie Valley Pipeline and
Mackenzie Gathering System
The Proponents have identified a general route
for the proposed Mackenzie Valley Pipeline
and the Mackenzie Gathering System pipelines
that consists of a one-kilometre wide corridor.
Within this corridor, the Proponents identified
On the record
Route and site selection criteria
The criteria used by the Proponents to evaluate the
preliminary route and identify alternatives included:
• route placement, including options for reducing
• geotechnical considerations such as avoiding
springs, perched aquifers and steep, ice rich,
or unstable slopes, and the distribution of
discontinuous permafrost;
• environmental considerations such as land use
plans, socio-economic concerns, and reducing
the length of the pipeline, potential facility sites,
proximity to critical wildlife habitat and important
and locating the right of way in order to avoid
cultural or archaeological sites;
encroaching on existing habitats, be close to
existing infrastructure, and parallel or use existing
linear disturbances;
• reducing the number, complexity, and width
of watercourse crossings;
a preliminary route which has been and will
• construction matters such as slopes, muskeg
and fen areas, grading, access, ground conditions,
crossing linear facilities, and the need for
adequate workspace;
• community interests; and
• relative costs of the route alternatives.
continue to be subject to refinement through
further study and public consultation.
On the record
• consult with communities on sites and routes; and
Proposed route of the Mackenzie
Route and site selection process
• revise site and route locations, where practical,
Gathering System
The Proponents’ stated objectives in the route
The upstream gathering pipelines consist of
four laterals, one from each field and a fourth
extending from the Storm Hills pigging facility
south to the Inuvik Area Facility (see Figure 1-2).
From the Inuvik Area Facility the natural gas
liquids pipeline and the Mackenzie Valley
based on community input.
and site selection process for the Mackenzie Gas
The selected preliminary route for the Mackenzie
Project included:
Gathering System and Mackenzie Valley Pipeline
• avoiding sensitive environmental and cultural areas;
followed the alignment of the 1984 Polar Gas Project
• reducing disturbance to communities and
the landscape;
• satisfying engineering and construction
requirements; and
application route from the Mackenzie Delta to Norman
Wells, and paralleled the existing Enbridge Pipelines
(NW) Inc. Norman Wells Pipeline from Norman Wells
to the Northwest Territories /Alberta border.
Alternatives to the preliminary route were identified
Pipeline would share a common right of
• reducing cost.
way south to Norman Wells, which would
The Proponents set up multidisciplinary teams
desktop study, field investigations, and community
of engineering, construction, and environmental
consultation using the route and site selection criteria
specialists to assess potential pipeline routes and
set out below.
be the terminus of the Mackenzie Gathering
System (see Figure 1-3).
facility sites. These teams assessed available information
from previous pipeline studies and proposals in the area
by the Proponents for further investigation through
The preliminary routes and alternatives for the
Mackenzie Gas Project were divided for evaluation
Niglintgak lateral
to determine the potential for using these previously
This lateral would be located entirely within
considered locations.
the Inuvialuit Settlement Region and would
The following methodology was used by the
Facility. Within each segment multiple routes were
Proponents to select the Mackenzie Gas Project’s
identified and assessed. After a route within each
proposed route and sites for the associated facilities:
segment was selected, field reconnaissance and
• establish route and site selection criteria;
community consultation were carried out to make
extend 14.7 kilometres in a 30-metre wide right
of way from the Niglintgak gas conditioning
facility to the Taglu gas conditioning facility. The
route would traverse the flat delta eastwards,
and cross three major channels before reaching
the Taglu gas conditioning facility.
• identify preliminary pipeline routes, sites,
and alternatives;
• conduct field investigations involving
community representatives;
• revise preliminary site and route locations based
on field investigations;
1249_NEB_MGP_Vol2_Text_ENG.indd 95
into 15 segments for the upstream gathering pipelines
and 29 segments downstream of the Inuvik Area
further routing refinements. These refinements:
• recognized route issues such as the severity of side
hill slopes not evident during the desktop study;
• took advantage of more favourable terrain, such
as better approaches to water crossings; and
• used other features, such as cut lines.
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96 Mackenzie Gas Project • Volume 2: Implementing the decision
Taglu lateral
final one kilometre leading into Norman Wells,
The Taglu lateral would begin at the
which would be located in a 30-metre wide
Taglu gas conditioning facility and extend
right of way. The natural gas liquids pipeline
80.9 kilometres in a 40-metre wide right
would begin in the Gwich’in Settlement Area
40 kilometres, the first stage involves the assessment of the project. At this stage,
of way in a southeasterly direction crossing
and terminate in the Sahtu Settlement Area.
the company files an application to the National Energy Board that includes a general
the east channel of the Mackenzie River
Did you know?
Definitions
General route – when a pipeline company applies to the National Energy Board
under the National Energy Board Act for approval of a pipeline longer than
route, which may be a corridor that is much wider than the actual right of way that
would ultimately accommodate the pipeline. In the case of the Mackenzie Valley
to the Storm Hills pigging facility south
Pipeline, the applied-for general route is a one-kilometre wide corridor, within
of Big Lake. This lateral would be entirely
which the much narrower pipeline right of way would be located. At this stage,
within the Inuvialuit Settlement Region.
the National Energy Board, through its public hearing process, considers a variety
Proposed route of the
Mackenzie Valley Pipeline
The proposed 1196 kilometre Mackenzie Valley
Pipeline route (see Figure 1-3) would:
of factors, including the appropriateness of the general route, to determine whether
Parsons Lake lateral
the project should be approved. If the project is approved, the general route is also
The Parsons Lake lateral would extend
from the proposed Inuvik Area Facility
route approval, which is approval of the detailed route.
26.4 kilometres in a 30-metre wide right of
to a pig receiver adjacent to the NOVA
Preliminary or preferred route – in its application for approval of a pipeline
way from the Parsons Lake gas conditioning
Gas Transmission Ltd. interconnect
project under the National Energy Board Act, a pipeline company may include with
facility located at the northeast corner of
facility, just south of the Northwest
its proposed general route a preliminary or preferred route for its pipeline. Such
Parsons Lake, south around the lake, and then
Territories-Alberta border;
approved, and the pipeline company can proceed to the second stage of pipeline
a route often serves as the centerline for the corridor used by the company to define
its proposed general route. This provides the pipeline company with a specific line
in a southwest direction to the Storm Hills
• generally follow the Mackenzie Valley
• pass through the Gwich’in and Sahtu
of focus for feasibility, design, and impact studies for general route selection, and
pigging facility. All of these facilities would be
Settlement Areas, and the Dehcho Region
it can also provide advance opportunities for the company to focus its landowner
located within the Inuvialuit Settlement Region.
including both Crown and Aboriginal
and community engagement efforts for confirming and securing a final pipeline
right of way route in preparation for detailed route approval.
Storm Hills lateral
Detailed route – if a pipeline company receives a certificate from the National
The Storm Hills lateral would extend
Energy Board that approves its pipeline project, the company can proceed to
the second stage of pipeline route approval, which is approval of its detailed route.
67.2 kilometres in a 40-metre wide right
At this stage, the pipeline company must prepare plans, profiles, and a book of
of way from the Storm Hills pigging facility
reference (PPBoR) that describe the precise location of the pipeline right of way in
to the Inuvik Area Facility located in
relation to the land properties it crosses. The PPBoR define the pipeline company’s
proposed detailed route. The pipeline company must make the PPBoR available
for public viewing and must serve notice on directly affected landowners as well
the Gwich’in Settlement Area.
private lands;
• follow the existing Enbridge Pipelines (NW)
Inc. Norman Wells Pipeline right of way for
about 45 percent of its length and parallel
previous disturbances, such as cut lines,
the winter road, and the Mackenzie Highway;
• be located within the pipeline study corridor
Natural gas liquids pipeline
identified by the Dehcho First Nations and
and persons that may be adversely affected have 30 days to file written statements
The proposed 457 kilometre natural gas liquids
the Government of Canada; and
of opposition to the proposed route. If the National Energy Board receives a written
pipeline route would extend from the Inuvik
statement of opposition within the 30 day timeframe, the National Energy Board
Area Facility to Norman Wells where it would
gas liquids pipeline from the Inuvik Area
to be heard by the National Energy Board before a decision is made on whether
connect with the Enbridge Pipelines (NW) Inc.
Facility to Norman Wells, where the natural
to approve that section of the detailed route. The pipeline company cannot start
Norman Wells Pipeline. It would share a
construction of any section of its proposed pipeline until that section of the detailed
gas liquids pipeline would connect to
50-metre wide right of way with the Mackenzie
the existing Enbridge Pipelines (NW) Inc.
Valley Pipeline for all of its length except for the
Norman Wells Pipeline.
as publish notices in newspapers in the vicinity of the proposed route. Landowners
may set the matter down for a detailed route hearing, allowing the affected person
route has been approved by the National Energy Board.
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• share a common right of way with the natural
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Chapter 5: Routing and land matters 97
5.2.2 Facilities site selection
The Proponents’ site selection process for
the Mackenzie Gas Project facilities involved
the following activities:
• establishing site selection criteria;
• identifying preliminary sites and alternatives;
• conducting field investigations involving
community representatives;
• revising preliminary site locations based
on field investigations;
• consulting with communities on sites; and
• revising site locations, where practical,
based on community input.
future compressor stations. This process led
be identified to accommodate potential
the Proponents to select the initial sites for
pipeline development. This process established
the Storm Hills pigging facility and the Inuvik
a 2.5-kilometre wide pipeline corridor on
Area Facility for the Mackenzie Gathering
the east side of the Enbridge Pipeline (NW) Inc.
System and the proposed compressor station
right of way near Trainor Lake, and a two-
sites, along with the heater station site and
kilometre wide corridor on the east side of
valve sites, for the Mackenzie Valley Pipeline.
the Enbridge Pipeline (NW) Inc. right of way
5.2.3 Community and government input
into route/site selection
The Proponents submitted that the route
and site selection process involved extensive
discussion with northern communities,
northern regulators, land use planners,
The Proponents initially identified five-kilometre
and other interested parties. The Proponents
target areas for each of the following facilities
plan to continue consulting with stakeholders
required to operate the Mackenzie Valley
throughout the regulatory process.
Pipeline: compressor stations, pig launching
and receiving facilities, a heater station,
and valve sites.
Community representatives provided local
knowledge about cultural resources and
land use, as well as personal experiences
Similarly, five-kilometre target areas were
with the Mackenzie Highway, the winter road,
identified for the Storm Hills pigging facility
construction of the Enbridge Pipeline (NW) Inc.
and the Inuvik Area Facility for the Mackenzie
Norman Wells Pipeline, and local resource
Gathering System.
use. Some representatives provided input to
The target areas were determined by a hydraulic
analysis of the Mackenzie Gas Project pipelines.
The Proponents undertook two further
field studies to assess and refine the route
for larger watercourse crossings, such
as the Ochre River crossing, and to align
it with proposed facility sites, such as
compressor stations, interconnections,
and valve sites selected for potential future
compressor stations.
Information from field studies and community
consultation was used by the Proponents to
refine the preliminary route and sites prior to
filing its application with the National Energy
Board. These refinements are summarized
in Table 5-1.
the route evaluation teams, which was used
in route selection.
Alternative sites within the target areas
The Proponents reviewed the pipeline route
were then identified and evaluated based
with representatives of the Dehcho First Nations
on hydraulic requirements, proximity to the
and Indian and Northern Affairs Canada as
pipeline route, and site-specific environmental,
part of its community consultation. This review
construction, operations, and maintenance
was in support of the Dehcho interim land
considerations, such as access. The assessment
withdrawal process regarding the location and
of potential pipeline valve sites along the route
size of a potential pipeline corridor across the
also considered the requirements for potential
Dehcho Region, within which the lands would
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near Headwater Pond (Deep Lake).
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98 Mackenzie Gas Project • Volume 2: Implementing the decision
Issues raised and route refinements
identified Smith Creek Falls as an important
In response to these issues, the Proponents
made following filing of application
cultural area and recommended the proposed
indicated that traditional knowledge has been
Subsequent to the Proponents filing their
pipeline route be relocated as far away from
forthcoming through a variety of methods. Early
applications, a number of local Aboriginal
this area as possible, subject to consultation
in the project, the Proponents consulted local
communities identified routing and siting
with Pehdzeh Ki First Nation.
communities, particularly Elders and Elders’
concerns and raised issues with the
Proponents’ route selection approach.
The Sambaa K’e Dene Band recommended
that a proposed heater station be relocated
Sahtu communities identified key cultural
to a site identified by the community in order
areas, such as Bear Rock, that they believed
to minimize the overall project footprint.
should be protected in project design.
groups, to provide direction for establishing
the pipeline route and some major facility sites.
Community involvement helped the Proponents
gain an understanding of areas to avoid, areas
that would be acceptable, and areas that
Local Aboriginal communities also urged
would be better alternatives. The Proponents
The Pehdzeh Ki First Nation opposed the
that traditional knowledge be used in pipeline
also worked with communities to conduct
proposed pipeline routing and siting of facilities
routing and selection of related facility sites.
traditional knowledge studies, such as the
in the Blackwater River area because of its
For instance, the K’ahsho Got’ine Lands
one conducted in the Gwich’in Settlement Area.
historical, spiritual, and cultural significance.
Corporation submitted that traditional
The Proponents used the results of this study
In addition, the Pehdzeh Ki First Nation raised
knowledge should play a decisive role in
to assess and refine their project designs, and
concerns about the Proponents’ plan to shift
designing the routes and sites, and expressed
stated that they have made similar efforts
the route away from the existing Enbridge
concern that these decisions were being
for those areas affected by the project where
Pipelines (NW) Inc. Norman Wells Pipeline route
made by engineers which may not be familiar
traditional knowledge studies have been
so that it would be closer to the community
with the land or the traditional way of life.
completed. For example, the Sambaa K’e Dene
of Wrigley. The Pehdzeh Ki First Nation also
Band traditional knowledge study recommended
that the Trout River heater station be moved
about three kilometres south of its originally
Table 5-1
Refinements to the preliminary route
Project Change
Moving the proposed route about six kilometres farther east of Travaillant Lake to avoid disrupting
areas of cultural and environmental significance to the Tsiigehtchic community and placing the proposed
route in an area identified by local land users.
Moving the proposed route 2.5 kilometres east for 39 kilometres of its length to maximize distance
from Trainor Lake (or K’eotsee Lake, as it is known) while remaining within the agreed-to Dehcho interim
land withdrawal pipeline corridor, as requested by both the Trout Lake community and as identified in
the Sambaa K’e Traditional Knowledge report.
proposed site, and this change was adopted
by the Proponents.
Based on further investigations, and in
response to issues raised through its
consultation program following its initial
application filing with the National Energy
Board, the Proponents made further changes
to their proposed general routing and site
locations which are shown in Table 5-2.
Realigning about 4.5 kilometres of the proposed route at the Ochre River crossing to accommodate
the preferred method of horizontal directional drilling.
Shifting the proposed route in the Willowlake River area to the east side of the Mackenzie Highway
to avoid encroaching upon residences, areas of high archaeological potential, and historical big game
mineral licks, as requested by the local community.
Moving about 8 kilometres of the proposed route up to 200 metres to the east to avoid
a University of Alberta research plot and to connect into the proposed valve site.
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Chapter 5: Routing and land matters 99
The Proponents submitted that the adjustments
potential community access to natural gas
measures to help mitigate the concerns,
identified in their November 2005 project
and electricity, as well as to increase its distance
such as changing the construction schedule.
update reduce the proposed pipeline length,
from the culturally significant Bear Rock.
The Proponents stated that in those cases where
resulting in reduced footprint, cost, and
To accommodate this adjustment, the one-
agreement cannot be reached, the Proponents
environmental impact.
kilometre wide pipeline corridor was realigned,
contact the concerned parties to explain why
which increased its length by 1.4 kilometres.
an agreement cannot be reached.
costs, and ongoing engineering and
The Proponents submitted that when a site
Subsequent to the November 2005 and May
construction planning, the Proponents filed
or proposed route is moved, the rationale for
2007 project updates filed by the Proponents,
another Project Update in May 2007. Although
that change is documented, agreed to, properly
some routing and siting concerns were still
Responding to community input, increased
many of the project elements did not change,
the Proponents relocated the proposed Great
Bear River compressor station about eight
kilometres downstream, to the east side of
the Great Bear River, in response to requests
approved, and recorded so that those involved
in subsequent phases of the project have
being raised by Aboriginal communities
in the Dehcho Region.
a reference record of commitments, changes,
The Dehcho Elders and Harvesters stated
and issues.
that the routing of the pipelines and the
from the community of Tulita. The Proponents
In situations where the Proponents have not
submitted that moving the compressor station
been able to make routing or siting adjustments
closer to Tulita is intended to reduce the cost of
to address concerns, they have sought other
siting of all project facilities and activities
need to avoid burial and sacred sites.
The Dehcho First Nations submitted
concerns that the Proponents’ application
forces assessment of the project at a very
Table 5-2
high, conceptual level rather than dealing
Project changes filed in November 2005
with the specific concerns of their communities
on issues such as pipeline routing and facility
Project change
locations. As a result, the Dehcho First Nations
Moving the Inuvik Area Facility about 16 kilometres south, so it will be closer to the Dempster Highway
and located on a flatter site.
argued that many community concerns about
Reducing the number of initial compressor stations from four to three, and relocating the proposed station
sites within the corridor.
they are being referred to subsequent regulatory
the project remain unaddressed, and that
Increasing the number of valve sites to 11 and relocating three of the original valve sites to accommodate
the revised system hydraulic requirements for potential future compressor stations.
processes rather than being directly dealt with
Shortening the pipeline by about 26 kilometres as a result of relocating the Inuvik Area Facility, adjusting
the pipeline corridor, and other route adjustments.
For example, the Dehcho First Nations
Shortening the pipeline by about 3.8 kilometres by straightening two segments of the preliminary route
near Travaillant Lake and relocating the corridor to accommodate the rerouting.
approval for various block valve locations
Moving a 14.7 kilometre segment of the preliminary route near Wrigley up to two kilometres to the east,
and making the necessary adjustments to the one-kilometre wide pipeline corridor, in response to
a community request to move the pipeline further away from a sacred spring and burial grounds.
Relocating the Loon River valve site 14 kilometres to the north based on community feedback regarding
a nearby hunting area, and converting the site to a compressor station site.
to resolve issues at this stage in the process.
submitted that the Proponents are seeking
without any consultations with them as to
the acceptability of those proposed locations
for future compressor stations.
Exchanging the Blackwater River and Trail River compressor station for a single compressor station near
River Between Two Mountains, in response to Pehdzeh Ki First Nation concerns about the culturally
significant Blackwater River area and due to pipeline hydraulics considerations.
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100 Mackenzie Gas Project • Volume 2: Implementing the decision
The Proponents submitted that, based on
an opportunity for communities to provide input
the approach taken by the Proponents to
consultations with communities in the Dehcho
on other project adjustments.
listen to, and to deal with, community and
Region, further project refinements included
moving the Willowlake River block valve site,
relocating the watercourse crossing on the
Mackenzie River further upstream, and
relocating the pipeline route near Satellite Lake.
The Proponents stated that consultation has
not led to agreement in every case, and in
some cases, the outstanding issues can only
be addressed at the permitting stage, following
the collection of additional information. They
submitted that consultation about the project
will continue, and that they will continue to
strive to address outstanding concerns, although
agreement may not be reached in every case.
In its report, the Joint Review Panel concluded
that, based on available information, it considers
the location of the proposed pipeline corridor
to be acceptable.
stakeholder concerns in their determination
and refinement of the general pipeline
route and facility site locations to be
acceptable and appropriate for this project.
The location of proposed block valve sites
Views of the Board
We find that the general routes of proposed
Mackenzie Gas Project pipelines, as defined
by the one-kilometre wide corridors put
forward by the Proponents, are appropriate. We are of the view that, using relevant
for future compressor stations is determined
primarily by the system design of the
pipeline. To some extent, their location
can be adjusted to accommodate local
community concerns. We expect the
Proponents to continue consultation with
local communities and make adjustments
information and experience for a Northern
to accommodate their concerns where
pipeline project, the Proponents applied
possible given the system design constraints.
a reasoned, systematic, and suitable
The latest version of the consultation summary
methodology for selecting the initial
table filed by the Proponents indicates that
locations of the pipelines and facility sites.
be traversed by the Mackenzie Gas Project,
we are of the view that the proposed
there will be ongoing discussions with commu-
1249_NEB_MGP_Vol2_Text_ENG.indd 100
Considering the nature of the lands to
nities and others with regard to a multitude of
We recognize the concerns raised by some
one-kilometre wide corridors provide
project related matters. Regarding the proposed
communities and stakeholders regarding
sufficient flexibility to avoid or minimize
location of the pipeline route and related
the need to consider the presence and
impacts to landowners, communities,
facilities, this table indicates that outstanding
protection of culturally and ecologically
and sensitive ecological or cultural features
concerns remain regarding the proximity of the
sensitive features in selecting and adjusting
in the determination and refinement of
proposed pipeline right of way to Satellite Lake
the proposed general pipeline route and
the detailed routes of the pipelines.
and the crossing of a possible underground
related facility locations. We note that the
stream in the vicinity of the community of
Proponents have demonstrated an ongoing
Jean Marie River. The Proponents have commit-
commitment to hear from communities
ted to continue dialogue with the residents of
along the proposed route and have made
Jean Marie River to try to address their concerns.
a number of substantial adjustments to
The Proponents noted that the Mackenzie Gas
their selected pipeline and facility site
Project’s consultation program will continue
locations to address community concerns,
throughout the regulatory process to afford
where possible and appropriate. We find
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Chapter 5: Routing and land matters 101
5.3 General land requirements
The Proponents estimated that the total amount
of land required for the Mackenzie Gathering
System pipelines, including the 457 kilometre
natural gas liquids pipeline and related facilities,
is approximately 3055 hectares. For the
Mackenzie Valley Pipeline and related facilities,
the Proponents estimated that 5265 hectares
of land would be required. Land requirements
are shown in Table 5-3.
temporary workspace along or near the right of
which would be identified as construction
way would also be required in such locations as:
planning and engineering progresses. Figure 5-2
• watercourse crossings;
shows the Proponents’ anticipated typical land
• bypasses around ravines and wet areas;
requirements, including potential temporary
• deep grade or large slope sites;
workspace needs, for a conventional open cut
• construction equipment turnaround areas;
watercourse crossing.
• sharp direction change areas;
• equipment storage areas;
• crossings of roads, highways, and other
pipelines;
• valve site installations;
The Proponents submitted that three compressor
stations and one heater station are initially
required for the proposed gas pipeline. The total
land requirements for each compressor station
would be 9.5 hectares, including allowances
Both the Mackenzie Valley Pipeline and the
• pig launcher and receiver installations; and
natural gas liquids pipeline can be accommo-
• timber storage areas.
dated within a 50-metre wide pipeline right
The Proponents estimated that more than
the operations stage, each compressor station
of way between the Inuvik Area Facility and
1600 temporary workspace sites, totaling about
site would be smaller with an estimated fenced
the Enbridge Pipelines (NW) Inc. Interconnect
420 hectares, would be needed in addition to
area of between six and seven hectares. The
Facility at Norman Wells. South of Norman Wells,
the proposed right of way during construction.
Trout River heater station would require a four
the Mackenzie Valley Pipeline would continue
This excludes timber storage and bypass areas,
hectare area.
for living quarters and helipads. This reflects
the size of the area to be cleared. However at
onward to the NOVA Gas Transmission Ltd.
Interconnect Facility within a 40-metre wide right
of way. Block valve and cathodic protection sites
would be located within the proposed right of
way. The proposed 50-metre wide right of way,
shared by the Mackenzie Valley Pipeline and
the natural gas liquids pipeline, would run for
about 456 kilometres, and a 40-metre wide right
of way would make up the remainder of the
1196 kilometre Mackenzie Valley Pipeline route.
Table 5-3
Land requirements by use
Total area1
(ha)
Land use
Gathering pipelines and facilities
770
105
2285
1285
Gas pipeline and facilities
5265
1710
Infrastructure 2690
1150
420
150
9150
3115
NGL pipeline 3
4, 5
The Proponents submitted that the different
Temporary workspace proposed pipeline right of way widths would
Total
provide work and travel areas to support safe
1. Includes Commissioner’s lands
2. Rounded to the nearest 5 ha.
3. Shared right of way with gas pipeline for 456 km, 2280 ha total.
4. The gathering system and gas pipeline share some sites.
5. Infrastructure includes access roads, barge landing sites, camps, pipe storage
locations, borrow sites and airstrips, some of which will be required for operations.
and efficient construction, including a travel
lane for the large construction equipment
required (see Figure 5-1). During construction,
1249_NEB_MGP_Vol2_Text_ENG.indd 101
Private land1,2
(ha)
4
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102 Mackenzie Gas Project • Volume 2: Implementing the decision
Figure 5-1
Gas and liquids pipelines - Inuvik Area Facility to Norman Wells
Typical right of way
cross-sections
Snow and slash
from right of way
Ditch
(natural gas
pipeline)
Right
of way
limit
Spoil
Pipe area
(natural gas
pipeline)
Pipe area
(liquids
pipeline)
Ditch
(liquids
pipeline)
Common work area
and travel lane
Snow and slash
from right of way
Spoil side
(liquids
pipeline)
17.0m
7.7m
Right
of way
limit
Trencher travel lane
and lighting lane
50.0m
Gas pipeline - Norman Wells to Alberta
Trencher travel lane
and lighting lane
Ditch
(natural gas pipeline)
Work area and
travel lane
Pipe area
Snow and slash
from right of way
22.0m
Right
of way
limit
Spoil
Right
of way
limit
Snow and slash
from right of way
40.0m
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Chapter 5: Routing and land matters 103
Some concern was raised about the amount of
• stockpiling of snow;
The Proponents initially considered using some
lands required for the proposed pipelines and
• pipe welding, trench excavating, and other
of the existing Enbridge Pipelines (NW) Inc. right
related facilities. Alternatives North submitted
that particular attention should be paid to
minimizing land disturbance by using existing
right of ways and minimizing the width of
new ones. The Dehcho Elders and Harvesters
submitted that too much land is being taken for
the proposed right of way. They stated that its
of way to reduce the new proposed right of way
pipeline installation activities;
footprint. However, the much larger pipeline
• a travel lane for safely moving crews,
proposed for the Mackenzie Valley Pipeline is
equipment, and materials;
• temporary parking areas, primarily for crew
not as flexible and, therefore, could not always
transportation vehicles and equipment
parallel the same route as the existing pipeline.
servicing and maintenance vehicles; and
The proposed route does parallel the existing
• emergency shelters.
width should be reduced to only what is required
to safely build the proposed pipeline, rather than
taking extra land just to make the construction
process easier, faster, and cheaper.
Figure 5-2
Conversely, the Lidlii Kue First Nation submitted
that they would like the right of way to be
as wide as is safely required for the Proponents
Construction
right of way
Temporary
workspace
(if required)
to do their work.
Typical land requirements
Working side
of right of way
Buried pipeline
in backfilled
trench
Temporary
workspace
(if required)
at an open-cut
watercourse crossing
The Proponents submitted that the minimum
right of way width required for safe and efficient
Slash
and
snow
pipeline construction activities varies depending
on terrain, pipeline size, the number of pipelines
Hard plug
(if required)
Spoil
storage
area
to be installed, and the access requirements
for construction and support equipment.
Assembled
pipeline
section
Slash
and
snow
The Proponents stated that the proposed
proposed for the project would allow for:
• stockpiling of loose surface materials removed
Buffer
zone
Spoil
containment
berm
50‑metre and 40‑metre right of way widths
Frozen
Watercourse
watercourse
Open cut
trench
during the grading operation;
• stockpiling of residue from the clearing
Buffer
zone
operation;
Backhoe
Vehicle
crossing
Buffer
zone
Spoil
storage
area
Slash
and
snow
Hard plug
(if required)
Slash
and
snow
Buried pipeline
in backfilled trench
Plan view, not to scale
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104 Mackenzie Gas Project • Volume 2: Implementing the decision
right of way in many locations, but the
Views of the Board
5.4 Land use planning
Proponents plan to generally maintain an
We find that, considering its nature and
undisturbed 20 to 100-metre wide buffer of
considerations
setting, the amount of land proposed to
native vegetation between the cleared portions
be required is reasonable and justified
of the two right of ways to reduce the potential
for safe and efficient construction of
for soil thaw interaction. In special cases,
the Mackenzie Gas Project.
such as limited construction areas, the two
right of ways may be adjacent to each other.
As land governance and regional planning
in the Mackenzie Valley are in varying stages
of development, we have considered the extent
to which the Proponents have recognized and
We recognize that 29 percent of the total
considered known land use planning objectives
length of the Mackenzie Gas Project and
in their project design.
The Joint Review Panel accepted that the
44 percent of the proposed Mackenzie
proposed widths of the various sections of
Valley Pipeline route pass through the
the right of way are necessary and appropriate
Dehcho Region, where there is concern
for safe and efficient construction. The Joint
about the proposed width of the pipeline
Review Panel further noted that it heard
right of way. We note that the Proponents
no evidence that would justify any widening
have identified lands in their permanent
of the right of way sections.
right of way that may not be needed for
the long-term operation of the Mackenzie
Valley Pipeline, namely the trencher travel
lane and lighting lane as indicated in
Figure 5-1. We expect the Proponents to
give further consideration to opportunities
The Mackenzie Valley Resource Management
Act establishes the land use planning authorities
and frameworks for settlement areas in the
Mackenzie Valley, including the Gwich’in and
Sahtu Settlement Areas. Section 46 of the
Mackenzie Valley Resource Management Act
requires that federal and territorial bodies
having authority to issue authorizations relating
to land or water use or the deposit of waste,
exercise their authority in accordance with the
applicable land use plan in a settlement area.
On the record
for minimizing the width of the permanent
To date, a land use plan for the Gwich’in
Narrowing the right of way
right of way and maximizing the long-term
Settlement Area has been approved, the
To enhance slope stability and reduce the need for
reclamation of lands adjacent to the
Gwich’in Land Use Planning Board is in place,
permanent right of way post-construction,
and the land use plan is being implemented.
typical 50 metre and 40 metre widths at steeper
as long as the safe and efficient operation
There is a preliminary draft land use plan for
slopes, such as at approaches to watercourse
and maintenance of the Mackenzie Valley
the Sahtu Settlement Area, although a land use
Pipeline is not compromised.
planning board has not been fully constituted
reclamation, the Proponents stated that they would
consider right of way widths narrower than the
crossings. The Proponents stated that these reduced
right of way widths would require additional clearing
and temporary off-right of way access routes, known
and its current status is unknown. Although
as shoo-flies, to safely move construction equipment.
a final land claim is not yet in place for the
Therefore, the Proponents submitted, narrowing the
Dehcho Region, the Dehcho Land Use Planning
right of way might not reduce the total amount of
cleared land. The Proponents also stated that placing
Committee issued an update to its draft land
the gas and natural gas liquids pipelines within the
use plan in November 2005. This Committee
same right of way along the proposed route from the
was established under the Dehcho Interim
Inuvik Area Facility to Norman Wells, was done with
the intention of minimizing environmental impact.
Measures Agreement, performs most of the
roles contemplated for a land use planning
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Chapter 5: Routing and land matters 105
board under the Mackenzie Valley Resource
before deciding to proceed with construction
Gas Project is approved or before construction
Management Act, and represents the land use
of the proposed pipeline.
commences. Some of these submissions, as
planning views of the Dehcho communities and
First Nations in the Dehcho Region.
The Proponents have had discussions with
and provided information to the organizations
well as other submissions, included suggestions
to complete other land governance and
conservation initiatives currently underway
Section 47 of the Mackenzie Valley Resource
developing the Sahtu and Dehcho land use plans.
Management Act requires a planning board to
The Proponents noted that generally these
determine whether an activity that has been
land use plans recognize and provide for the
referred to it or applied for, is in accordance
proposed pipeline through such means as
with the land use plan. A referral or application
defining a potential pipeline development
must be made before the issuance of any
corridor. The Proponents stated that they are
authorization by the federal body. This obliga-
awaiting further progress towards completion
tion would also apply to any further land use
of land use plans in the Sahtu and Dehcho
plans that may be finalized and approved in
regions, and that it was premature to consider
accordance with Mackenzie Valley Resource
any similar applications for amendments
Management Act.
to these draft land use plans. However,
measures for managing cumulative impacts on
the meetings with the Sahtu and Dehcho
areas of ecological and cultural importance.
organizations have provided an opportunity
The Yamoga Land Corporation submitted
to understand and address potential land
that until there is substantial progress on land
use plan consistency issues, including
use plans in the Sahtu and Dehcho Regions,
conforming to the pipeline corridor interim
no project approvals should be granted.
The Proponents have undertaken to determine
whether the Mackenzie Gas Project conforms
to existing and draft land use plans in the
Mackenzie Valley. On their own, and through the
Canadian Association of Petroleum Producers,
the Proponents held informal discussions with
Territories Protected Areas Strategy and the
Dehcho Process (land claim negotiations in the
Dehcho Region). Further, arguments made by
Joint Review Panel parties referred to the Joint
Review Panel recommendations and supported
its view that regional land use plans and
a network of protected areas are important
and possibly the most effective conservation
land withdrawal in the Dehcho Region.
Alternatives North stated that the Mackenzie
the applicable land use planning boards and
The Proponents stated that they have and
committees before filing their land use permit
will continue to comply with all finalized land
applications. These meetings helped develop an
use plans. The Proponents also stated that they
initial appreciation of the degree to which the
have addressed and will continue to address
Mackenzie Gas Project conforms to the Gwich’in
land use planning concerns in the Dehcho
Land Use Plan and is consistent with the two
Region through the Dehcho Land Use Planning
unapproved land use plans. As a result, the
Committee until a Dehcho land use planning
Proponents filed applications for amendments
board is established.
and exceptions to the Gwich’in Land Use Plan.
in the project region, including the Northwest
Valley Resource Management Act is an attempt
to put together for the Mackenzie Valley
an integrated system of land-use planning
and other elements based on the negotiated
provisions of constitutionally protected
Aboriginal land claim agreements. According
to Alternatives North, the problem is that
this system has not been fully implemented
A number of parties submitted that a
or funded, and that completing the proper
The Proponents noted that, although their
comprehensive land use planning framework
implementation of this system, as set out
amendment and exception applications to the
must be finalized and approved in accordance
in many of the Joint Review Panel’s
Gwich’in Land Use Planning Board were still in
with the Mackenzie Valley Resource
recommendations, is required to adequately
progress, they would require these approvals
Management Act either before the Mackenzie
manage the scale and pace of development
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106 Mackenzie Gas Project • Volume 2: Implementing the decision
that will come with the Mackenzie Gas Project.
The Dehcho Elders and Harvesters submitted
They maintain that having a legally-binding
Alternatives North argued that, while most of
that access to their rights in the Dehcho Territory
agreement and land use plan in place are
the Joint Review Panel’s recommendations are
for the Mackenzie Gas Project should be delayed
the only affordable and secure ways in which
aimed at government, we could and should
until the Dehcho Process has been concluded.
Dehcho interests in relation to the Mackenzie
reinforce the need for this work in any approvals
They stated that conclusion of the Dehcho
Gas Project can be represented and protected.
we may issue. Consequently, Alternatives North
Process with a final agreement would provide
recommended that, if we are not persuaded to
the Dehcho Dene with a clear and necessary
adopt the future-oriented Joint Review Panel
authority to ensure that the Mackenzie Gas
recommendations, then we should limit the
Project could only proceed in a manner
capacity of the Mackenzie Valley Pipeline to
acceptable to them and with their full involve-
23.5 Mm3/d (0.83Bcf/d) and make any future
ment in all aspects of the project. The Dehcho
expansions subject to full implementation of
Elders and Harvesters noted that the draft
the Joint Review Panel’s recommendations by
Dehcho Land Use Plan was ratified by the
governments and the Proponents. Alternatives
Dehcho First Nations in 2006, but that the
North also submitted that it supports the need
governments of Canada and the Northwest
for an approved Dehcho Land Use Plan before
Territories have yet to adopt this plan. They
the Mackenzie Gas Project proceeds, and
argued that they cannot support the Mackenzie
do this by acknowledging these matters in our
that the Dehcho Process negotiations should
Gas Project approval without a Dehcho Land
certificate conditions as in the best interests of
be completed before construction begins.
Use Plan in place to protect their rights and
sustainability and construction of the pipeline.
their sovereignty. They stated that the Dehcho
Then the National Energy Board could have
The Sambaa K’e Dene Band stated that it
Process and the Dehcho Land Use Plan need to
the ability to monitor and comment on
supports the finalization of a Dehcho land claim
be resolved before the Mackenzie Gas Project
the status of governments’ compliance to the
agreement, the approval of the Dehcho Land
can be allowed to proceed to construction.
Joint Review Panel Report recommendations,
Use Plan, the finalization of protected areas,
and establishment of a Dehcho Resource
Management Authority as a precondition to
construction of the Mackenzie Gas Project.
1249_NEB_MGP_Vol2_Text_ENG.indd 106
The Dehcho First Nations also maintained
the position that the Dehcho Process must be
concluded and that the final Dehcho Land Use
Canadian Parks and Wilderness Society argued
that the National Energy Board, as the primary
decision maker for the Mackenzie Gas Project,
should consider that as a condition of construction, existing initiatives such as the Protected
Areas Strategy be implemented ahead of
construction. Understanding that these
initiatives are outside of the National Energy
Board’s legal authority, Canadian Parks and
Wilderness Society submitted that we could
to provide encouragement for fulfilling timelines
and expectations set out for conservation and
community initiatives.
Plan be in place as soon as possible, and at least
World Wildlife Fund Canada submitted that
The Sierra Club of Canada argued that, based
before the Mackenzie Gas Project proceeds
chief among its concerns was Joint Review Panel
on the Joint Review Panel’s recommendations,
to construction, as development needs to occur
recommendation 11-3, which is to complete
we should set out conditions for the establish-
in an orderly fashion with the appropriate and
implementation of the Mackenzie Valley
ment of interim withdrawals to support
necessary land governance and planning
Five-Year Action Plan of the Northwest Territories
a network of protected areas and land use
structures in place. The Dehcho First Nations
Protected Areas Strategy prior to commence-
plans to incorporate thresholds and limits
argued that, if the Dehcho Land Use Plan
ment of Mackenzie Gas Project construction.
of acceptable change prior to commencement
had already been implemented, many of the
World Wildlife Fund Canada recommended that
of construction of the project.
Dehcho’s concerns could have been eliminated.
we clearly and publicly state that the Mackenzie
12/6/10 11:02:15 AM
Chapter 5: Routing and land matters 107
Gas Project would only be in the public interest
The Joint Review Panel also noted its view
Views of the Board
if all of the Joint Review Panel’s recommenda-
that, in the absence of a completed settlement
We are satisfied that the Proponents have
tions are implemented, even if recommendations
agreement under the Dehcho Process or an
provided reasonable assurance that they are
such as 11-3 are not within the National Energy
approved land use plan for the Dehcho Region,
working with the appropriate authorities
Board’s authority to implement.
Aboriginal interests in managing and protecting
to ensure that the Mackenzie Gas Project
traditional and non-traditional land uses and
conforms to the land use plans approved or
land access in the Dehcho Region may not be
drafted pursuant to the Mackenzie Valley
fully realized. The Joint Review Panel was of
Resource Management Act. These plans
the view that the Dehcho Process land claim
generally contemplate infrastructure
negotiations between the Dehcho First Nations
development along the proposed general
and the governments of Canada and the
route of the Mackenzie Valley Pipeline.
In its report, the Joint Review Panel accepted
that taken in isolation, the impacts from the
Mackenzie Gas Project on existing and proposed
protected areas and on the establishment of a
network of protected areas in the Mackenzie
Valley would not likely be significantly adverse.
The Joint Review Panel stated that it was satisfied
that, if the Proponents fulfill their commitments
and follow through with a process of ongoing
consultation with communities, wildlife
management boards, regulators, and Northwest
Territories Protected Area Strategy committees
during engineering design and refinement, the
quantum of those lands that remain undisturbed
would still allow for the conditions of land use
and conservation plans to be met and the
Northwest Territories should continue to be
of the highest priority to all negotiating parties.
We note that the Dehcho land claim process
However, the Joint Review Panel agrees
continues and an interim land use plan is in
with the governments of Canada and the
place for the region. Concerns from Dehcho
Northwest Territories that final approval and
communities also led to a number of route
implementation of a land claim agreement
and design changes that now form part
with the Dehcho First Nations should not
of the commitments the National Energy
be a condition precedent for approval of
Board will enforce. A number of our
the Mackenzie Gas Project.
conditions respond to Dehcho concerns
such as participation in environmental
monitoring and wildlife management.
objectives of the Northwest Territories Protected
Areas Strategy to be largely realized. The Joint
Review Panel noted that the Mackenzie Gas
Project would introduce some new development
constraints on the conditions for managing
conservation and development in the existing
and proposed land use and conservation plans.
However, this was anticipated to some extent
in these plans through identification and
reservation of an infrastructure corridor for the
pipeline, through interim withdrawal of selected
conservation lands, and through procedural
arrangements established to accommodate this
type and level of development.
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108 Mackenzie Gas Project • Volume 2: Implementing the decision
5.5 Land acquisition
5.5.1 Land ownership in
the Mackenzie Gas Project area
• 528 kilometres crosses the Dehcho Region,
• the Gwich’in Tribal Council, which provides
of which 10.4 kilometres (2 percent) is
tenure on privately owned Aboriginal lands
privately owned Aboriginal land (Sahtu private
acquired through the Gwich’in
land) and the remainder is federal Crown land
Comprehensive Land Claim Agreement, 1992;
• District Land Corporations in the Sahtu
The Proponents provided the following
administered by Indian and Northern Affairs
breakdown of lands crossed by the proposed
Canada pursuant to the Dehcho Interim
Settlement Area, which provide tenure on
Mackenzie Gas Project:
Measures Agreement; and
privately owned Aboriginal lands acquired
• 174.2 kilometres crosses the Inuvialuit
Settlement Region, of which 23.4 kilometres
(13 percent) is privately owned Aboriginal
lands (Inuvialuit private lands) and the
remainder is federal Crown land;
• 181.2 kilometres crosses the Gwich’in
Settlement Area, of which 106.2 kilometres
(59 percent) is privately owned Aboriginal
lands (Gwich’in private lands) and the
remainder is federal Crown land;
• 231.1 kilometres crosses the K’ahsho
Got’ine District of the Sahtu Settlement Area,
of which 118.9 kilometres (51 percent) is
privately owned Aboriginal lands (Sahtu
private lands) and the remainder is mostly
federal Crown land and some Government
• 0.05 kilometres crosses provincial Crown
land in Alberta.
through the Sahtu Dene and Métis
Comprehensive Land Claim Agreement, 1993;
and
The Mackenzie Gas Project’s proposed route
crosses five major land regions: the Inuvialuit
Settlement Region; the Gwich’in Settlement
Area; the Sahtu Settlement Area; the Dehcho
Region; and Alberta (see Figure 1-7). Land
ownership and administration differ in each
region. Generally, there are six different types
of landowners with which the Proponents
would have to acquire land rights. These
landowners include:
• Indian and Northern Affairs Canada,
• the Government of Alberta, which allocates
tenure on provincial Crown lands.
With the exception of those components in
the Inuvialuit Settlement Region and the small
Alberta component, the proposed Mackenzie
Gas Project route is within the area subject to the
Mackenzie Valley Resource Management Act.
Land and water boards have been established
pursuant to the Mackenzie Valley Resource
Management Act. These boards issue land use
permits that provide land tenure on Crown lands
which issues tenure on federal Crown land;
for terms of less than five years. They also issue
• the Government of the Northwest Territories,
land use permits on privately owned Aboriginal
which issues tenure on Commissioner’s
lands once access agreements have been
and municipal land (both of which comprise
reached with the respective Aboriginal authority.
of the Sahtu Settlement Area, of which
about three percent of all land in the
Within the area subject to the Mackenzie Valley
128.3 kilometres (47 percent) is privately
Northwest Territories and are concentrated
Resource Management Act, both the necessary
owned Aboriginal lands (Sahtu private lands)
within or near municipal boundaries;
land tenure from the landowner and a land use
of the Northwest Territories land;
• 270.4 kilometres crosses the Tulita District
and the remainder is mostly federal Crown
• the Inuvialuit Land Administration,
permit from the appropriate land and water
land and some Government of the Northwest
which provides tenure on privately
board must be obtained. The land use permit
Territories land;
owned lands acquired through the Inuvialuit
authorizes the proposed activity, while the land
Final Agreement, 1984;
tenure authorizes access to and occupation
of the land requested to carry out that activity.
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Chapter 5: Routing and land matters 109
5.5.2 The Proponents’
land acquisition approach
The type of land ownership along the route of
Did you know?
Land tenure instruments
a licence of occupation) is permission to do something on the land
owned by somebody else that, without such permission, would be
unlawful. Unlike a lease, a licence is not an estate or an interest in
Easement – an easement agreement is the most common agreement
the project, particularly the distinction between
the land and therefore does not carry its own title and cannot be
that a pipeline company acquires for the right to use the land for
bought or sold like other property. The holder of a licence has fewer
Crown land and privately owned Aboriginal
a pipeline. Simply put, it is the right that a pipeline company has
legal rights than the holder of a lease. The use of the licence must be
over the land of another, usually confined to that strip of land which
limited to the activity or activities authorized by the licence, otherwise
forms the pipeline right of way. The landowner still owns the land,
the licence holder may be treated as a trespasser. Unlike an easement,
but the pipeline company has acquired certain rights over that land
a licence can be revoked at will by the landowner. A pipeline company
to build and operate a pipeline. In this way, the easement is a written
may choose to obtain a licence where it needs to access and use
contract that sets out the rights of the company and the rights of
land rights would be required for the
a parcel of land for a shorter period of time and does not need extra
the landowner. The easement agreement usually covers things such
measures to maintain exclusive use of that land. An example could
proposed Mackenzie Gas Project pipelines
as: the land area subject to the easement; the size and location of
be the need to travel on a private road.
land, is an important factor in the Proponents’
approach to land acquisition for this project.
The Proponents submitted that long-term
and related facilities. Short-term land rights
under several types of land tenure instruments
the right of way; protection from liabilities; how the land will be used;
terms of payment; legal responsibilities of the pipeline company
and the landowner; and any land use restrictions. A pipeline company
would be required for temporary workspace
may offer the landowner a standard easement, but its final form and
such as crossing areas and camp sites
contents are a matter of negotiation. If the landowner sells its land,
during construction.
On federal and provincial Crown lands and
any future landowners must also follow the terms and conditions of
the easement agreement. The land remains subject to the easement
agreement until the pipeline company officially removes it.
Permit – generally, a land use permit is permission granted by the
landowner to carry out specific works or activities on a specific area
of land for a limited period of time. In the Mackenzie Valley, land use
permits are issued by land and water boards for temporary authorization (typically two to five years) of certain activities to be carried out
on a certain area of land. In the Inuvialuit Settlement Region, land use
permits are issued by the Inuvialuit Land Administration on Inuvialuit
private lands and by Indian and Northern Affairs Canada on federal
Lease – a lease agreement is an agreement whereby the landowner
Crown land. These land use permits allow for certain uses of the land
gives the right of possession to another (such as a pipeline company)
but do not convey the permission to enter and occupy that land.
for a specific period of time and for a specific amount of rent. Similar
A pipeline company must get permission from the landowner before
ments, leases, licences, and permits depending
to easements, the landowner still owns the land, but the pipeline
it can carry out its authorized activity on that land as provided for in
on the need for exclusive or non-exclusive
company has acquired the right to occupy and use the land for a
the land use permit.
the Government of the Northwest Territories
lands, the Proponents would apply for ease-
access to the right of way and related facilities.
certain purpose. The holder of a lease has certain well defined rights
which may be enforceable without the agreement of the landowner.
Temporary workspace would be authorized by
Leases are usually acquired by pipeline companies for areas where
land use permits, although other surface tenure
they need secure, enforceable rights of exclusive use for a long period
may also be required for temporary land use.
The Proponents noted that easement and right
of time, such as for building and operating surface facilities like
compressor stations and heater stations.
Access Agreement – in the Northwest Territories, an access agreement
outlines the terms and conditions, including financial arrangements, for
access on or through land with Aboriginal interest. Access agreements
may also include details on benefits. In some areas, such as the Gwich’in
and Sahtu Settlement Areas, these agreements are legislated under
land claims, and in other areas, such as the Dehcho Region, they are
Licence – a licence has different meanings, depending on the
voluntary agreements between groups. In the Mackenzie Valley, access
situation. For instance, in the Mackenzie Valley, a licence may refer
agreements also constitute permission from the Aboriginal landowner
surface access rights for a pipeline where
to an authorization for the use of waters or the deposit of waste,
or group to apply to the appropriate land and water board for a permit
exclusive possession of the land is not required,
or both, issued by a board under the Northwest Territories Waters Act.
or licence. Such permission is required before these land and water
Generally, for land tenure purposes, a licence (typically referred to as
boards will consider a permit or licence application.
of way agreements are typically used to obtain
and where the surface of the land is reclaimed.
However surface leases are typically used to
obtain sites for surface facilities such as compressor and heater stations, where a tenure holder
requires the right for exclusive, ongoing use
of the land surface.
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110 Mackenzie Gas Project • Volume 2: Implementing the decision
Land tenure agreements would also be required
ments provide for private land ownership by
consider alternative ideas. The K’ahsho
for those privately owned Aboriginal lands
the Inuvialuit, Gwich’in, and Sahtu, respectively.
Got’ine District Lands Corporation contended
crossed by the proposed Mackenzie Gas
Under the Dehcho Process, land ownership is
that the Proponents have decided to gain
Project route and facilities. These agreements
a matter between the Dehcho First Nations and
access to K’ahsho Got’ine District Lands
would either be site-specific authorizations
the Government of Canada. The Proponents
Corporation’s lands through expropriation
or an initial agreement reserving the right to
submitted that they will comply with, and
rather than expending the effort necessary
access lands and establishing a framework
respect, applicable agreements reached between
to build a trusting relationship or engage
within which site-specific authorizations or
the Dehcho and the Government of Canada
in meaningful two-way dialogue with
agreements are obtained.
through the Dehcho Process, as well as
Aboriginal landowners.
Access agreements
The Proponents recognized that securing access
and legislation.
to privately owned Aboriginal lands, as well as
The Proponents noted that typically they would
unsettled lands in the Dehcho Region, requires
strike an initial agreement with an Aboriginal
a contract between itself and the landowner
private landowner, such as a district land
called an access agreement.
corporation, that provides a basis for securing
The Proponents noted that while there are
fewer private landowners along the proposed
a specific right of way, once its location has
been finalized and confirmed.
• The Dehgah Alliance Society asked
the Proponents if they would continue
into the project design and construction
phase in the Dehcho Region if they had not
signed an access agreement with the Dehcho
communities. The Dehgah Alliance Society
submitted that the Proponents should be
required to conclude an access agreement,
including access fees, with the Dehcho First
Mackenzie Gas Project route than in other
Issues raised by parties during the proceeding
Nations before the National Energy Board
jurisdictions, there is also less process assurance
focused on the Proponents’ approach for
approves the project.
associated with securing site-specific access
acquiring access agreements on Aboriginal
agreements over privately owned Aboriginal
lands. Some parties requested information on
neither the Proponents nor Canada has
lands. Access to the surface rights legislation,
or raised concerns regarding the status of access
respected the Sambaa K’e Dene Band’s right
boards and processes needed to secure
agreement negotiations while others submitted
and its stated preference to independently
site-specific access agreements on private land
that the Proponents should sign access
does not exist in the Northwest Territories. Land
negotiate an area-specific impact benefit
agreements with the relevant Aboriginal groups
claim agreements provide for surface rights
agreement with the Proponents. The
before the project is approved. For example:
Sambaa K’e Dene Band submitted that if the
• The K’ahsho Got’ine District Lands
Proponents continue to refuse its request to
legislation, but it has not been acted upon.
1249_NEB_MGP_Vol2_Text_ENG.indd 110
applicable land claims agreements, treaties,
• The Sambaa K’e Dene Band argued that
The Proponents stated that they are negotiating
Corporation asked the Proponents how many
enter into negotiations, then Canada must
access agreements with all the Aboriginal
Aboriginal landowners had signed access
address section 35 accommodation matters
landowners recognized in land claim agree-
agreements and why they chose to file their
relating to impacts to traditional land use
ments, in addition to the Dehcho First Nations,
project application before access agreements
before the issuance of a certificate for the
for the areas crossed by the proposed route. The
were in place. The Corporation submitted that
Mackenzie Gas Project, so we can be assured
Proponents noted that the Inuvialuit, Gwich’in,
the Proponents are not prepared to modify
that the project will have unchallenged access
and Sahtu Dene and Métis land claim agree-
their standard form access agreements or
to the land required for the project.
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Chapter 5: Routing and land matters 111
• The Dehcho Elders and Harvesters submitted
with the K’ahsho Got’ine District, and are still
any National Energy Board bulletins and guides
that Dehcho corridor communities must be
in negotiations with the Dehcho First Nations
that outline the rights and remedies available to
covered by an access agreement granting
to obtain a similar access agreement for
landowners. The Proponents also submitted that
permission to use Dehcho traditional lands
the Dehcho Region.
there is no standard access or tenure agreement
before the Mackenzie Gas Project is allowed
to proceed.
• The Liidlii Kue First Nation stated that
we must require as a condition of approval
that the Proponents enter into a benefits
agreement with Liidlii Kue First Nation
and the Dehcho First Nations that meets
the needs of all of them fairly.
• The Dehcho First Nations stated that access
agreements and benefits agreements
are required before the final pipeline route
is approved, and that permission for the
The Proponents indicated that negotiating
access agreements is intended to precede the
start of construction, and that site-specific
access agreements need to be concluded with
all private Aboriginal landowners in order to
satisfy regulatory requirements for issuing land
specific to the Mackenzie Valley Pipeline, and
the terms, conditions, and compensation are to
be negotiated. These agreements would include
the provisions required by subsection 86(2) of
the National Energy Board Act and applicable
land claim agreements.
use permits. The Proponents stated that they
The Proponents submitted that, as of
have offered, and continue to offer, to negotiate
April 2010, benefit and access agreements
mutually acceptable access agreements for the
have been negotiated in all regions except
Dehcho Region and the K’ahsho Got’ine District
the Dehcho Region.
in the Sahtu Settlement Area.
Proponents to access Dehcho traditional
The Proponents also submitted that concluding
Views of the Board
lands will only be granted through
site-specific access agreements with all private
We find the Proponents’ land acquisition
an access agreement.
Aboriginal landowners would require more time
approach to be appropriate, considering
after project approval, if it is granted, than is
the special circumstances of land ownership
the case for other pipeline projects because of
and administration in the Mackenzie Valley.
greater complexity and less certainty in process
We note the Proponents’ commitment
and timing. The Proponents stated that even if
to negotiate access agreements with all
they receive a certificate from us, they must still
private Aboriginal landowners. Further,
apply for, and receive, National Energy Board
we recognize the Proponents’ commitment
approval for the detailed route of the Mackenzie
to enter into access negotiations with
Valley Pipeline right of way within the identified
the Dehcho First Nations.
The Proponents stated that they have made
some progress on concluding access agreements
over these privately owned Aboriginal lands,
but that the work is not complete. Access
agreements have been executed with the
Gwich’in Land Administration and the Tulita
District Land Corporation for part of the Sahtu
Settlement Area. These two agreements include
processes under which site-specific access could
be granted. However there is still some process
associated with securing site-specific access
one-kilometre wide corridor before they can
conclude site-specific access agreements with
Aboriginal landowners.
We recognize the Proponents’ efforts
to comply with the land acquisition
requirements of the National Energy
if and when the Proponents finalize and
The Proponents stated that, for the Mackenzie
Board Act. We are of the view that the
receive regulatory approval for its pipeline
Valley Pipeline, notices pursuant to subsection
Proponents have demonstrated that
right of way and related facility site locations.
87(1) of the National Energy Board Act
they will be respectful of landowner rights
The Proponents stated that they are working
would be served on all owners of lands where
and concerns.
towards concluding an access agreement
agreements are required along with copies of
1249_NEB_MGP_Vol2_Text_ENG.indd 111
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Chapter 6
Facilities
6.1 Overview of facilities
The proposed Mackenzie Gas Project extends from the three development fields in and adjacent
to the Mackenzie Delta (see Chapter 4), south along the Mackenzie River Valley into the northwest
corner of Alberta (see Figures 1-2 and 1-3). The land changes along the route from the waterdominated Mackenzie Delta and treeless tundra to boreal forest in Alberta. Design, construction
and operation of the pipelines and associated facilities are directly influenced by the harsh northern
climate, the presence of permafrost, a unique transportation infrastructure that relies on ice
roads and the Mackenzie River and the potential effects of climate change. To address the unique
conditions of the project, the Proponents proposed a number of design innovations, including very
high pressures, high strength steel, strain-based design, the use of statistical techniques and a greater
emphasis on monitoring and subsequent intervention. A fundamental issue was the level of detail
required at the approval stage to support our decision on whether or not to approve the project.
The proposed Mackenzie Gathering System
The proposed Mackenzie Valley Pipeline is
includes upstream gathering pipelines, the
an NPS 30 (DN 750) natural gas pipeline which
Inuvik Area Facility and a natural gas liquids
would share the same right of way as the
pipeline from the Inuvik Area Facility to Norman
natural gas liquids pipeline from the Inuvik Area
Wells. The upstream gathering pipelines would
Facility to Norman Wells. It would then continue
bring a mixture of natural gas and natural
in a separate right of way into northern Alberta,
gas liquids produced at the three development
where it would connect to facilities to be
fields to the Inuvik Area Facility. At the Inuvik
constructed by NOVA Gas Transmission Ltd.1
Area Facility the natural gas liquids would be
separated from the natural gas and stabilized
before being shipped south to Norman Wells in
the NPS 10 (DN 250) natural gas liquids pipeline.
At Norman Wells the natural gas liquids pipeline
would connect to the Enbridge Pipelines (NW)
Inc. Norman Wells Pipeline on which the natural
gas liquids would be shipped in batches.
1249_NEB_MGP_Vol2_Text_ENG.indd 112
[1] NOVA Gas Transmission Ltd. filed an application with
the Alberta Energy and Utilities Board on 27 June 2006
requesting a permit to construct the proposed Northwest
Mainline (Dickins Lake Section), Northwest Mainline Loop
(Vardie River Section) and the Northwest Territories Border
Meter Station. The Alberta Energy and Utilities Board subsequently announced that it would postpone the establishment of a date for the hearing on these facilities pending
the issuance of the Joint Review Panel Report. On 29 April
2009 the NOVA Gas Transmission Ltd. system became
subject to the jurisdiction of the National Energy Board.
As a result, NOVA Gas Transmission Ltd. must file a new application with the National Energy Board for these facilities.
12/6/10 11:02:18 AM
Chapter 6: Facilities 113
6.3 Overall design strategy
The Mackenzie Valley Pipeline is designed to
Specific design issues:
operate at a pressure of 18.7 MPa (2,710 psi).
• pipeline operating temperatures;
6.2 Assessment of
engineering Issues
• pipeline materials;
• joining (including welding and
non-destructive examination);
6.3.1 Design process
The Proponents presented a three-phase
design process for the Mackenzie Gas Project:
When assessing an application for proposed
• seismic design;
conceptual engineering; preliminary engineering;
facilities, the National Energy Board considers
• slopes;
and detailed engineering design (see Figure 6-1).
the facilities’ design and proposed operation
• watercourse crossings;
The Proponents stated that the applications
to determine whether the project would be
• pipeline control systems and leak detection;
submitted to the National Energy Board were
constructed and operated in a safe, reliable
• settlement of backfill; and
based on conceptual engineering and that
and environmentally responsible manner.
• geohazards.
preliminary engineering started after the
As mentioned in Chapter 2, pipelines under
Other technical considerations:
National Energy Board jurisdiction must be
designed in accordance with the National
Energy Board’s Onshore Pipeline Regulations,
1999 and the latest versions of relevant
design codes, including Canadian Standards
Association Z662, Oil and Gas Pipeline Systems.
applications were filed.
The detailed engineering phase takes into
• air emissions;
account the information from the previous
• pressure testing;
design phases, inputs from the regulatory phase
• support infrastructure;
• northern logistics and construction;
• right of way protection; and
• monitoring and surveillance plans.
and additional information collected through
field investigation programs. Detailed engineering results in products which can be used to
initiate contracting and construction activities
A number of engineering issues were examined
and would not start without project approval.
in our hearing, some unique to the northern
climate, others typical of pipelines in Canada.
These issues are grouped into the following
categories and discussed in this chapter.
Overall design strategy:
• design process;
• cost estimate;
• stress-based and strain-based design,
including consideration of frost heave
and thaw settlement; and
Figure 6-1
Environmental
studies
• hydraulic design and proposed configuration
Environmental
Impact Statement
and applications
Regulatory
review
Recommendations, regulatory
decisions and conditions
Engineering design
process
of the Mackenzie Gathering System,
the Mackenzie Valley Pipeline and
Workshops
station facilities.
Conceptual
engineering
Information requests
public hearings
Preliminary engineering:
- Route and design refinements
- Site-specific studies
Detailed
engineering
Construction
1249_NEB_MGP_Vol2_Text_ENG.indd 113
Operations
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114 Mackenzie Gas Project • Volume 2: Implementing the decision
6.3.2 Cost estimate
Costs for various project components were
derived from different sources. The Proponents
The initial cost estimate for the Mackenzie
submitted that materials and equipment costs
Gas Project was prepared by the Proponents
were based on estimates from suppliers for
based on the proposed scope of work at the
larger items such as pipe and valves and from
completion of the conceptual design phase.
the Proponents’ own data or manufacturers’
After filing the application, the preliminary
engineering phase began. This resulted in
revised cost estimates, which were based on:
• improved definition of project materials
and labour;
• project construction plans; and
of the ground surface caused by the formation
of ice in the soil.
Thaw settlement – the settlement of the ground
under its own weight or applied stresses caused
and infrastructure. Construction cost estimates
by the loss of ice due to melting.
included allowances for:
Strain-based design – designing a pipe by setting
• northern conditions; and
us and are shown in Table 6-1 and Figure 6-2.
• proposed construction methods.
The capital cost estimate included expenditures
allowance for funds used during construction.
by the pipe at any given location in response
turers’ recommendations. By comparison,
These revisions were subsequently filed with
costs and construction, but excluded an
Stress – the force per unit area experienced
Frost heave – the upward or outward movement
• contractor input;
for engineering design, procurement, owners’
dimensions resulting from the applied loads.
spares were estimated on the basis of manufac-
• past experience;
• costs of the regulatory process.
Strain – the deformation or change in pipe
to the applied loads.
detailed construction industry data for pipelines
watercourse crossings;
Definitions
price lists for smaller times. The capital costs for
construction cost estimates were based on
• designs for slope stability and
Did you know?
the limit (or maximum amount) of deformation
that it can safely sustain.
Stress-based design – designing a pipe that can
safely accommodate the predicted combination
of internal and external loads without permanent
deformation.
A specific set of allowances for specific project
Thermal load – changes in temperature result in
risks and a contingency allowance based on
expansion or contraction of the pipeline (strain)
the level of definition for each major project
which in turn induces a stress on the pipeline.
component were also factored into the cost
estimate. The Proponents submitted that the
Table 6-1
Project expenditures 2007 update
Estimated cost
Project component
Niglintgak
(2006$ million)
800
method used to prepare and revise the capital
6.3.3 Stress-based and
cost estimate is consistent with the Association
strain-based design
for the Advancement of Cost Engineering
The Mackenzie Gas Project would be
International’s recommended practice for
constructed and operated in Canada’s harsh
process industries.
northern environment through terrain containing
Taglu
1,750
Parsons Lake
1,200
varying amounts of permafrost. The design
Mackenzie Gathering System
3,500
of pipelines in permafrost terrain requires
Mackenzie Valley Pipeline
7,050
Total initial cost
14,300
consideration of the thermal properties of the
ground, the pipe and the product being shipped,
and presents a number of unique geotechnical
Future Mackenzie Valley
Pipeline facilities
Future anchor field investments
Total cost
1249_NEB_MGP_Vol2_Text_ENG.indd 114
800
1,150
and structural engineering challenges. Freezing
and thawing of the ground can cause frost
heave, thaw settlement and slope instability.
16,250
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Chapter 6: Facilities 115
These ground movements impose stresses
designed to meet the stress limits in Canadian
and strains on the pipeline that need to be
Standards Association Z662-07, Oil and Gas
considered during design, construction and
Pipeline Systems while secondary loads such
operation. Construction activities can disturb
as frost heave and thaw settlement would
the permafrost and alter terrain conditions.
be designed using a strain‑based limit state
remain constant for long periods of time, such as
design methodology.
the pipeline’s weight or that of the soil over the pipe.
is based on allowable stresses. This approach
The Proponents stated that the overall design
during the pipeline’s operation and can vary over
measures or predicts the combination of
approach relies on strain monitoring and
internal and external loads a pipeline can safely
mitigation during operation. A Geopig® tool
These loads are grouped into primary or secondary
withstand without deforming during operation.
travelling inside the pipe is able to determine
loads for pipeline design purposes.
Information needed for stress-based design
longitudinal strains. When the strain at a given
Primary loads create stresses or forces within the
includes an understanding of the site-specific
location is approaching the serviceability strain
geotechnical properties of the soil around the
limit, the Proponents would take action such as:
pipe and its potential for interacting with pipe.
• reducing the size and rate of frost bulb
The conventional approach to pipeline design
These properties include soil type, presence of
growth;
Did you know?
Stress-based and strain-based design
Pipelines are designed to withstand a number
of different loads. Some loads are permanent or
Operational loads such as internal pressure occur
time. Environmental loads such as frost heave and
thaw settlement can be of short or long duration.
pipe as long as the load is applied. The loads can
be permanent or operational and if the stress in the
pipeline were allowed to exceed the peak strength of
the steel, the pipe would fail. The pipeline’s internal
pressure is an example of a primary load. Canadian
Standards Association Z662, Oil and Gas Pipeline
groundwater or permafrost, and the magnitude
• reducing resistance to pipe movement;
and likelihood of slope movements, seismic
• reducing settlement;
events or other geohazards.
• providing additional pipe support;
stress-based design, and most pipelines in Canada
An alternative approach is strain-based design,
• replacing the pipe; or
are designed using this method.
which focuses on the pipe’s material and its
• relocating the pipe.
Secondary loads are generated within the pipe as it
behaviour. The pipeline designer sets boundaries
The Proponents submitted that specific
or limits, referred to as limit states, which define
the maximum amount of strain the pipe can
intervention criteria for pipeline strain would
be developed.
active monitoring to identify where and how
Following from this approach to overall project
fast the pipeline is changing or deforming.
design, two issues arose during the hearing:
lifespan engineering approach for the Mackenzie
Gas Project that includes a combination of stress
and strain -based design, construction mitigation
and operational monitoring and interventions to
ensure the integrity of the pipeline. The primary
loads on the Mackenzie Valley Pipeline, such
from primary loads be limited to a certain percentage
of the yield stress of the pipe. This is referred to as
conforms to environmental loads. In order to design
safely tolerate. This approach, however, requires
The Proponents stated that they would use a
Systems requires that stress combinations resulting
pipelines to resist secondary loads, it is necessary to
determine the size of the secondary load and the
amount of deformation the pipe can safely sustain
(called strain capacity or allowable strain). Pipelines
designed to resist secondary loads in this way are
called strain-based design pipelines.
• the applicability of using a strain-based
design for the Mackenzie Valley Pipeline
and the Mackenzie Gathering System; and
• the type, amount and timing of site-specific
geotechnical information required by the
applicant in the design and regulatory
approval processes.
as internal pressure and dead weight, would be
1249_NEB_MGP_Vol2_Text_ENG.indd 115
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116 Mackenzie Gas Project • Volume 2: Implementing the decision
These issues are inter-related and are addressed
Frost heave and thaw settlement
below in the context of frost heave and
The Mackenzie Gas Project pipelines would be
thaw settlement along a northern pipeline.
subject to environmental loads, such as large
The availability of site-specific geotechnical
temperature differentials between construction
piping on the Mackenzie Gathering System without
information is also addressed in the context of
and operation, frost heave and thaw settlement,
heat tracing would be -53oC. With insulation and
the specific design issues related to watercourse
which are not commonly encountered by
crossings and geohazards such as seismic risks
conventional onshore pipelines. The Proponents
and slope stability.
indicated that several factors contribute to the
On the record
Pipeline design temperatures
The Proponents stated that the minimum design
temperature for exposed, above ground high pressure
heat tracing the minimum design temperature for
above ground piping would be -45oC. The Proponents
reviewed 40 years of Environment Canada climate
data for Inuvik, and the lowest minimum average
daily air temperature recorded was -53oC.
The preliminary design phase, including
engineering design calculations such as those
for the combination of external forces that
Did you know?
could be imposed on the pipe, was ongoing
Frost heave and thaw settlement
at the time of the hearing. Detailed design
The Mackenzie Valley Pipeline and Mackenzie
and the gathering of the necessary remaining
Gathering System would be buried in areas
containing permafrost, giving rise to design issues
site-specific route information would not start
related to frost heave or thaw settlement depending
unless the project is approved, and would
on local ground conditions. The resulting loads
continue until construction begins on each
exerted on the pipe would vary depending on the
presence of groundwater, the porosity of soil and
facility or pipeline construction spread.
loading conditions, including the unfrozen span
length and the number of unfrozen spans per
kilometre. The Proponents stated that statistical
distributions best characterized these factors, as
well as the strain capacity of the pipe. This made
probabilistic methods suitable for assessing
design safety and estimating the number of
operational interventions that may be required
during the life of the pipeline. Various simulation
programs including finite element analyses were
used to determine serviceability strain limits.
the temperature of the ground relative to the pipe
at a given location. Where the pipe temperature is
below 0oC and the surrounding ground is initially
unfrozen, such as in taliks beneath rivers, a frost bulb
may grow around the pipe, applying uplift forces
over the affected span of pipe. Where the pipe
temperature is above 0oC and the ground is frozen,
any thawing may cause the ground to settle, leaving
unsupported spans of pipe. If a pipe crosses through
ground with varying soil types and ice contents,
differential settlement or heave may occur, causing
Figure 6-2
Frost heave
localized stresses and strains on the pipe.
Stable frozen soil helps hold the pipe in place
As soil freezes around pipe, ice
forms and heaves the pipe upward
Frozen soil
1249_NEB_MGP_Vol2_Text_ENG.indd 116
Unfrozen soil
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Chapter 6: Facilities 117
Strain capacity
construction challenges (see Chapter 5), and
The limit state design methodology (Canadian
that it was not practicable to collect new
Standards Association Z662-07, Annex C)
geotechnical and geothermal data to further
considers all phases of the pipeline life span,
optimize the route. The Proponents mapped
the combination of loads and the properties
geotechnical conditions by terrain class. The soil
and deformation.
of the materials to be used. The value of the
properties for each terrain class were established
In-line inspection – the use of internal inspection
compressive strain limit for the Mackenzie Gas
using statistical methods. The Proponents
tools, which travel inside the pipeline, to carry out
Project pipes is expected to be 1.5 percent and
submitted that pipeline strain calculations
the tensile strain limit is 2.0 percent. Although
based on this information would not take
these strain limits were determined analytically,
into account all areas of high frost heave and
the resulting values were confirmed through
thaw settlement. As a result, the pipe may be
several laboratory verification tests. The
installed in an area with soil properties that
Probabilistic methods – pipe properties and loads
Proponents considered several combinations of
produce higher values of frost heave and thaw
used in design are not discrete numbers but are
internal and external forces during the iterative
settlement than established for the terrain class.
deemed to be a range of values, each with a certain
design process. The most significant forces were
Limit states would be set for the ultimate tensile
internal pressure, frost heave (see Figure 6-2)
strain, within which the pipeline’s integrity is
based on the desired degree of confidence and
and thaw settlement (see Figure 6-3).
maintained, and for serviceable compressive
conservatism and determine the likelihood that
Strain demand
For the overland design, the Proponents
strain, whereby the pipeline would initially
buckle but would not leak.
submitted that they used pipeline route
The Proponents submitted that it was not
selection criteria to avoid design and
practical to collect detailed soil and temperature
Did you know?
Definitions
Geopig® – a brand of internal inspection tool
that can be used to determine pipe location
an inspection.
Longitudinal strains – elongation or compression
of the pipe along its length.
Span lengths – the length of pipeline over which
the load or deformation occurs.
probability of occurrence based on statistical data.
Designers select the design load and pipe properties
a particular limit state will be exceeded.
Strain capacity – the amount of deformation
the pipe can safely tolerate.
Strain demand – amount of deformation caused
by internal and external forces.
Serviceability strain limit – the point at which
a deformity will cause the pipeline to become
inoperable, but not cause a loss of containment.
Ultimate strain limit – the point at which a pipeline
deformity will cause a loss of containment.
Figure 6-3
Thaw settlement
Stable unfrozen soil helps hold the pipe in place
Unfrozen soil
1249_NEB_MGP_Vol2_Text_ENG.indd 117
Ground settles as ice-rich
permafrost around pipe thaws
Frozen ice rich soil
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118 Mackenzie Gas Project • Volume 2: Implementing the decision
On the record
Iterative design process
The Proponents’ pipeline design process for the
conceptual and preliminary design phases includes
data in sufficient detail to support site-specific
design. To illustrate, the Proponents pointed out
that changes between permafrost and unfrozen
ground conditions can occur over tens of metres
Effect of heat transfer
Heat transfer between the pipe and the soil will
cause water in the soil to freeze or ice in the soil
the following steps:
and changes in ice content can occur within
to thaw depending on the pipe temperature,
• Conduct hydraulic modeling (system design) to
metres. Consequently, the Proponents’ design
the ground temperature and the time of year.
establish the pipe sizes, grade, wall thicknesses,
operating temperatures and pressure profiles,
and compression requirements.
• Conduct thermal modeling to predict the
approach incorporated a requirement to
The growth of frost or thaw bulbs around the
pipeline over successive years can cause frost heave
monitor pipeline loads which accumulate slowly
or thaw settlement forces, respectively, to develop
over several years, such as frost heave and thaw
on the pipeline. Disrupting the insulating vegetative
mat during pipeline construction will also affect
potential for frost heave and thaw settlement
settlement loads. After several years, these loads
using the temperature profile.
may reach specific values that would require
the soil, further altering the permafrost regime
the Proponents to take action. The Proponents
beneath the right of way. In addition to displacement
• Conduct structural modeling to predict the
potential for frost heave and thaw settlement
effects over time. This is known as strain demand.
submitted that with this approach, detailed
the rate of heat transfer between the air and
of the pipe by frost heave and thaw settlement,
the span over which the displacement occurs also
mapping of the geotechnical and geothermal
impacts the magnitude of the bending strains
the tensile and compressive strains predicted
conditions for most of the route would not be
(strain demand) imparted to the pipe.
by the structural modeling. This is known
necessary for conceptual or preliminary design.
• Model the capability of the pipe to sustain
as strain capacity.
• Compare the calculated strain demand as it
Other loads, such as those which may be rapidly
varies over time to the design strain demand
applied and those typical of most pipelines
to ensure pipeline integrity.
would be accounted for in the base design
recommended that the geotechnical and
for the pipeline.
thermal data be presented to the National
• Check the heave and settlement displacements
and freeze and thaw bulb growth to assess
environmental impacts.
• Evaluate options for design and maintenance
Indian and Northern Affairs Canada expressed
Energy Board prior to pipeline construction.
the view that significant data on actual soil
The Proponents indicated that extensive
properties and ground temperatures along the
airborne and ground-based geophysical surveys
pipeline route would be required to accurately
were planned before the start of construction to
requirements are met, strain demand and strain
model frost heave and thaw settlement on
delineate the presence of permafrost along the
capacity are balanced and the environmental
the pipeline. To delineate permafrost along
entire route. Furthermore, an extensive borehole
the entire pipeline route, Indian and Northern
program would be undertaken during the
Affairs Canada recommended that the
geotechnical verification program to be carried
Proponents use geophysics and additional
out in the two-year period preceding pipe-laying
boreholes, collect ground temperatures at more
operations. The data on permafrost distribution,
frequent intervals along the right of way than
ground temperature measurements and soil
proposed by the Proponents and develop a
data would be used to revise the preliminary
detailed characterization of soils in support of
estimates of frost heave and thaw settlement
frost heave and thaw settlement assessments.
during final engineering design. It would also
Indian and Northern Affairs Canada further
be used by the Proponents to identify regions
and make changes to the temperature limits,
pipe sizes, pipe grades and pipe wall thicknesses
• Repeat the above steps until the system design
impacts are acceptable.
1249_NEB_MGP_Vol2_Text_ENG.indd 118
On the record
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Chapter 6: Facilities 119
of high heave and settlement potential and to
Climate Change
refine monitoring and intervention programs
The Proponents found that mean annual soil
during operations.
temperatures are typically about 4.5oC warmer
The Proponents stated that heavy wall pipe
would be used for watercourse crossings but
was not being considered as an option for
frost heave and thaw settlement mitigation.
It would be impractical to delineate all critical
permafrost occurrences in time to procure
heavy-wall pipe. The Proponents submitted
that the approach adopted for the project was
to design a pipeline with a tolerance for frost
than mean annual air temperatures and surface
On the record
Data collection
The Proponents submitted that the conceptual
design work required a significant amount of
disturbance can increase the mean ground
information about the route. Data collected using
temperature by about 2 C. At the development
global positioning systems and light detection and
o
fields the ground temperatures vary from about
-4oC at Niglintgak to -7.6oC at Parsons Lake.
ranging (LiDAR) and incorporated into geographic
information systems made it unnecessary for the
Proponents to clear the centreline of the route for
land surveys before construction. The Proponents
Temperatures rise to the south, where the
used the large volume of existing geotechnical
mean ground temperatures are about -3 C
o
in Fort Good Hope and -2oC in Norman Wells
in undisturbed areas.
and geothermal data from previous highway
and pipeline studies, and incorporated some new
project boreholes to populate its project borehole
database. Information collected from the design
heave and thaw settlement and use monitoring
Climate change data shows a warming trend
and construction of the Enbridge Pipeline (NW) Inc.
and interventions during operations to detect
in the Mackenzie Valley which may affect
Norman Wells Pipeline, specifically the geophysical
and address local areas of high-strain demand
the distribution of permafrost over the life of
as they actually occur.
the pipeline. The Proponents established values
Route temperature measurements collected during
for climate warming for different regions within
the 1970s and 1980s were available for conceptual
the project area for consideration in its design,
Did you know?
shown in Table 6-2.
than the general design requirement is capable of
profiles of the permafrost south of Norman Wells.
engineering from a Geological Survey of Canada
database. This information was supplemented by
new information from the Geological Survey of
Definitions
Heavy wall pipe – pipe with a greater wall thickness
survey and ditch logs, provided nearly continuous
Canada and the Proponents. The Proponents plan
to collect additional geotechnical and geothermal
Table 6-2
information including probe holes, test pits,
tolerating greater stress and is more resistant to
Regional climate-warming rates selected
geotechnical boreholes with sampling and
deformation (can absorb more strain energy).
by the Proponents
geophysics after the right of way is cleared.
LiDAR – a technology that employs an
Climate warming rate
airborne scanning laser to measure the elevation
Region
(ºC/year)
of the ground.
Inuvik
0.094
Piezometers – instrumentation used to measure
Norman Wells
0.05
Fort Simpson
0.076
in areas where frost heave is anticipated allows
Northern Mackenzie Valley
0.072
the pipeline to displace more evenly over the entire
Southern Mackenzie Valley
0.063
pore water pressure in soil.
Reduced pipe cover – reducing pipeline cover
span length, relieving the heave induced stress and
reducing the total strain experienced by any one
discrete pipe segment.
Thermistor – a device used to measure temperature,
relying on the change in its electrical resistance with
changing temperature.
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120 Mackenzie Gas Project • Volume 2: Implementing the decision
The thermal modeling used in the development
and post-abandonment. The Joint Review
Views of the Board
of frost heave and thaw settlement predictions
Panel was of the view that this analysis should
We are of the view that the Proponents’
was based on historical trends in air temperature
be conducted for a series of representative
use of a lifespan engineering approach
warming rates at locations along the route
locations, conditions and terrain types and
for the Mackenzie Gas Project that includes
(Inuvik, Norman Wells and Fort Simpson) rather
should incorporate climate variability and,
a combination of stress and strain-based
than general climate models. Mr. Doug Ritchie
in particular, upper limit temperature scenarios
design, construction mitigation and
raised concerns that the thermal modeling used
to account for the range of future temperature
operational monitoring and interventions
did not include rigorous general climate models,
conditions, including their variability and
to ensure the integrity of the pipeline
as used by other organizations for predicting
extremes, and the impact of this variability on
is acceptable for the project.
climate warming in the Arctic. The Proponents
stream flow regimes. The Joint Review Panel
responded that historical trends for sites along
added that the results should be incorporated
As stated in Chapter 3, we are satisfied with
the route represented the best information for
into the monitoring, mitigation and adaptive
the Proponents’ climate change estimates
pipeline design and resulted in a higher and
management plans. The Joint Review Panel
used in the design. Given the uncertainty
therefore more conservative rate of climate
thought that this analysis should be provided
regarding climate change predictions, a
warming than the rate predicted by available
to other appropriate regulators in sufficient
prudent step would be to assess the design
general climate models.
time for review and to provide input to
using upper limit temperature scenarios as
the National Energy Board.
recommended by the Joint Review Panel. As
The Joint Review Panel was generally satisfied
the name implies, upper limit temperature
that the Proponents had taken climate change
Indian and Northern Affairs Canada argued
scenarios would be less likely to occur than
into account in their design. Nevertheless the
that the Proponents should consider how these
what has been used by the Proponents for
Joint Review Panel recommended that we
upper limit scenarios influence their predictions
the design of the project. Condition 6
require the Proponents to file final design plans
regarding pipeline integrity in particular for
requires the Proponents to submit a report
that incorporate further analysis of the impacts
those areas where permafrost may degrade
which includes an analysis of the impacts of
of climate change on permafrost and terrain
over the life of the pipeline.
climate change and variability on
stability over the design life of the project
permafrost and terrain stability for a series
of representative locations and conditions
using potential upper limit temperature
scenarios which may occur along the
pipeline. The analysis is to include potential
impact on slope and water course crossing
design. We have not specified how the
study should be structured. We are of the
view that, as part of this study, government
departments such as Environment Canada,
Indian and Northern Affairs Canada and
Natural Resources Canada should be
consulted to benefit from their expertise.
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Chapter 6: Facilities 121
6.3.4 System design and configuration
Mackenzie
Bay
Amundsen Gulf
To accomplish the stated project objective of
KP
Tuktoyaktuk
Mackenzie Valley Pipeline
kilometre post
Facility site
delivering natural gas and natural gas liquids
from the Mackenzie Delta to existing pipeline
infrastructure in Alberta, the Proponents
proposed a system of gas and liquids gathering
pipelines, station facilities and a large diameter
Gas conditioning facility
Inuvik
Aklavik
Proposed Alberta pipeline route
Gathering pipelines route
KP-0
Liquids pipeline and gas pipeline route
Inuvik Area Facility
Gas pipeline route
Fort McPherson
Tsiigehtchic
Regional boundary
Production field
Significant discovery licence area
Mackenzie Gathering System will transport both
100
50
0
100
Kilometres
natural gas and liquids from the anchor fields
be measured, separated and prepared for
Loon River North
future compressor
station
Colville Lake
N o r t h w e s t Te r r i t o r i e s
Fort Good Hope
KP-275
Nunavut
N u n a v u t
transmission south to interconnections with
Great Bear
Lake
existing pipeline infrastructure. The separated
natural gas will be compressed and shipped
KP-540
Tulita
Yu k o n
Tuktoyaktuk
Taglu
Great Bear River
compressor station
south to an interconnection in Alberta via the
Mackenzie Valley Pipeline.
Kendall Island
Bird Sanctuary
Déline
KP-457
st
Norman Wells in a dedicated liquids line while
Norman Wells
Enbridge interconnect
facility
Niglintgak
n
an
Ch
el
Ea
natural gas liquids will be transported to
Mackenzie
Gathering System
Future facility site
natural gas transmission pipeline. The proposed
to the Inuvik Area Facility where receipts will
Figure 6-4
Parsons Lake
A primary consideration of the system design
is selecting an initial system capacity that meets
Wrigley
M
ac
nz
ke
the requirements for immediate hydrocarbon
r
ive
account requirements for future gas and liquid
shipments. The final system design will specify
Storm Hills
Jeanfacility
Marie River
Pigging
composition, temperature and pressure selected
parameters in turn are used to determine the
pipeline materials that will be necessary. The
throughput capacity of an existing pipeline can
Yellowknife
Fort Simpson
the combination of pipeline diameter, fluid
to achieve the desired system capacity. These
Rae
R
ie
transportation commitments and takes into
Fort Providence
Inuvik Area Facility
Trout River
KP-1098
Fort Liard
British Columbia
Trout Lake
Aklavik
KP-1196
Hay River
Kakisa
Inuvik
Enterprise
Interconnect facility
(located in Alberta)
Alberta
be increased by adding pumps, compressors or
pipeline loops during the lifespan of the project.
1249_NEB_MGP_Vol2_Text_ENG.indd 121
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122 Mackenzie Gas Project • Volume 2: Implementing the decision
from the Niglintgak, Taglu and Parsons Lake
On the record
Design considerations
When designing the Mackenzie Gathering System,
the Proponents considered:
which extends 26.4 kilometres from the
the volumes committed by MGM Energy
Parsons Lake gas conditioning facility to
Corp. to the Inuvik Area Facility;
the Storm Hills pigging facility with a design
the gas produced;
• potential locations for gas processing;
pressure of 12.2 MPa (1,770 psi); and
• the NPS 32 (DN 800) Storm Hills lateral which
• an approximately 457-kilometre long NPS 10
extends 67.2 kilometres from the Storm Hills
• potential locations of dehydration facilities;
(DN 250) pipeline to transport natural gas
pigging facility to the Inuvik Area Facility with
• minimization of the environmental footprint;
liquids from the Inuvik Area Facility to
a design pressure of 12.2 MPa (1,770 psi).
• existing infrastructure;
Norman Wells; and
• total costs over the life of the project;
• above-ground and buried pipeline alternatives;
• block valves, pigging facilities, and meter
• input from community consultation;
stations for the gathering pipelines and
• field delivery pressures;
the natural gas liquids pipeline.
• delivery pressures entering the gas
processing facility;
• accommodation for gas volumes from 24 Mm /day
3
The design of the upstream gathering pipelines
is based on natural gas production volumes from
the three development fields and other potential
sources in the Mackenzie Delta. The natural gas
The Mackenzie Gathering System would have
and natural gas liquids mixture would be
the capacity to deliver about 30.9 Mm3/d
dehydrated at the development fields and
(1.1 Bcf/d) of natural gas to the Mackenzie
shipped to the Inuvik Area Facility for processing
• pipeline operating temperatures in permafrost;
Valley Pipeline and to transport about 4000 m3/d
in lateral pipelines designed for two phase flow.
• pipe sizes from NPS 12 to 36 (DN 300 to 900); and
(25,200 Bbl/d) of natural gas liquids from
The upstream gathering pipelines are designed
• pipeline material grades up to 483 MPa (X70).
the Inuvik Area Facility to Norman Wells.
to carry volumes of up to 30.9 Mm3/day
The approximate capital cost of the Mackenzie
(1.1 Bcf/d) in the summer. This could be
Gathering System is $3.5 billion (2006$).
expanded by looping portions of the lateral
It is scheduled to be in service in 2018.
pipelines or by adding new laterals, additional
(.85Bcf/d) to 34 Mm /day (1.2 Bcf/d);
3
Figures 6-4 and 6-5 illustrate the proposed
configuration of the Mackenzie Gathering
System and Mackenzie Valley Pipeline, described
in greater detail in the following sections.
The Proponents submitted that the proposed
Mackenzie Gas Project system is expandable
through the addition of laterals and facilities
on the Mackenzie Gathering System and
the addition of up to 11 compressor stations
along the Mackenzie Valley Pipeline.
Design of the Mackenzie Gathering System
1249_NEB_MGP_Vol2_Text_ENG.indd 122
natural gas fields (development fields) and
• the Inuvik Area Facility, which would process
• historical and existing pipeline routes;
• the NPS 18 (DN 450) Parsons Lake lateral
Mackenzie Gathering System – upstream
compression or liquid handling facilities.
gathering pipelines
Mackenzie Gathering System – natural gas
The gathering pipelines upstream of the
liquids pipeline
Inuvik Area Facility (Figure 6-6) consist of:
The Proponents determined that the best
• the NPS 16 (DN 400) Niglintgak lateral which
design for the pipelines south of the Inuvik
extends 14.7 kilometres from the outlet of
Area Facility would be to use two single-phase
the Niglintgak gas conditioning facility
pipelines. One pipeline would be for natural
to the Taglu gas conditioning facility with
gas, as discussed in following sections, and
a design pressure of 12.9 MPa (1,870 psi);
the other would be for the natural gas liquids.
• the NPS 26 (DN 650) Taglu lateral which
The Proponents chose a buried NPS 10
The Mackenzie Gathering System includes:
extends 80.9 kilometres from the Taglu
(DN 250), Grade 359 (X52) pipe with a wall
• approximately 190 kilometres of NPS 16,
gas conditioning facility to the Storm Hills
thickness of 7.8 millimetres and a maximum
18, 26 and 32 (DN 400, 450, 650 and 800)
pigging facility with a design pressure of
operating pressure of 9.93 MPa (1440 psi)
gathering pipelines to transport production
12.2 MPa (1,770 psi);
for the liquids pipeline. The 457.2‑kilometre
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Chapter 6: Facilities 123
long natural gas liquids pipeline would
Mackenzie Explorer Group presented evidence
terminate at the Enbridge Pipelines (NW) Inc.
which indicated that the nominal capacity of
pump station in Norman Wells where a pig
the system would be 30.4 Mm3/day
receiver and block valve would be installed.
(1,075 MMcf/d). This would leave 8.65 Mm3/day
No pump stations would be required between
(305 MMcf/d) of available, non-contracted
would be three 7.1 Mm3/day (~250 MMcf/d)
the Inuvik Area Facility and Norman Wells for
capacity of which 5.1 Mm /day (180 MMcf/d)
expansions north of the Inuvik Area Facility and
the initial operation. The line’s initial capacity
is available at Taglu and the remainder is
would be about 4000 m3/day (25,200 Bbl/d),
available south of the Storm Hills pigging
which could be increased to about 6700 m /day
facility. Mackenzie Explorer Group stated that
(42,150 Bbl/d) with two additional pump
the design philosophy upstream of the Inuvik
stations. From Norman Wells, the liquids
Area Facility did not match the downstream
would be carried further south in batches
design philosophy. Mackenzie Explorer Group
by the existing Enbridge Pipelines (NW) Inc.
noted in its evidence that while the upstream
identified seven alternative designs for the gathering
Norman Wells Pipeline.
gathering pipelines had a maximum
pipelines and two alternative designs for the Inuvik
3
Capacity and expansion of
3
capacity of 30.4 Mm3/day (1,075 MMcf/d),
On the record
Expansion study
For the purposes of the joint Mackenzie Explorers
Group/Proponents study, it was assumed there
the fully expanded Mackenzie Gathering System
would match the Mackenzie Valley Pipeline’s capacity.
The study did not consider the potential for gas
entering the Mackenzie Valley Pipeline downstream
of Inuvik which would use available Mackenzie Valley
Pipeline expansion capacity at Inuvik.
The joint Mackenzie Explorers Group/Proponents
study submitted by Mackenzie Explorers Group
Area Facility. Of the seven pipeline alternatives, three
allowed for expansion to match the capability of the
the Mackenzie Valley Pipeline could be
Mackenzie Valley Pipeline. These alternatives are:
expanded to 48 Mm3/day (1,695 MMcf/d).
installing NPS 36 (DN 900) pipelines between Taglu
the design capacity of the upstream gathering
The Proponents and Mackenzie Explorer Group
pressure of the gathering pipelines to 18 MPa
pipelines and how it could be increased.
members Chevron Canada Resources and
However, no intervenors questioned the
BP Canada Energy Company undertook
pipeline. Of the three, Mackenzie Explorers Group
design adequacy of the natural gas liquids
a joint effort to evaluate alternatives that
favoured the 18 MPa (2,610 psi) design option
pipeline or its ability to transport present
could increase the capacity on the gathering
and future volumes of liquids.
system north of the Inuvik Area Facility for new
pipelines increases to accommodate new volumes,
natural gas discoveries. Based on this study,
additional compression would be required at each
the Mackenzie Gathering System
During the hearing, intervenors questioned
Mackenzie Explorer Group expressed the view
Mackenzie Explorer Group supports an option
that the most likely expansion of the two phase
that requires upgraded pipe and components
design proposed by the Proponents would be
to be pre-installed for future expandability.
through looping. Mackenzie Explorer Group
The Proponents estimated the cost of this pre-
believes this would probably not be the most
installation would be an additional $142 million.
and the Inuvik Area Facility; increasing the operating
(2,610 psi) to match the design of the Mackenzie
Valley Pipeline; and constructing a separate or looped
requiring upgraded pipe and components to be
pre-installed. As the pressure in the gathering
existing field for the natural gas and natural gas
liquids to flow into the upstream gathering system.
cost effective approach especially if new
natural gas production comes on line in
small increments.
In argument the Mackenzie Explorer Group
expressed the view that the higher-pressure
design of the two‑phase system is superior in
terms of total unit of capacity cost, avoiding
lumpiness of expansion and minimizing
incremental environmental impact.
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124 Mackenzie Gas Project • Volume 2: Implementing the decision
Did you know?
Definitions
Batches – quantities of oil/oil products or
condensate with particular properties owned by a
The Proponents rejected the assumption
that the ultimate capacity of the Mackenzie
Gathering System needed to match the ultimate
capacity of the Mackenzie Valley Pipeline. The
particular shipper and transported in a pipeline
Proponents pointed to the possibility that gas
between other batches.
could enter the Mackenzie Valley Pipeline at
Block valve – a valve that can completely block
locations south of Inuvik from the Colville Hills.
the flow in a pipeline in both directions.
Dense phase pipeline – under certain conditions
of pressure and temperature natural gas liquids
The Gilbert Laustsen and Jung Associates supply
study forecasted that Colville Hills production
and natural gas can be transported in a pipeline
could exceed 8.5 Mm3/d (300 MMcf/d). The
in a single phase, referred to as dense phase,
Proponents noted that MGM Energy Corp. had
which has properties between those of a gas
requested 5.7 Mm3/d (200 MMcf/d) of capacity
and a liquid. Dense phase pipelines may have
• a meter station located at the Inuvik Area
Facility; and
• a pig receiver and block valve just south of
the Alberta-Northwest Territories boundary.
The Mackenzie Valley Pipeline has a design
capacity of 27.3 Mm3/d (0.96 Bcf) with one
compressor station and 34.3 Mm3/d (1.2 Bcf)
with three compressors and heater station
in operation. The capacity could be expanded
to 49.8 Mm3/d (1.8 Bcf/d) with a total of
14 compressor stations (see Figure 6-5). Only
three compressor stations are included in the
higher wall thickness which makes them more
over the 23.5 Mm3/d (830 MMcf/d) used by the
resistant to bending stresses.
Proponents which left 1.3 Mm3/d (45 MMcf/d)
Lateral – a pipeline that connects a new supply
of capacity for other shippers. The Proponents
or a new market to the main pipeline.
noted that another 10.6 Mm3/d (375 MMcf/d)
The design selection of the Mackenzie
Looping – expansion of pipeline capacity by building
of capacity could be added with the construc-
Valley Pipeline was affected by several
tion of a compressor station at Storm Hills.
factors including:
The Proponents also stated that the capacity
• gas composition;
of the upstream gathering system could be
• operating temperatures in continuous
another pipeline adjacent to the existing pipeline.
Mass flow rate – mass of fluid transported by
the pipeline over a period of time.
Nominal capacity – the capacity that is available
year round and is determined by using historical
ambient temperatures in the warmest month (July)
further expanded by looping.
since pipeline capacity increases with decreasing
Design of the Mackenzie Valley Pipeline
air temperature due to the increased driver power
The Mackenzie Valley Pipeline includes:
of the gas turbines at cooler ambient temperatures.
Pig receiver – a piping arrangement that allows
• approximately 1196 kilometres of NPS 30
applications before us. The Mackenzie Valley
Pipeline is scheduled to be in service in 2018.
and discontinuous permafrost;
• initial and future volumes; and
• the potential location of station facilities
along the route.
(DN 750) pipeline from the Inuvik Area Facility
The Proponents evaluated three potential
without stopping the flow of the pipeline.
to a point of interconnection with the NOVA
design concepts for the Mackenzie Valley
Pipe grade – the specified minimum yield strength
Gas Transmission Ltd. system just south of
Pipeline: a dense phase design, a two phase
of the steel used in making the pipe, typically
the Alberta-Northwest Territories boundary;
design and a single phase design. The criteria
inline tools (pigs) to be removed from a pipeline
expressed in mega Pascals (MPa).
Single phase pipeline – a pipeline that conveys
either a liquid or gas but not both at the same time.
Slug catcher – a piping arrangement used in two
phase pipelines to separate liquids from gas in the
pipeline before it can enter a gas compressor.
Two phase pipeline – a pipeline that conveys
both liquid and gas at the same time.
• three compressor stations, one at Great Bear
used to evaluate the designs included:
River to be installed initially and two others
• flexibility with respect to changes in
at Loon River North and River Between Two
volume and gas composition caused
Mountains to be installed when additional
by potential changes in supply;
shipping commitments are received;
• the Trout Lake heater station to be installed
when additional shipping commitments
• costs over the life of the project;
• constructability; and
• operability.
are received;
1249_NEB_MGP_Vol2_Text_ENG.indd 124
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Chapter 6: Facilities 125
The Proponents selected a single phase
Figure
6-52 Fig 6.6
Volume
Mackenzie valley Pipeline design capacity
Mackenzie Valley Pipeline design capacity
pipeline with a maximum operating pressure
of 18.7 MPa (2,710 psi) for the Mackenzie
Valley Pipeline. This design was described by the
27.3 million
cubic metres/day
34.3 million
cubic metres/day
Inuvik
Expansion up
to 49.8 million
cubic metres/day
Proponents to best accommodate potential
(Additional facilities
not part of application)
composition, timing and location. Cited
variation and uncertainty in gas volumes,
advantages of the single phase, high pressure
design include lower lifespan costs, simpler
facilities and a more flexible operation. Most
of the pipe would have a wall thickness of
16.2 millimetres while locations with the
potential for higher external loads, such as road
Loon River North
Fort Good Hope
crossings and watercourse crossings, would
have a wall thickness of 21.6 millimetres.
The design parameters are shown in Table 6-3.
Norman Wells
Great Bear River
Table 6-3
Mackenzie Valley Pipeline design parameters
Wrigley
River Between
Two Mountains
Fort Simpson
Pipe type
NPS 30 (DN 750)
Line pipe
NPS 30 (DN 750)
Heavy wall pipe
Grade
550 MPa (X80)
550 MPa (X80)
Wall thickness
16.2 mm
21.6 mm
Design pressure
18.7 MPa (2,710 psi)
18.7 MPa (2,710 psi)
Estimated quantity
1185 km
19 km
Trout River
NWT
Alberta
The applied-for design includes three
1 Station
3 Stations
14 Stations
compressor stations and a heater station
capable of delivering 34.3 Mm3/d (1.2 Bcf/d)
Inuvik Area Facility
Compressor station
Heater station
1249_NEB_MGP_Vol2_Text_ENG.indd 125
Interconnect with proposed
gas pipeline in Alberta
Interconnect with Enbridge
Pumping station
Liquids pipeline
of natural gas in the summer and 38.4 Mm3/d
Enbridge pipeline
(1.35 Bcf/d) in the winter.
Gas pipeline
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126 Mackenzie Gas Project • Volume 2: Implementing the decision
On the record
Dense phase, two phase
and single phase designs
The Proponents considered a dense phase design
Mackenzie Valley Pipeline expansion
approval for these 11 compressor stations
No intervenors questioned the adequacy of the
in the applications before us.
design of the Mackenzie Valley Pipeline or its
ability to transport present and future volumes
where the operating pressures would be increased so
of gas. However, there were questions about
the natural gas and natural gas liquids would behave
the initial capacity of the pipeline, how it would
as a single fluid. This concept would result in smaller
pipe sizes and fewer compressor stations and would
be expanded in the future and the design
Design of station facilities
The applied-for station facilities for
the Mackenzie Gas Project include:
• receipt metering facilities at each of
potentially eliminate the need for the natural gas
implications of a phased expansion on the
the development fields where natural
liquids line. The Proponents found that operating
thermal regime of the pipeline route.
gas and natural gas liquids would be
pressures of about 40 MPa (5,800 psi) would be
required to operate in a dense phase. At pressures
The development field owners have contracted
less than this, natural gas liquids would be present.
for 23.5 Mm3/day (0.83 Bcf/d) of the initial
The Proponents estimated that it would be necessary
to store, sell or dispose of approximately 150 m3/day
pipeline capacity and the remaining capacity
(940 Bbl/d) of liquids along the pipeline route, which
of approximately 11 Mm3/day (0.39 Bcf/d) is
would be impractical. Also, a processing plant would
available for contracting. With one compressor
be required at the end of the Mackenzie Valley
Pipeline to remove the liquids from the gas in order
station in operation near the Great Bear River,
to meet downstream gas pipeline specifications.
the pipeline is capable of delivering all the initial
The Proponents chose not to use this design because
contracted capacity.
its operation would be sensitive to gas composition,
the presence of liquids at all but the highest
operating pressures would increase the need for
processing facilities, and the very high operating
The approximate capital cost of the Mackenzie
Valley Pipeline is $7,050 million (2006$) with
metered separately;
• a pigging facility at the junction of the
Taglu and Parsons Lake laterals (Storm Hills)
consisting of pig receivers and launchers
that could be remotely operated from
the main control centre;
• the Inuvik Area Facility which would remove
natural gas liquids to meet the inlet gas
specifications for the Mackenzie Valley
Pipeline and natural gas liquids pipelines;
• natural gas liquids and natural gas
pressures would increase costs.
one compressor station at the Great Bear River.
metering facilities located within
In a two phase pipeline, liquids and gas are shipped
The Loon River North and River Between Two
the Inuvik Area Facility site;
together. While a two phase pipeline can operate at
Mountains compressor stations and the Trout
pressures similar to a single phase pipeline, the
• compressors to deliver natural gas to
Lake heater station would add approximately
the Mackenzie Valley Pipeline and pumps
stations to prevent them from damaging the compres-
$800 million to the capital cost. While
to deliver natural gas liquids to the natural
sors. This requires the addition of slug catchers and
the Proponents have applied for approval
gas liquids pipeline also located within
liquids must be separated from the gas at compressor
pumps at each station to collect the liquids and
re-inject the liquids into the pipeline after the gas is
of all of these facilities, they plan to delay
compressed. The Proponents rejected this design
construction of two of the three compressors
because it was less flexible than a single phase design.
and the heater station until the remaining
With a single phase pipeline, liquids are separated
capacity is contracted for.
from the gas and either trucked, flared, re-injected
or shipped in a separate pipeline. The Proponents
The addition of 11 more compressor stations
indicated that it selected the single phase gas pipeline
on the Mackenzie Valley Pipeline could increase
option with a separate liquids pipeline because it
the Inuvik Area Facility site;
• three natural gas compressor stations
near Fort Good Hope (Loon River North),
the Great Bear River and the River Between
Two Mountains; and
• a heater station near Trout River to maintain
best accommodated the potential variability between
the nominal capacity to about 49.8 Mm3/day
the pipeline operating temperature within
initial and future gas composition, had lower costs
(1.8 Bcf/d). The Proponents have not applied for
the design limits.
over the life of the project, required simpler facilities
and allowed for more flexible operation.
1249_NEB_MGP_Vol2_Text_ENG.indd 126
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Chapter 6: Facilities 127
The Proponents state that Mackenzie Gas
components would later be re-injected into
indirect-fired bath heaters fuelled by pipeline
Project station facilities would be designed
the Mackenzie Valley Pipeline. The Inuvik
gas. The heater station would be designed for
to Canadian Standards Association Z662,
Area Facility would use a flare system to burn
remote operation, with maintenance staff being
Oil and Gas Pipeline Systems with the exception
gaseous streams produced during operational
flown to the station by helicopter. The facility
of the Inuvik Area Facility which would be
upsets. The design and performance standards
would be designed to operate at a pressure
designed to American Society of Mechanical
would be consistent with Alberta’s Energy and
of 19.8 MPa (2,870 psi). Natural gas-fuelled
Engineers Code B31.3.
Utilities Board Guide G-40.
reciprocating engines would be used for
At the Inuvik Area Facility, the natural gas and
The natural gas would be compressed by two
natural gas liquids delivered by the upstream
centrifugal compressors located within the
gathering pipelines must be separated and
Inuvik Area Facility. These compressors would
processed to meet the inlet gas specifications
be driven by two ISO 30 MW gas turbines
for the pipelines. The natural gas liquids
fuelled by natural gas sourced from within
The Proponents indicated they would select
contain components which vaporize when
the facility. The compressed natural gas would
engines with a proven low-emission design and
stored in a conventional oil storage tank.
be cooled using aerial coolers and gas-to-gas
would meet or exceed Alberta Environment’s
To make it easier to transport natural gas
heat exchangers. The gas turbines would be
Code of Practice for Compressor and Pumping
liquids in a pipeline, the unstable components
commercially available, dry, low nitrogen oxide
Stations and Sweet Gas Processing Plants,
would be removed at the Inuvik Area Facility
units. The compressors would be manufactured
1996, which specifies maximum nitrogen oxide
in a process called stabilization. The removed
according to American Petroleum Institute
emissions of 6 g/kWh for engines over 600 kW.
primary power production at the heater station.
Reciprocating engines would also be used
for standby emergency power generation
and would be fuelled by diesel.
Standard 617. All compressor stations would
have a design pressure of 19.8 MPa (2,870 psi)
to allow for the maximum discharge pressure
of the Mackenzie Valley Pipeline. Primary
On the record
power production for the compressor stations
Design considerations
After determining that a single phase pipeline
would be generated by natural gas-fuelled
On the record
Location of the Inuvik Area Facility
During the early stages of engineering design, the Proponents had planned to locate
the Inuvik Area Facility 16 kilometres to the north of its currently applied-for location.
The Proponents submitted that the new location is flatter, requires less imported
was the best design concept for the project,
reciprocating engines. Diesel reciprocating
gravel for the facility and shortens the access road by 14 kilometres. Early design
the Proponents considered the following factors:
engines would be used for standby emergency
work had established a requirement that all pipeline segments in the continuous
• historical and existing pipeline routes;
power generation.
• total costs over the life of the project;
• operating temperatures in continuous
and discontinuous permafrost;
• volumes from 24 Mm /day to 56 Mm /day
3
3
(0.8 Bcf/d to 2 Bcf/d);
• facility locations along the route;
• initial shipper requirements and potential
future expansion;
Although not required initially, the Trout River
permafrost zone should have a constant pipeline inlet gas temperature of -1oC to
prevent thawing. To meet this operating requirement, the Inuvik Area Facility needed
gas refrigeration units. At the new location of the Inuvik Area Facility, the Proponents
found there was little evidence of thaw sensitive soils for some distance downstream.
heater station would eventually be needed
As part of this design refinement, the Proponents investigated the possibility of
to maintain pipeline operating temperatures
replacing the gas refrigeration units with heat exchangers which would cool the
within the design limits established for the
three compressor station configuration. The
Proponents’ preferred design option is to use
gas using the surrounding air.
Because of the low temperatures of the product entering the Inuvik Area Facility
and the relatively low summertime air temperatures, the Proponents found that
without the refrigeration units the Inuvik Area Facility could discharge gas at about
3oC in the summer and at or below 0oC the rest of the year. This would result
• input from community consultation; and
in approximately 0.3 m of thaw settlement on the right of way at the outlet of
• minimizing footprint by using existing
the Inuvik Area Facility, decreasing to zero settlement 50 kilometres downstream
infrastructure.
1249_NEB_MGP_Vol2_Text_ENG.indd 127
of the Inuvik Area Facility.
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128 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
We are of the view that the system design
undertaken by the Proponents for the
6.4 Specific design issues
6.4.1 Overview
relatively insensitive to ground conditions
along the route, thus reducing the need for
Specific issues arose as a result of the project’s
very detailed and precise data (i.e., the pipe
gas liquids line between the Inuvik Area
location in a northern environment and on
wall thickness for overland portions of each
Facility and Norman Wells is consistent with
the proposed engineering design approach.
pipeline is predominately one thickness).
good design practice and provides sufficient
Our focus in the hearing was to ensure that
A monitoring and mitigation tool box was
expansion capability for future volumes. We
the facilities could be designed and operated
developed to address geohazards during
are also of the view that there is uncertainty
in a safe and environmentally responsible
construction and operation.
in regards to volume, composition, timing
manner, while maintaining system reliability.
single phase gas pipeline and the natural
and location of future gas supplies. Because
of this uncertainty, we do not share the
6.4.2 Geohazards
view of Mackenzie Explorer Group that
Geohazards are naturally occurring or
pre-investing in heavy wall pipe and other
project-induced geological, geotechnical,
facilities to permit a future increase in
geothermal or hydrological phenomena that
operating pressure is warranted for the
could lead to pipeline or other component
two-phase gathering system. We note that
failure, causing adverse environmental impacts,
in the event that new capacity is required
or that could affect the right of way, causing
from the Mackenzie Delta, the option to
environmental concerns.
construct compression facilities at Storm
The Proponents indicated that the principal
Hills is a viable potential alternative to
geohazards to the project are well known
looping. It also has the advantage of not
requiring changes to compressor facilities
at other receipt points.
from the previous studies and projects in the
Mackenzie Valley. The Proponents were of the
view that the initial consideration of geohazards
did not require detailed information on the
location or the quantification of risk associated
with each specific geohazard occurrence.
During the conceptual and preliminary design
the Proponents used route selection approaches
1249_NEB_MGP_Vol2_Text_ENG.indd 128
used to develop a pipeline design that was
The Proponents stated that a more formalized
geohazard assessment approach would be
beneficial for the detailed design phase in
terms of systematically organizing available
information on geohazards, verifying preliminary
design assumptions, and obtaining information
about the distribution and potential effects of
various individual and combined geohazards
along the pipeline route.
The Proponents plan a three-phased approach
consisting of: a geohazard inventory and
assessment using terrain mapping and LiDAR;
a field geotechnical program and detailed
design engineering to develop mitigation;
and a construction and operations monitoring
phase where expected conditions would
be further verified during ditch excavation
and later upgraded based on in-line inspection
and monitoring of the right of way.
to avoid potentially difficult terrain and unstable
In order to assess the geohazards which act
slopes. The Proponents indicated that credible
alone or in combinations the Proponents
worst case scenarios had been used to develop
propose to use a semi-quantitative index based
conservative estimates of the effects of
approach to rank the susceptibility of individual
geohazards on the pipelines, pipeline ditch
geohazards along the route. As part of this
or pipeline right of way. These estimates were
approach the values and rankings associated
12/6/10 11:02:27 AM
Chapter 6: Facilities 129
with each geohazard would be based on
pipeline design to evaluate its proposed
expert judgment. To facilitate the assessment
approach and made modifications in response
of possible combined geohazards the route
to the comments received. A workshop was
would be segmented based on the extent
held in Calgary on 10 and 11 July 2006 where
The Inuvik Area Facility includes:
• gas-to-gas heat exchangers;
of each individual geohazard.
the Proponents, the Senior Advisory Team
• a liquid slug catcher;
• utility gas equipment;
• liquid stabilization;
• fuel gas equipment;
• pumping and storage facilities;
• station power generating equipment;
• residue gas processing and
• controls and communication
In undertaking their geohazard assessment
the Proponents would consider only those
geohazards within the pipeline corridor that
may directly affect the pipe, the pipeline ditch,
or the right of way. The Proponents referred
to these as “credible probable geohazards.”
The Proponents identified 31 geohazards
and staff from Indian and Northern Affairs
Canada and Natural Resources Canada met
and discussed the Proponents’ semi-quantitative
geohazard assessment approach. Following
On the record
Inuvik Area Facility, compressor stations and heater station equipment
compression equipment;
• propane refrigerant equipment;
• safety and control systems; and
equipment; and
• safety equipment.
The centrifugal compressor at each of
the July workshop four more geohazards were
• utility systems.
identified by the Proponents. The results of
Liquid processing and storage
by an ISO 15 MW gas turbine fuelled
these workshops were submitted in our hearing.
equipment includes:
by natural gas sourced from the
• stabilizer and associated equipment;
pipeline. The gas turbines would be
the compressor stations would be driven
commercially available, dry low nitrous
which could result from:
Indian and Northern Affairs Canada indicated
• heat exchangers;
• the freezing of unfrozen ground;
that the success of any geohazard risk
• aerial coolers;
• the thawing of permafrost terrain;
assessment will depend on the adequacy of the
• pumps;
• landslides impacting the right of way;
database and acknowledged the Proponents’
• tectonics/seismicity;
efforts at organizing existing data and its
• watercourse hydraulics resulting in
preparations to accommodate anticipated data
Area Facility would be protected by
• line heaters;
in a geographic information system. Indian
a foam-based fire protection system
• fuel gas and metering equipment;
and the tank farm would be designed
• glycol storage tanks;
to meet Alberta’s Energy Resources
• electrical power generating
exposed pipe;
• storage tanks; and
• a pressure vessel.
The liquid storage in the Inuvik
• erosion;
and Northern Affairs Canada was of the view
• geochemical concerns such as the
that the geohazard list was adequate for the
Conservation Board’s Guide G-55
preliminary stage of the assessment and that
requirements. The tanks would be
occurrence of acid-generating rock; and
• soil structure issues such as the presence
of large rocks which could damage the pipe.
The Proponents are of the view that these
naturally occurring or project-induced
geohazards could load the pipeline causing
a pipeline integrity concern, could affect
the pipeline or ditch causing an operational
concern, or could affect the right of way
causing an environmental concern.
would be manufactured according
to API Standard 617.
Equipment at the heater station
site includes:
equipment;
• controls and communication
constructed within a bermed contain-
equipment; and
ment area with an impermeable liner.
• safety equipment.
The three downstream compressor
As noted above, the heater station piping
stations would all contain similar
would comply with Canadian Standards
indicated that it was not possible to fully
equipment, including:
Association Z662, Oil and Gas Pipeline
assess the Proponents’ methodology at the July
• pipe and pipeline components such
Systems; however, the line heaters
the Proponents’ work may benefit from broader
input by geoscientists with northern mapping
experience. Indian and Northern Affairs Canada
meeting because much of the presentation was
conceptual. Indian and Northern Affairs Canada
as mainline block valve assemblies;
• pig launcher and receiver;
• inlet scrubber;
noted that the assessment approach outlined
• gas turbine compressor package;
was adequately structured and in conformity
• aerial coolers;
would be designed and manufactured
in accordance with American Society
of Mechanical Engineers Boiler and
Pressure Vessel Code, Section VIII,
Division 1, as permitted by Canadian
Standards Association Z662.
with other semi-quantitative methodologies
The Proponents assembled a Senior Advisory
described in the literature but that in its
Team consisting of four external experts
view significant challenges remain. Indian
experienced in northern engineering and
and Northern Affairs Canada cautioned that
1249_NEB_MGP_Vol2_Text_ENG.indd 129
oxide units. The compressor units
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130 Mackenzie Gas Project • Volume 2: Implementing the decision
a semi-quantitative approach, such as the
The Proponents stated that a quantitative
Views of the Board
one adopted by the Proponents could “easily
risk assessment for all geohazards was neither
We note that there was general agreement
stray from good science regardless of the
required at the preliminary engineering stage
that a geohazard assessment of the project
best intentions of those involved” and that
of project nor meaningful, given the lack of
would be beneficial in providing useful
the individual geohazard scores obtained
site-specific information required to support
information for the detailed design
from the Proponents’ methodology would
the engineering judgment of probabilities
and the implementation of geohazard
be difficult to compare and sum, and thus
required in a quantitative approach. The
mitigation during construction. There
integrate into risk assessment.
Proponents indicated that during operations,
was disagreement however on whether
integrity management decisions for specific
the semi-quantitative approach described
locations might be suited to the quantitative
by the Proponents is adequate or whether
or probabilistic site‑specific treatment
the quantitative approach suggested
of geohazards.
by Indian and Northern Affairs Canada
susceptibility (i.e., high, medium, low, very
Indian and Northern Affairs Canada suggested
is required. Both require a significant
low, or negligible) relative to specific pipeline
that the geohazard risk assessment should be
level of expertise to implement.
elements. The Proponents stated that the
conducted using a quantitative risk assessment
We are satisfied that the semi-quantitative
spatial distribution and sorting of individual and
approach on a segment-by-segment basis
geohazard approach described by the
combined geohazards by susceptibility provides
and that the preferable approach would be
Proponents is a suitable design tool for
sufficiently detailed information to guide
a geohazard risk assessment which examined
the detailed design phase of the project.
decisions regarding design, field activities,
every segment of the pipeline route. Indian
Therefore we will not require the
specialized engineering analysis and testing,
and Northern Affairs Canada was of the view
Proponents to undertake a quantitative
operations monitoring and operations mitigation
that the segments should be small. Indian and
geohazard assessment. Condition 45
maintenance. The Proponents characterized
Northern Affairs Canada stated that in the least,
requires the Proponents to file a geohazard
their approach as adaptable and well-suited
the assessment should include a relative risk
assessment of the project prior to pipe-
to the abundance of regional data available
rating and analyses of geohazards acting in
laying operations. This report shall:
to the project. The Proponents also noted that
combination where applicable. Indian and
their approach allowed for more site specific
Northern Affairs Canada was of the view
information to be incorporated into it as
that we should consider a condition specifically
the project progresses.
listing the geohazards and specific combinations
The Proponents are of the view that their
semi-quantitative index-based geohazard
assessment approach allows geohazards to be
identified and ranked in terms of the associated
of geohazards which the Proponents would
be required to analyze.
•• detail its geohazard assessment
methodology and the specific
and combined geohazards identified
along the route;
•• describe specific measures to be
implemented to mitigate individual
and combined geohazards;
•• provide decision criteria for
implementation of mitigation
for geohazards identified during
construction;
1249_NEB_MGP_Vol2_Text_ENG.indd 130
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Chapter 6: Facilities 131
•• outline the qualifications of the
Mackenzie Gathering System –
Mackenzie Valley Pipeline
staff making decisions regarding
upstream gathering pipelines
The Proponents indicated that they intend
design and implementation; and
The Proponents stated that the gathering
to limit the compressor station discharge
•• outline the ongoing monitoring
pipelines north of the Inuvik Area Facility
temperature to ensure that the pipeline
requirements for geohazards identified
would be operated cold since they are located
temperature does not cause long-term thawing
during the detailed design and
in continuous permafrost. These pipelines
of the permafrost beyond that caused by clearing
construction phases.
would be subject to frost heave where unfrozen
the right of way. The Proponents selected an
pockets of ground referred to as taliks occur.
average annual station discharge temperature of
The Proponents indicated that design mitigation
-1oC in continuous permafrost areas. Figure 6-6
would be used as required on a site-specific
shows the expected temperature profiles at
basis to limit the strain demand on the gathering
different times of year for the one compressor
pipelines to below 0.5 percent, so that common
station configuration and the three compressor
line pipes that comply with Canadian Standards
stations plus a heater station configuration.
6.4.3 Pipeline operating temperatures
The operating temperature of a pipeline is
an important design consideration as heat
is exchanged between the pipeline and
the surrounding ground. The difference in
temperature of the pipeline compared to
Association Z245.1, Steel Pipe, can be used.
In their May 2007 updated evidence the
the surrounding ground could result in
Mackenzie Gathering System – natural
Proponents indicated that the Mackenzie
a change of temperature in the ground around
gas liquids pipeline
Valley Pipeline would begin operation with
the pipeline as well as how the surrounding
The temperature of a liquids pipeline is affected
only one compressor station between the Inuvik
ground exchanges heat with the atmosphere
by the mass flow rate and the transfer of heat
Area Facility and the Alberta border, at Great
(the thermal regime). In permafrost
between the pipe and the soil. The Proponents
Bear River. The full potential capacity of the
environments the structural and physiographic
determined that since the mass flow rate in
Mackenzie Valley Pipeline could be reached in
properties of the ground are dependent on
the natural gas liquids pipeline is low, the
the future with a total of 14 compressor stations
the thermal regime. A change in ground
pipe temperature would be close to the soil
in operation. Figure 6-7 shows the different
temperature could cause the formation
temperature anywhere along the pipeline.
temperature profiles for the Mackenzie Valley
of a frost or thaw bulb around the pipeline,
Natural gas liquids entering the liquids pipeline
Pipeline with different compressor
a change in the depth of the active layer
from the Inuvik Area Facility would be designed
arrangements. The variation in the temperature
or a change in the timing of active layer
to have a constant inlet temperature of -1 C.
profile with added compressor stations is
freeze-thaw cycles, resulting in loading and,
The Proponents stated operating temperature
a consideration in the overall design of the
in some cases, deformation of the pipe.
guidelines are based on the criteria that
pipeline. Areas which would begin operation
the average annual temperature will not
with average pipeline temperatures well below
Did you know?
increase long-term thaw of the right of way
0oC could operate with temperatures above
Joule-Thompson effect
compared to the effects of just clearing
0oC in the fully expanded case. For example,
As natural gas moves downstream in a pipeline,
without pipeline operation.
near kilometre 400, the annual average
o
energy is lost mostly due to friction and this causes
temperature with one station operating would
a drop in pressure. When pressure decreases the gas
be about -6oC but with 14 stations operating
expands and the temperature of the natural gas.
decreases The decrease in temperature is referred
the annual average temperature would be 2oC.
to as the Joule-Thompson effect.
1249_NEB_MGP_Vol2_Text_ENG.indd 131
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132 Mackenzie Gas Project • Volume 2: Implementing the decision
monitored with thermistors and pipeline strain
8
would be monitored with high resolution
4
1200
Distance from Inuvik Area Facility (km)
Views of the Board
The pipeline operating temperatures for
1200
0
200
-16
frost heave and thaw settlement potential.
Trout River
-12
non frost-susceptible soils at locations of high
1000
pipe cover, and backfill of the trench with
-8
1000
pipe, thermosiphons, pipe insulation, reduced
-4
River Between
Two Mountains
deformation including the use of heavy wall
800
measures against thermally induced pipeline
0
600
The Proponents discussed several mitigation
Temperature (°C)
in-line inspection tools (such as the Geopig®).
Great Bear
River
stated that ground temperatures would be
400
temperature on the pipeline, the Proponents
Volume 2 Figure 6.8
Comparison
of one and three-station cases,
Figure
6-6
annual average temperature profiles
Temperature profiles for configurations with one and three compressor stations
Loon River
To monitor the effects of changes in ground
Annual average pipeline operating temperatures
1 compressor station
3 compressor stations and Trout River heater station
the gas pipeline are significantly influenced
by the system configuration. We are of the
view that the Proponents’ approach of
developing a pipeline design which is
relatively insensitive to pre-existing ground
Volume
2 Figure 6.8
Figure 6-7
Annual average temperature profiles for compressor station scenarios
Temperature profiles for various compressor configurations
conditions is prudent. Nevertheless, we have
4
added requirements to Conditions 46, 48
2
maintaining pipeline integrity. Conditions
regarding monitoring are discussed in
-6
-8
-10
0
Section 6.6.
-4
800
of pipeline strain will be important to
-2
600
increases in compressor stations. Monitoring
400
operating temperatures associated with
0
200
potential impact of changing pipe
Temperature (°C)
and 51 for further assessments of the
Distance from Inuvik (km)
Annual average pipeline operating temperatures
1 compressor station with no heater station
3 compressor stations
7 compressor stations
14 compressor stations
1249_NEB_MGP_Vol2_Text_ENG.indd 132
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Chapter 6: Facilities 133
6.4.4 Pipeline materials
The Proponents’ approach to pipeline design for
the project, as discussed in Section 6.3, includes
Views of the Board
Table 6-4
The design specifications will require
Line pipe specifications
Parameter
Manufacturing specifications
Pipe material
Low carbon, high strength,
low alloy steel
Proponents would then use monitoring during
Steel grade
550 (X80)
operation to identify locations where loads are
Skelp (plate)
Thermo-mechanically rolled
Welds
Longitudinally or helically
double submerged arc
Notch toughness
160 Joules
using a strain-based design methodology for
secondary loads such as ground movement. The
accumulating, and would intervene to repair
or maintain the pipe at these locations. The
materials selected for the project must be
material properties able to meet the
requirements for operation in cold
temperatures at high pressures and
subjected to secondary loads such as ground
movement. We are of the view that the
current piping manufacturing technology
exists to enable the Proponents to select
and test the appropriate piping materials to
ensure they meet the design specifications.
suitable for strain-based design and operation
at high pressures in an environment with
The Proponents performed ductile fracture
The Proponents have indicated that they
limited seasonal access for pipeline repair and
arrest analysis using the Battelle method and
will be using a quality control and assurance
maintenance. The materials must also be
conducted a full-scale burst test. Based on the
process to ensure that the piping materials
able to withstand cold temperatures during
results of the analysis and verification test the
will be selected, manufactured, tested,
construction and potentially high external loads.
Proponents would specify a notch toughness
transported and installed to ensure they
of 160 Joules to provide for a positive ductile
continually meet the design specifications.
fracture arrest in the Mackenzie Valley Pipeline.
Condition 18 requires the filing of
The line pipe, components and plant-applied
external coating would be designed and
manufactured in accordance with the Canadian
Pipeline components such as valves, fittings,
Standards Association Z245 series requirements.
flanges, and induction bends would be
Line pipe specifications are shown in Table 6-4.
manufactured in accordance with Canadian
Qualified suppliers would be selected to
Standards Association Z245.15, Z245.11,
produce the pipe and apply external coating
Z245.12, and the Proponents’ specification
in accordance with the Canadian Standards
and quality assurance program. Components
Association Z245.1 and Z245.20/Z245.21,
would be of Grade 483 (X70), PN250 and
and the Proponents’ specification and quality
Category II to provide sufficient strength
assurance program.
and fracture resistance for reliable operation
specifications, mill joining programs and
project-specific quality assurance programs
to facilitate National Energy Board audits.
Condition 58 requires summary reports
of non-compliances with design, materials
and construction specifications and the
disposition of these non-conformances.
in the northern environment.
1249_NEB_MGP_Vol2_Text_ENG.indd 133
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134 Mackenzie Gas Project • Volume 2: Implementing the decision
6.4.5 Joining – welding and
The Proponents indicated that a combination
project involves the use of unconventional design
non-destructive examination
of stress and strain-based design would be
methods or state of the art joining techniques.
Individual pipe sections are factory
used on the pipeline portion of the project
manufactured using either longitudinal welding
and a conventional stress-based design would
or spiral welding techniques. Sections of pipe
be used for the station and facility construction.
are then joined together at the pipe mill or the
The specific components identified in the
project site by welding the circumference joint
welding and non-destructive examination
using girth welds. The factory and field welding
programs are related and form part of an overall
procedures are critical to ensuring pipeline
joining program. The successful implementation
integrity. To ensure quality control the
of an effective joining program is necessary
welds are tested using non-destructive
to provide the required weld quality.
examination techniques.
Welding
Strain-based design calls for a higher degree
The Proponents have developed a framework
for weld qualification requirements which they
would use to develop final girth weld procedure
specifications. The Proponents stated that all
welding procedure specifications would meet
Canadian Standards Association Z662, Oil
and Gas Pipeline Systems requirements and
any additional project-specific requirements.
The objective for the Proponents’ strategy
for developing welding procedures for the
project is to achieve weld properties critical
Did you know?
of weld quality and more stringent mechanical
Definitions
properties than stress-based design. The integrity
Arc weld – a welding process where metal is joined
and strain bearing capacity of the weld and the
by using a power supply to create an electric arc
area adjacent to the weld, known as the heat
• weld strength overmatch;
to melt the metals.
affected zone, are important factors. In addition
• appropriate consumable selection;
Ductile fracture arrest – the ability of pipe,
to any flaws which may be introduced during
• bevel design; and
which fails in a ductile manner, to resist or arrest
the welding process, heat from this process may
• the appropriate welding process selection.
crack propagation.
change the micro-structure of the parent metal
Full-scale burst test – burst testing of sections
adjacent to the welding material in the heat
between a consumable electrode and the base metal
pipe to validate material behaviour models,
such as crack propagation.
Girth weld – the circumferential weld used
affected zone. This in turn may affect the
strength and ductility of the original parent
to join two pipe joints together.
metal. Therefore, it is important that the welding
Helically double submerged weld – the welding
procedure minimizes the potential for flaws
process used to join spiral pipe; the pipe is
and ensures any changes in the parent material
manufactured from steel coils formed helically
into cylinders.
Longitudinal weld – the weld used to join U
properties are still within the design parameters.
The welding procedure design should not
and O formed pipe; the pipe is manufactured from
only consider flaws and mechanical property
steel coils or plate formed into a cylinder and then
requirements, but also balance the need for
the length of the joint is welded.
Notch toughness – the ability of pipe steel
to resist crack initiation and propagation.
Skelp – a piece or strip of metal produced to
a specified thickness and width during the pipe
acceptable construction productivity in the
to a strain-based design. These welding
procedures relate to:
The Proponents indicated that all circumferential
field and pipe mill welds would be required
to meet the same weld performance criteria,
based on their intended application in either
a stress or strain-based design. The identified
performance criteria include mechanical
properties and maximum allowable flaw sizes.
In addition, the Proponents indicated that
the target weld overmatch yield strength value
is five percent higher than the yield strength
of the parent metal.
challenging northern environment. Verification
The Proponents indicated that they would use
that a welding procedure can achieve the
a combination of stress and strain-based design
predicted and desired results is critical when the
for all pipeline applications on the Mackenzie
manufacturing process.
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Chapter 6: Facilities 135
Gas Project and a stress-based design for
testing on buried flaws or interacting flaws
the Inuvik Area Facility, compressor station
to determine if the acceptable flaw criteria
and the facility construction. The weld quality
could be expanded to accommodate actual
requirements for these two design approaches
field production welding.
are different due to the different operating and
loading regimes. The Proponents submitted that
the Canadian Standards Association Z662 flaw
acceptance criterion is very conservative and
would be impractical to use on the strain-based
design piping, due to the high cost associated
with repairing defects which may have excess
stress and strain capacity for the intended
loading regime. Canadian Standards Association
Z662 provides the option of using fracture
The Proponents stated that they are attempting
improvements contemplated on the project,
for this work was the potentially high strains
of a pipeline weld and the associated heat affected
zone was required because traditional fracture
such as dual torch metal arc weld or single torch
mechanics methods have not been fully validated
tandem (dual wire) welding process, may enable
for higher strain demands.
the Proponents to find efficiencies during
The mechanical properties required to achieve high
pipeline production and to complete more,
higher quality welds in a shorter time frame.
developed a curved wide plate test program to
criteria that meet the design requirements
perform large‑scale proof testing to determine
have been established, the next step is to
the critical flaw sizes for the various proposed
choose a reliable method for identifying
pipe sizes and to verify the preliminary estimates
and fully characterizing any flaws. The weld
of tensile strain capacity of the welds.
inspection method must be able to non-
a simulated coating heat treatment to represent
strain capacity of pipe and girth welds. The driver
operation. A reliable means to analyze strain capacity
Once welding procedures and flaw acceptance
and spiral welded pipe which had undergone
into testing and analysis to determine the tensile
associated with offshore piping installation and
acceptance criteria. Therefore, the Proponents
performed on UOE (longitudinally welded pipe)
Since the early 1980s considerable work has gone
they are involved in. Welding related
Non-destructive examination
a total of 60 curved wide plate tests were
Testing of welds
to leverage new technology or process initiatives
mechanic principles to develop alternative
Under the curved wide plate test program,
Did you know?
destructively examine the finished weld to
determine whether the weld integrity meets
tensile strain capacity in pipeline girth welds include
weld metal yield strength overmatch (where the weld
metal has higher strength properties than the parent
metal) yield to tensile strength ratio and uniform
elongation in both the pipe and weld metal and,
in addition, adequate toughness in both the heat
affected zone and the weld metal. Currently, the
only method to obtain these properties accurately
is through empirical testing with methods such as
curved wide plate testing. The curved wide plate test
(a large-scale tensile test of a piece of pipe which
may include a girth weld) has been used within
both the offshore and onshore pipeline industry to
better represent actual pipe behaviour under strain
conditions compared to transverse tensile testing.
specified flaw acceptance criteria requirements.
The chosen non-destructive examination
technique must be proven to accurately
characterize potential flaws in terms of vertical
when developing non‑destructive examination
height, depth and circumferential location.
procedures and related quality checks.
tests may be considered during detailed design
A solid understanding of the types of potential
To aid in the preparation of a joining program,
to further enhance the design and to identify
flaws associated with the welding process, and
the Proponents developed a non-destructive
areas which could reduce construction costs.
their anticipated size, location and orientation
examination strategy framework to inspect
Some of the identified follow-up testing may
is required when choosing and proving the
the estimated 80,000 circumferential girth
include confirmation of weld procedure strain
effectiveness of the non-destructive examination
and facility welds. The main purpose of the
capacity and critical flaw size. In addition,
technique. In addition, knowledge of the
non‑destructive examination strategy is to
the Proponents would consider additional
potential weld flaw characteristics is also required
identify any flaws in the weld metal which
the aged heat condition. The Proponents
indicated that additional curved wide plate
1249_NEB_MGP_Vol2_Text_ENG.indd 135
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136 Mackenzie Gas Project • Volume 2: Implementing the decision
would reduce the strength of the weld joint
detailed engineering to ensure each weld is
ment values for the alternative flaw
during the anticipated loading.
uniquely identified and traceable during all
acceptance criteria we are of the view that
stages of construction and over the operating
it would be prudent to determine the crack
life of the pipeline.
tip opening displacement values for the
The Proponents are planning to use a zonal
discrimination approach to determine the flaw
sizes using either focused probes or phased
array technology. Prior to detailed engineering,
heat affected zone and the weld metal
Views of the Board
of the pipe mill circumferential, helical and
longitudinal welds. Condition 17 requires
the Proponents would implement an automated
Due to the anticipated strain-based design
ultrasonic testing vendor qualification program
and the associated loads we are of the view
along with an automated ultrasonic testing
that joining of the piping is an important
flaw size verification program to determine
consideration in meeting the material
the accuracy of the automated ultrasonic
design specifications. Instances of localized
testing system under cold climate conditions.
low fracture toughness properties are
Pursuant to the Onshore Pipeline
known to have occurred in or adjacent to
Regulations, 1999 the Proponents must
the weld. Currently there is no requirement
file a joining program with the National
in the piping manufacturing standard to
Energy Board prior to conducting welding
perform testing such as crack tip opening
procedure qualification tests for the field
displacement that would identify areas of
circumferential production, tie-in and
localized low fracture toughness. Instances
repair pipeline welds and welding of
of localized low fracture toughness could
that they would comply with Onshore Pipeline
project facilities. In addition, the Proponents
affect the integrity of the weld or the base
must file the non‑destructive examination
Regulations, 1999 requirements which stipulate
metal adjacent to the weld during any
procedure qualification records shortly
100 percent non-destructive examination
pipeline deformation associated with
after the completion of qualification
inspection of all welds. However, the Proponents
a strain-based design at low operating
tests. Conditions 52, 53 and 54 address
stated that they intend to request an exemption
temperatures. Therefore, in addition to
these requirements.
from the Onshore Pipeline Regulations, 1999
determining the crack tip opening displace-
The stress-based design used for station
and facility construction would employ flaw
acceptance criteria specified in either the
applicable Canadian Standards Association Z662
or American Society of Mechanical Engineers
B31.3 standards. The Proponents confirmed
the Proponents to undertake testing
to determine the susceptibility to areas
of localized low fracture toughness associated with welds.
non-destructive examination requirement for
welds in the auxiliary systems of the Mackenzie
Valley Pipeline.
The Proponents plan to develop a project-wide
data management system designed specifically
for the Mackenzie Gas Project to manage
the large amount of data resulting from
over 80,000 pipeline welds. The Proponents
indicated that a weld management and
materials system would be developed during
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Chapter 6: Facilities 137
6.4.6 Seismic design
Indian and Northern Affairs submitted that
the occurrence of earthquakes could impose
On the record
Threshold slope angles
The Proponents define threshold slope angles
Gathering System and Mackenzie Valley Pipeline
would cross 372 and 822 longitudinal slopes,
respectively, as well as 64 kilometres and
339 kilometres of cross slopes, respectively.
significant environmental loads and subsequent
as the angles below which a particular slope will
strain on the pipeline. A recommendation was
be stable regardless of surface disturbance and
Of these slopes, the Proponents identified
permafrost thaw. The method was adopted based
246 that required stability mitigation. Based
made that the Proponents should satisfy us that
seismic related hazards had been incorporated
on its successful utilization for the Norman Wells to
Zama Pipeline.
on preliminary geothermal and pore water
into the design of the pipelines and associated
pressure modeling and preliminary soil data,
facilities. The Proponents submitted that
the Proponents developed threshold slope
earthquakes and other seismic related
geohazards were to be considered as part
of the final design and would be addressed
during detailed engineering.
6.4.7 Slopes
If the soil surrounding a pipeline moves after
a pipeline is built, as in the case of an unstable
in the case of soil movement. The Proponents
expressed the view that the objective for slope
design for the project is essentially one of
environmental protection and, in particular,
angles for three types of frost susceptible
soils and four geographical regions. The
Proponents plan to update the threshold
angles during final design.
one of protecting watercourses from the ingress
Slope design
of soils from slope movement or soil erosion
Where LiDAR measurements of slope angle
caused by pipeline construction and operation.
exceed the threshold angle, the Proponents
propose the use of slope stability mitigation
slope, the movement can cause stresses and
The Proponents submitted that the Mackenzie
strains in the pipe, expose the line, damage
Valley is very active in terms of slope movement
the pipe coating, or possibly cause the pipe
and the pipeline route would cross terrain
to fail. The Proponents submitted that the
susceptible to slope movement and other
structural integrity of the proposed pipelines is
geological hazards. Permafrost has a significant
• installing pipe insulation;
such that rupture and leakage would be unlikely
influence on slope stability design in northern
• using right of way passive cooling systems
regions. When permafrost thaws, the ice in
the ground melts, causing the pore water
pressure to rise until the water is able to
drain. The Proponents’ goal is to manage pore
Did you know?
Definitions
Cross slopes – slopes that dip perpendicular
water pressures in the slopes so that thawing
permafrost does not cause the calculated
factor of safety for the slope to fall below
to the pipeline.
a predetermined value, and the slope to become
Longitudinal slopes – slopes that dip roughly
potentially unstable.
parallel to the pipeline.
Pore water pressure – the pressure of groundwater
at a given location within the soil.
1249_NEB_MGP_Vol2_Text_ENG.indd 137
techniques. The primary methods proposed
to increase slope stability and reduce the rate
of permafrost thaw are:
such as thermosiphons;
• employing surface erosion control measures;
and
• using surface insulation.
Other proposed slope stability mitigation
methods include re-grading the slope to a lesser
angle or installing friction-reducing wrap on
the pipeline to prevent damage during slope
movement. Studies to determine the suitability
Slopes were categorized on the basis of slope
of carbon dioxide versus ammonia refrigerant
angle and orientation in relation to the pipeline.
thermosiphons and the available types of surface
The Proponents estimated that the Mackenzie
insulation (flax straw, wood chips and synthetic
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138 Mackenzie Gas Project • Volume 2: Implementing the decision
sheeting) were ongoing during the hearing.
(rerouting and directional drilling) or stabilizing
slopes with evidence of soil movement or
The Proponents submitted preliminary analysis
the site using secondary mitigation measures
slopes where large toe excavations are required.
of data from the surface insulation field trials
such as slope grading or thermosiphons.
The Proponents stated that intervention criteria
indicating that straw bales provided the best
The Proponents described the buildup of strain
other than pipeline strain, such as thaw depth
thermal protection of materials tested, but were
due to earth movement from frost heave, thaw
or slope movement, would not be developed
subject to shrinkage and would require further
settlement and soil creep as a gradual process
for monitored slope parameters.
that could be identified prior to reaching
To address the expected variation in ground
threshold intervention values for pipeline strain.
The Proponents submitted that the risk
conditions along the proposed route, the
In addition, the Proponents plan to install slope
Proponents’ preliminary slope design method
of potentially rapid events such as slope
monitoring equipment, including piezometers
incorporates a field change manual with
movements would be reduced in design
and thermistor cables on the right of way. Slope
contemplated design responses to foreseeable
and construction by identifying rapid loading
movement indicators would be installed at sites
changes in ground conditions from those
mechanisms and then avoiding these areas
with stability concerns such as ice rich slopes,
assumed in final design.
study to determine if the effects were material.
Figure 6-8
Thermosiphon (left)
and wood chips
used as surface
insulation (right)
Heat is released to atmosphere
in winter as vapour in
thermosiphon condenses
Cooling occurs in
ground as liquid in
thermosiphon evaporates
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Chapter 6: Facilities 139
Indian and Northern Affairs Canada reviewed
Indian and Northern Affairs Canada indicated
an exhaustive inventory of slopes on the
preliminary documents submitted by the
that further detail was required regarding the
project in the report submitted in evidence
Proponents and made several recommendations
remedial actions the Proponents would take
which will require revision when the final
as outlined in Section 6.4.8. Indian and
should monitoring indicate that the factor of
route is determined. We also note that the
Northern Affairs Canada and the Proponents
safety for a slope falls below the design factor
Proponents have proposed a field change
participated in a series of meetings and
of safety. Indian and Northern Affairs Canada
manual for slopes in anticipation of the
technical workshops and reached a general
was concerned over who would make this
need for changes during construction.
agreement on a design approach for slopes
determination and what kind of training or
We are of the view that such a manual
and geohazards.
expertise they would have. Indian and Northern
should be approved by the National Energy
Affairs Canada suggested that there needs
Board prior to use so that changes made
to be specific requirements for the technical
in accordance with the manual would not
ability and skills of the individuals making this
require amendments to submitted final
determination and suggested that this should
designs. Indian and Northern Affairs
be specified in a condition.
Canada’s concern regarding the effects
Indian and Northern Affairs Canada was of
the view that the Proponents should assess
the effects of changes in ground thermal regime
due to the addition of compressor stations
or selected slopes where those effects could
of changes in ground thermal regime
occur. Indian and Northern Affairs Canada
also suggested that the Proponents prepare
Views of the Board
a complete inventory of all slopes along the
We find the Proponents’ preliminary design
right of way, especially lesser slopes, and not
methodology for slopes to be satisfactory.
just those requiring site-specific slope designs.
We note however that there appears to be
due to the addition of compressor stations
is valid and should be considered by
the Proponents during the final design
phase to preserve their ability to safely
add compression in the future.
We are of the view that the Proponents
On the record
temperature. The Proponents indicated that
understand the importance of ensuring
manufacturers currently favour carbon dioxide
competent design staff for the final slope
as the heat transfer agent but that ammonia had
design and we are not persuaded that
not been ruled out.
this needs to be specified in a condition.
Design which described the use of thermosiphons.
The Proponents indicated that ammonia had been
However we will make adequate training
Thermosiphons are passive devices (require no power
used in the 120,000 thermosiphons, called heat pipes,
source) designed to remove heat from the ground
installed on the Alyeska Pipeline which carries crude
during winter when the air temperature is lower than
oil from Prudhoe Bay, Alaska. Ammonia was found to
manual since the presence of qualified
both the ground temperature and
have the best thermal performance and a lower working
geoscientists on each pipeline spread is
the boiling point of the heat exchange agent. The
pressure, meaning that thinner-walled pipe could be
not a typical requirement.
thermosiphons considered for the project are sealed
used for the thermosiphons. The Proponents noted,
systems containing a pressurized heat transfer agent.
however, that these thermosiphons had operational
Conditions 48 and 49 require the submission
This agent would be either pressurized carbon dioxide
problems due to non-condensing gas accumulating
within the pipes, and the company was converting these
of a slope design methodology final report
or ammonia. Heat is removed from the ground in
winter, when the heat transfer agent boils within
pipes to carbon dioxide. During preliminary engineering
the buried portion of the thermosiphon and the gas
the Proponents had not yet considered the corrosion
rises and condenses in the radiator segment above
protection requirements for thermosiphons but
ground. The heat exchange process stops in summer
acknowledged that the loss of containment of the heat
when the air temperature is warmer than the ground
transfer agent due to corrosion would be undesirable.
Thermosiphons
The Proponents filed an April 2006 report entitled Slope
Design Methodology Report – Preliminary Engineering
1249_NEB_MGP_Vol2_Text_ENG.indd 139
a requirement of the field changes
and a field changes manual for slopes.
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140 Mackenzie Gas Project • Volume 2: Implementing the decision
6.4.8 Watercourse crossings
Figure 6-9
Construction
right of way
Watercourse crossing –
open trench
Temporary
workspace
(if required)
Slash
and
snow
Where a pipeline crosses a watercourse, there
Working side
of right of way
Buried pipeline
in backfilled
trench
is a possibility that the water quality, aquatic
habitat and navigable waterways could be
degraded. Watercourses are a dynamic
component of the physical environment and
are subject to floods, debris flows, ice jams,
Hard plug
(if required)
Spoil
storage
area
Temporary
workspace
(if required)
Assembled
pipeline
section
Slash
and
snow
erosion, and changing banks which can damage
or trigger slope instability or expose the pipe.
In permafrost regions, taliks present the
potential for very large frost bulbs to form
around the pipe which could cause frost heave
Buffer
zone
Spoil
containment
berm
Frozen
Watercourse
watercourse
patterns at watercourse crossings.
The Proponents submitted that the Mackenzie
Open cut
trench
Gathering System and Mackenzie Valley Pipeline
Buffer
zone
Backhoe
Vehicle
crossing
Buffer
zone
natural gas liquids pipeline would cross 260
unmapped, vegetated drainage features to
Hard plug
(if required)
Buried pipeline
in backfilled trench
Plan view, not to scale
would cross 643 water bodies. The shorter
water bodies. These watercourses range from
Spoil
storage
area
Slash
and
snow
and disrupt the surface and groundwater flow
named, navigable corridors including the
Slash
and
snow
Mackenzie River. The project route also crosses
bodies of standing water and peatlands, which
are typically areas of significant shallow
groundwater flow. The Proponents anticipate
taliks to be present beneath perennial
watercourses in areas of continuous or
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Chapter 6: Facilities 141
discontinuous permafrost. With the exception
Figure 6-10
of the major watercourses, there is limited
Watercourse crossing –
flow data from northern regions for use in the
Buried pipeline
in backfilled
trench
hydrologic design of watercourse crossings.
The Proponents selected the proposed crossing
Assembled
pipeline
section
locations to minimize the number and width
of crossings and to avoid areas prone to
Slash
and
snow
channel migration, local scour and ice jams.
Slash
and
snow
The Proponents plan to use a generic design
Spoil
storage
area
template based on company best practices
and a minimum burial depth of two metres
for the majority of crossings. Site-specific
designs for all large watercourse crossings
Spoil
containment
berm
would be based on local stream characteristics,
the 1:100 year flood event, or the 1:200 year
flood event where hydraulic data is limited.
Screened
Watercourse
Frozen
intake
watercourse
Vehicle
crossings
Buffer
zone
Upstream
dam
Open cut
trench
Ditch pump
Vehicle
crossings
constructed using an open trench method when
the watercourses are frozen (see Figure 6-9).
Spoil
storage
area
Where winter flows occur, the flows would
Slash
and
snow
Slash
and
snow
(see Figure 6-10). The Proponents intend to
Pump
install the pipe in horizontal directionally drilled
Discharge
under ice
Backhoe
be controlled and watercourse crossings
would be constructed using isolation methods
Discharge in
approved area
Downstream
dam
Buffer
zone
Generally, watercourse crossings would be
bores (see Figure 6-12) to cross 17 perennial
isolated method
Ditch
excavation
Buried pipeline
in backfilled trench
Plan view, not to scale
watercourses where fish habitat is present
and isolation methods are not feasible.
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142 Mackenzie Gas Project • Volume 2: Implementing the decision
Figure 6-11
Diversion berm at top of slope
Diversion berms
and ditch plugs
Drainage chute with check dams
Diversion berms carry
water off right of way
Rock rip rap
Silt fence
Rock rip rap
Diversion berm
Ditch plug
Pipe
The Proponents propose to control groundwater
flow and seepage along the pipelines using
ditch plugs and diversion berms for overland
areas (see Figure 6-11). In areas of high
groundwater flow, such as watercourse
Did you know?
Definitions
Ditch plug – a section of ditch filled with a material
intended to prevent the flow of ground water
in the backfill along the ditch.
crossings and fens, the Proponents expect
Diversion berm – a berm constructed on
pipe strain related to frost bulb growth to be
the surface of a slope which is intended to direct
manageable, and intend to monitor frost bulb
surface water off the right of way in order to
growth at these locations using aerial patrols
minimize erosion.
and in-line inspection tools.
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Chapter 6: Facilities 143
Volume 2 Figure 6.11
Water crossing by horizontal drilling
Horizontal directionally drilled crossings
Feasibility assessments were carried out for
Horizontal
drilling rig
all proposed horizontal directionally drilled
Figure 6-12
Entry point
Drill pipe
crossings based on subsurface data from
Watercourse crossing –
Designed drill path
Exit point
existing boreholes in the vicinity of the crossings.
horizontal directional
drill using backreaming
method
Additional field work is planned for each
horizontal directional drill location before
drilling begins to confirm soil types, ice
content and the presence of any ice lenses.
Drilling muds are used during directional drill
A small diameter pilot hole is
drilled from the entry point, under
the river bed, to the exit point.
operations to remove drill cuttings, cool and
lubricate the drill bit, provide fluid loss control
and create pressure on the walls of the borehole
Drill pipe
for stability. The Proponents stated that muds
with freezing temperature depressant additives
have a lasting impact on the environment
and increase the complexity of the horizontal
directional drill operation compared to using
chilled muds without freezing temperature
depressant additives. Therefore, using temperature controlled (5°C) drilling fluids without
freezing temperature depressant additives
Next, a reaming tool is pulled back through the pilot hole
to enlarge the hole. More than one pass may be required
to make the hole larger than the diameter of the pipe.
is preferable due to restrictions placed on
Prefabricated pipe section
the disposal of freezing temperature depressant
muds. The Proponents stated that using freezing
temperature depressant additives would be
assessed further during detailed design and
would only be considered where there is
significant concern about hole instability during
drilling. While freezing temperature depressant
muds remain an option, the Proponents
expressed confidence that the directional drill
Prefabricated pipe is attached to a swivel behind
the reamer and pulled into place under the river bed.
operations can be successfully completed using
drilling muds chilled to within a few degrees
above freezing.
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144 Mackenzie Gas Project • Volume 2: Implementing the decision
On the record
Horizontal directional drilling
in Arctic environments
The Proponents indicated that there is little precedent
for horizontal directional drilling operations in
Additional mitigative measures proposed by
The Joint Review Panel expressed concerns
the Proponents to prevent the degradation or
regarding the potential release of sediments
thaw of unstable or ice rich permafrost include
at stream crossings during construction and
insulated work pads, temporary surface drill
the post-construction phase and the potential
casing and auxiliary mud chilling systems.
negative effects of the formation of frost bulbs
permafrost and Arctic environments. A horizontal
directional drilling comprehensive review undertaken
During the course of the hearing Indian
by the Proponents identified several key issues which
and Northern Affairs Canada reviewed
could affect the success of the overall horizontal
directional drilling operations including:
• limited numbers of horizontal directional drilling
contractors with Arctic experience;
the watercourse crossing conceptual designs
and recommended that the Proponents
collect and incorporate into the design
and aufeis at stream crossings. The Joint Review
Panel recommended that measures must be in
place to avoid the creation of frost bulbs and
aufeis at stream crossings through effective
design and mitigation. Frost bulbs in streams
could have an impact on the physical environ-
• logistical planning;
additional data on:
• continuous operation in an extreme cold
• distribution of ground ice;
The biological community in these streams,
• thermal regime of river sediments;
particularly fish and their habitat could be
• extent of taliks;
negatively affected. The Joint Review Panel heard
A significant challenge identified by the Proponents
• soil properties; and
that frost bulb formation can be reduced by
is the development of a drilling mud that will not
• slope characterization at stream crossings.
using pipe insulation however the effectiveness
Indian and Northern Affairs Canada further
of that insulation could degrade over time.
environment; and
• the need for tight control of drilling fluid
properties.
freeze when used in permafrost environments, yet
will remain viscous enough to remove drill cuttings,
provide lubrication and prevent hole collapse. In ice
rich soils the circulation of warm drilling muds will
recommended that prior to construction,
cause the permafrost to thaw, which could lead
the Proponents should submit to the National
to the collapse of the borehole, surface subsidence
Energy Board:
or slope instability.
The horizontal directional drilling study made
• detailed stream crossing designs for
ment if the flow in certain streams is blocked.
Impacts at stream crossings can be further
reduced by deeper burial of pipe but that burial
by itself requires substantial depth to be effective.
The Joint Review Panel was generally satisfied
a number of recommendations including:
the Mackenzie Valley Pipeline and natural
that the Proponents have adequately addressed
• investigating the use of non-toxic, biodegradable
gas liquids pipeline;
potential impacts of the Project on groundwater
methyl glucoside as a freezing temperature
• a comprehensive river engineering analysis;
depressant mud additive;
• revised frost bulb predictions; and
• use of temperature controlled (cooled)
flow, subject to a number of recommendations.
• a typical crossing design for an ice rich slope.
Views of the Board
• investigating mud disposal requirements;
The Proponents submitted that the proposed
We are satisfied with the design approach
• the calculation of frost heave at crossings; and
field investigations and final design requirements
adopted by the Proponents. The design
• the completion of an extensive geotechnical field
would address the recommendations made
approach and construction techniques,
by Indian and Northern Affairs Canada during
for the most part, are conventional and
the oral hearing.
have been used on other projects
drilling fluids;
investigation to identify and delineate horizontal
directional drilling unfavourable substrates,
high ice content soils and taliks.
successfully. We note that horizontal
directional drilling has been used only once
in permafrost areas and that this increases
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Chapter 6: Facilities 145
the potential for unforeseen issues during
6.4.9 Pipeline control systems
installation. We agree with the use of
and leak detection
temperature controlled drilling muds for
Project facilities would be remotely monitored
the majority of the horizontal directional
Leak detection capabilities depend on the accuracy of the measurement devices,
and operated using Supervisory Control and
the design and location and capabilities of the SCADA. At the time of the hearing,
drilling crossings. When this is not possible,
Data Acquisition Systems (SCADA) from a main
the overall system design had not progressed to the point where the Proponents
the alternative use of freezing temperature
control centre in Calgary. Emergency shutdown
depressants has potential undesirable long
systems capable of being initiated remotely
Methodology for Software-based Leak Detection Systems. The Proponents
term impacts on slope stability and their
or locally would be installed. A leak detection
confirmed that its leak detection system for the natural gas liquids pipeline would
use as an option in horizontal directional
system is an important complement to SCADA
drilling must be carefully considered before
because it uses the information SCADA collects
test the leak detection system’s effectiveness annually by inferred methods and not
implementation. Condition 47 requires the
to help detect leaks earlier than surveillance
by annually removing the liquids.
Proponents to undertake a hazard analysis
programs such as aerial patrols. According to
and prepare contingency plans for each
the Proponents, the leak detection system’s
horizontal directional drilling crossing.
performance is important to the integrity
Condition 51 requires an inventory of all
watercourse and water body crossings,
design information, drawings, information
regarding frost bulb analysis, evidence
demonstrating the prevention of aufeis and
unacceptable pipe strains, information
regarding thermal, erosion, scour control
and ground water flow mitigation measures,
of the entire system. Therefore, they would
develop a leak detection quality program
to annually review the system’s performance.
The Proponents added that a typical quality
program would use direct methods, such
Did you know?
Leak detection systems
could accurately determine the necessary leak detection system capabilities.
The Proponents’ decision criteria would be based on API 1155 Evaluation
comply with Canadian Standards Association Z662-03, Annex E Recommended
Practice for Liquid Hydrocarbon Pipeline System Leak Detection; however, it would
as the gathering system upstream of the Inuvik
Area Facility; however, potential performance
improvements were possible with additional
operational experience. The Proponents
would also develop a project-specific plan
to address the full implications of process
control network security.
as liquid withdrawals, and inferred methods,
such as inputting false data into the system,
to evaluate both the system’s performance
Views of the Board
and the response of operating personnel.
In order to minimize potential damage
and evidence of consultation with the
The Proponents indicated that as part of the
from spills during operation, early detection
Department of Fisheries and Oceans.
quality program alarm statistics, actual leak
of leaks and breaks is paramount. Given
Surveillance and monitoring is a
data and system performance information
the remoteness of the pipeline we are of
requirement of the Onshore Pipeline
would be reviewed annually to improve
the view that it is important to ensure the
Regulations, 1999 and all pipeline
system performance.
monitoring and surveillance programs
The Proponents plan to use computational
incorporate the monitoring of watercourse
not prone to false alarms. Conditions 63 and
pipeline monitoring with statistical process
64 require the submission of data regarding
crossings and their approach slopes.
control technology on the Mackenzie Valley
the expected capabilities of the system and
Condition 39, which is discussed later,
Pipeline and Mackenzie Gathering System
reports detailing the actual performance
requires the monitoring of water course
pipelines. The Proponents noted that this
of the system and how the Proponents have
crossings for scour, aufeis, drainage
technology would not be able to detect leaks
addressed performance issues.
impedance and erosion issues.
as effectively in multi-phase lines such
1249_NEB_MGP_Vol2_Text_ENG.indd 145
system can be adequately controlled and
the leak detection capability is sensitive but
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146 Mackenzie Gas Project • Volume 2: Implementing the decision
6.4.10 Settlement of backfill
After a pipeline is built, the earth along the right
of way and ditch line may settle. This settlement
can disrupt drainage and promote erosion if not
addressed. Furthermore, if the backfill thickness
and strength decreases, the pipe may become
buoyant. Experience from the construction
of other northern pipelines demonstrates that
settlement would be limited. The Proponents
intend to mine the material at borrow sites,
and deliver and backfill the pipe trench soon
after the pipe is placed in the trench. They
would use equipment which could process
the backfill into smaller lumps at the borrow
site and on the right of way so that large
lumps would not be placed over top of the pipe.
localized settlement occurs primarily in the first
To help protect the pipe, the Proponents
spring and summer after winter construction.
indicated that the three millimetre, three-layer
In planning their mitigation for ditch settlement,
the Proponents drew on the knowledge gained
by others during the construction of the Ikhil
Pipeline. They plan to import thaw stable fill to
supplement or replace the local backfill at the
time of construction. The Proponents stated that
granular fill material (e.g., sand or gravel) would
be best; however, they recognized that granular
and stockpiling those fill requirements;
• the methods for monitoring for and
remediating ditch subsidence; and
• the methods for disposal of excavated
material not required for backfill.
Views of the Board
expected backfill conditions. In addition to the
during our hearing which presented the
pipeline coating, foam pillows and imported
method used to estimate the settlement
fill for bedding and padding purposes would be
of backfill material that might be required.
used. Pipe protection products such as Rockshield
The ditch settlement values calculated were
and wood lagging (i.e., lumber strapped around
used as the basis for the preliminary designs
the circumference of the pipe) might also be
and estimates of replacement backfill.
used to protect the pipe as required.
The imported backfill quantities were based
route. The Proponents indicated that the only
is more stringent than the requirement for
quality requirement for replacement backfill
overland replacement backfill due to the
was that it be of low ice content so that thaw
potential for slope instability during thawing.
The Proponents identified the need to replace
or improve trench backfill as a function of
slope angle, soil type and method of excavation
in their preliminary slope design.
on route soil information obtained from
geotechnical information available to
the Proponents during preliminary design.
We are confident that these estimates
will improve as a result of the planned
Geotechnical Verification Program. However,
measures are required to ensure that the
Proponents’ efforts to remediate backfill
settlement do not lead to other impacts
The Joint Review Panel considered the
which may be caused by excess backfill
of three factors. First, excavated material tends to
Proponents’ plans for remediating ditch
material being left on the right of way.
increase in volume to the extent that it cannot all
fill settlement satisfactory for most of the
Condition 44 addresses these concerns
be graded back into the ditch. Inevitably some of
terrain likely to be encountered but remained
and implements the Joint Review Panel’s
in areas of permafrost the soil immediately below
concerned about the effectiveness of the ditch
recommendations. The condition requires
the active layer can be ice rich, and this material will
fill settlement remediation for areas of massive
the Proponents to consult with land
lose some volume after it has melted. Third, freshly
ice. The Joint Review Panel recommended that
managers and the appropriate regulators
we require the Proponents to file:
to ensure they are aware of the project
Localized ditch settlement is primarily the result
this excavated soil remains along the ditch. Second,
exposed earth will absorb more solar radiation and
would tend to thaw faster than the adjacent less
disturbed soil.
1249_NEB_MGP_Vol2_Text_ENG.indd 146
• the timing and methods for hauling
We note that the Proponents filed a report
The requirement for slope trench backfill
Ditch settlement
and quantity of imported fill requirements;
pipeline coating would protect against the
material is in short supply along the pipeline
On the record
• methods for determining the quality
backfill requirements for the project and
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Chapter 6: Facilities 147
the need for potential disposal sites for
6.4.11 Right of way protection
the Inuvik Area Facility and Fort Good Hope.
unused material.
during construction
The Proponents are of the view that available
Condition 43 requires the approval of
Thaw-sensitive terrain along the pipeline route
borehole and terrain mapping data from
backfill and padding specifications. The
may be affected by thaw-induced erosion, slope
previous ground disturbances in the Mackenzie
purpose of this requirement is to ensure
instability, or excessive settlement. Disturbance
Valley as well as experience gained from
that this material is not injurious to the
of the vegetative cover specifically on thaw-
building earlier northern pipelines, suggests
pipe and its coating. There is a potential
sensitive overland areas could lead to ponding
a combination of conventional surface leveling
that some of this material will be sourced
and possible sustained thawing.
and cut and fill techniques can be used
from areas where acid-bearing rock may
Based on expected terrain conditions developed
be present. It is our expectation that the
specification will contain a requirement
that quarried material be screened for
this possibility.
successfully south of Inuvik.
from available data, the Proponents plan to
The Proponents indicated that existing borehole
build snow-ice pads, where practical, north
data is sufficient to determine the expected
of the tree line, and at specific locations along
average amount of thaw settlement for a terrain
about 50 kilometres of sensitive terrain between
group. The average settlement for each terrain
NGTL Interconnect
Trout River
Ft Simpson
Willowlake River
Wrigley
Crow Rock Creek
Tulita
Norman Wells
Ft Good Hope
Little Chicago
Inuvik Area Facility
Volume 2 Figure 6.14
Five-year potential surface settlement between Inuvik area facility and
Alberta boundary for different surface disturbances
Fiqure 6-13
Anticipated right of way
settlement for different
clearing techniques
1.6
Note: Thaw settlement values apply only where terrain is frozen
1.4
Settlement (m)
1.2
1.0
0.8
0.6
0.4
0.2
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
0.0
Mainline kilometre post
Locations of thick peat and predicted five-year thaw settlement for
various levels of surface disturbance in frozen terrain – mainline route
Thaw settlement – clearing and removed surface organics
Thaw settlement – clearing and disturbed surface organics
Thaw settlement – clearing and undisturbed surface organics
1249_NEB_MGP_Vol2_Text_ENG.indd 147
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148 Mackenzie Gas Project • Volume 2: Implementing the decision
group between Inuvik and Norman Wells is
pursuant to Condition 44(d), we will verify
as oxides of nitrogen, fine particulate matter,
predicted to be less than about 0.5 metres after
that the Proponents’ plans to remove excess
carbon monoxide and volatile organic
five years. Figure 6-13 shows the anticipated
replacement backfill from the right of
compounds could have a direct impact on
right of way settlement between Inuvik and
way will incorporate measures to limit
human health, wildlife and vegetation. Oxides
the Nova Gas Transmission Ltd. interconnection
disturbance of the surface organics.
of nitrogen and volatile organic compounds
are precursors to the formation of secondary
in Northern Alberta for three different clearing
and right of way preparation techniques in
areas of thick peat. The Proponents added that
long-term terrain effects would be acceptable
provided the necessary rehabilitation and
re-vegetation is carried out. Where grading is
considerations
6.5.1 Overview
particulate matter and ozone. Oxides of
nitrogen also contribute to acid rain.
Environment Canada noted that air quality
in the project area is good and recommended
In addition to the design issues discussed
pollution prevention measures to minimize
above, a number of technical issues were raised
negative effects on air quality. Recommenda-
during the hearing related to construction and
tions were made for both the pipeline and the
operation. The following issues are included
facilities and included ways to reduce methane
Mitigative measures being considered
in this section:
emissions during operation including:
by the Proponents include:
• air emissions;
• reducing oxides of nitrogen and sulphur oxide
• using surface insulation, such as a layer
• pressure testing;
necessary and high-ice content soil is exposed,
special protective measures would be applied
before the construction season ends.
emissions from gas turbines;
of stripped organics, wood chips or
• northern logistics and construction;
• minimizing greenhouse gas emissions; and
board stock insulation under a layer
• right of way protection during construction;
• reducing benzene and other emissions.
of soil, to limit seasonal thaw;
• installing berms and breakers
for erosion control; and
• stabilizing the right of way through
and
• preliminary plans for integrity monitoring
and surveillance
Methane emissions
Environment Canada provided examples of
pipeline best management practices that
6.5.2 Air emissions
address operational methane emissions. These
During operation the project would emit
examples included:
greenhouse gases including carbon dioxide
• dry gas seals on compressors;
from combustion‑related sources such as
• unit isolation valve systems;
Based on the successful use of conventional
compressors, along with methane gas released
• electric or air starting systems for gas turbines;
surface leveling techniques on the Norman
through normal venting procedures and minor
• optimized maintenance and pigging
Wells Pipeline we are satisfied with
leaks (fugitive emissions). Annual equivalent
the Proponents’ proposed right of way
carbon dioxide emissions during operation are
• regular leak detection and aerial surveys;
preparation plans south of the tree line.
estimated at 812.8 kt/a. Construction activities
• line break controls;
North of the tree line and in limited
are expected to generate up to 487.6 kt/a
• computational leak detection;
areas north of Fort Good Hope, where
of equivalent carbon dioxides. Other air
• pre-installed connecting tees for future
construction from snow pads is required,
contaminants which may be emitted, such
re-vegetation.
Views of the Board
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6.5 Other technical
schedules;
gathering pipelines and compressor stations;
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Chapter 6: Facilities 149
• hot tapping;
Environment Canada supported the
would be used as primary power production
• operator training; and
implementation of these best management
for the Storm Hills pigging facility, compressor
• an emergency response plan.
practices by the Proponents, but added that
stations, and the Trout Lake heater station.
it was not necessary as a prerequisite that the
Diesel engines would be used for standby
best management practices be adopted by
emergency power generation. Engines would
Alberta’s Energy Resources Conservation Board.
be selected using proven low emission design
The Proponents stated they would implement
the best management practices that are
currently being developed by the Canadian
Association of Petroleum Producers,
Oxides of nitrogen and
Environment Canada, the Canadian Energy
sulphur oxides emissions
Partnerships for Environmental Innovation
Environment Canada stated that using dry
and the Canadian Gas Association, once these
low oxides of nitrogen gas turbines that meet
are adopted by Alberta’s Energy Resources
the 1992 Canadian Council of Ministers of
Conservation Board Directive 60. This
the Environment National Emission Guidelines
document is called Best Management Practice:
Management of Fugitive Emissions at Upstream
Oil and Gas Facilities and is expected to:
• identify large versus small fugitive emission
criteria and would meet or exceed the requirements of Alberta Environment’s Code of Practice
for Compressor and Pumping Stations and
Sweet Gas Processing Plants, 1996, which
specify a maximum oxides of nitrogen level of
6 grams/kilowatt-hour for engines over 600 kW.
for Stationary Combustion Turbines along
Greenhouse gas emissions
with reciprocating engines that meet or
Environment Canada stated that maintaining
exceed the requirements for such engines in
an efficient gas processing and pipeline system
Alberta’s Energy Resources Conservation Board
is important factor in minimizing greenhouse
sources, to allow operators to focus on
Directive 56 would meet Environment Canada’s
gas emissions and conserving natural gas.
sources with larger volume emissions;
recommendations regarding the appropriate
Environment Canada cited waste heat
application of best available technology and
recovery as a method of achieving this goal.
best management practices in order to reduce
The Proponents’ preliminary designs incorporate
the project’s oxides of nitrogen and sulphur
waste heat recovery in the Inuvik Area Facility.
oxide emissions. Alberta’s Energy Resources
Environment Canada recommended that
Conservation Board Directive 56 requires
the Proponents provide details concerning
compliance with Alberta Environment’s Code
the design choices for waste heat recovery at
of Practice for Compressor and Pumping
the Inuvik Area Facility prior to construction.
• provide a tiered approach for developing
leak detection and repair programs;
• recommend a framework for establishing
guidelines, such as leak definition, sampling
protocols, leak detection frequency, repair and
maintenance and other monitoring methods;
• describe methods of flow indication to
determine leakage, and to determine how
this information would be used to guide
Stations and Sweet Gas Processing Plants, 1996.
Benzene emissions
The Proponents intend to specify the require-
Natural gas produced at the development
ment that gas turbines meet or exceed Canadian
fields would be dehydrated before entering
benchmarking fugitive emissions information
Council of Ministers of the Environment
the gathering pipelines. Glycol dehydrators
resulting from any leak detection and repair
guidelines in the purchase agreements. The
typically used in the upstream oil and gas
program implemented.
Proponents added that vendors would be
industry have the potential to emit benzene gas.
required to guarantee emissions performance
Benzene can cause harmful effects at any level
and fuel efficiency. The Proponents indicated
of exposure and available evidence indicates that
that natural gas fuelled reciprocating engines
it is a carcinogen. Accordingly, benzene emissions
repair and maintenance decisions; and
• provide a method for collecting and
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150 Mackenzie Gas Project • Volume 2: Implementing the decision
were a concern for Environment Canada.
Views of the Board
The Proponents indicated that molecular sieve
Addressing emissions issues begins with
dehydration units would be used where required.
making appropriate design decisions to
Environment Canada expressed the view that
minimize energy use, implementing best
phrase “best available technology” varies according
glycol dehydrators could be specified during
to the specific application. For the Mackenzie Gas
available technologies and using best
final design and suggested implementing
available management practices. The
a condition requiring glycol dehydrators be
Proponents made undertakings during
safety and environmental protection and would
designed, installed and operated in accordance
our hearing which indicate their intention
expect any best available technology to achieve
with recommended practice Control of Benzene
to implement these measures. Conditions 11
Emissions from Glycol Dehydrators (Canadian
and 13 require the Proponents to submit
a particular proposed technology is best available
Association of Petroleum Producers, 2000)
reports that will confirm the implementation
technology. These criteria are that:
and comply with Alberta’s Energy Resources
of their undertakings. Condition 67 requires
• it must be a technology with superior
Conservation Board Directive 39: Revised
the Proponents to minimize and reduce
program to Reduce Benzene Emissions from
emissions from flaring.
On the record
Best available technologies and best
management practices
Environment Canada stated that the intent of the
Project, Environment Canada understood the phrase
to refer to the continuous improvement of pipeline
that intent. In addition, Environment Canada pointed
to certain criteria guiding its assessment of whether
emissions performance;
• it must be commercially available at the time
it is required for the project;
• the cost for the technology must be reasonable;
and
Glycol Dehydrators.
We agree with the measures proposed
Other emissions
by Environment Canada to limit mercury,
Environment Canada noted that incinerators
dioxin and furan emissions. Condition 12
operating at work camps and other project-
requires the submission of a report
related facilities could emit mercury, dioxins
evaluating technologies and practices the
management practices are innovative, dynamic,
and furans. Environment Canada recommended
Proponent will implement to reduce these
and improved environmental protection practices
that all incinerators be required to meet
emissions from camps and station facilities.
emission limits in the Canada-wide Standards
These technologies and practices must be
Canada indicated that best management practices
for Mercury Emissions and the Canada-wide
reflected in the waste management plans
may exist as formal guidelines or generally accepted
Standards for Dioxins and Furans. Environment
procedures recognized by regulators and industry
required by Conditions 16 and 59.
Canada stated that using best available
• the best available technology includes the goals
of pollution prevention and energy efficiency.
Environment Canada expressed the view that best
that help ensure development is conducted in an
environmentally responsible manner. Environment
associations as best practices. Best management
practices for this project refer to both system
incineration technologies and best management
design and operating practice for all activities and
practices would also minimize emissions of
operations from the wellhead to the product’s final
particulate matter and precursors to pollution
destination, using overall system optimization, energy
efficiency, reliability and air emissions prevention.
management and ozone. Environment Canada
added that best management practices for
incineration focus on waste segregation,
reducing the amount of waste to be incinerated
and proper operation and maintenance of
incineration equipment. Dual chamber and
controlled air technologies are considered best
available technology for incineration.
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Chapter 6: Facilities 151
6.5.3 Pressure testing
Prior to final commissioning, testing is conducted
on the assembled pipeline to verify at the outset
that the pipeline does not have undetected leaks
and that the pipeline is capable of containing
its design pressure plus an appropriate safety
margin. While water is generally considered to
be the most acceptable testing medium, freezing
temperature depressants must be added to
prevent freezing in the pipeline or test facilities
in cold climates. For alternative test mediums
such as air, operators may need to address
additional safety risks and demonstrate that
an equivalent degree of accuracy, as compared
to hydrostatic fluids, can be achieved.
The Proponents stated that the installed
pipelines and facilities would be pressure tested
in segments to confirm the strength and to
check for leaks in accordance with Canadian
Standards Association Z662 requirements.
Potential test media evaluated by the
Proponents include:
• heated water;
• water with freeze depressants;
• air;
• nitrogen; and
• hydrocarbons.
The Proponents indicated that their plan
is to use a mixture of water and methanol
to pressure test the natural gas liquids pipeline
with freeze depressants and air are both being
assessed. The Proponents indicated that air
testing was also being considered as an option
because of difficulties with water testing such
as drying pipelines and managing the different
volumes required by each test section (with
varying pipeline lengths and diameters),
as well as cost and schedule considerations.
In order to compensate for the air test’s lack
of sensitivity, it was suggested that test section
volumes and hold period durations could be
adjusted. Further, odorant could be added
to increase the ability to detect small leaks. If a
leak occurs, the segment identified by the test
would be uncovered and repaired or replaced.
Views of the Board
6.5.4 Support infrastructure
The Proponents submitted that construction
of the project facilities will involve the construction of extensive off right of way support
infrastructure including roads, borrow sources,
camps, barge landings and staging areas. The
project would require new roads to transport
materials, equipment and personnel to and from
camps, facility and pipeline construction sites.
The Proponents estimate they would need
60 kilometres of all-weather roads and
820 kilometres of winter roads for the
project. Of the 820 kilometres of winter,
roads 235 kilometres would be ice roads over
rivers and lakes. Approximately 80 percent of
the winter roads would be needed to access
water and borrow sources for the project.
Due to its ability to detect leaks and for
safety reasons we consider hydrostatic
The borrow requirements for the project are
testing to be the preferred method of
estimated at 7.6 Mm3 and would be sourced
ensuring pipeline integrity prior to
from 68 primary sites in the Mackenzie Delta
operation. We recognize that there may
and Mackenzie Valley. This material is required
be circumstances where air testing may
for development field facility sites, the Inuvik
be necessary. Condition 57 requires the
Area Facility, pipeline facilities, infrastructure
filing of the Pressure Testing Program
development and pipeline backfill.
required by section 23 of the Onshore
Pipeline Regulations, 1999 which specifies
additional requirements for air testing
should its use be necessary.
Winter roads for the project must be durable
enough to support the expected construction
equipment needed to transport 7.6 Mm3 of
borrow material, as well as project equipment
and materials. The Proponents indicated this
and Mackenzie Valley Pipeline. The mixture
of water with freeze depressants could be
reused to minimize the volume of fluid required
for testing and for eventual disposal. For the
upstream gathering pipelines, water mixed
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152 Mackenzie Gas Project • Volume 2: Implementing the decision
would require developing similar, but more
Views of the Board
6.5.5 Northern logistics and construction
stringent, design specifications than the
The construction, operation and closure of
Logistics
Government of the Northwest Territories winter
winter roads require regulatory measures to
The Mackenzie River would be the primary
road construction standards. The Proponents
reduce the off right of way impacts of the
transportation corridor for the project. Most of
stated that maintenance would comply with
project. There are also safety concerns since
the material required to build the pipeline would
local regulatory approvals and would generally
235 kilometres of these winter roads would
be shipped by rail from the south to Hay River
conform to Environmental Guidelines for the
be over lakes and rivers. The Northwest
where it would be transferred to barges for
Construction, Maintenance and Closure of
Territories Department of Highways has
travel north in the summer. Pipeline construction
Winter roads in the NWT, a handbook used by
experience constructing and operating
would take place mostly in winter when the
the Northwest Territories Department of
these roads and the handbook used by
ground surface is sufficiently frozen to support
Transportation. The Proponents also indicated
the Northwest Territories Department of
the movement of vehicles. Trucks would use
that ice thickness requirements for ice crossings
Transportation is sufficient for their needs.
existing highways, winter roads and new project
would be similar to the Government of the
However, is likely that most of the workers
roads. Construction crews would travel to the
Northwest Territories ice bearing assessments.
constructing, operating, using and closing
camps by aircraft, which would limit private
the project’s winter roads, many of whom
vehicle use by the workforce. Substantial
will come from outside of the Northwest
improvements to existing infrastructure and
Territories, will not have the benefit of this
new project-specific infrastructure such as barge
experience. We are of the view that a single
landings, camps and temporary winter roads
manual encompassing both safety and
would be required to accommodate construc-
environmental requirements of winter road
tion activities. Some very large processing and
management is required for the project to
compressor modules for the Inuvik Area Facility
minimize off right of way environmental
would be shipped by sea to Inuvik where
impacts and promote safety. Conditions 9
specialized carriers would transport them to the
and 10 require the filing of winter road
site on purpose-built gravel and winter roads.
manual as well as the permits, authorizations and letters of advice issued by
governments and regulators which have
a bearing on winter road construction,
operation and closure.
Schedule
The Proponents’ construction plan assumes
four years of construction for infrastructure,
pipelines, and associated facilities. To address
potential issues related to the availability of
labour and increased costs, the construction
plan distributed pipeline construction activities
over three full winter seasons.
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Chapter 6: Facilities 153
Construction Activities by Season
First Summer
First Winter
• Mobilize some equipment, small camps and fuel for initial site development.
• Develop borrow sites and stockpile borrow material.
• Begin to develop barge landing sites.
• Begin to install main construction camp pads and stockpile pads.
• Mobilize equipment, small camps and fuel for right of way clearing.
• Transport fuel by barge and truck to support future construction.
• Continue borrow site development work.
• Develop barge landing sites.
• Install main construction camp pads, stockpile pads and facilities pads.
• Begin installing main infrastructure, including camps and field-erected tanks.
• Survey, clear and, potentially, grade the right of way and facility sites.
• Geotechnical Verification Program.
Second Summer
Second Winter (First pipe-laying season)
• Mobilize pipe, equipment, camps and fuel to support main construction.
• Install construction camps.
• Clear pipeline right of way, where practical.
• Continue developing and operating borrow sites.
• Continue installing infrastructure and facility pads.
• Construct pipeline sections with multiple construction spreads.
• Continue surveying and clearing right of way and facility sites.
• Continue developing and operating borrow sites and installing infrastructure,
including camps and field-erected tanks.
• Install pile foundations at facility sites.
• Begin pipeline right of way construction cleanup.
• Geotechnical Verification Program.
Third Summer
Third Winter (Second pipe-laying season)
• Mobilize pipe, equipment, camps and fuel to support main construction.
• Construct pipeline sections with multiple construction spreads.
• Continue surveying and clearing right of way and facility sites, where required.
• Continue developing and operating borrow sites and installing infrastructure,
including camps and field-erected tanks.
• Install pile foundations at facility sites.
• Install construction camps.
• Clear pipeline right of way, where practical.
• Transport facility modules from Hay River.
• Install pile foundations at facility sites.
• Begin facility assembly at sites and continue construction.
• Continue pipeline right of way construction cleanup and reclamation.
• Continue developing and operating borrow sites and installing infrastructure.
Fourth Summer
Fourth Winter (Third pipe-laying season)
• Mobilize pipe, equipment, camps and fuel to support main construction.
• Complete surveying and clearing right of way and facility sites, where required.
• Construct remaining pipeline sections with multiple construction spreads.
• Transport facility modules to remote sites.
• Complete pipeline construction.
• Continue operating borrow sites.
• Continue facility construction.
• Continue pipeline right of way construction cleanup and reclamation.
• Install construction camps.
• Clear pipeline right of way, where practical.
• Transport facility modules from Hay River and offshore locations.
• Continue installing facility modules and construction.
• Continue developing and operating borrow sites and installing infrastructure.
• Begin demobilizing camps and equipment.
Fifth Summer
Fifth Winter
• Complete facility construction.
• Begin commissioning and start-up activities for pipelines and facilities.
• Begin infrastructure and borrow site reclamation.
• Continue pipeline right of way construction cleanup and reclamation.
• Complete commissioning and start-up activities.
• Start up and begin operating facilities and pipelines in Q4 2018.
• Continue pipeline right of way construction cleanup and reclamation.
• Continue demobilizing camps and equipment.
• Continue demobilizing camps and equipment.
Sixth Summer
• Complete pipeline right of way construction cleanup and reclamation.
• Complete reclamation of infrastructure sites not required for operations.
• Complete demobilization.
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154 Mackenzie Gas Project • Volume 2: Implementing the decision
Construction Safety
situation, contractors participating in project
project will promote worker safety,
Pipeline construction projects in winter
construction must meet safety requirements.
protect the environment and help maintain
conditions similar to those in the project area
The Proponents added that safety training must
the project schedule.
have been successfully completed in the past.
be completed before workers are assigned to a
To ensure the Mackenzie Gas Project is equally
work site and that supplemental safety training
successful, the Proponents have incorporated
would also be provided, both before and
the following mitigation measures in
during construction, to ensure workers have
construction planning:
the required safety related qualifications.
• providing shelters for welding, horizontal
directional drilling and pressure testing;
• using electric resistance and propane flame
heating to meet preheat, inter-pass and
post heating requirements for welding and
the field application of weld joint coatings;
• fitting construction machinery for
arctic service;
• installing cooling and lubricating system
heater devices to allow equipment to
be shut down for extended periods;
• developing activity shutdown criteria; and
• sizing crews and equipment to allow work
These conditions include the filing of:
•• Environmental Protection Plans (EPP)
and corresponding environmental
alignment sheets;
•• a waste management plan;
In order to maintain worker safety in northern
working conditions, the Proponents indicated
that the personal protective equipment provided
for each worker would be appropriate for
their work assignments. This equipment would
typically include a hooded arctic parka, insulated
coveralls, lined leather mitts, insulated arctic
work boots, face protection and headgear.
In addition, the Proponents stated it would
provide crew transportation buses and
emergency shelters with heaters so that
warm-up breaks could be taken depending
on working conditions.
•• an emergency response plan;
•• a construction safety manual;
•• construction schedules;
•• a manual for the construction
operation, maintenance and closure
of winter roads;
•• permits, authorizations and letters of
advice from federal departments, the
Government of the Northwest Territories
and local regulatory organizations;
•• project organization details
of the Proponent;
•• engineering alignment sheets;
to continue during warm-up breaks.
•• field change manual for slope design;
The Proponents’ planning assumes pipeline
Views of the Board
construction crews would work seven days
Conditions 3, 4, 7, 8, 9, 10, 15, 16, 19, 20,
a week, 12 hours per day. Some activities such
21, 29 to 36, 39, 42, 49 and 56 require the
as directional drilling and ditching may be
Proponents to construct the Mackenzie Gas
carried out around the clock. The Proponents
Project with due consideration of safety, the
estimated that 15 to 20 percent of scheduled
environment, and logistical and scheduling
There is also a requirement to provide
working days may end up being weather days,
difficulties in the North. Some of these
logistical support to the National Energy
resulting in little or no productivity.
conditions have been elaborated elsewhere
Board staff undertaking construction
The Proponents stated that one of the primary
in this volume. Implementation of these
inspection and reclamation.
project priorities is to provide an injury-free,
conditions during construction of the
•• heritage resources management plans;
•• wildlife management plans;
•• air quality monitoring program; and
•• project progress reports.
incident-free, healthy workplace and that,
regardless of the labour supply and demand
1249_NEB_MGP_Vol2_Text_ENG.indd 154
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Chapter 6: Facilities 155
6.6 Preliminary plans for integrity
although high operating pressures and long
Integrity management program
monitoring and surveillance
inspection lengths would also limit certain tools.
An Integrity Management Program is a proactive
The Proponents outlined preliminary plans
Did you know?
program which typically incorporates the tools,
technologies, procedures and strategies needed to
In-line inspection tools perform better within
for monitoring and surveillance as well as
ensure pipelines are safe, reliable and environmen-
its proposed frequency of inspection. These
tally responsible. The included management system
preliminary plans are listed in Table 6-5.
defines the scope of the program, organizational
certain speed ranges. Another challenge is
developing speed control that would minimize
impacts on throughput while allowing accurate
inspection of the pipeline. The Proponents were
The Proponents expressed the view that strain
of the view that, although these constraints
accumulation from frost heave and thaw
would pose challenges for in-line inspection
Program incorporates a records management system
settlement would occur over several years before
tool vendors, these are not vastly different
to provide timely access to important integrity
they would approach critical strain levels. During
from other challenges that have been solved in
information. The program would also typically
the operating phase, inline strain monitoring
the past with enough lead time and planning.
lines of responsibility, personnel training and
qualification requirements, change management
and program monitoring. An Integrity Management
include hazard identification and condition
monitoring using methods such as in-line inspection
would be required so that the Proponents
tools (pigs) and a mitigation program to correct
can undertake appropriate maintenance before
integrity issues identified. The monitoring of pipeline
the onset of the limiting strains. Therefore it is
strain, corrosion and geotechnical hazards is within
the scope of an Integrity Management Program.
particularly important to the project to construct
a suitable in-line inspection tool or tools that
can detect strain accumulation in the Mackenzie
Gas Project pipelines and would work under
the anticipated conditions. Also required is
a detailed survey of as-constructed base line
approximately two years prior to operation
and in-line inspection monitoring can only be
done in the first year of operation, Indian and
Northern Affairs Canada suggested that the
Proponents be required to survey the location
of the pipe after it is lowered into the trench
to determine its precise location prior to line fill.
conditions in order to measure strain that
Indian and Northern Affairs Canada suggested
develops following construction. The Proponents
that In-line inspection monitoring of the pipeline
indicated that the baseline survey of the pipe
be conducted twice in the first year of pipeline
would be undertaken during construction
operation, with the frequency thereafter based
instead of running the inspection tool immedi-
on those results and as directed by the National
ately after the start of pipeline operation.
Energy Board, with a minimum of one In-line
The Proponents assessed the pipeline operating
1249_NEB_MGP_Vol2_Text_ENG.indd 155
Because the pipelines will be buried for
inspection per year.
parameters of temperature, pressure, fluid
The Joint Review Panel recommended that
speed, fluid composition and multiphase flow
we require the Proponents to implement
against the operating capabilities of currently
an effects monitoring plan that includes,
available in-line inspection tools and discovered
in addition to pipeline integrity monitoring,
challenges that would limit pipeline inspection
monitoring of permafrost, terrain and
capability. The most difficult challenge is
geotechnical parameters relevant to thaw
overcoming low operating temperatures,
and frost bulb impact assessment.
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156 Mackenzie Gas Project • Volume 2: Implementing the decision
Table 6-5
Proponents’
Mechanism
Preliminary monitoring
method options
Indicator
Preliminary monitoring frequency
preliminary plans
Frost heave
Curvature in-line
Strain accumulation
Baseline is the construction as-built survey.
for monitoring
inspection (ILI)
and surveillance
Annual in-line inspection runs for the first three years of operation.
Frequency of subsequent runs based on projected strain accumulation.
Thaw settlement
Remote sensing methods
Ground deformation
Quarterly, at identified sites.
Inertial ILI
Strain accumulation
Baseline is the construction as-built survey.
Annual in-line inspection runs for the first three years of operation.
Frequency of subsequent runs based on projected strain accumulation.
Upheaval displacement
Aerial patrol
Ground deformation
Monthly.
Remote sensing methods
Ground deformation
Quarterly, at identified sites.
Inertial ILI
Strain accumulation
Baseline is the construction as-built survey.
Annual in-line inspection runs for the first three years of operation.
Frequency of subsequent runs based on in-line inspection trends.
Slope instability
Aerial patrol
Ground deformation
Monthly.
Inertial ILI
Strain accumulation
Baseline is the construction as-built survey.
Annual in-line inspection runs for the first three years of operation.
Frequency of subsequent runs based on projected strain accumulation.
Aerial patrol
Ground deformation
Monthly.
Slope monitored by
inclinometers, thermistors,
piezometers
Ground deformation
As required.
Remote sensing
Ground deformation
Quarterly, at identified sites.
Frost bulb growth-crossings
Aerial patrol
Icings
Monthly.
Frost bulb growth-general
Aerial patrol
Drainage impedance
Monthly.
Buoyancy
Aerial patrol
Loss of cover
Monthly.
River scour-lateral
Aerial patrol
Loss of cover
Monthly.
River scour-vertical
Diver survey
Loss of cover
As required.
Right of way performance
Aerial patrol
Drainage and erosion integrity
Monthly.
Corrosion
Magnetic flux leakage
or ultrasonic ILI
Metal loss
Initial run in years 5 to 7 of operations.
Investigative digs
Cracking
As required.
Third party damage
Aerial patrol
Encroachment on rights of way
Monthly.
Seismicity
Aerial patrol
Slope movement
Monthly.
Frequency of subsequent runs based on in-line inspection trends.
Loss of support
1249_NEB_MGP_Vol2_Text_ENG.indd 156
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Chapter 6: Facilities 157
Views of the Board
Given the importance of strain monitoring
in the current design, Condition 60 requires
the Proponents to have the necessary
in-line inspection tools available to inspect
the pipeline during operation.
Condition 39 requires the development
of an effects monitoring program. We
have specified that the program’s scope,
objectives, monitoring methodologies,
frequencies and criteria for the selection
of instrumented sites be determined prior
to the first of the pipe-laying activities to
We agree with Indian and Northern Affairs
facilitate the early selection of sites to
Canada that establishing a base line for
be monitored, the acquisition of detailed
future in-line inspection monitoring of a
data on pre-disturbance/ pipeline
pipeline’s position is important. Condition 70
operation conditions, and early installation
requires the Proponents to survey the
of instrumentation.
position of the pipelines after they are
lowered in the trench. We are not persuaded that Indian and Northern Affairs
Canada’s suggestion of running the in-line
inspection twice in the first year is warranted given the pipelines will be in the ground
To facilitate effects monitoring, and
adaptive management during operation
Conditions 66 and 68 to 72 require the
submission of as-built slope information,
post-construction environmental reports,
ditch wall logs and the stream flow, ice
two seasons prior to operation; however
thickness and ground temperature data
we are of the view that requiring a high
used for project planning and design.
resolution in‑line inspection to determine
Condition 37 which requires the filing of
their position within one month of opera-
the Geotechnical Verification Program data
tion has merit. Condition 70 requires that
and Condition 45 which requires the filing
the Proponents monitor geotechnical and
of the Proponents’ geohazard assessments
thermal effects on the Mackenzie Gathering
would also inform the effects monitoring
System and Mackenzie Valley Pipeline with
program. In keeping with the National
respect to thaw subsidence, frost heave
Energy Board’s usual practice, these
and slope stability using inertial in-line
submissions will be available to the public
inspection within one month of the start of
by way of the National Energy Board’s
operation and on an annual basis thereafter.
regulatory repository.
1249_NEB_MGP_Vol2_Text_ENG.indd 157
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158 Mackenzie Gas Project • Volume 2: Implementing the decision
6.7 Emergency response
Views of the Board
The Onshore Pipeline Regulations, 1999
Safely responding to a transportation
requires pipeline companies to develop, regularly
emergency or spill requires coordination,
review and update, as required, an emergency
training, knowledge of the products
procedures manual. A company must take all
involved, the appropriate personal protective
reasonable steps to inform all persons who
equipment and spill response equipment.
may be associated with an emergency response
activity on the pipeline of the practices and
procedures to be followed, and make available
to them the relevant information that is
consistent with that which is specified in the
emergency procedures manual. A company must
also develop a continuing educational program
for the police, fire departments, medical
facilities, other appropriate organizations
and agencies and the public residing adjacent
to the pipeline to inform them of the location
of the pipeline, potential emergency situations
To address worker and public safety and
environmental protection during construction, Condition 4 requires the Proponents
to file an Emergency Response Plan at
least 60 days prior to pre-construction.
During construction, the Proponents and
their contractors will be on the scene for
incidents on the right of way, on project
opportunities and constraints of establishing these teams and a commitment to work
with local communities to build and
maintain capacity. Condition 62 requires
the Proponents to confirm that they have
completed an emergency response exercise
to evaluate the effectiveness of their
response plans prior to operation.
Government departments have
responsibility for emergencies occurring
on territorial highways, winter roads
and on the Mackenzie River. They will
have the responsibility for emergency
response training and equipment needs
at these locations.
winter roads and at camps and they will
be required to have the necessary resources
to respond appropriately. We have there-
involving the pipeline and the safety procedures
fore decided local, community-based
to be followed in the case of an emergency.
spill response teams are not necessary
for the construction phase of the project.
The Joint Review Panel recommended that we
1249_NEB_MGP_Vol2_Text_ENG.indd 158
require the Proponents to provide, prior to the
To ensure that the Proponents are
commencement of construction, and as part of
prepared for an emergency on the first
the an emergency preparedness and response
day of operation Condition 61 requires
plan for all forms of transportation associated
the submission of emergency procedures
with the Mackenzie Gas Project, an assessment
manuals at least 30 days prior to operation.
of the potential for the establishment of local,
We believe that local communities could be
community-based spill response teams. This
involved in pipeline emergencies occurring
assessment would include their commitment to
during operation as they may be the closest
build community spill response and a discussion
to the incident. Condition 61 requires
of the opportunities and constraints in
an assessment of the potential for local
establishing local spill response teams.
community-based spill response teams,
12/6/10 11:02:39 AM
Chapter 6: Facilities 159
6.8 Other requirements
Debris Liability Regulations and pursuant
specific to the Mackenzie
to subsection 27(1) of the Canada Oil
Gathering System
Views of the Board
We are of the view that the requirements
for the Mackenzie Gathering System,
regulated under the Canada Oil and Gas
Operations Act, should be consistent with
and Gas Operations Act in the amount
of $25,000,000 in a form satisfactory
to the National Energy Board prior
to commencement of pre-construction
activities and that will remain in place until
all facilities are abandoned in accordance
with National Energy Board requirements.
the requirements for the Mackenzie Valley
Condition 79 stipulates that the authoriza-
Pipeline, regulated under the National
tion for the Mackenzie Gathering System
Energy Board Act. In this regard, for the
under paragraph 5(1)(b) of the Canada Oil
Mackenzie Gathering System, Condition 77
and Gas Operations Act is subject to the
requires the Proponents to comply with
Minister of Indian Affairs and Northern
the Onshore Pipelines Regulations, 1999,
Development Canada providing confirma-
as amended from time to time; the National
tion that the Proponents have satisfactorily
Energy Board Processing Plant Regulations,
met the Benefits Plan requirements
as amended from time to time; and those
of section 5.2 of the Canada Oil and Gas
sections of the National Energy Board
Operations Act.
Pipeline Crossing Regulations Part I and
Part II as amended from time to
time. Similarly, Condition 78 requires
the Proponents to file for approval the
information referred to in the National
Energy Board Filing Manual, 2004, for
opening the pipeline for operation.
There are also requirements under the
Canada Oil and Gas Operations Act that
apply to the Mackenzie Gathering System.
Condition 80 requires the Proponents
to provide a declaration pursuant to
subsection 5.11(1) of the Canada Oil and
Gas Operations Act in a form satisfactory to
the National Energy Board prior to commencement of pre-construction activities.
Condition 81 requires the Proponents to
provide any necessary certificates pursuant
to subsection 5.12(1) of the Canada Oil and
Gas Operations Act in a form satisfactory
Condition 76 requires the Proponents to
to the National Energy Board prior to
provide financial responsibility pursuant
commencement of the related activities.
to the Canada Oil and Gas Spills and
1249_NEB_MGP_Vol2_Text_ENG.indd 159
12/6/10 11:02:39 AM
Chapter 7
Economic feasibility
7.1 Public convenience and necessity
The National Energy Board must be satisfied that any facilities it approves pursuant to section 52
of the National Energy Board Act are required by the present and future public convenience
and necessity. In making that determination, the National Energy Board considers the economic
feasibility of the project. This involves determining the likelihood of the facilities being used at
a reasonable level over their economic life and the likelihood of the demand charges being paid.
The National Energy Board takes the following
criteria into consideration when considering
economic feasibility for facilities built under
the National Energy Board Act:
Development of the large natural gas deposits
that lie buried under the Mackenzie Delta
has had a unique history. The resources were
• the availability of markets for the gas flowing
discovered in the early 1970s when natural gas
on the pipeline (will the gas be purchased?);
prices were not high enough to justify building
• the availability of downstream pipeline
costly pipeline infrastructure. Growing natural
capacity (will there be sufficient pipeline
gas consumption and decreasing production
capacity to move the gas from the end
from conventional sources in North America
of the Mackenzie Valley Pipeline to
have enticed producers back to the Mackenzie
ultimate markets?);
Valley in search of hydrocarbons. While a small
• the long-term gas supply which is available
amount of gas is currently produced in the
to the pipeline (is there sufficient gas to
Mackenzie Delta for local use, producers will
be transported?);
need access to the larger markets in southern
• the contractual commitments underpinning
Canada and the lower 48 U.S. states in order
the project (will the fixed cost component
to support the significant development of these
of the pipeline tolls be paid?); and
resources. The Mackenzie Gas Project would
• the ability of the project to be financed
(will investors fund the pipeline?).
1249_NEB_MGP_Vol2_Text_ENG.indd 160
7.2 Economic setting
provide northern producers with access to the
North American pipeline network and markets.
12/6/10 11:02:41 AM
Chapter 7: Economic feasibility 161
The Mackenzie Gas Project would be:
• the timing of the development of these
• Is there “open access” so that any
• largely owned and operated by producers;
producer that meets the tariff requirements
• opening access to a previously
is able to use the pipeline?
little-developed basin;
• located a great distance away from
natural gas markets and existing
transportation infrastructure; and
• located in an environmentally unique
resources; and
• whether resources will be large enough to
allow them to be connected economically.
The first question is discussed here in
The natural gas resources in the area are shown
Chapter 7 and the second in Chapter 8.
in Figure 7-1.
7.3 Supply
The Proponents assume that three years after
For many new natural gas pipelines, the main
they begin producing natural gas from the
challenge is ensuring that there will be enough
The project must meet a threshold or
Niglintgak, Parsons Lake and Taglu development
natural gas to supply the pipeline for its
minimum size; otherwise the cost to bring
fields, other producers will begin producing
economic life. However, the more significant
that gas to market could be far more than the
both the remaining discovered onshore fields
concern in this proceeding has been the
value of the gas. Due to significant economies
in the Mackenzie Delta and fields in the Colville
question of whether the facilities will be large
of scale, services would be more efficiently
Hills region. The Proponents concluded there
enough to transport present and future
provided by one larger pipeline operated by
are sufficient gas resources to fill a 34 Mm3/d
volumes. Estimating future volumes is full of
one firm than by competing firms operating
(1.2 Bcf/d) pipeline for 25 years, given
uncertainty and must account for issues such as:
separate smaller pipelines.
a reasonable pace of exploration and
• uncertainty in resource estimates, both
development. The Mackenzie Valley Pipeline
and sensitive area.
Given these circumstances, it is important that
the facilities are the right size for the available
supply, that the cost of shipping the gas is fair,
discovered and undiscovered;
Volume 1 Figure 1.10
Projected production from anchor fields, other discoveries
and future speculative development
and that the pipeline is accessible by all parties.
0.71
15
0.53
10
0.35
5
0.18
0
0.00
to the facilities in the future?
1249_NEB_MGP_Vol2_Text_ENG.indd 161
2062
Listric Onshore and Basin Margin are play groups within the Mackenzie-Beaufort shown in Figure 7-3.
shipping arrangements) fair and reasonable?
• Will other parties have fair access
Billions of cubic feet/day
20
2058
0.88
2054
Year
25
2050
2.Are the proposed tolls and services (i.e., the
1.06
2046
• Will it be paid for?
30
2042
• Can the project be financed?
Natural gas resources
2038
• Is there sufficient demand?
1.24
2034
• What is the supply?
35
2030
right for the circumstances?
Figure 7-1
2026
• Are the facilities, as they are proposed,
1.41
2022
1.Is the project economically feasible?
40
2018
to answer when assessing this project:
Millions of cubic metres/day
There are two main economic questions for us
Taglu field
Parsons Lake field
Niglintgak field
Other Mackenzie Delta
discovered
Colville Hills discovered
Beaufort Sea undiscovered
Basin margin undiscovered
Colville Hills undiscovered
Beaufort Sea discovered
Listric onshore undiscovered
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162 Mackenzie Gas Project • Volume 2: Implementing the decision
Table 7-1
Comparison of
available natural gas
supply forecasts
Resource type
Area
Discovered
Development fields
Non-anchor onshore
Sproule Supply Study for
Mackenzie Explorer Group
(sales gas volumes)
(sales gas volumes)
Metric
Imperial
Metric
Imperial
(Gm3)
(Bcf)
(Gm3)
(Bcf)
161.3
5694
161.3
5694
7.7
272
21.9
772
64.4
2275
57.5
2028
0.0
0
0.0
0
10.7
379
15.2
537
244.1
8620
255.9
9031
Onshore
86.9
3069
226.4
7993
Offshore shallow
47.6
1679
198.6
7010
Offshore shallow (</= 100 m)
Offshore deep (> 100 m)
Colville Hills
Total discovered
Undiscovered
GLJ Supply Study
for the Proponents
Offshore deep
Colville Hills
Total undiscovered
0.0
0
256.0
9036
45.3
1599
71.3
2517
179.8
6347
752.3
26556
as applied for has a design capacity
Both studies supported the prediction that
construction of a 34.3 Mm3/d (1.2 Bcf/d)
of 27.3 Mm3/d (964 MMcf/d) with one
sufficient resources would be available to
pipeline or a larger 49.8 Mm3/d (1.8 Bcf/d)
compressor and 34.3 Mm3/d (1.2 Bcf/d) with
keep a 34.3 Mm3/d (1.2 Bcf/d) pipeline full
pipeline. For example, there is a 75 percent
three compressors, and is expandable to
throughout its economic life.
probability that a 62.3 Mm3/d (2.2 Bcf/d)
49.8 Mm3/d (1.8 Bcf/d) with the installation
of fourteen compressor stations.
Figure 7-2 illustrates the productive capacity
forecasts of the Proponents and Mackenzie
Based on the results of the Sproule Supply Study,
Gilbert Laustsen Jung Associates Ltd. prepared
Explorer Group along with the proposed contract
Mackenzie Explorer Group supported the design
the gas supply study for the Proponents
profile and the pipeline capacities at the sizes
of the Mackenzie Valley Pipeline because it
(the GLJ Supply Study) and Sproule Associates
Limited prepared the gas study submitted by
of 27.3 Mm3/d (964 MMcf/d), 34.3 Mm3/d
(1.2 Bcf/d) and 49.8 Mm3/d (1.8 Bcf/d).
Mackenzie Explorer Group (the Sproule Supply
1249_NEB_MGP_Vol2_Text_ENG.indd 162
pipeline would be fully used for 20 years.
could be expanded to 49.8 Mm3/d (1.8 Bcf/d) by
adding compression. Mackenzie Explorer Group
anticipates that demand for space on the natural
Study). These studies show a minor difference
The Sproule Supply Study examined scenarios
gas pipeline would increase significantly as
in estimates for discovered resources but
in which different sized pipelines would remain
the basin is opened by further exploration and
a major difference in estimates for undiscovered
full for a 20 year period. The study concluded
development. It also supported the size of the
resources for the Mackenzie Valley and Colville
that it is likely that resources could be developed
liquids line from Inuvik to Norman Wells, which
Hills areas (See Table 7-1).
in the future that would support the
is part of the Mackenzie Gathering System.
12/6/10 11:02:41 AM
Chapter 7: Economic feasibility 163
Sverdrup
Figure 7-3
Supply basins and sub basins
Billions of cubic feet/day
Arctic
Coastal
Beaufort/
Mackenzie
Eagle
Plain
Peel
30
29
28
27
26
25
24
23
22
21
20
19
18
1
Contract quantity
Sproule base case
Sproule sensitivity case
Gilbert Laustsen Jung forecast
17
0
16
0
Year
15
.5
14
14
13
1.0
12
28
11
1.5
9
42
10
2.0
8
56
7
2.5
6
70
5
3.0
4
84
3
3.5
Arctic Platform
Colville
Hills
ckenzie Plain
Ma
98
2
Millions of cubic metres/day
Volume 2 Figure 7.2
Figure
7-2Laustsen Jung contingent and prospective sales gas production forecasts vs.
Gilbert
Sproule resource-based natural gas deliverability forecasts
Capacity forecasts
Expanded pipeline capacity 14 stations
Pipeline capacity 3 stations
Pipeline capacity 1 station
Southern
NWT
Liard
Natural gas flowing from the Mackenzie Delta
to southern markets must pass through the
Mackenzie Gathering System as well as the
Table 7-2
Eagle Plain basin resource estimates
Mackenzie Valley Pipeline. Mackenzie Explorer
Group contends that the Mackenzie Gathering
Discovered
Potential resource estimates
Gm3 (Bcf)
Gm3 (Bcf)
GLJ Supply Study
2.37 (83.7)
(P90)
10.8 (382)
(P50)
21.3 (751)
(P10)
39.7 (1401)
GSC Supply Study
2.37 (83.7)
(P95)
67.4 (2379)
(P50)
152.7 (5392)
(P05)
339.8 (12000)
System north of Inuvik could not be expanded
to the same extent as the Mackenzie Gas
Project. A discussion of the appropriate design
of the Mackenzie Gathering System facilities
can be found in Section 6.3.4.
The Government of Yukon also prepared
currently uneconomic but could become viable
a gas supply study that focused on the Eagle
with adequate gas prices and pipeline access
Plain region (see Figure 7-3) in Yukon – the
to markets. Table 7-2 provides a comparison
Geological Survey of Canada Supply Study
of Eagle Plain resource estimates used in the
(GSC Supply Study). According to this study,
GLJ Supply Study and the GSC Supply Study.
production from the Eagle Plain region is
1249_NEB_MGP_Vol2_Text_ENG.indd 163
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164 Mackenzie Gas Project • Volume 2: Implementing the decision
On the Record
7.4 Markets/demand
Market supply and demand cases
There are two traditional considerations when
The Proponents submitted the Mackenzie Valley
assessing markets for natural gas. The first
Pipeline Market Demand, Supply and Infrastructure
consideration is whether there is sufficient
Analysis Final Report, by Navigant Consulting, Inc.
the study, markets would need the proposed
34.3 Mm3/d (1.2 Bcf/d) of gas to be transported
on the Mackenzie Valley Pipeline.
and Energy and Environmental Analysis, Inc.
demand for the gas that would be transported
Even with the increase in capital costs and
(the Navigant Study). In the report, four cases
by the proposed project. The second considera-
cost of service filed in the spring of 2007,
tion is whether there would be sufficient space
the Proponents’ view was that there would
on connecting downstream pipelines to receive
be adequate markets for the natural gas from
and move the gas to market.
the project, and Mackenzie Delta gas would
were studied:
• The Base Case – studied the impact of the
Mackenzie Delta region delivering 34 Mm3/d
(1.2 Bcf/d) of gas to the marketplace by the
end of 2009.
• The Mackenzie Expansion Case – identified
be required to offset the expected decline
In its original evidence, the Proponents
in conventional gas production.
the impact of expanded Mackenzie Delta
submitted the Mackenzie Valley Pipeline Market
production to 42.5 Mm3/d (1.5 Bcf/d) in 2015
Demand, Supply and Infrastructure Analysis
Mackenzie Explorer Group noted that the
Final Report, prepared by Navigant Consulting,
forecasts are subject to some uncertainty.
Inc. and Energy and Environmental Analysis, Inc.
Regardless, the favourable results obtained in all
– April 13, 2004 (the Navigant Study). The
of the sensitivity cases that were studied suggest
Navigant Study assessed the long-term ability
that “market risk” would not be a significant
of the market to accept natural gas from the
issue for the Mackenzie Gas Project.
Mackenzie Valley using four different scenarios.
The Government of the Northwest Territories
and to 51 Mm3/d (1.8 Bcf/d) in 2020.
• The North American Economic Slowdown Case –
identified the impact on gas markets from
a North American economic slowdown.
• The Alaskan Pipeline Development Case –
identified the impacts of Alaska gas coming
onstream, ultimately reaching a level of
113.3 Mm3/d (4.0 Bcf/d) in 2014.
Conclusions of the report:
• There is an adequate market for gas supplies
from the Mackenzie Gas Project in all cases.
• With small increments to the NOVA Gas
The Navigant Study focused on market regions
that are connected via gas pipelines to the
Western Canada Sedimentary Basin and looked
Transmission Ltd. system, there is sufficient
at forecasted consumption over the period
capacity on NOVA Gas Transmission Ltd. and
2010 to 2030, which was expected to cover
on other pipelines leaving Alberta except in
the Alaska Case. Under that scenario, 85 Mm3/d
the Mackenzie Valley Pipeline’s first 20 years of
(3 Bcf/d) of additional export capacity would
operation at the time the study was prepared.
be required.
The forecasts projected strong growth in gas
demand in Canada, particularly Alberta, and
1249_NEB_MGP_Vol2_Text_ENG.indd 164
natural gas demand. Therefore, according to
submitted that the Mackenzie Basin reserves
are a long-term resource that, over time,
will find their way to very diverse markets.
The Government of the Northwest Territories
position was that the Mackenzie Gas Project
should provide access to as much of the
North American market as possible and market
economics should be allowed to determine
the use of the reserves thereafter.
the United States for electrical power generation,
In March 2010, the Proponents filed updated
residential and commercial consumption and
projections for North American natural gas
for use in industrial and resource development.
markets and supply in a report prepared
However, the study anticipated only modest
by Angevine Economic Consulting Ltd.
growth in gas production in Canada and the
(the Angevine Report) An Updated Natural Gas
United States and suggested that a significant
Market Demand and Supply Analysis for Canada
shift to currently untapped resources would be
and the U.S. Lower 48 States. The author
needed over the next 20 years to meet growing
of the Angevine Report was also a co-author
12/6/10 11:02:42 AM
Chapter 7: Economic feasibility 165
3000
Total consumption
projects and would support the construction
of the Mackenzie Valley Pipeline.
The Angevine Report assumed that the
Mackenzie Pipeline would be constructed
and put in service by October 2018, and that
a gas pipeline from Alaska’s North Slope would
also be constructed and would be in service
40
1000
supply and consumption
20
500
0
0
Year
American natural gas
Net LNG imports
Alaska (own use plus pipeline exports)
Mackenzie Pipeline
Other unconventional (primarily coalbed methane)
2030
incremental gas volumes from northern gas
2026
American market remains sufficient to absorb
60
1500
2022
of increasing shale gas production, the North
2000
2018
The Angevine Report concluded that in spite
Projected North
80
2014
and Environmental Analysis Inc. in 2007.
Figure 7-4
100
2500
2010
by ICF International, which acquired Energy
Millions of cubic metres/day
for the Angevine Report was performed
Billions of cubic feet/day
of the Navigant Study. Gas modelling analysis
Shale formations
Offshore (mostly Gulf of Mexico)
Conventional
by October 2023. The updated projections
for North American natural gas consumption
and domestic gas production suggested that
incremental gas volumes would be required
In the Navigant Study, the Proponents also
expansions would be required to accommodate
from other sources such as northern gas
assessed the capability of the Alberta pipeline
the delivery of 34.3 Mm3/d (1.2 Bcf/d) from the
or imports of liquefied natural gas to meet
system and the main export pipelines from the
Mackenzie Valley Pipeline. However, in the case
growing North American requirements (see
Western Canada Sedimentary Basin to deliver
where the Alaska Pipeline is also built, additional
Figure 7-4).
Mackenzie Delta gas to markets in central
downstream pipeline capacity would be required.
The approach used by both the Angevine
Report and the Navigant Study did not assess
the competitiveness of Mackenzie Valley gas
relative to other sources of gas supply. The
Canada and the United States. These markets
are currently served by five export pipeline
corridors from the Western Canada Sedimentary
Basin (see Figure 7-5 and Table 7-3).
With respect to intra-Alberta infrastructure,
the Canadian Arctic Resources Committee
expressed concern that the Proponents did not
accurately or sufficiently assess the requirements
reports assessed the impact of incremental gas
The Navigant study concluded that with a
and costs of constructing additional infrastruc-
volumes from the proposed project into the
forecasted increase in natural gas consumption
ture in Alberta to ship Mackenzie Valley gas
market and left the Proponents to determine if
in western Canada along with an expected drop
via the existing NOVA Gas Transmission Ltd.
the project would be economic at the resultant
in conventional gas production in the Western
system. The Proponents submitted that the
natural gas prices which are predicted by the
Canada Sedimentary Basin, there will be no
Mackenzie Valley Pipeline volumes can be
modelling analysis. Both reports concluded that
pipeline capacity constraints on gas exports from
accommodated in the NOVA Gas Transmission
the North American market would be sufficient
the Western Canada Sedimentary Basin.
Ltd. system with a modest expansion in
and able to absorb the 34.3 Mm3/d (1.2 Bcf/d)
Furthermore, no export pipeline facility
the northwest part of the system.
from the Mackenzie Gas Pipeline.
1249_NEB_MGP_Vol2_Text_ENG.indd 165
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166 Mackenzie Gas Project • Volume 2: Implementing the decision
Figure 7-5
Proposed pipeline route
Existing pipeline infrastructure
Extension of existing pipeline infrastructure
Existing export
pipeline corridors from
the Western Canada
Sedimentary Basin
Table 7-3
Western Canada
Sedimentary Basin
export pipeline capacity
Mm3/d (Bcf/d)
Pipeline Corridor
2003
2010
2020
Capacity
Projected Flow
Capacity
Projected Flow
Capacity
Projected Flow
Capacity
Projected Flow
Northwest
Pipeline
39.92 (1.41)
28.61 (1.01)
49.58 (1.75)
29.12 (1.03)
49.58 (1.75)
32.32 (1.14)
49.58 (1.75)
21.95 (0.78)
Base Case
60.91 (2.15)
42.10 (1.49)
60.91 (2.15)
33.80 (1.19)
Alaska Case
Gas Transmission
Northwest
77.05 (2.72)
77.05 (2.72)
64.08 (2.26)
77.05 (2.72)
59.77 (2.11)
Base Case
94.05 (3.32)
80.68 (2.85)
94.05 (3.32)
68.36 (2.41)
Alaska Case
Foothills and
Northern Border
62.04 (2.19)
62.04 (2.19)
60.96 (2.15)
62.04 (2.19)
35.52 (1.25)
Base Case
70.54 (2.49)
68.73 (2.43)
70.54 (2.49)
67.56 (2.39)
Alaska Case
Alliance Pipeline
43.54 (1.54)
43.54 (1.54)
42.18 (1.49)
43.54 (1.54)
40.82 (1.44)
Base Case
52.04 (1.84)
51.02 (1.80)
52.04 (1.84)
49.72 (1.76)
Alaska Case
203.12 (7.17)
136.37 (4.81)
203.12 (7.17)
112.44 (3.97)
Base Case
242.78 (8.57)
182.46 (6.44)
242.78 (8.57)
145.55 (5.14)
Alaska Case
and projected gas flows
TransCanada
1249_NEB_MGP_Vol2_Text_ENG.indd 166
2030
203.12 (7.17)
59.24 (2.09)
60.28 (2.13)
42.41 (1.50)
152.66 (5.39)
77.05 (2.72)
62.04 (2.19)
43.54 (1.54)
203.12 (7.17)
63.43 (2.24)
60.31 (2.13)
42.69 (1.51)
171.47 (6.05)
12/6/10 11:02:44 AM
Chapter 7: Economic feasibility 167
7.5 Transportation contracts
Pipeline. The capacity available for third-party
7.5.2 Mackenzie Gathering System
shippers is shown in Table 7-4 under three
The Mackenzie Gathering System owners have
scenarios, with one, three and fourteen
been allocated rights to capacity in various
When considering economic feasibility, the
compressor stations in place. As noted
functional units under the Mackenzie Gas
National Energy Board evaluates whether there
previously, this application seeks approval
Gathering and Processing Facilities Development
is adequate contractual support for the pipeline
for construction of three compressor stations.
and Operating Agreement. In October 2007,
If additional shippers do not sign contracts for
the Proponents filed contracts signed
capacity on the pipeline, the installation of two
with MGM Energy Corp. for 5.66 Mm3/d
of the compressor stations would be delayed.
(200 MMcf/d) of capacity on segments of
To date, only the owner-shippers have signed
Table 7-5 shows the volumes that have been
the Mackenzie Gathering System. These
contracts for capacity on the Mackenzie Valley
contracted by each of the shipper-owners.
were the first third-party contracts executed
7.5.1 Mackenzie Valley Pipeline
from prospective shippers. The National Energy
Board is also mindful of the desire for capacity
to be available for third-party shippers.
for capacity on the Mackenzie Gathering
System. MGM Energy Corp. did not sign
a corresponding contract for capacity on
the Mackenzie Valley Pipeline at that time.
Table 7-4
Contracted and available capacity on Mackenzie Valley Pipeline
System design
System capacity
(summer)
Owner-shipper
contracted
capacity
1 compressor
station
27.3 Mm3/d
(964 MMcf/d)
23.5 Mm3/d
(830 MMcf/d)
3 compressor
stations
34.3 Mm /d
(1.2 Bcf/d)
23.5 Mm /d
(830 MMcf/d)
14 compressor
stations
49.8 Mm /d
(1.8 Bcf/d)
23.5 Mm /d
(830 MMcf/d)
3
Owner-shipper
contracted
capacity
Uncontracted
capacity
86%
3.8 Mm3/d
(134 MMcf/d)
14%
69%
10.8 Mm /d
(380 MMcf/d)
31%
47%
26.3 Mm /d
(928 MMcf/d)
53%
3
3
Uncontracted
capacity
Did you know?
Volume and energy measurements
for natural gas
3
3
Natural gas can be measured in several different
ways. It can be measured by volume which is
3
stated in cubic metres or cubic feet. One cubic
metre equals approximately 35.3 cubic feet under
standard temperature and pressure conditions.
(Standard is defined as 15 degrees Celsius
(60 degrees Fahrenheit) and 101.325 kPa
Table 7-5
(14.7 pounds per square inch)).
Contracted volumes by shipper
Natural gas can also be measured in terms of energy.
One gigajoule (GJ) is equal to one billion joules (or
15 year term
20 year term
Total
Total
(GJ/d)
(GJ/d)
(GJ/d)
(Bcf/d)
Imperial
361 821
90 455
452 276
.400
ConocoPhillips
197 255
49 314
246 569
.225
65 752
16 438
82 190
.75
Shell
111 040
27 760
138 800
.130
of one pound of water by one degree Fahrenheit.
Total
735 868
183 967
919 835
.830
Refer to Appendix E for a conversion chart of volume
Shipper
ExxonMobil
109 joules) and, in terms of volume, is equivalent to
approximately 26.8 cubic metres (or 946 cubic feet)
of natural gas, depending on the heat content of the
gas stream. One gigajoule is approximately 950,000
British thermal units (Btus), where one Btu is the
amount of heat needed to raise the temperature
measurements and energy measurements.
Note: energy content assumed is 39.1 MJ/m3
1249_NEB_MGP_Vol2_Text_ENG.indd 167
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168 Mackenzie Gas Project • Volume 2: Implementing the decision
7.6 Financing
The National Energy Board has an obligation
to satisfy itself that the proponents of a project
can obtain the necessary funds to pay for their
facilities. In this case, the Proponents have
proposed a joint venture structure for owning
and operating the Mackenzie Valley Pipeline.
The final ownership interests would be
determined once the group decides to proceed
with construction. The ownership interest of
each development field owner, or its affiliate,
would be the ratio of its development field
firm service transportation agreement to the
total firm service transportation agreement
commitments at that time. Predevelopment
interests are shown in Table 7-6.
Ultimately, the Mackenzie Valley Aboriginal
interest could be in the range of two to
conventional capital markets and can access, if
three percent. However, the Mackenzie Valley
necessary, backstop funding from the owners of
Aboriginal Pipeline Limited Partnership would
the development fields for its equity share of the
have the option to increase its ownership
Mackenzie Valley Pipeline’s construction costs.
interest up to the maximum of one third
within the first 10 years from pipeline start-up
As noted at the beginning of the chapter,
as additional contracts are entered into.
when considering the economic feasibility
of an application, the National Energy Board
Table 7-6
considers all of the evidence dealing with
Predevelopment interests of owner-shippers
markets, downstream facilities, supply, contracts
Owner-shipper
Predevelopment
interest
is likely to be used and useful and whether
the pipeline’s costs will be paid.
Imperial Oil Resources
Ventures Limited
34.2%
Mackenzie Valley Aboriginal
Pipeline Limited Partnership
33.3%
enough to say the decision on economic viability
ConocoPhillips
16.0%
lies with the Proponents alone as financial,
Shell
11.2%
environmental and socio-economic costs and
Alternatives North argued that it is not good
ExxonMobil
5.3%
Pipeline Limited Partnership could own up to
impacts would be borne by others. Alternatives
North also argued that the Proponents had
33.3 percent of the Mackenzie Valley Pipeline.
Once the Proponents decide to construct
failed to prove the need for, and the economic
Its actual ownership interest in the facilities
the facilities, TransCanada PipeLines Limited
feasibility of, the pipeline.
would be calculated as the ratio of third-party
would have the option to acquire from the
contracts to the total contracts in place on the
development field owners an interest in the
Mackenzie Valley Pipeline when the Proponents
pipeline equivalent to five percent of the total
make their decision to construct the pipeline.
development field capacity.
If no shippers, other than the owner-shippers,
1249_NEB_MGP_Vol2_Text_ENG.indd 168
and financing to assess whether the pipeline
Views of the Board
Financing
If the shipper-owners decide to construct
have signed contracts before the decision
According to the Proponents, the joint venture
the facilities, we agree they will be able
is made to construct the facilities, then the
structure was selected because it allowed for
to finance the project from internally
Mackenzie Valley Aboriginal Pipeline Limited
financing flexibility, tax efficiency and efficient
generated funds or other sources as business
Partnership would be given a minimum
use of overhead resources. The development
conditions may dictate. We note that
interest in the pipeline. The minimum interest
field owners will arrange financing for their own
the Mackenzie Valley Aboriginal Pipeline
is calculated as the ratio of the Mackenzie
share of the project costs, most of which will
Limited Partnership would be able to
Valley Aboriginal Pipeline Limited Partnership’s
probably come from internally generated funds.
access backstop funding from the owners
predevelopment phase spending, which
The Proponents argued that the pipeline
of the development fields if not through
is being funded by TransCanada PipeLines
owners are all part of organizations that are
conventional capital markets.
Limited, to the total construction costs, plus
very financially strong and highly credit worthy.
all predevelopment phase costs for the gas
The Mackenzie Valley Aboriginal Pipeline Limited
pipeline. It is expected that the minimum
Partnership intends to raise debt and equity in
12/6/10 11:02:45 AM
Chapter 7: Economic feasibility 169
Supply
For the Mackenzie Valley Pipeline to be
a decision to construct until after that
We note that no evidence was filed which
successful, the natural gas moved through it
date. Therefore, all existing Precedent
was contrary to the Proponents’ long-term
would need to compete with other sources
Agreements could theoretically be
forecasts for the supply and consumption
of gas supply in the North American market.
terminated. Accordingly, we require
of natural gas in North America. In our
In final argument some parties raised
the Proponents to demonstrate to the
view, the evidence demonstrates that there
concerns that the evidence on the record
National Energy Board’s satisfaction that
is, and there will be, adequate natural gas
does not prove that Mackenzie gas could
the necessary long-term transportation
supply to support the use of the project
successfully compete in the market. We note
service contracts have been executed
over its expected economic life.
that it is impossible to know how markets
for the Mackenzie Valley Pipeline before
and circumstances will change over time.
construction starts.
We are satisfied that the forecasted
If the pipeline is built it would take several
The Proponents and shippers have made
growth in the North American market
years for construction and the pipeline
significant financial commitments and
would be sufficient to absorb the expected
would be expected to operate for at least
will have to make further commitments
gas volumes from the Mackenzie Valley
25 years. The Proponents estimated that
by signing Firm Service Transportation
Pipeline. We note the forecasted growth in
2018 is the earliest the pipeline could
Agreements. If they do, we are satisfied
natural gas consumption and the continued
commence service. Therefore, the pipeline
this will demonstrate that parties have
decline in gas production from conventional
could be in operation until 2043 and
determined Mackenzie Valley gas would
sources in western Canada. We accept that
beyond. Economic conditions will inevitably
be competitive in the market and that the
this supports the conclusion that adequate
change over that time as they have in the
pipeline would be useful. If producers are
pipeline capacity exists to accommodate the
past several years. More specifically, supply
confident that Mackenzie gas can compete
delivery of 34.3 Mm /d (1.2 Bcf/d) of natural
and demand forecasts and gas prices will
in the market they will enter into the
gas from the Mackenzie Valley Pipeline
continue to change over time. We do not
required long-term contracts for service
to downstream markets.
agree that these are reasons to deny the
on the Mackenzie Gas Pipeline. These
project. Our approval gives Mackenzie gas
contracts provide necessary assurance that
an opportunity to compete. Denial would
the demand charges for the pipeline will
block that opportunity indefinitely.
be paid. It is an important indicator that
Transportation contracts and markets
3
Although the Angevine Report did not
specifically re-assess the availability of
pipeline capacity, the updated projections
the proposed pipeline will be used.
for combined production from British
Although the shipper-owners have entered
Columbia, Alberta and Saskatchewan in
into Precedent Agreements, these agree-
Economic feasibility
the updated evidence are significantly lower
ments are only in effect until a Firm Service
Given our views on financing, supply,
than the original projections for natural
Transportation Agreement is entered into.
contracts and markets we believe that if
gas production in the Navigant Study.
Either party to the agreement has the
long-term contracts are signed as required,
Consequently, the evidence of the Angevine
option of terminating the agreement if
the pipeline is likely to be sufficiently well
Report would support the Navigant Study
the Proponents have not provided start up
utilized over its economic life.
conclusion that no export pipeline expan-
notice by 1 November 2012 or such later
sions would be required to accommodate
date as may be agreed to by the parties.
the delivery of 34.3 Mm /d (1.2 Bcf/d) from
In final argument the Proponents indicated
the Mackenzie Valley Pipeline.
they would not be prepared to make
3
1249_NEB_MGP_Vol2_Text_ENG.indd 169
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Chapter 8
Toll, tariff and
access provisions
8.1 Regulation of tolls, tariffs and access
The Mackenzie Valley Pipeline is a producer owned, basin opening pipeline in an environmentally
sensitive area. The gas must flow through the Mackenzie Gathering System before reaching the
Mackenzie Valley Pipeline. Each of these system components, the Mackenzie Gathering System and
the Mackenzie Valley Pipeline, has a different ownership structure, different contractual
arrangements and will operate under a slightly different regulatory framework.
The Mackenzie Valley Pipeline is regulated under
appropriate.1 During the evidentiary portion of
the National Energy Board Act which provides
the hearing in 2006, the Canada Oil and Gas
for regulation of the physical facilities as well as
Operations Act did not have provisions for toll,
the applicable tolls, tariffs and access provisions.
tariff and access regulation. Therefore the
The tolls and tariffs on National Energy Board
appropriate means of addressing these topics
regulated pipelines must conform to Part IV of
was a key issue in our hearing. On 14 December
the National Energy Board Act. A requirement
2007 legislation was passed which amended the
of the National Energy Board Act is that a
Canada Oil and Gas Operations Act to allow the
company cannot charge for service on a pipeline
National Energy Board to regulate the tolls and
unless it has a tariff on file with the National
Energy Board. The National Energy Board Act
also requires that tolls be just and reasonable
and charged equally to all shippers using the
same services.
The Mackenzie Gathering System was applied
for under the Canada Oil and Gas Operations
Act and we subsequently found this to be
1249_NEB_MGP_Vol2_Text_ENG.indd 170
[1] Mackenzie Explorer Group filed a motion on 7 April
2006 asking us to declare that once in service both the
Mackenzie Gathering System and the Mackenzie Valley
Pipeline would be a single “pipeline” under the National
Energy Board Act and entirely subject to regulation
under Part IV of that Act. They also asked us to direct the
Proponents to prepare, file, and serve the toll principles
and the tariff(s) that would apply to both systems for
approval in this proceeding. On 10 July 2006 we determined that the Mackenzie Gathering System was appropriately applied for under the Canada Oil and Gas Operations
Act and denied the motion. However, we noted that
we remained concerned about the tolls, access and
tariff provisions for the Mackenzie Gathering System
and the methods for resolving disputes on these matters.
Our decision was upheld by the Federal Court of Appeal.
12/6/10 11:02:47 AM
Chapter 8: Toll, tariff and access provisions 171
tariffs of these facilities in a manner similar to
• tolling methodology;
regulation under the National Energy Board Act.
• access issues;
In Canada, economic regulation of federal
pipelines by the National Energy Board is
intended to produce outcomes that are similar
• laterals and service to northern
communities; and
• the Code of Conduct.
Did you know?
Why there is economic regulation of the pipeline sector in Canada
Most industries in Canada have some form of regulation that governs what they can
and cannot do. However, the pipeline sector is subject to more economic regulation
than most because of the unique features of energy supply and delivery.
A market allows sellers and buyers to exchange their goods or services. In a fully
to what would happen in a competitive market.
For the Mackenzie Gathering System, issues
Traditionally, pipelines have been regulated using
centered around the need for economic
or services. This competition motivates buyers to keep their prices down and drives
a “cost of service” approach, although there
regulation, methods for collecting fees and
the innovation of new products or services. Pipeline markets are different. They are
are alternatives such as use of negotiated
setting tolls, and codes of conduct.
settlements and complaint-based regulation.
competitive market, there are many buyers and sellers competing for the same goods
often natural monopolies with a limited number of companies providing the product
or service. In some cases, there is only one provider. Pipelining of natural gas is a
necessary service, but because the construction of major pipelines and associated
The cost of service methodology basically
8.2 Mackenzie Valley Pipeline
involves a two step process. In the first step,
8.2.1 Timing of decision on toll
difficult for other companies to provide the same service. This economic barrier
a pipeline company calculates the cost to deliver
and tariff matters
becomes even higher because the existing company can often expand its system
The Proponents applied under Part IV of
Yet buyers often do not have a substitute service – there is nothing else to take
the National Energy Board Act for an order
the place of the pipeline. As a result, the existing company can control the market,
the gas (the throughput) in the following year.
This is referred to as determining the annual
cost of service or the revenue requirement.
The second step is to distribute these total costs
among the different customers and the different
types of services offered by the pipeline. This
step is commonly referred to as toll design. The
Proponents propose to use this general approach
for the Mackenzie Valley Pipeline, although not
for the Mackenzie Gathering System.
economic barriers to entry. Once a single pipeline is built, it often becomes more
approving the toll and tariff principles that
innovation in the market place.
At the same time, companies are unwilling to undertake the massive investments
that are often required without reasonable assurance that they will be able to recoup
Explorer Group, raised issues related to these
their money and earn a reasonable return on investment.
principles throughout the hearing. In argument
In a monopoly situation, markets are not fully competitive and would not function
Mackenzie Explorer Group took the position
efficiently on their own. Regulation can be used as a non-market force to set prices
for the goods or services. Pipeline regulation in Canada therefore is a substitute
that we should leave the toll and tariff issues
for the competitive economic forces that would normally work in a fully functioning
to be determined through some future process
market. The goal of economic regulation is that the public good (in this case pipeline
of concerns with specific costs, the
known. They suggested that there would
methodology for their distribution among
be ample time to resolve these issues.
for the Mackenzie Valley Pipeline:
and there is no pressure from competitors for prices to become lower, or for
Pipeline. Various parties, including Mackenzie
once the economic parameters are better
Specifically, the following issues were discussed
at a lower price than what it would cost another company to build a new pipeline.
are to apply to service on the Mackenzie Valley
In this proceeding, parties raised a number
customers and the method to review costs.
facilities can take many years and be extremely costly, there can be significant
infrastructure) is provided at a price, and in amounts, that would be expected from
a competitive market.
The Proponents responded that they need
to know the toll and tariff principles prior
to making the decision to construct.
• method of regulation;
• cost of capital including capital structure,
return on equity and the deemed cost
of debt;
• depreciation;
1249_NEB_MGP_Vol2_Text_ENG.indd 171
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172 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
Although the Mackenzie Valley Pipeline
will not go into service before 2018 at
the earliest, we find that it is appropriate
to make a decision on the toll and tariff
to tolling costs. However, for third-party
groups with sufficient information so that they
shippers that would be competing with
may determine whether the tolls are reasonable.
the owner-shippers for access to markets,
The tariffs and the resulting tolls are effective
this approach is contrary to the concept of
once filed unless a complaint is filed or the
an open access pipeline system.
National Energy Board, on its own motion,
In addition to the lack of incentive to control
Proponents, potential third-party shippers,
costs, MGM Energy Corp. stated that there is
The Proponents have not specifically asked
and others a clearer understanding of the
no opportunity to review costs and the onus is
to be classified as either a Group 1 or Group 2
terms of service that will prevail as they
placed on third-party shippers to file a complaint
company. They noted that they expect the
make decisions concerning the project.
with respect to the prudence and level of any
Mackenzie Valley Pipeline to be classified
costs. In order for the tolls to be considered
as a Group 1 company but would be satisfied
fair and transparent, third-party shippers must
if we found that a Group 2 designation
have sufficient notice of the incurred costs and
was more appropriate.
8.2.2 Method of economic regulation
The Proponents have proposed that tolls be
established based on the best estimate of the
Mackenzie Valley Pipeline’s costs for the coming
year. Any differences between the original
the opportunity in a public forum, if necessary,
to adequately assess these costs before the
Mackenzie Valley Pipeline begins operation.
MGM Energy Corp. supported a public hearing
Did you know?
estimates and the actual amounts at the end of
process once the Mackenzie Valley Pipeline
the year would be recorded in deferral accounts
Definitions
is in service that would occur on a regular basis,
and included in the following year’s tolls. The
Access provisions – the provisions in a tariff
whether annually or over some specific
which allow third parties to contract for the use
Proponents also committed to providing each
negotiated period, for example every three
shipper with the annual revenue requirement
to five years.
Tariff – the list of rules for transporting (moving)
Group 1 versus Group 2
rules sets out the terms and conditions under which
and the applicable tolls at least 30 days prior
to the beginning of the new toll year.
For the purpose of economic regulation (not
1249_NEB_MGP_Vol2_Text_ENG.indd 172
decides to review the toll.
principles at this time. This will give the
of the pipeline facilities.
gas on a pipeline company’s facilities. This list of
the service of a pipeline are offered or provided,
including the tolls, the rules and regulations, and
According to MGM Energy Corp. this form
safety or environmental regulation) the National
the practices relating to specific services.
of regulation includes little incentive to
Energy Board has divided pipeline companies
Tariff principles – the general principles that will
control costs since there is little or no risk of
into two groups. Group 1 companies own
be used to define the tariff.
non-recovery of actual costs incurred. Higher
the major pipeline systems. Those companies
Toll – the price charged by a pipeline company
than anticipated costs can be recovered through
that own smaller pipelines or pipelines with
the following year’s tolls. MGM Energy Corp.
relatively few shippers are classified as Group 2
contends that this form of regulation might be
companies. Group 2 companies and certain
appropriate for a pipeline without third-party
Group 1 companies are regulated on
shippers since, as both the owners of and
a complaint basis. Under complaint-based
shippers on the Mackenzie Valley Pipeline,
regulation, the pipeline company is responsible
the Proponents would be relatively indifferent
for providing their shippers and other interested
for the use of its facilities.
Toll principles – the general principles outlining how
the tolls will be determined.
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Chapter 8: Toll, tariff and access provisions 173
Views of the Board
Imperial Oil Resources Ventures Limited
will be designated as a Group 1 company.
determined either through a negotiated
Did you know?
RH-2-94 formula for calculating return on equity
In 1995, the National Energy Board started using
It will be required to file Quarterly
a formula for setting the annual return on equity
Surveillance Reports as outlined in the
for a hypothetical or benchmark pipeline. This
Toll Information Regulations and Section BB,
could be used as the standard for determining the
settlement with Mackenzie Valley Pipeline
shippers or the Proponents would apply to the
National Energy Board to set the allowed rate.
Mackenzie Explorer Group asked us to approve
return on equity for pipelines that did not have an
a different capital structure and return on equity
Financial Surveillance Reports in the
alternative, negotiated arrangement. This National
for the Mackenzie Valley Pipeline than what the
National Energy Board’s Filing Manual.
Energy Board formula was based on the forecast
interest rate for long-term Government of Canada
Given that, as a Group 1 company, both
shippers and the National Energy Board will
have the opportunity to review the
Mackenzie Valley Pipeline’s costs and any
Proponents applied for. Specifically, Mackenzie
bonds, plus a risk premium. Each year, the formula
Explorer Group contended that the cost of
was adjusted by 75% of the change in 30 year
capital for the Mackenzie Valley Pipeline should
Government of Canada bonds. In October 2009,
vary according to risk so we should approve
the National Energy Board decided that the formula
would no longer be in effect.
a capital structure and return on equity that
concerns can be brought to the National
vary with the different phases of the project.
Energy Board, we accept the Proponents’
The proposal using this approach is shown in
proposed method of regulation.
Table 8-1. Alternatively, Mackenzie Explorer
8.2.3 Cost of capital
The Proponents originally proposed a capital
Group stated that if it had to recommend
structure that combines 30 percent equity
one premium for the entire project, it would
with 70 percent debt and a return on equity
suggest a premium of 70 basis points over
Capital structure and return on equity
for the first 10 years of operation that is equal
the RH-2-94 formula return on equity.
Capital structure is the mix of debt and equity
to the return on equity derived from the
that a company uses to finance projects, such
National Energy Board’s RH-2-94 formula
Table 8-1
as a pipeline. Ideally, the capital structure should
return on equity , plus 221 basis points.
Mackenzie Explorer Group’s proposed return on
minimize the cost of capital while meeting
For example, if the formula return on equity
equity capital for the Mackenzie Valley Pipeline
the objectives of a fair return. Debt is generally
were 9.0 percent, the return on equity for
2
cheaper than equity financing because,
the Mackenzie Valley Pipeline would be
unlike equity, it is tax deductible and because
11.21 percent. When the Proponents originally
it is less risky. In the event of bankruptcy, it is
filed their application to build the Mackenzie
the lenders, not the company shareholders,
Gas Project, the return on equity derived
who have the first call on cash. However, the
by the RH-2-94 formula was 9.79 percent.
determination of the optimal capital structure
At that time, the Proponents chose a 221 basis
can be a fine balance – too much debt and
point premium on the premise that a 12 percent
the pipeline’s financial risk increases along
return on equity was reasonable for the
with its cost of capital.
Mackenzie Valley Pipeline. After the initial
Deemed
equity
The Proponents
Premium above the
RH-2-94 formula
(basis points)
30%
221
80%
150
Construction
25%
150
Operations
30%
50
–
70
Mackenzie Explorer
Group (Option 1)
Predevelopment
Mackenzie Explorer
Group (Option 2)
10 years, the return on equity would be
[2] In the RH-2-94 Decision, the National Energy Board
established a mechanism to annually adjust the return
on equity for several Group 1 pipelines.
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174 Mackenzie Gas Project • Volume 2: Implementing the decision
These differing positions on what the Mackenzie
National Energy Board regulated pipelines in
in effect. At that time, the only National Energy
Valley Pipeline’s capital structure and return
2005 as provided in evidence.
Board regulated pipelines which were subject
on equity should be are based on different
determinations of the risk related to the project.
The Proponents submitted that the risks for
to the formula were the TransCanada Mainline,
Table 8-2
Foothills Pipe Lines Ltd., and Westcoast
Comparison of 2005 returns on equity capital
Energy Inc. Transmission.
the Mackenzie Valley Pipeline are significantly
ROE
In argument, the Proponents noted that
different than the risks for the established
Alliance
30%
11.3%
National Energy Board regulated pipelines
Maritimes &
Northeast
25%
13.0%
Mackenzie Valley
Pipeline proposed
30%
11.7%
of service. In such a case, the principle stated
TransCanada Mainline
33%
9.5%
that the return on equity will be determined
accessing the well-proven Western Canada
Sedimentary Basin. The fact that it is a greenfield
pipeline accessing a new and untested supply
basin increases the risk of the project, thereby
Subsection 3.5 of the Toll Principles contemplated the possibility that the formula would
be eliminated prior to the end of the 10th year
through a negotiated settlement or as
necessitating a higher return for investors
Mackenzie Explorer Group disagreed with
a result of an application to the National
compared to other National Energy Board
the Proponents’ assessment of the risks for
Energy Board in a manner which preserves the
regulated gas pipelines. A greenfield pipeline
the Mackenzie Valley Pipeline. According
principle that the return on equity will reflect
is a new pipeline built on undeveloped land
to Mackenzie Explorer Group’s analysis of
a 2.21 percent premium over the National
or where a pipeline has not yet been located.
the business risks facing the Mackenzie
Energy Board prescribed rates of other Group 1
The Proponents also noted that, on a stand-
Valley Pipeline:
pipelines to which the formula had been applied
alone basis, if the Mackenzie Valley Pipeline
• supply risk is low;
immediately prior to 9 October 2009.
were being financed in its entirety in the public
• market risk is not significant and there will
markets, or if the National Energy Board’s
be no direct competitors;
formula for return on equity had applied,
• construction risk is immaterial; and
it would require a higher equity component
• there is little regulatory risk for the Mackenzie
than that of established pipelines because of
the greenfield characteristics of the Mackenzie
Valley Pipeline once it is in service.
The Government of the Northwest Territories’
position in argument was that determining
the return on equity at least eight years prior
to commencement of service and based on
a formula, the main component of which
Once in operation, Mackenzie Explorer Group
already no longer existed, did not make
contended that the Mackenzie Valley Pipeline
sense. Consequently, the Government of the
faces no more risk than any of the mature
Northwest Territories, as had Mackenzie Explorer
pipelines accessing the Western Canada
Group, asked us not to fix the return on equity
Sedimentary Basin.
for the Mackenzie Valley Pipeline at this time.
transmission pipelines, Canadian local
On 8 October 2009, the National Energy Board
Deemed cost of debt
distribution companies and American gas
issued a decision stating that the formula, which
The cost of debt for a pipeline is typically
pipelines. Table 8-2 compares the common
the Proponents had used as the basis of their
determined when the pipeline goes to the
equity ratios and equity returns of major
return on equity calculation, would no longer be
capital markets to borrow funds. However,
Valley Pipeline combined with the magnitude
of the investment. The Proponents contended
that the proposed return on equity capital for
the Mackenzie Valley Pipeline is reasonable
when compared to other Canadian greenfield
1249_NEB_MGP_Vol2_Text_ENG.indd 174
Deemed equity
12/6/10 11:02:47 AM
Chapter 8: Toll, tariff and access provisions 175
the Proponents would not access debt
markets to directly finance the project. Instead,
rating of A (low) by DBRS3;
• the Mackenzie Valley Aboriginal Pipeline
with an ‘A’ credit rating from Standard & Poor’s
and DBRS. If the cost of debt were closer to
each of the Proponents would provide the
Limited Partnership’s sole business is to
7.0 percent when it is issued, interest coverage
funds needed to cover its share of the debt.
invest in the Mackenzie Valley Pipeline;
ratios and fixed charge coverage ratios could
The development field owners, all of which
• the Mackenzie Valley Aboriginal Pipeline
be lower, weakening the Mackenzie Valley
have strong credit ratings, expect that this
Limited Partnership’s debt would be serviced
Pipeline’s credit profile. The Proponents stated
would likely come from internally generated
by the same pool of cash flows that would
that a credit rating lower than A- may impact
funds. However, the Mackenzie Valley
service the Mackenzie Valley Pipeline
the ability of an issuer to access the debt capital
Aboriginal Pipeline Limited Partnership plans to
stand-alone debt;
markets to raise the debt required for this
access the capital markets to raise the funds it
would need to finance both debt and equity.
Since the cost of debt for the Mackenzie Valley
Pipeline would not be determined directly by
the market, the Proponents proposed to deem
• the Mackenzie Valley Aboriginal Pipeline
Limited Partnership‘s debt would be secured
directly against the Mackenzie Valley Pipeline;
and
• the Mackenzie Valley Aboriginal Pipeline
Limited Partnership partners would be
project on a stand-alone basis. A rating lower
than A- would also impact the cost of financing.
Mackenzie Explorer Group stated that deeming
the debt cost of the development field owners
as proposed by Proponents could be unfair and
the debt rate. Parties in the hearing agreed
taxable — therefore the coverage ratios,
unreasonable because:
that the appropriate cost of debt would be the
debt ratings and cost of debt for the
• the Mackenzie Valley Aboriginal Pipeline
rate that would apply if the Mackenzie Valley
Mackenzie Valley Aboriginal Pipeline Limited
Limited Partnership’s share of Mackenzie
Pipeline, as a stand-alone entity, borrowed
Partnership should be similar to those of
Valley Pipeline ownership could be very small
funds. As a proxy for this rate, the Proponents
the Mackenzie Valley Pipeline.
and therefore Mackenzie Valley Aboriginal
proposed that the debt cost to be included
in Mackenzie Valley Pipeline tolls be deemed
as the weighted, average interest rate of the
project debt financing provided by the senior
lenders for the Mackenzie Valley Aboriginal
Pipeline Limited Partnership. At the time of
application, the cost of this debt was estimated
to be 6.1 percent.
The Proponents contended that the Mackenzie
Valley Aboriginal Pipeline Limited Partnership
cost of debt is a reasonable proxy for the cost
The Proponents noted that if specific
circumstances caused the Mackenzie Valley
Aboriginal Pipeline Limited Partnership’s debt
rating to differ from that of the Mackenzie
Valley Pipeline as a stand-alone pipeline, they
would deal with that situation when it arose.
Limited Partnership and the Mackenzie Valley
Pipeline have been given a provisional credit
may not be reflective of the true debt costs
for a venture the size of the Mackenzie
Valley Pipeline;
• the Mackenzie Valley Aboriginal Pipeline
Limited Partnership’s equity may be funded
by a loan from the development field owners
Assuming the financial forecasts unfolded as
and therefore the investment takes on the
planned, the Proponents’ evidence suggested
characteristics of a 100 percent margin loan.
that the proposed capital structure, return
While it may be low risk, it will still be more
on equity and cost of debt would be aligned
risky and expensive than debt backstopped by
genuine equity; and
of debt because:
• both the Mackenzie Valley Aboriginal Pipeline
Pipeline Limited Partnership’s cost of debt
[3] DBRS and Standard & Poor’s are rating agencies which
provide credit ratings on issuers of various types of debt
including bonds, commercial paper and preferred shares.
The March 2005 credit rating was subject to a number
of assumptions such as that the project be completed
without cost overruns, that the Mackenzie Valley Pipeline
capacity is 28.3 Mm3/d (1 Bcf/d) to 34.3 Mm3/d (1.2 Bcf/d)
and fully subscribed and that there is no change in the
current shippers, owners, or agreements throughout the
entire term of the debt.
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176 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
8.2.4 Depreciation
Limited Partnership is a limited partnership
The specific return on equity for the
The Proponents plan to use a depreciation
which may not pay corporate income taxes
Mackenzie Valley Pipeline will be set closer
method that would allow them to recover
so the financial parameters such as interest
to the in-service date, either through a
80 percent of their asset costs over the first
coverage ratios may be worse than if the
negotiated settlement subject to National
20 years of operation of the Mackenzie
Mackenzie Valley Pipeline were operating
Energy Board approval, or as a result of an
Valley Pipeline. The owners would only
as a conventional limited liability corporation.
application brought to the National Energy
recover the remaining 20 percent of the initial
(After this evidence was filed, the Proponents
Board. We accept the Proponents’ approach
costs if there were shippers beyond year 20.
clarified that the current Mackenzie Valley
of preserving the 221 basis point premium
Using this method, the annual depreciation
Aboriginal Pipeline Limited Partnership
over other Group 1 companies that were
rate would be between four and five percent,
partners will be taxable.)
subject to the formula. However, we
depending on the ratio of 15 year and 20 year
Mackenzie Explorer Group proposed that the
cannot make future National Energy
Firm Service Transportation Agreements.
Mackenzie Valley Pipeline’s cost of debt should
Board decisions and, as noted in RH-2-2004
Based on the initial contracts signed by the
be the lowest equivalent term issue cost for
(TransCanada PipeLines Limited Phase II),
owner shippers, the proposed depreciation
NOVA Gas Transmission Ltd., TransCanada
when determining the appropriate returns
rate would be 4.8 percent for the first 15 years
PipeLines Limited, and Enbridge Gas Distribution,
for a pipeline, the National Energy Board
of the Mackenzie Valley Pipeline’s operating life
which Mackenzie Explorer Group contended are
looks at the total return taking into account
and 1.6 percent in years 16 to 20. This would
more appropriate proxies. This proposal would
both return on equity and equity thickness,
result in a significant reduction in tolls for the
apply to the operating stage of the Mackenzie
not one factor in isolation.
last five years of the Mackenzie Valley Pipeline’s
Valley Pipeline. For the predevelopment and
With respect to the deeming of the debt
construction stages, Mackenzie Explorer Group
rate, if there is evidence in the future that
Mackenzie Explorer Group submitted that the
proposed different debt rates as follows:
the Mackenzie Valley Aboriginal Pipeline
proposed overall depreciation rate is too high
• predevelopment – 30 year Government of
Limited Partnership’s cost of debt is
• the Mackenzie Valley Aboriginal Pipeline
Canada bond yield plus 60 basis points; and
• construction – three to five year Government
of Canada bond yield plus 50 basis points.
Mackenzie Explorer Group submitted that the
option is “always on the table” for the National
Energy Board to review the Mackenzie Valley
Aboriginal Pipeline Limited Partnership’s cost
of debt if there was evidence that it was not
the same cost of debt that would apply to
a stand-alone Mackenzie Valley Pipeline.
different than the cost of debt that would
apply to a stand-alone Mackenzie Valley
Pipeline, a party can bring the issue to the
20 year economic life.
Did you know?
Depreciation
Depreciation for accounting purposes is a method of
National Energy Board in the usual fashion.
distributing the costs of assets, such as a pipeline,
We do not accept Mackenzie Explorer
over their estimated useful lives by allocating annual
Group’s proposal for a different capital
structure, allowed return on equity or
debt rate for each phase of the project.
We find the approach to be unnecessarily
complicated and inconsistent with typical
regulatory practice in Canada.
amounts as an expense. For example, if a project’s
capital costs were $20 million and the depreciation
rate was five percent, then each year $1 million
would be included in tolls to allow the owner to
recover the original capital. For toll making purposes,
this depreciation expense is part of the company’s
annual cost of providing transportation service. By
including depreciation in the cost of service, the
company can recover the costs of its investment over
time. In addition to this return of capital, there is also
a return on capital.
1249_NEB_MGP_Vol2_Text_ENG.indd 176
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Chapter 8: Toll, tariff and access provisions 177
and that it would be inappropriate at this time
8.2.5 Tolling methods
for us to fix the system’s allowed depreciation
(zonal versus volume distance tolling)
rates for a 20 year period. Mackenzie Explorer
Group stated that the perceived economic
life of the system would be tied to a number
of factors such as the discovered and likely
to be discovered gas supply, as well as supply
Did you know?
Toll design
The three main cost of service tolling methods
Zonal tolls – all receipts from, or deliveries within,
are zonal, volume distance, and postage stamp.
the same zone pay the same toll, regardless of
Depending on the circumstances, any of these
exactly where the product is received or delivered
methods can produce just and reasonable tolls.
within the zone. For example, on the TransCanada
Mainline the province of Saskatchewan comprises
a zone. Therefore all gas received in Saskatchewan
and demand conditions in the entire North
The Proponents have proposed two tolling
American gas market. Mackenzie Explorer
zones for the Mackenzie Valley Pipeline:
the west side of the province or the east side.
Group proposed that given the current
• a long haul zone for gas coming into the
Volume-distance tolls – the further the gas moves,
knowledge and understanding of the resource
Mackenzie Valley Pipeline upstream of Little
base, it would not object to us approving
Chicago at approximately kilometre post 203;
a forecasted 25 year economic life with
and
an initial depreciation rate of four percent.
Mackenzie Explorer Group also contended
• a short haul zone for gas entering at or
downstream of that point.
that, every five years after commissioning, the
The 20 year short haul toll is proposed to
Proponents should be required to file a review
be fixed at 72.4 percent of the firm service
of the allowed depreciation rates, including an
transportation toll. This would allow shippers of
evaluation of the economic life of the facilities
gas from Colville Hills to pay the reduced rate.
based on gas supply forecasts at the time.
This rate was originally fixed at 80 percent but
Views of the Board
We accept the Proponents’ proposed
depreciation method but note that circumstances may change over the 20 years,
pays the same rate whether it was received on
the higher the charge. For example, the charge could
be per kilometre. (If the contracts are negotiated in
energy units, such as $/GJ or $/MMBtu rather than
volumetric units such as $/Mcf or $/cubic metre, then
the term “energy-distance tolls” is sometimes used.)
Postage stamp tolls – a toll that is charged per
volumetric unit transported regardless of the distance
traveled and the points of origin and destination.
This is similar to the charge for a postage stamp
Volume
2 Figure
8.1 is the same whether the letter goes
where
the rate
Proposed toll zones in the region
to the next block or the other side of the country.
was revised downward to reflect the distance
Figure 8-1
from the midpoint between Little Chicago and
Proposed toll zones
for the Mackenzie
Norman Wells to the NOVA Gas Transmission
Valley Pipeline
Ltd. interconnect in Alberta relative to the total
length of the Mackenzie Valley Pipeline.
Little Chicago
necessitating a review of the economic life
The Proponents indicated that two zones,
of the project and therefore the appropri-
each with a single toll, would be reasonable
ate depreciation rates. While noting that
for the Mackenzie Valley Pipeline. This approach
we cannot bind future panels of the
recognizes that the large quantities of gas
National Energy Board, if the National
flowing into the Mackenzie Valley Pipeline at
Energy Board reviews the depreciation
Inuvik make it economically possible to move
method during the first 20 years of opera-
gas from more southern Northwest Territory
tion it would have regard to the effect of
locations. The Proponents did not support
any change in depreciation on the ability
volume-distance based tolls as a stand‑alone
of the Mackenzie Valley Aboriginal Pipeline
tolling method. The Proponents were concerned
Limited Partnership to finance its interest.
that applying highly distance-sensitive rates
Short-haul toll
Long-haul toll
could allocate too many benefits of economies
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178 Mackenzie Gas Project • Volume 2: Implementing the decision
of scale and scope to future short haul
expansions of that pipeline, and future
Views of the Board
shippers and thereby undermine the willingness
extensions and laterals connecting with the
It would be most economically efficient
of the initial anchor shippers to proceed with
Mackenzie Valley Pipeline. (See Section 8.2.8
from a pipeline perspective for the entire
the project.
for a further discussion of these topics.)
pipeline from Inuvik to the Alberta border
While there are currently no plans to establish
The Government of Yukon noted that a
to be filled to capacity at all times. If this
any other zones, the Proponents would consider
volume-distance toll design in differing formats
were the case, it would make sense to use a
doing so if transportation was requested for gas
is used on many Canadian pipeline systems,
postage stamp methodology and have only
produced south of Colville Hills. In such a case,
including on the TransCanada Mainline,
the appropriate tolling arrangements would be
TransCanada’s British Columbia system and
considered at that time. The Proponents would
Westcoast’s T-South. A volume-distance cost
consider any benefits from the additional
method would result in tolls that are efficient,
commitments, the availability of competitive
fair and equitable, well understood by shippers
alternatives, any stranding of upstream capacity,
and the National Energy Board, and flexible
and all other relevant factors in making a
and durable over a wide range of future
In accordance with the principles of
decision. They further noted that it would
circumstances. The Government of Yukon also
cost-causation and user-pay, we find it
ultimately be up to the National Energy Board to
stated that the tolling method would not have
desirable that tolls would be distance
decide what tolls would be just and reasonable.
to be purely volume-distance tolls. Toll zones
sensitive. However, we find using a pure
The Government of Yukon submitted that
could be created along a pipeline that uses
volume-distance based toll would be
the Proponents’ toll design is not economically
energy-distance or volume-distance toll design.
unnecessarily complicated. Based on the
efficient and may lead to less than optimal
pipeline development and use. Specifically,
they were concerned that a short haul zone of
994 kilometres (the distance from Little Chicago
to Alberta) is a very long distance over which
to apply a single toll and would discourage
potential shippers from using the southern
portion of Mackenzie Valley Pipeline. The
Government of Yukon submitted that we should
find a volume-distance (or energy-distance)
toll design to be appropriate and in the public
interest for the Mackenzie Valley Pipeline.
MGM Energy Corp. and Apache Canada Ltd.
both supported a pipeline toll method with a
toll based on distance as this reflects a shipper’s
proportionate share of costs for use. MGM
Energy Corp. wanted the volume-distance
method to be applied to both the Mackenzie
Valley Pipeline and the natural gas liquids
transmission facilities and was not opposed
to the use of a zonal method. They and other
parties supported distance-sensitive tolls in
final argument.
Further, we should direct that it be implemented
The Proponents are also offering a separate
using a single rolled-in revenue requirement that
tolling arrangement for service to northern
includes the cost of the initial pipeline, future
communities (see Section 8.2.9).
one toll zone. However, this is not the case.
The Mackenzie Valley Pipeline, as proposed,
has spare capacity available and attracting
additional shippers would increase
economic efficiency and generally result
in lower tolls for everyone.
location of the gas reserves noted in
evidence, we approve the Proponents’ initial
tolling method with two zones. However,
we expect that additional zones (over and
above the two proposed zones) would be
considered in the future, and expect the
tolls in each zone to be distance sensitive.
Considerations in determining the location
and timing of future zones should include:
•• distance;
•• capital expenditure;
•• the benefit of the additional
commitments;
•• the availability of competitive
alternatives;
•• any stranding of upstream capacity; and
•• all other relevant factors.
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Chapter 8: Toll, tariff and access provisions 179
8.2.6 Open access
Producers of other natural gas resources in the
region need access to the Mackenzie Valley
Pipeline to reach the North American market.
Open access means that shippers willing to
meet the toll and tariff conditions have the
right to access service where it is economically
feasible for the Proponents to provide that
service. Without this access, natural gas supplies
in the Northwest Territories could not be
economically developed.
determine if other producers needed
Toll treatment for future expansions
capacity. Once there were sufficient precedent
The second issue, the appropriate toll treatment
agreements, the Proponents would then
of expansions, addresses the question of
make the necessary applications to expand
whether the costs of expansions should be
the Mackenzie Valley Pipeline. Finally, potential
rolled into the Mackenzie Valley Pipeline’s
shippers would retain the right to ask the
existing rate base.
National Energy Board to order the Mackenzie
Valley Pipeline to provide the service. The
Proponents also noted that it is not possible
to be definitive at this stage about the
circumstances and timing of future Mackenzie
Valley Pipeline expansions.
Parties who could be potential third-party
shippers raised the following issues with regard
to access to the Mackenzie Valley Pipeline:
• access and expansion policy, which includes
the process for addressing expansions
and toll treatment for future expansions;
• precedent agreements;
• minimum contract term; and
• interruptible service for gas which fails
to meet specifications.
on a rolled-in basis. However, the Proponents
also stated that they cannot establish a definite
circumstance and it would not be appropriate
processing capacity and pipeline capacity can
for them or us to make such a guarantee.
be economically accessed or developed within
a reasonable period of time. They submitted
that this could be provided by developing
an expansion policy for both the Mackenzie
Valley Pipeline and the Mackenzie Gathering
System. In Mackenzie Explorer Group’s view,
an expansion policy should include, among
prospective shippers to request service, as well
discussed regarding the access and expansion
as a public and transparent open-access process
policy. The first concerned the process for, and
to solicit other requests. Further, the Mackenzie
timeliness of, expansions and the second the
Valley Pipeline operator should be required to
appropriate toll treatment for future expansions.
make information such as expansion volumes,
Pipeline are received, capacity could be found
the tolls for an expansion would be determined
tolling method that would apply for every
During our hearing two key issues were
requests for service on the Mackenzie Valley
existing tolls, it is currently contemplated that
assurance that when resources are discovered,
other things, a clear procedure for existing and
The Proponents submitted that when future
foreseeable expansions are expected to reduce
Mackenzie Explorer Group sought a degree of
Access and expansion policy
Process for addressing future expansions
The Proponents’ Toll Principles stated that, as all
costs and expected tolls available on a timely
basis. Mackenzie Explorer Group also requested
that the Proponents consider and execute any
expansion in a timely manner.
The Government of the Northwest Territories
contended that, as a matter of principle,
potential shippers on an expanded Mackenzie
Gas Project should receive categorical assurance
that tolls would be determined on a rolled-in
basis, whether or not the costs of that
expansion would reduce existing tolls. The
Government of the Northwest Territories noted
that it has been the National Energy Board’s
practice for every major gas pipeline under
its jurisdiction to roll in all of the capital costs
associated with its facilities to one rate base,
and therefore to one cost of service. This
rolled-in approach was challenged in the 1980s.
At that time the National Energy Board chose
this approach based on a large body of evidence
and argument. An indication of intended or
in a number of different ways. The Proponents
The Government of Yukon also contended
required conformity to rolled-in tolling would
could ask existing shippers to give up (“turn
that if the access conditions are met, the
be valuable for parties which expect to contract
back”) any unneeded capacity. Alternatively, the
Proponents should be required to proceed
for the Mackenzie Valley Pipeline’s services in
Proponents could conduct an open season to
with an application.
the future. It would also provide a long-term
1249_NEB_MGP_Vol2_Text_ENG.indd 179
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180 Mackenzie Gas Project • Volume 2: Implementing the decision
signal to encourage exploration and
The Proponents replied that the National Energy
In order to obtain the right to capacity on
development of gas resources, particularly
Board is not strictly bound by its earlier decisions
the Mackenzie Valley Pipeline, potential
in respect of a basin opening pipeline.
and must consider each case on its own merits
shippers must first sign a Precedent
based on the record before it. It can therefore
Agreement. As the Proponents have
only decide the tolling treatment of a particular
structured the agreements, the pro forma
expansion when an application for that
Precedent Agreement contains the proposed
expansion is made. However, they agreed
Firm Service Transportation Agreement,
to remove the clause in section 20.4 of the
the Toll Principles and the Tariff Principles.
The Government of Yukon also asserted that
we should find that the costs of expansions,
as well as extensions and supply laterals,
should be rolled in as long as they meet
standard economic tests to ensure the facility
would be used and that shippers would be
held accountable through contracts with
sufficient primary terms.
Tariff Principles that caused concern about
the willingness to undertake expansions which
would result in higher tolls. That clause states:
“As all foreseeable expansions are expected
to reduce existing tolls…”
Did you know?
approval of the Precedent Agreement or
the Firm Service Transportation Agreement
but they are requesting approval of the toll
and tariff principles. The Proponents’ position
Precedent agreements
is that an agreement on the tolling principles
As discussed previously, the only parties that
provides greater certainty for both shippers
have signed Precedent Agreements for the
and the Proponents as to how tolls will be
charge is based on the daily contracted quantity
Mackenzie Valley Pipeline to date are the
determined. This increased certainty allows
and is payable regardless of whether the quantities
owner-shippers, which have signed contracts
shippers to make plans to develop their gas
for capacity totaling 23.5 Mm3/d (830 MMcf/d).
resources and it allows the Proponents to
This leaves 10.8 Mm3/d (380 MMcf/d) of
obtain financing. It also reduces the need
to the market and receives bids for that capacity
capacity available in the summer with three
for, and cost of, annual rate hearings.
from market participants.
compressor stations, as in the base case design,
The Proponents stated that, once we release
Precedent agreements – a formal understanding
or 3.8 Mm3/d (134 MMcf/d) with only a single
our Reasons for Decision, each Mackenzie Gas
compressor station at Great Bear River. While
Project shipper will have to sign a Firm Service
companies will sign a Service Agreement if certain
additional capacity would be available during
Transportation Agreement at which time the
conditions are met. The Precedent Agreement
the winter because of the effect of ambient
Precedent Agreement will terminate. Within
temperature on capacity, firm contracts are
75 days of our Reasons for Decision date,
the pipeline company to making that amount
based on the level of flow that can be achieved
the Proponents will issue Firm Service
of space available to the shipper for moving
during the lowest flow period which is the
Transportation Agreements to all shippers
summer. The number of third-party contracts
and shippers will have 15 days after the Firm
is important because it influences, among
Service Transportation Agreement is received,
precedent agreement.
other things, the number of compressor stations
or 45 days after our decision date, whichever
Revenue requirement – the total cost of providing
that would be required, the level of tolls on
is later, to sign the contracts. The Firm Service
service, including operating and maintenance
the system and the share of the project that
Transportation Agreement will be signed
would be owned by the Mackenzie Valley
before the Proponents decide to go ahead
Aboriginal Pipeline Limited Partnership.
with the project.
Definitions
Demand charges – a monthly charge that typically
covers the fixed costs of a pipeline. The demand
of gas are transported.
Open season – a process in which a pipeline
company offers either existing or new capacity
between a potential shipper and the pipeline
company saying that once capacity is available the
commits the shipper to using that pipeline to
transport specific volumes of gas and commits
the gas if the conditions are satisfied.
Pro forma contract or pro forma precedent
agreement – a sample contract or sample
expenses, depreciation and amortization, taxes,
and return on rate base.
1249_NEB_MGP_Vol2_Text_ENG.indd 180
The Proponents are not requesting our
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Chapter 8: Toll, tariff and access provisions 181
The Precedent Agreement gives parties the
According to Mackenzie Explorer Group
Transportation Agreement, other than a right
right to terminate the agreement for any
the requirement for shippers that entered into
to “buy out” its transportation obligations by
reason within 30 days of us issuing our Reasons
a Firm Service Transportation Agreement
paying $285 per gigajoule of contract demand.
for Decision. However, if a shipper wishes to
to support aspects of the Mackenzie Gas
Adverse events could include unreasonable
terminate the agreement it would have to pay
Project application with which they do not
escalation of projected rate base, an adverse
a termination fee of $285 for each gigajoule
agree discourages parties from signing
National Energy Board decision, regulatory
of daily contract quantity. For example,
contracts before our hearing process is
delays, and the lack of available downstream
a party which signed a Precedent Agreement
complete. Mackenzie Explorer Group asserted
pipeline capacity. Other impediments to signing
for 2.83 Mm3/d (100 MMcf/d) would pay
that this is unreasonable to shippers which
contracts include the lack of assurances that
approximately $30 million in termination fees.
are not owner-shippers.
access to other segments of the Mackenzie Gas
The Proponents may terminate all Firm Service
Transportation Agreements within one year
of our Reasons for Decision date if the
Proponents decide not to proceed with
construction of the Mackenzie Valley Pipeline.
Mackenzie Explorer Group notes that the
Precedent Agreement and the Firm Service
Transportation Agreement lay out numerous
items which would normally be addressed
in a pipeline tariff or determined by the
Project would be made available on reasonable
terms and conditions during the term of the Firm
Service Transportation Agreement, and the lack
of a Code of Conduct during the construction
and operation phases of the pipeline.
Because the Toll and Tariff Principles are
National Energy Board in tolls and tariff
To address the concerns regarding the Precedent
embedded in the Precedent Agreement, any
proceedings such as:
Agreement, Mackenzie Explorer Group contends
shipper that signed a Precedent Agreement
• capital structure;
that the Proponents should be required to file
contractually agrees that the tariff for the
• return on equity;
a proposed tariff with the National Energy Board
Mackenzie Valley Pipeline should reflect these
• cost of debt;
within three months of the date our decision
toll and tariff provisions. In effect, they would
• depreciation;
is issued. After reviewing that filing, including
be contractually precluded from raising concerns
• taxes;
a public hearing if required, the National Energy
about these issues before us and would be
• toll design;
Board would approve an appropriate tariff and
contractually obliged to support the Proponents’
• renewal rights;
Firm Service Transportation Agreement. This
position in proceedings before the National
• force majeure;
tariff would reflect the National Energy Board’s
Energy Board.
• services offered by the pipeline;
determinations in this proceeding on the toll
• authorized overrun service;
and tariff principles.
A specific exception was made within the
Precedent Agreement which would give
signatories the right to challenge the prudence
of predevelopment costs and capital expendi-
• restrictions on the availability
of interruptible transportation service; and
• various other matters.
MGM Energy Corp. also noted that it was
not surprising no third-party shippers had yet
signed a Precedent Agreement given the lack
tures, as well as the prudence of operating
In addition, Mackenzie Explorer Group contends
of agreement on tariff and tolling methods,
costs. This right to challenge would allow
that parties are discouraged from signing
the lack of an operating Code of Conduct
shippers to question whether or not the costs
the Precedent Agreement because it contains
and the lack of tolling and tariff information
claimed by the Proponents were reasonable.
no provisions protecting the shipper against
on the natural gas liquids pipeline.
adverse events before signing a Firm Service
1249_NEB_MGP_Vol2_Text_ENG.indd 181
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182 Mackenzie Gas Project • Volume 2: Implementing the decision
Minimum contract term
if one develops. The Government of the
under its firm service agreement. Also related to
The Proponents have offered two contract
Northwest Territories expressed the belief that
interruptible service, Mackenzie Explorer Group
terms, 20 years and 15 years, provided that
these deficiencies will discourage the economic
asserted that interruptible service should not be
at least 20 percent of the contracts are for
development of further gas reserves in the
restricted to firm service shippers.
20-year terms to satisfy financing requirements.
region. To address this concern, the Government
The toll for a 15-year term would be higher
of the Northwest Territories submitted that it
than the toll for a 20‑year term. For gas
would be just and reasonable for us to ensure,
flowing the full distance this premium would
even if only as a fallback, that primary capacity
be $0.15 per gigajoule. The Proponents also
on the Mackenzie Valley Pipeline would be
noted that consideration of any other term
available from the start of operations for terms
lengths would be determined after deliveries
shorter than the 15-year minimum, perhaps
start and would depend on many factors
10 years. As with the 15-year term, the pricing
including volume, timing and cost.
of shorter-term service would also reflect a term
Mackenzie Explorer Group and the Government
1249_NEB_MGP_Vol2_Text_ENG.indd 182
toll differentiation.
The Proponents responded that they don’t
intend to offer interruptible service to shippers
that don’t hold firm service contracts so Suncor
Energy Inc. will in any event be required to
enter a Firm Service Transportation Agreement.
It is through firm service contracts that the
Mackenzie Valley Aboriginal Pipeline Limited
Partnership will earn its interest in the
Mackenzie Valley Pipeline. The Proponents
noted that since it will be at least eight years
of the Northwest Territories both expressed
Interruptible service for gas which fails
until natural gas flows, Suncor Energy Inc.
concerns with the lack of shorter-term contracts.
to meet specifications
would have time to redesign its plant so that
Mackenzie Explorer Group accepts that 15 years
Suncor requested in written argument that
its gas meets specifications.
is an appropriate minimum contract term for
the Mackenzie Valley Pipeline be required
initial contracts. However, it notes that the
to offer a special interruptible service for gas
Mackenzie Valley Pipeline, when it files its
which fails to meet the tariff specifications
proposed tariff, should be required to clarify
for minimum heat content. Suncor Energy Inc.
We find it fundamental to our decision that
that minimum contract terms of one year
noted in its request, that there would be a long
the Mackenzie Valley Pipeline be accessible
for firm service are acceptable for existing
lead time to redesign its gas plant so that its gas
to all shippers that meet the terms of the
uncontracted capacity.
could meet the minimum specifications.
tariff. There are a number of principles
The Government of the Northwest Territories
As background, in June 2006, the Proponents
is concerned that no transportation service is
and potential shippers negotiated a provision
currently planned for shippers which cannot
which would allow gas which did not meet the
commit to the minimum 15-year term. Shippers
minimum heat content to be shipped as long
which need shorter-term service will have
as a surcharge was paid. The Tariff Principles
to wait a number of years to find out whether
also provide for gas to flow even if it exceeds
The Board, however, considers it
or not this service will be available. Further,
the CO2 limits as long as various conditions
essential that all terms and conditions
they may be left in a disadvantageous position
are met. However, if the conditions are not
of access to a pipeline be clearly
of contracting in the secondary market for
met, the pipeline can curtail those flows and
reflected in the tariff in order to
transportation on the Mackenzie Valley Pipeline,
the shipper is still obligated to pay the tolls
ensure that there are no undue
Views of the Board
which enhance open access on a pipeline.
For example, it is essential that shippers
know the terms and conditions of access
to a pipeline in advance of negotiations. In
GH-2-87 the National Energy Board stated:
12/6/10 11:02:49 AM
Chapter 8: Toll, tariff and access provisions 183
service restrictions imposed by
With respect to toll treatment for future
We acknowledge the preference of
pipeline companies involved in the
expansions, we note the concerns about
Mackenzie Explorer Group and the
marketing or producing sectors
the clause in the tariff which states: “As all
Government of the Northwest Territories
of the natural gas industry. In the
foreseeable expansions are expected to
for flexibility with respect to minimum
National Energy Board’s view,
reduce existing tolls…” With the removal
contract terms when capacity emerges.
prospective shippers are entitled to
of this clause as offered by the Proponents
We also note that no party disputed the
know the conditions of access to a
in final argument, the governments of the
need for minimum 15-year contracts to
pipeline system in advance of contract
Northwest Territories and Yukon agreed
support the construction of the project
negotiations, as this knowledge will
that, while it has been the National Energy
and for the Mackenzie Valley Aboriginal
allow market participants to make
Board’s practice to roll in the capital
Pipeline Limited Partnership to obtain
informed supply and market decisions
costs of an expansion, the appropriate
financing. We wish to focus at this stage
thereby contributing to the efficient
toll treatment would be determined
on the arrangements that will put the
at the time of the expansion after
Mackenzie Valley Pipeline on a sound
considering the specific circumstances.
commercial footing between now and the
functioning of the natural gas market.
4
As elaborated in RH-3-2004:
This ensures transparency and puts
the pipeline and its customers on
an equal footing in negotiating
a business arrangement.
5
Certain provisions of the Precedent
Agreements purport to require that
potential shippers support all aspects of
the toll and tariff principles and therefore
preclude potential shippers from raising
in-service date. For this reason, we will not
require a shorter minimum contract term
at this time. We expect that the Proponents
would investigate shorter contract terms
once the project becomes operational.
To provide this transparency and clarity,
concerns with the National Energy Board.
The proposal by the Proponents to offer
the Proponents are directed to include in
This provision is contrary to the National
interruptible service only to parties that
the tariff all terms and conditions of access
Energy Board’s principles and to the
have signed a Firm Service Transportation
to the Mackenzie Valley Pipeline including
fundamental tenets of open access. The
Agreement is acceptable at this time given
a clear procedure for shippers and potential
Proponents are directed to remove these
the need to establish a firm commercial
shippers to request service and the specific
words from any document that relates
foundation for the Mackenzie Valley
process that will be used for open seasons.
to access to the Mackenzie Valley Pipeline.
Pipeline. The specific proposal for a special
We expect the clause to be removed as
interruptible service for gas which fails
soon as possible but, in any event, no later
to meet minimum specifications is not
than 31 December 2011. In the meantime,
required, particularly given the long lead
any potential shipper can approach the
time for Suncor Energy Inc. to address this
National Energy Board to resolve a dispute.
issue at its facilities.
Regarding future expansions, we cannot
provide the degree of assurance sought
by Mackenzie Explorers Group and
the Government of Yukon absent
the information that would accompany
a specific request for service.
The Proponents are also directed to file a
tariff as soon as reasonably possible but, in
any event, no later than 31 December 2011.
[4] GH-2-87 Reasons for Decision, p 92.
[5] RH-3-2004 Reasons for Decision, p. 9.
1249_NEB_MGP_Vol2_Text_ENG.indd 183
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184 Mackenzie Gas Project • Volume 2: Implementing the decision
8.2.7 Term-related toll differential
8.2.8 Lateral policy
As mentioned in the previous section, the toll for
The Proponents, for business reasons, do not
a 15-year term would be higher than the toll for
intend to build extensions or laterals either for
a 20-year term. For gas flowing the full distance
tying in supply or for delivering natural gas to
and operate the extension or lateral facility that
this premium would be $0.15 per gigajoule.
market. They will, however, accommodate the
interconnects with the mainline. Parties wishing
Mackenzie Explorer Group argued that the $0.15
tie-in of interconnecting pipelines built by others.
per gigajoule premium had not been justified on
a cost basis, and should not be approved.
The Government of Yukon argued that we
On the record
Transportation-by-others model
A separate company could construct, own
to use those facilities would contract with the
Mackenzie Valley Pipeline which would in turn
contract with the company that owns the laterals.
The cost of that contracted service would be
should find that lateral and extension services
combined with the costs of the mainline to form
The Proponents argued that the differential was
must be provided by the Mackenzie Valley
a single annual revenue requirement. Shippers
not intended to reflect costs and was arrived
Pipeline. Allowing the Proponents to limit their
at as a matter of judgment intended to reflect
investment to the mainline is inconsistent with
the different values that shippers would place
the public interest in achieving economies of
on 15- and 20-year contracts.
scale and scope that can lower system-wide
costs upon which tolls are based. The
Views of the Board
We find that the proposed toll differential
reflects different services and is reasonable.
Potential shippers will have the choice of
entering into a longer-term contract with a
slightly lower toll or a shorter-term contract
with a higher toll. We expect they will make
the choice that best meets their needs.
Government of Yukon contended that if these
economies, both of scale and of scope, were
would see a seamless service despite using facilities
of two different owners.
resources located away from, but dependent
on, the Mackenzie Valley Pipeline for
transportation to southern markets.
not realized, some extensions or laterals which
If the Proponents will not build extensions
would otherwise be of economic value may not
or laterals, the Government of Yukon submitted
be constructed and the regional development
that a transportation-by-others model could
of natural gas would almost certainly be
be used to achieve the economies of scope.
reduced. Such an approach would establish
Integral to this solution is the Government
an unnecessary barrier to developing gas
of Yukon’s request for volume-distance tolls.
Although the cost per kilometre would be
the same across the mainline and lateral
On the record
Economies of scale and scope with laterals
Economies of scale occur when a single product,
such as pipeline transportation services, can be
offered for a lower unit cost by one large diameter
pipeline than by several smaller pipelines built along
a higher total toll because it would be going
further since it would use the extension
or lateral in addition to the mainline.
The Government of Yukon noted that another
the same route. Instead of each shipper building and
variation of the transportation-by-others
operating facilities for its own needs, the transmis-
structure would be for the Mackenzie Valley
sion company can combine demand from several
shippers and build a single, larger pipeline.
Economies of scope occur when there is a reduction
Pipeline to operate and administer the upstream
interconnected facilities, instead of the facility
in costs if two or more services, such as provision of
owner. The facility owner would not need its
pipeline services and provision of lateral services, are
own operating and administration function
produced by a single company rather than a number
of companies.
1249_NEB_MGP_Vol2_Text_ENG.indd 184
or extension, an extension shipper would incur
since these functions would be undertaken
by the Proponents.
12/6/10 11:02:50 AM
Chapter 8: Toll, tariff and access provisions 185
Did you know?
Definitions
Distribution system – the pipeline facilities
which transport the fuel from the mainline to
authorizes the National Energy Board to
Rebate for shippers selling gas
direct a pipeline company to extend its
to northern communities
transmission facilities to the junction with
When shippers on the Mackenzie Valley Pipeline
local distribution companies.
sell gas to small gas users in the Northwest
Territories, the Proponents propose to give those
the end users, including homes and businesses.
Gathering system – the pipeline facilities
which collect gas from producing fields.
Mainline – the main transportation line(s) of
a pipeline system.
Views of the Board
We will not require the Proponents to
construct supply extensions and laterals or
roll in the costs of those facilities. In order
for the National Energy Board to make
these decisions, even if it has the authority
to do so, it would have to have a specific
The Government of the Northwest Territories
stated that the Proponents’ policy of not
investing in supply laterals is unfortunate
since the Proponents were probably in the
application before it. Without the detail
contained in an application, we cannot
assess the circumstances, public interest
or burden.
best position to construct and integrate these
Our views with respect to delivery laterals
facilities. The Government of the Northwest
are discussed in Section 8.2.9 below.
shippers a rebate of 50 percent of the applicable
20-year toll. The program is called the
Northwest Territories Small Market Delivery
Rebate Expense. The rebate would apply to:
• residential, commercial or institutional
users, including power generators that
serve these users;
• small industrial companies that consume
less than 100,000 gigajoules per year; and
• power generators that produce less than the
amount of electricity that could be generated
from 100,000 gigajoules annually.
Territories noted that the Proponents cannot,
by declaring that they will not invest in laterals,
escape the requirement of the National Energy
8.2.9 Service to northern communities
Board Act which states that the National Energy
Four issues on the record related to community
Did you know?
Board can, upon request, require extension
access to gas flowing on the Mackenzie Valley
Definitions
of the Mackenzie Valley Pipeline facilities,
Pipeline:
Community gas pipeline – a lateral from the main
if required and if no undue burden is imposed
• a rebate for shippers selling gas to northern
on the pipeline.
The Proponents argued in reply that section
71(3) of the National Energy Board Act did
not appear to give the National Energy Board
authority to direct a pipeline owner to build
communities;
• the allocation of capital costs for metering
and related facilities;
• laterals to communities; and
• community access to gas supply.
pipeline to a local distribution system.
Local distribution company – a legal entity that
distributes natural gas throughout a community or
area, for example, to homes, businesses, institutions
or power generators. The legal entity may be a
private company, an entity owned by a municipality,
or a cooperative. The term local distribution
company can also be used for a company that
distributes electricity.
supply laterals or extensions, but section 72(1)
1249_NEB_MGP_Vol2_Text_ENG.indd 185
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186 Mackenzie Gas Project • Volume 2: Implementing the decision
After small industrial companies and power
the pressure of the Mackenzie Valley Pipeline
The Proponents plan to include the cost of valve
generators were included in the program,
would be much higher than the pressure of a
access points in the Mackenzie Valley Pipeline’s
the Government of the Northwest Territories
distribution system going into the community.
rate base. However, they propose that the
withdrew evidence raising concerns about
The natural gas would also need to be heated
community or developer would be responsible
the program.
so that liquid hydrocarbons do not form when
for all costs downstream of these valves. These
the gas goes from a higher pressure to a lower
costs could include metering and associated
pressure. The facilities would also include valves,
interconnection facilities as well as any transpor-
vessels and safety control equipment.
tation, distribution, processing or other facilities
Capital costs for metering
and related facilities
Communities requesting access to natural gas
flowing on the Mackenzie Valley Pipeline would
After leaving the depressurization and metering
require an agreement with a pipeline shipper
facility, the gas would flow on a community
to purchase the gas, an agreement with
gas pipeline, or lateral, to a local distribution
the Proponents for an interconnection, and
system serving homes, businesses, institutions
regulatory approvals for facilities and gas
and, potentially, power generators. The length
distribution. A number of facilities would need
of the lateral would depend on the distance
to be installed to access gas from the Mackenzie
between the community and the Mackenzie
Valley Pipeline including a depressurization
Valley Pipeline. See Figure 8-2 for an example
and metering facility at each access point.
of a community gas pipeline connection.
Depressurization would be necessary because
needed to bring gas from the pipeline to
the users. The Proponents intend to construct
and own the meter station and all associated
interconnection facilities and would charge
communities for these facilities at cost. These
facilities would not be part of the rate base
for the Mackenzie Valley Pipeline and therefore
would not be included in the Mackenzie Valley
Pipeline’s tolls. The details of how these costs
would be passed on to the communities have
not yet been determined but would be subject
to regulatory approval.
Figure 8-2
This arrangement was agreed to in the
Community gas pipeline
Mackenzie Gas Project Socio-Economic
Agreement between the Government of
From
Mackenzie
Valley Pipeline
Depressurization
and metering facility
Community
the Northwest Territories and the Proponents.
However, the Socio-Economic Agreement
recognized that these commitments are subject
to the tariffs, tolls, terms and conditions of
service approved by us.
Heater
Community
lateral
The Proponents estimated that the capital cost
of the metering and related facilities for eight
communities along the line (Inuvik, Fort Good
Hope, Norman Wells, Tulita, Déline, Wrigley,
Power
generation
facilities
1249_NEB_MGP_Vol2_Text_ENG.indd 186
Fort Simpson and Jean Marie River) would total
$27 million if all communities received service
12/6/10 11:02:50 AM
Chapter 8: Toll, tariff and access provisions 187
(see Table 8-3). The Proponents also estimated
The Proponents stated that the requirement
increase in the Mackenzie Valley Pipeline toll are
operating costs of $3.0 million per year, two
for the downstream community to pay for
shown in Table 8-4.
thirds of which would be spent on weekly visits
metering and related facilities was driven
by operations staff to each of these communities.
by cost considerations.
Table 8-3
Estimated capital costs for metering and related
facilities by community
Capital cost
Community
($millions)
Inuvik
6.0
Fort Good Hope
2.8
Norman Wells
4.2
Tulita
2.8
Déline
2.8
Wrigley
2.1
Fort Simpson
4.2
Jean Marie River
2.1
Total
Community access to gas supply
The Pehdzeh Ki First Nation submitted that a
Laterals to communities
condition of any approval must be a requirement
The Proponents provided a screening level
to supply natural gas for local use in the
evaluation of the cost to construct a lateral from
community of Wrigley. The Ayoni Keh Land
the Mackenzie Valley Pipeline to eight different
Corporation argued that the Proponents should
communities. The Proponents based their cost
be required to guarantee the availability of
estimate on the expected gas demand, distance
a minimum gas supply of 10,000 MMBtu/day
and any site specific considerations such as
horizontal directional drilling costs for river
for domestic use in communities of the
Northwest Territories at no commodity cost
crossings as required for Fort Simpson and
Déline. The estimates do not include the cost
to these communities.
of the community gas distribution system or the
The Proponents replied that it isn’t contrary to
cost of converting the power generation system
the public interest for the Mackenzie Gas Project
to use natural gas. The capital costs, distance,
gas producers to receive a market based price
estimated gas demand, and average annual
for the gas they produce.
27.0
The Proponents’ proposed treatment of
the metering and related facilities costs for
downstream communities differs from the way
these costs are handled on most National
Table 8-4
Estimated cost of service to northern communities
Energy Board regulated pipelines. Typically,
Distance to Community
metering and related costs associated with
Community
sales to local communities have been rolled
Inuvik
into the rate base and included in the pipeline’s
tolls rather than in the cost of distribution.
The exception has been some laterals on
Tulita
the Maritimes and Northeast Pipeline system.
Déline
Where Maritimes and Northeast Pipeline built
laterals that failed to meet an economic viability
test, the costs of those facilities, including
both the pipe and the metering facilities, were
paid for by the local distribution company.
1249_NEB_MGP_Vol2_Text_ENG.indd 187
(km)
Estimated Gas Demand
(m3/d)
(MMcf/d)
Estimated Capital Cost
Incremental Cost of Service
20 year Average
($millions)
($millions/year)
28
130,000
4.6
41.8
4.7
Fort Good Hope
5
24,000
.8
4.8
.5
Norman Wells
1
36,000
1.3
1.0
.1
7
14,000
.5
6.7
.8
110
20,000
.7
97.7
11.1
5
6,000
.2
3.2
.4
Fort Simpson
23
43,000
1.5
36.2
4.1
Jean Marie River
25
3,000
.1
12.9
1.5
204
276,000
9.7
204.3
23.1
Wrigley
Total
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188 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
mainline cost of service. We see no reason
Northerners should have a reasonable
why a similar toll treatment should not
opportunity to benefit from this project by
apply to the Mackenzie Valley Pipeline.
obtaining access to clean-burning natural
Accordingly, the Proponents are directed
gas for use in their communities when it
to incorporate this toll methodology
makes economic sense to do so. The
in their toll and tariff principles.
Proponents’ commitment to a 50 percent
With respect to gas supply to communities,
a Code of Conduct for all predevelopment
rebate of the 20-year toll for shippers selling
we expect natural gas markets to
activities of the Mackenzie Valley Pipeline.
to communities is valuable. However, we feel
continue to function effectively. As long
The Code covers topics such as confidentiality
that the public interest requires that more
as communities are paying market prices
of information, separation of activities of
be done to give residents of the Northwest
which provide shippers with a netback
Mackenzie Valley Pipeline staff and Mackenzie
comparable to what they would receive
Valley Pipeline owners, staff, appropriate cost
We have decided that it is in the public
if the gas was sold in Alberta, there should
allocation, acquisition of services at fair market
interest to require the Proponents to
not be difficulty in obtaining gas supply.
value and arrangements to ensure there is
construct, own and roll into rate base the
Therefore, there is no need to guarantee
no preferential treatment for owners.
cost of laterals to communities that meet
a minimum gas supply to communities.
Territories a chance to access this gas.
an economic test. If a proposed lateral
8.2.10 Codes of conduct
The purpose of a Code of Conduct is to guide
company officials by setting out the standards
and conditions for the interaction between a
company, staff, owners, affiliates, and potential
and actual shippers. The Proponents established
The Code of Conduct was to apply to all
We are interested in monitoring the ability
activities on the Mackenzie Valley Pipeline
of communities to access Mackenzie Valley
from 1 July 2002, until either 1 January 2011,
gas supplies. To this end, Condition 76 for
or the date that a decision to construct the
the Mackenzie Valley Pipeline requires the
Mackenzie Valley Pipeline has been made,
Proponents to file a report identifying details
whichever is earlier. At that point the
of any community’s expression of interest in
Proponents would upgrade the Code of
connecting to a delivery lateral or in having
Conduct to include the construction and
a delivery lateral constructed to connect to a
operating phases of the Mackenzie Valley
local gas distribution system. Condition 76
Pipeline. The Proponents committed to develop
has been modified since it was floated 9
such a Code, in consultation with shippers and
With respect to metering and pressure
March 2010 to accommodate the circumstance
prospective shippers, before the next project
reducing facilities, in most cases in Canada
where the Mackenzie Valley Pipeline is
phase proceeds.
these facilities are rolled into the pipeline’s
asked to build a lateral to a community.
does not meet the economic test, the
Proponents could require a contribution
(“aid to construct”) to cover the shortfall.
To put this into effect, the Proponents are
directed to develop and file the details of
the economic test by 31 December 2011,
following consultation with potential
shippers and the Government of the
Northwest Territories.
The Proponents believed there was no reason to
develop a new Code covering the construction
and operation phases prior to our decision, nor
would it be an efficient use of resources to do
so. Codes of Conduct are highly evolutionary
documents and highly specific to any particular
1249_NEB_MGP_Vol2_Text_ENG.indd 188
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Chapter 8: Toll, tariff and access provisions 189
pipeline, organization or project. The
Mackenzie Explorer Group is also concerned
MGM Energy Corp. was concerned that the
Proponents proposed to defer the detailed
that the proposed Firm Service Transportation
Proponents did not believe the National Energy
Code of Conduct finalization process for future
Agreements require prospective shippers to
Board is required to approve the Operating
project phases until it could be accomplished
disclose extensive and detailed information
Code of Conduct; that they did not plan to
in a timely and efficient manner.
about their resources and forecasts of their
submit the Operating Code of Conduct until
deliverability to the Proponents. The
after our decision; and that the operating owner
appropriateness of this disclosure requirement
would continue to transfer staff between the
would presumably be addressed in the context
pipeline and related facilities and the owners’
of the tariff filings the Proponents should be
producing and operating companies.
While the Proponents filed the Code of
Conduct for information only, they did not
have a problem with the National Energy
Board adjudicating the adequacy of the
Operating Code of Conduct for the Mackenzie
Valley Pipeline that is ultimately developed.
required to make with the National Energy
Board. However, if it were to be approved by
the National Energy Board, then significant
A Code of Conduct was not filed for the
issues would arise relating to the possibility of
Mackenzie Gathering System. However,
improper disclosure or use of that information,
according to the Proponents they have been
including to, or by, affiliates of the Proponents.
following the principles of the Mackenzie Valley
They submitted that we must take all necessary
Pipeline Code of Conduct for all matters relating
steps to ensure that any such information
to the Mackenzie Gathering System.
a shipper may be required to provide will
Two interveners, Mackenzie Explorer Group and
not be improperly used or disclosed.
MGM Energy Corp. believed the Proponents’
position was inappropriate and did not meet
the minimum operating standards for potential
third-party customers for a regulated pipeline
in Canada. The Operating Code of Conduct
should have been filed with the Application
or submitted prior to the start of the hearing.
Regulators have required pipeline companies
under their jurisdiction to file Codes of Conduct.
MGM Energy Corp. reviewed the Codes
MGM Energy Corp., expressed concerns with
Regulated utilities are often required
of Conduct developed for the Maritimes &
the Proponents’ Code of Conduct. Mackenzie
to implement a Code of Conduct. The
Northeast Pipeline and TransCanada’s Alberta
Explorer Group wanted to ensure that arm’s
TransCanada PipeLines Limited Mainline
system. It believed these Codes of Conduct,
length shippers would be treated fairly and
Code of Conduct was filed in response to
developed in conjunction with industry
appropriately relative to the facility owners
the RH-2-2004 decision and approved by
participants, provided the Proponents with
and their affiliated shippers. Issues concerning
the National Energy Board on 7 July 2005.
a good framework for the development and
appropriate standards of conduct for utility
Mackenzie Explorer Group contends that a
implementation of its own Code of Conduct.
owners in their dealings with affiliates have
Code of Conduct should apply to all portions
MGM Energy Corp. cited the National Energy
been extensively canvassed in other jurisdictions.
of the Mackenzie Valley Pipeline and Mackenzie
Board’s decision in RH-3-2004 where the
Regulators have prescribed standards and
Gathering System and throughout all phases,
National Energy Board reiterated the principle
enforcement mechanisms that are intended to
i.e., pre-construction, construction and
that shippers are to know in advance
ensure affiliates gain no unfair advantage as
operation. It should be included as part
of negotiations the terms and conditions
a result of their relationship with utility owners.
of the filed tariffs and be subject to approval
of access to a pipeline. (See Views of the Board
Mackenzie Explorer Group expressed concern
by the National Energy Board.
in 8.2.6 for elaboration.)
that some of the provisions of the Code
of Conduct are too permissive.
1249_NEB_MGP_Vol2_Text_ENG.indd 189
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190 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
Hesitancy about the terms and conditions
of access on the Mackenzie Valley Pipeline
and the Mackenzie Gathering System has
impaired the ability for non-owner shippers
to negotiate contracts for service. This is to
the detriment of potential shippers with
stranded gas in the Mackenzie Delta and the
public interest to which a successful project
could contribute.
We note that several existing Codes
of Conduct could serve as examples for
the Proponents in drafting a thorough
and appropriate Code of Conduct for an
open-access pipeline system.
The Proponents are directed to file,
for approval, a Code of Conduct for
the Mackenzie Valley Pipeline and the
of Conduct are to be filed as soon as
8.2.11 Tolls and tariff task force
possible but in any event not later than
In written argument Suncor Energy Inc.
31 December 2011. At a minimum, the
recommended that, as a condition of approval,
Code(s) of Conduct should address in detail:
the Proponents be required to file with the
•• prevention of undue preferential
National Energy Board formal procedures
treatment;
•• governance of the interactions
between shippers and transporters;
•• independence of transmission
operations from affiliate operations;
•• governance of separation of business;
•• protection of confidential and
commercially-sensitive information;
•• mechanisms and methodologies
related to the design of an acceptable
Mackenzie Valley Pipeline shipper committee
in a form similar to the formal procedures
filed with the National Energy Board regarding
NOVA Gas Transmission Ltd.’s Tolls, Tariff,
Facilities & Procedures Committee. Suncor
Energy Inc. asserted that such procedures
would be a significant aid in conducting the
work required to compile the tariff, as well as
addressing many other issues which will likely
arise over time.
transfer pricing mechanism;
•• a Code of Conduct compliance plan
with independent audits; and
•• penalties for breaches of the Code of
Mackenzie Gathering System for all phases
Conduct and recourse to a third-party
of development including pre-construction,
arbitrator.
construction and operation. The Code(s)
regarding the conduct of business at a
The Proponents responded that this condition
is unnecessary and there is no reason to
formalize the procedures for consultation
with potential shippers at this stage. They noted
that development of a final tariff is not a near
term critical path activity.
Views of the Board
While we have directed the Proponents to
file a tariff no later than 31 December 2011,
we do not see the need to direct the
Proponents to file formal procedures for
a toll and tariff task force at this time.
However, the Proponents may wish to do
so in the future.
1249_NEB_MGP_Vol2_Text_ENG.indd 190
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Chapter 8: Toll, tariff and access provisions 191
8.3 Mackenzie Gathering System
8.3.1 Overview
Mackenzie Explorer Group contends that,
although the Proponents describe the liquids
line, the Inuvik Area Facility and the facilities
upstream of the Inuvik Area Facility as a
“gathering system”, it is difficult to conceive of a
large diameter pipeline with a capacity near 31.1
Mm /d (1.1 Bcf/d) as a “gathering pipeline” in
3
any conventional sense. The same could be said
for the 476 kilometre natural gas liquids pipeline
and the Inuvik Area Facility. The Government
of the Northwest Territories notes that these
Mackenzie Gathering System facilities are more
correctly described as “supply laterals”. The
discussion of whether or not these facilities are
appropriately characterized as a gathering system
speaks to the issue of whether the methods used
elsewhere for determining fees on a gathering
system are suitable in this context.
During our hearing, the issues discussed
around toll, tariff and access provisions on
the Mackenzie Gathering System included:
• the need for economic regulation and
dispute resolution;
• tolls on the system (excluding the natural
gas liquids pipeline);
• tolls on the natural gas liquids pipeline; and
• the Code of Conduct.
1249_NEB_MGP_Vol2_Text_ENG.indd 191
8.3.2 The need for economic regulation
on the Mackenzie Gathering System
The Proponents submitted their application
for the Mackenzie Gathering System under
the Canada Oil and Gas Operations Act.
This legislation did not include any provision for
the regulation of tolls, tariffs and access to the
systems at the time the project was applied for
and through the course of the hearings in 2006.
However, we felt that this was an important
matter and added “the appropriate tolls,
access and tariff provisions for the Mackenzie
Gathering System and the methods for resolving
disputes on these matters” as Issue 13 on the
List of Issues in the proceeding. In response
to Mackenzie Explorer Group’s motion which
sought to have the Mackenzie Gathering System
regulated under the National Energy Board Act,
we ruled that the facilities were appropriately
applied for under the Canada Oil and Gas
Operations Act. However, we noted in our ruling
that we remained concerned about Issue 13.
• the market power would be manifested in
both higher fees/tolls for use of the various
components of the Mackenzie Gas Project
and an inefficiently small set of facilities;
• access to the natural gas pipeline would be
essentially meaningless without similar
access to the liquids pipeline;
• the public interest is served by regulation,
or the threat of regulation, to discourage
the potential abuse of a dominant position;
• the tolling and tariff principles proposed
by the Proponents are not adequately
transparent nor predictable;
• the anchor field producers would enjoy
considerable economies of scale and
together may acquire a dominant position
in the regional market for gathering and
processing services to the disadvantage
of developers which have smaller volumes
needing those services;
• by focusing expansion, to the extent
technically possible, on the applied-for
gathering and processing facilities, the
Mackenzie Explorer Group, the Government
unnecessary duplication of facilities could
of the Northwest Territories and MGM Energy
be avoided, thereby minimizing the project’s
Corp. contended that regulatory oversight
environmental “footprint”;
was needed on significant portions of the
• the efficient development of the basin
Mackenzie Gathering System. Their reasons
demands that potential producers have
included the following:
confidence the tolls and tariffs applicable
• the Proponents could exercise significant
to all of the Mackenzie Valley Pipeline, the
market power for each component of the
natural gas liquids line, the Inuvik Area Facility
Mackenzie Gathering System and therefore
and the gathering pipelines (supply laterals)
in the provision of transmission services for
will be developed in a transparent manner
northern gas supplies;
consistent with sound principles of pipeline
12/6/10 11:02:51 AM
192 Mackenzie Gas Project • Volume 2: Implementing the decision
rate design including that tolls be just and
When the amendments to the Canada Oil and
and an investment cost base for tolls
reasonable, non-discriminatory, fair, and
Gas Operations Act were passed by Parliament
negotiated between the historical cost and
charged equally to all persons at the same
on 14 December 2007 giving the National
replacement cost.
rate under substantially similar circumstances;
Energy Board power to regulate tolls, tariffs and
• there needs to be open access to pipeline
services; and
• commercial processes should be transparent.
The Proponents agreed that these facilities
have characteristics of a monopoly. However,
they also noted the opportunity for
regulated facilities, issues related to the need for
economic regulation of these facilities were fully
addressed. The Access Process terminated as it
was no longer required and it was subsequently
removed from the record of this proceeding.
However in October 2007, MGM Energy Corp.
signed contracts for 2.83 Mm3/d (100 MMcf/d)
on each of the Niglintgak and Taglu laterals. At
that time, the fee principles for the Mackenzie
Gathering System were revised to reflect the
new principles for third‑party use of the system.
The after-tax return on equity was set at 150
others to acquire ownership in the Mackenzie
8.3.3 Proposed method for setting
basis points above the Mackenzie Valley Pipeline
Gathering System including the natural gas
Mackenzie Gathering System
return on equity. While Jumping Pound-05
liquids pipeline, the opportunity to subscribe for
fees (excluding the natural gas
provided for the investment cost base used
transportation and processing services, and their
liquids pipeline)
in the calculation of tolls to be negotiated
proposal for dispute resolution would ensure
that they could not exercise market power.
The Proponents believed the traditional
cost of service method is not appropriate
between historical and replacement cost,
the Proponents’ fee principles were revised to
set the investment cost base at actual historical
To address the concerns about the absence
for producer-built gathering and processing
of financial regulation for Canada Oil and Gas
facilities like the Mackenzie Gathering System.
Operations Act facilities including the lack
Rather, the Proponents have structured the
of provision for dispute resolution, and to be
project so that the fees for owners are set
The revised fee principles form a basis for
responsive to Issue 13, the Proponents put in
in a different manner than the fees for third-
negotiation between the Proponents and
place the Access Process in May of 2005. The
party shippers. The fees for shippers are a
potential shippers. The Proponents noted that if
cost. The capital structure was maintained at
100 percent equity.
Access Process would be used to resolve disputes
consequence of individual negotiations that
negotiations fail and the National Energy Board
involving non-owner access to the facilities, terms
occur at different times. Therefore, fees can
is asked to adjudicate a process, the National
of facilities ownership, fees and other terms
vary significantly between owners and shippers
Energy Board can decide at that time what
of service. This Access Process was intended to
as well as between various shippers.
principles will be used to determine the fee.
At the time of the hearing the Proponents
In its evidence and testimony, MGM Energy
provide the Proponents with sufficient certainty
about how fees would be set in the future.
1249_NEB_MGP_Vol2_Text_ENG.indd 192
access on Canada Oil and Gas Operations Act
proposed to use the principles of the 2005
Corp. did not accept the use of JP-05. It stated
The Access Process contained a provision stating
Jumping Pound Formula (Jumping Pound-05)
that the Mackenzie Gathering System tolls
it would be in effect until amendments were
as the basis for tolling negotiations on the
should be cost-based and the system should be
effective to the Canada Oil and Gas Operations
Mackenzie Gathering System, other than
regulated as a Group 2 company which means
Act legislation or other legislative was enacted
the liquids line. Jumping Pound-05 provisions
that it would be regulated on a complaint basis.
or amended which addresses access and fees
include, among other things, a capital structure
Mackenzie Explorer Group suggested that the
related to Canada Oil and Gas Operations Act
based on 100 percent equity, a 20 percent
Proponents have not shown that the Mackenzie
facilities in the Northwest Territories.
before-tax return on equity, no depreciation
Gathering System is distinguishable from the
12/6/10 11:02:51 AM
Chapter 8: Toll, tariff and access provisions 193
Mackenzie Valley Pipeline in terms of cost of
return on equity and a four percent depreciation
tolls than under conventional cost of service
capital. It recommends the same cost of service
rate. The impact of Mackenzie Explorer Group’s
regulation. (It should be noted that the evidence
parameters for the Mackenzie Gathering System
assumptions would be to reduce Mackenzie
of both of these parties was provided prior to
as are recommended for the Mackenzie Valley
Gathering System tolls by about 45 percent.
the fee principles being revised in October 2007
Pipeline including a capital structure of 70
Mackenzie Explorer Group asserts that the use
as a result of negotiations between the
percent debt and 30 percent equity, the same
of Jumping Pound-05 results in much higher
Proponents and MGM Energy Corp.)
Mackenzie Explorer Group contended that
On the record
under the Proponents’ proposal, the owners
The Jumping Pound Formula
of the Mackenzie Gathering System will be
Jumping Pound-05 and its predecessors, Jumping Pound-95 and Jumping Pound-90 were originally developed
in a fundamentally different relationship with
as a framework for negotiating gathering and processing fees in Alberta. Jumping Pound-05 contains provisions
the Mackenzie Valley Pipeline than will either
for determining the level of fees and emphasizes the use of negotiation and alternative dispute resolution among
the sponsors or their affiliates. In order to avoid
facility owners and potential users of the facilities. In Alberta, if parties are unable to reach agreement, they can
take their dispute to the regulator, Alberta’s Energy Resources Conservation Board, for adjudication.
Initially, the Proponents had proposed to use the Jumping Pound-95 formula but changed to Jumping Pound-05
unjust discrimination, and to ensure that tolls
for using the Mackenzie Gathering System
when it was adopted as the industry standard. Both Jumping Pound-05 and Jumping Pound-95 provide for a range
appropriately reflect the cost of providing
of fees with the intent that parties would settle on a fee within those ranges. The difference between the ranges
service, it is essential that all shippers, including
of Jumping Pound-95 and Jumping Pound-05 are shown in the figure below which is drawn from the Jumping
Pound-05 document. While Jumping Pound-95 has a lower and upper limit, the Proponents had formulated their
the sponsors and their affiliates, receive service
fee structure based on the lower limit.
on terms that are verifiably the same. The only
There are two major differences between Jumping Pound-95 and Jumping Pound-05 in terms of the effect on tolls.
way to ensure this result is to require all shippers
The first is the elimination of the depreciation component of the capital charge in Jumping Pound-05 so that tolls
to enter the same form of service agreement,
no longer decrease over time as a result of depreciation. The second major difference is the return on investment,
be subject to the same tariff, and pay tolls that
which is fixed at 20 percent before tax in Jumping Pound-05 versus a formula-based return in Jumping Pound-95.
However, the Proponents have agreed to an after-tax return on equity which is set at 150 basis points above the
are verifiably the same for all shippers receiving
return on the Mackenzie Valley Pipeline, rather than the before-tax return of 20 percent provided for in JP-05.
the same service.
Volume 2 Figure 8-Y
Figure 8-3
JP-05 / JP-95 Fee comparison
JP-05 / JP-95 fee comparison (20 year life)
The Government of the Northwest Territories
stated that Jumping Pound-05 is “very rich”
compared to the return parameters for the
50
Mackenzie Valley Pipeline, particularly when
JP-95 upper limit
there does not appear to be any fundamental
$/Volume
40
JP-05 upper limit
difference in supply risk, market risk, natural
risk, completion risk, regulatory risk and so on.
30
JP-05 lower limit
20
JP-95 lower limit
10
1249_NEB_MGP_Vol2_Text_ENG.indd 193
30
25
20
15
10
5
0
Year
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194 Mackenzie Gas Project • Volume 2: Implementing the decision
Views of the Board
In response to concerns about the lack of
toll and tariff regulation and our concern
that this pipeline be accessible to thirdparty shippers, we added Issue 13 to
the List of Issues. Issue 13 is:
of access to capacity on the Mackenzie
more traditional cost of service regulation
Gathering System as the owner‑shippers.
reflecting risks for the Mackenzie Gathering
In addition, all parties have the option of
System and the Mackenzie Valley Pipeline
becoming either owners or shippers.
which were similar. The Government of
the Northwest Territories did not see any
fundamental difference in risks between
8.3.4 Proposed method for tolls
on the natural gas liquids pipeline
The appropriate tolls, access and
the two systems. However, we are of the
tariff provisions for the Mackenzie
view that the risks, and therefore the cost of
Similar to the contractual arrangements for
Gathering System and the methods
service parameters for the two systems are
the rest of the Mackenzie Gathering System,
for resolving disputes on
not necessarily the same. Potential differ-
a potential shipper on the natural gas liquids
these matters.
ences include the character of the physical
pipeline would sign a Capacity Request
facilities, contract terms and dependence
Agreement and could then choose either an
of some components of the Mackenzie
ownership option or third‑party transportation
Gathering System on specific fields.
option for use of the Mackenzie Gathering
On this topic, things evolved over the
course of the proceeding and events
overtook the discussion in a number of
System. If they chose the ownership option,
ways. The issue of the need for regulation
Given the unique features of the Mackenzie
of the Mackenzie Gathering System was
Gathering System, we accept the Proponents’
addressed when Parliament amended the
proposal to negotiate fees for use of the
Canadian Oil and Gas Operations Act in
Mackenzie Gathering System which will be
December 2007 allowing us to regulate
regulated on a complaint basis. If parties
tolls, tariffs and access on these facilities.
are not successful in their negotiations,
Rather than using the Jumping Pound
In addition, the Proponent’s proposed
then any party has recourse to the National
framework, the Proponents proposed to use
basis for negotiations of the fees moved
Energy Board. The National Energy Board
traditional cost of service regulation on the
from Jumping Pound-95 to Jumping
would at that time decide what principles
natural gas liquids pipeline and assumed a 65/35
Pound-05 to the fee principles established
would be used to determine fees.
debt equity ratio, a 12 percent return on equity
in October 2007 as a result of negotiations
with MGM Energy Corp.
1249_NEB_MGP_Vol2_Text_ENG.indd 194
Mackenzie Explorer Group sought a
We note Mackenzie Explorer Group’s
concern about owners and third parties
they would be subject to the Development
and Operating Agreement. The transportation
option would be subject to the Natural Gas
Liquids Pipeline Firm Transportation Agreement.
and five percent depreciation. However, these
parameters would form the basis of negotiation,
meaning that the fees on the natural gas liquids
We acknowledge that the Proponents
being under different forms of service
did not ask for approval of the toll
agreements, not subject to the same tariff
principles for the Mackenzie Gathering
and not necessarily paying the same fee.
Although the Proponents are proposing to
System as they did for the Mackenzie Valley
However, parties have the option at any
use a conventional cost of service method
Pipeline. We also note that the Proponents
time of bringing a complaint to the National
on the natural gas liquids pipeline, subject
expected us to address any concerns about
Energy Board. We also note in this case that
to negotiation, Mackenzie Explorer Group
the proposed methodology in our decision.
contracting shippers have the same priority
does not accept the Proponents’ proposed
pipeline could also be negotiable.
12/6/10 11:02:51 AM
Chapter 8: Toll, tariff and access provisions 195
parameters. Mackenzie Explorer Group asserts
that the debt equity ratio and the return on
equity should be the same as is applicable
to the Mackenzie Valley Pipeline and the
depreciation rate should be four percent.
This formula would reduce the toll on the
natural gas liquids pipeline by 22 percent.
8.3.5 Code of Conduct
As discussed previously, the Proponents
established a Code of Conduct for all
predevelopment activities of the Mackenzie
Valley pipeline but not for the construction
and operating phases, nor for any phase
on the Mackenzie Gathering System. The
MGM Energy Corp. contends that there needs
Proponents stated they had been following
to be adequate disclosure of information and
the principles of the Mackenzie Valley Pipeline
data on tolls and tariffs on the natural gas
Code of Conduct for all matters relating to
liquids line.
the Mackenzie Gathering System. The concerns
of intervenors discussed in Section 8.2.10
Views of the Board
As with the other components of the
Mackenzie Gathering System, we accept the
Proponents’ proposal to negotiate fees for
applied to the Mackenzie Gathering System
as well as the Mackenzie Valley Pipeline.
Views of the Board
the natural gas liquids pipeline. If parties are
As explained in Section 8.2.10, the
not successful in their negotiations, then any
Proponents are directed to file, for
party has recourse to the National Energy
approval, a Code of Conduct for the
Board. The National Energy Board would
Mackenzie Valley Pipeline and the
at that time decide what principles would
Mackenzie Gathering System.
be used to determine fees.
In accordance with the National Energy
Board’s publication entitled Financial
Regulation of Pipeline Companies under
the Board’s Jurisdiction, it is the responsibility of a company regulated on a complaint
basis to provide its shippers and interested
parties with sufficient information to
enable them to determine whether a
complaint to the National Energy Board
is warranted.
1249_NEB_MGP_Vol2_Text_ENG.indd 195
12/6/10 11:02:51 AM
Chapter 9
Consultation
9.1 Introduction
The National Energy Board expects proponents to consider consultation for all projects. Depending
on the project scope, this could mean carrying out a very extensive consultation program or a very
simple program such as notifying a single landowner. Proponents are responsible for justifying the
extent of consultation carried out for each project. For complex projects that require an extensive
consultation program, such as the Mackenzie Gas Project, the following information is expected
to be provided within an application to the National Energy Board:
• an outline of the principles and goals
for consultation by which the project
proponent will ensure that it adequately
consults with, and respects the rights of,
those potentially affected;
• a description of the project’s consultation
program and an indication why its design
is appropriate for the nature of the project
and the type of application; and
• a description of the results of the consultation
conducted to date for the project, with
sufficient detail to demonstrate that those
potentially affected by the project have been
adequately consulted and that any concerns
raised have been considered and addressed
as appropriate.
1249_NEB_MGP_Vol2_Text_ENG.indd 196
• Aboriginal people;
• local, territorial and federal government
authorities; and
• others who might have an interest in
the project such as community associations
and environmental groups.
Proponents are required in their applications
to describe the results of the consultation
carried out, including how the consultation
program was undertaken, a summary of the
comments and concerns raised, how comments
and concerns have been addressed by the
proponents, and how outstanding concerns will
be addressed. Proponents should also be able
to demonstrate how public input influenced
the design, construction, or operation of the
A project-specific consultation program
project. When an application is filed with the
should identify all potentially affected persons
National Energy Board, it is reviewed to assess
or groups to be consulted, including:
whether or not the company has taken into
• people living near the proposed pipeline;
consideration the comments and concerns
• local land users;
raised about the project.
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Chapter 9: Consultation 197
The National Energy Board provides members
9.2 The Proponents’
• Environmental Impact Statement consultants;
of the public with information on how they may
consultation program
• development field operators; and
participate in the National Energy Board process
• engineering consultants.
through various publications and community
9.2.1 Overview
information sessions to ensure that all interested
The Proponents define public consultation as
individuals and groups have an opportunity
the process of involving all affected parties in
to make their views on a project known to
the National Energy Board.
the design, planning and operation of a project.
This process requires the Proponents to give the
This process is designed to provide the National
parties to be consulted notice of the matter in
Energy Board with a full understanding of
sufficient form and detail and with a reasonable
the concerns that governments, Aboriginal
amount of time to allow them to prepare their
people and the public in general may have
views on the matter.
with the project so that the National Energy
Board may appropriately consider and address
those concerns in its decision making.
Gathering System and Mackenzie
Valley Pipeline
The Proponents undertook consultations
related to the Mackenzie Gathering System and
Mackenzie Valley Pipeline. Some initiatives were
undertaken jointly with the development field
operators. In addition, each development field
operator conducted separate consultations
The Proponents stated their goal for the
for their respective field developments.
Mackenzie Gas Project is to conduct consulta-
(For more information see Section 9.2.3.)
tion that is meaningful and effective. Consulta-
In addition to consultations undertaken by
tion activities are to be well documented,
the Proponents and the opportunities for
inclusive and dynamic, and provide transparent
participation by parties in the Joint Review Panel
engagement with communities affected by
and National Energy Board hearing processes,
the project. The Proponents also noted that
the federal government established the Crown
consultation would continue throughout the
Consultation Unit to coordinate its consultation
lifespan of the project.
with Aboriginal people about the project.
9.2.2 Consultation for the Mackenzie
The Proponents stated their consultation
and community affairs group provides a
multi-layered support system which is structured
to provide consistent activities and information
exchange in all regions and communities
throughout the project area. This includes
resident community representatives in the
The Proponents indicated that their public
pipeline corridor, regional representatives who
consultation efforts for the project have been
are beneficiaries of and live within the region,
primarily focused on Aboriginals and other
and Calgary-based representatives who routinely
Canada, Department of Fisheries and Oceans,
Northerners. Most of the interactions with the
travel within the region.
and Transport Canada. In addition, the Govern-
public, governments, regulatory authorities,
ment of the Northwest Territories consulted
local businesses, non-government organizations
extensively with the territories’ residents and
and people directly affected by the project
Aboriginal people about the project. Consulta-
development have involved Aboriginal people
tion with Aboriginal people by the Crown for
of Inuit, Dene and Métis heritage.
The Crown Consultation Unit included representatives from Environment Canada, Indian and
Northern Affairs Canada, Natural Resources
the Mackenzie Gas Project will continue as the
project progresses.
was an integral part of the project. They
have been consulting with Aboriginal and
non-Aboriginal people in communities
that might be affected by the project since
The public consultation program for the
January 2002. They have also consulted with
Mackenzie Gas Project was conducted
governments, regulatory authorities, potential
by representatives of the:
shippers and suppliers, labour groups,
• Mackenzie Gathering System and Mackenzie
non-government organizations and industry
Valley Pipeline operator;
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The Proponents stated that public consultation
representatives, and members of the public
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198 Mackenzie Gas Project • Volume 2: Implementing the decision
On the record
Consultation methods
The Proponents used various methods to address the broad range of interests, levels
of understanding and needs of potentially affected parties, including establishing
throughout the Northwest Territories and
members involved in subsequent phases of the
Canada. Consultation was used to explain
project have an accurate record of commitments
the purpose, needs and limitations of the
that are made.
project. At the same time, the Proponents were
three regional offices with open door policies. Consultation methods and activities
seeking to understand local concerns and to use
were also selected to address the needs of stakeholders in more remote locations.
this information in project planning. The primary
To provide opportunities for community input, regional liaison staff, community
representatives, Proponents’ and contractors’ consultation staff have:
• conducted one-on-one visits;
• contacted community leaders, individually and collectively;
• provided written materials such as letters, brochures, project website materials,
posters and advertisements and third-party items such as the Cooperation Plan;
• conducted interviews with local media, including stations that broadcast local
language programs;
• created audio-visual materials;
• held workshops, public meetings and open houses;
• made project presentations at many community events and conferences;
• sponsored project-focused events, such as an organized tour of a pipeline
construction site, for community residents;
• visited schools, made presentations and attended career fairs; and
• met with various representative groups within the communities and regions.
goals of the ongoing consultation program
were stated to be:
• to increase public awareness of the project
by providing timely information and soliciting
comments from affected members of the
public about proposed development and
activities that might affect their communities,
including the potential environmental and
socio-economic effects;
• to respond to public input and concerns,
In addition the Proponents’ engineering
contractors worked with the Proponents’
consultation staff to communicate information
on the design, site and route selection, and
initial site investigation in support of the project.
Community consultation activities have been
coordinated through local project offices in
Inuvik, Norman Wells, Fort Simpson and Hay
River. The project’s public consultation program
will continue throughout the regulatory process,
and throughout the construction and operations
phases of the project.
and take them into account during project
Environmental Impact Statement
planning, design and implementation;
consultation program
• to encourage the participation of Aboriginal
The consultants that prepared the
The Proponents have conducted over 1500 meetings with northern residents and
and other northern residents, as well as other
Environmental Impact Statement developed
community organizations, the results of which have been recorded and documented.
Canadians, in the employment and business
and implemented a complementary, but distinct,
There have been more than 350,000 visits to the project website. The information
opportunities created by the project; and
program of biophysical and socio-economic
and feedback gathered from affected communities and organizations during the
consultation program identified a number of concerns, some expressed by more than
• to identify, and reduce or mitigate, any
public participation. This program was
one group. Other concerns were more localized and affected only one group or area.
negative effects the project might have on the
conducted to obtain input for the Environmental
In many cases, the concerns raised were dealt with by the Proponents. In a few cases,
biophysical or socio-economic environment.
Impact Statement prepared for the three
additional study and consultation was required to develop satisfactory solutions.
Formal mechanisms were developed to
share the information obtained during the
consultation program with the different
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development field plans — Niglintgak, Taglu,
and Parsons Lake , the Mackenzie Gathering
System and the Mackenzie Valley Pipeline.
consultation groups working on the Mackenzie
A separate team was responsible for designing
Gas Project. One mechanism is an issues
and completing the public participation program
database, which the Proponents use to capture
for the Proponents’ Environmental Impact
meeting notes and any follow-up items that
Statement. This team worked closely with
arise. Everyone working on the Mackenzie Gas
the Proponents’ consultation and community
Project can view this issues database. Another
affairs group in developing and implementing
mechanism is a system that the Proponents use
stakeholder participation opportunities. Staff
to track commitments, to ensure that the staff
from the Proponents’ consultation and
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Chapter 9: Consultation 199
community affairs group was directly involved in
9.2.3 Consultation for
items to ensure full understanding of the
many of the meetings that were held specifically
the development fields
potential impacts before making a decision.
Each of the development field operators
Shell met with Aboriginal and non-Aboriginal
conducted its own public consultation program.
Northerners; municipal, territorial and federal
Each operator was responsible for consultation
representatives; communities; regulators and
on its own particular field and staffed its
agencies; and other oil and gas companies.
project team to facilitate consultation objectives,
During consultation, specific concerns regarding
Two main rounds of activity occurred. The first
methods, activities and materials. Where
Niglintgak were raised, including:
round consisted of identifying and scoping
possible, activities were combined and
• the size and nature of the development’s
issues, with communications centering on
coordinated to include the Mackenzie Gathering
to discuss the Environmental Impact Statement.
The meeting notes and any follow-up items
from the meetings with the Environmental
Impact Statement public participation team were
recorded in the Proponents’ issue database.
land footprint;
introducing the project and identifying commu-
System. In order to share information from
• the biophysical and socio-economic effects
nity concerns. Consultation efforts during the
the consultation programs that might affect
of the proposed gas conditioning facility
second round focused on assessing mitigation
their venture partners, the Proponents had both:
and management measures to mitigate the
• a formal process (i.e., meetings of
concept;
• the drilling waste disposal method; and
effects of the project. During both rounds,
development field partners every two weeks
• the use of drilling sumps.
meetings were held in potentially affected
to discuss matters related to consultation
Shell submitted that information arising
communities to seek input on identifying
and regulatory affairs to ensure a common
from these discussions was used to develop
possible impacts. These meetings were followed
understanding of the issues they are each
and refine its plans. Design changes for the
by workshops in regional centres. All of these
facing); and
Niglintgak field that resulted from community
meetings and workshops helped the Proponents
• an informal process (i.e., development field
identify potential impacts associated with the
partners working with the Proponents’
Mackenzie Gas Project for which mitigation
regional staff to ensure they are informed
measures had to be considered. A number
about each other’s activities and any matters
of changes were made to the project design
that have come up in their meetings).
as a result of this input.
consultations included:
• reducing the development footprint by
locating drilling sites at pre-disturbed
locations and using above ground flow lines;
• reducing the draught of the proposed
Shell – Niglintgak
barge-mounted gas conditioning facility,
The Proponents submitted that, while all
Shell stated that working with stakeholders is
moving the barge set down location outside
suggested mitigation measures were considered,
a key principle in its commitment to sustainable
the Little Kumak Channel, and committing to
not all were adopted. The Proponents must
development, and that it developed a
schedule dredging activities to avoid impacts
also consider other factors including technical
coordinated consultation plan for all of its
to the beluga whale harvest;
feasibility, safety and cost in determining which
activities in the Mackenzie Delta. For the
mitigation measures to adopt. In this way, the
Niglintgak field, Shell submitted that emphasis
to transport drilling waste to a waste
Proponents have stated that mitigation measures
had been placed on consultation, and concerns
management facility outside of the Northwest
are considered within a sustainability framework.
raised in these discussions were considered
while preparing the Niglintgak Development
1249_NEB_MGP_Vol2_Text_ENG.indd 199
• eliminating the remote sump and committing
Territories; and
• scheduling most of Shell’s activities during
Plan Application and subsequent filings.
winter months when wildlife is less abundant
Stakeholder input helped Shell focus on specific
in the area.
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200 Mackenzie Gas Project • Volume 2: Implementing the decision
Shell committed to ongoing consultation with
ConocoPhillips – Parsons Lake
ConocoPhillips committed to conducting
stakeholders and interested parties.
ConocoPhillips stated that responsible business
consultation in a manner that is consistent with
involves listening and responding to the needs of
its Stakeholders Relations Policy, by providing
its stakeholders. ConocoPhillips said it consulted
stakeholders with project information, and
throughout the evolution of the Development
listening to and considering their input,
Plan for Parsons Lake and concerns raised
throughout the life of the development.
Imperial – Taglu
Imperial’s consultation activities for the Taglu
field development were, for the most part,
integrated into the Proponents’ consultation
program. Imperial’s participation in Mackenzie
Gas Project consultation activities included:
preparing the Development Plan Application.
9.2.4 Consultation with government
ConocoPhillips met with Aboriginal and
Representatives from territorial and federal
• developing printed material and brochures;
non-Aboriginal Northerners; municipal, territorial
agencies were invited by the Proponents to
• exchanging information at workshops;
and federal representatives; communities;
participate in Mackenzie Gas Project workshops
• public meetings and open houses;
regulators and agencies; and other oil and gas
specific to the Environmental Impact Statement
• seeking input from community
companies. ConocoPhillips further submitted
and open house activities related to the project.
representatives and regulators; and
that information from these discussions has
In addition, the Proponents held regular
• communicating with community leaders.
been used to develop and refine the plans for
meetings with territorial and federal government
Imperial submitted that many of the concerns
the Parsons Lake field development. Design
departments and agencies to provide activity
changes to the Parsons Lake field that resulted
updates, discuss emerging issues, and develop
from community consultations included:
plans to manage the issues and coordinate
region, were common to the Mackenzie
• in response to concerns that above ground
schedules for activities of interest to all parties.
Gathering System, the Mackenzie Valley
pipelines would negatively impact caribou
The Proponents also advised in evidence that
Pipeline, and the Taglu field. Specific concerns
migration patterns, changing the design
they kept the relevant government agencies
raised by stakeholders in the Beaufort Delta
of the lateral line from the north pad to be
apprised of any concerns raised that were
region included land disturbance and footprint
a buried line, and designing the flow lines
beyond the ability of the Proponents to address.
in Kendall Island Bird Sanctuary, and
from the south pad to be 2.2 metres above
the disposal of drilling waste. In response
ground to allow for the passage of caribou
to these concerns, Imperial proposed a number
and harvesters below;
raised at Mackenzie Gas Project public
meetings, particularly in the Beaufort Delta
of mitigation measures, including:
• use of a single well pad;
• staging materials and supplies offsite at an
existing disturbed area at Tununuk Point; and
• using a disposal well for drilling waste.
Imperial stated that consultation activities
for the Taglu field will continue throughout
1249_NEB_MGP_Vol2_Text_ENG.indd 200
by stakeholders were considered while
• reducing the size of the north and south pads;
• strapping together two required flare stacks
to minimize overall land required;
• utilizing two levels of lighting so that a lower
intensity lighting level is normally used, and
a higher intensity will only be used during
maintenance activities; and
• optimizing distance between wellbores
the construction, operation, abandonment,
to prevent coalescence of well permafrost
and reclamation phases.
thaw bulbs.
The Proponents also noted that the scope
of Crown involvement included:
• working with the Dehcho First Nations to
establish a pipeline study corridor, as specified
in the Interim Measures Land Withdrawal
Agreement between the Dehcho First Nations
and the Government of Canada;
• participating as observers in regional
Mackenzie Gas Project Environmental
Impact Statement workshops and in
non-governmental organization workshops;
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Chapter 9: Consultation 201
As set out in the Agreement, the Joint Review
the Joint Review Panel Report filed with us
the Inuvialuit Settlement Region, Gwich’in
Panel was required to conduct its review in a
for consideration in our decision.
Settlement Area, Sahtu Settlement Area and
manner that would promote and facilitate
Dehcho regions in the Northwest Territories
public participation, and ensure that the
9.4 Participation by parties
and with the Dene Tha’ in Northeastern
concerns of Aboriginal people and the general
in our hearing process
Alberta; and
public were taken into account in that process.
• corresponding with Aboriginal Leaders in
• announcing a Crown Consultation Unit
To fulfill this mandate, the Joint Review Panel
to facilitate and report to the National
held public hearings in the Northwest Territories
Energy Board on Crown consultation with
and Alberta. Persons or groups were allowed
Aboriginal Groups.
to participate fully in the Joint Review Panel’s
review process as intervenors, and the Joint
9.3 Participation by parties
Review Panel granted intervenor status to
in the Joint Review Panel
103 individuals, groups or organizations.
hearing process
Persons or groups who were not intervenors
were given other opportunities to participate
As discussed in Chapters 2 and 3, parties had
in the public hearings, and any individual, group
the opportunity to raise socio-economic and
or organization could file written comments at
environmental concerns in the Joint Review
any time throughout the review.
Panel hearings.
In order to ensure that its record is as complete
as possible about the potential impacts of a
project, and to ensure that these factors can
be considered in its final decision, the National
Energy Board relies on evidence provided in
accordance with the requirements of its
Filing Manual, and on its hearing process.
The National Energy Board encourages those
with an interest in a project to participate
in the hearing process in order to make the
National Energy Board aware of their views
and concerns. To facilitate participation,
we held community information sessions and
The Joint Review Panel held hearing sessions
pre-hearing conferences and had staff available
The overarching purpose of the Joint Review
between 14 February 2006 and 29 November
in the hearing room to assist parties.
Panel, as described in the Agreement for an
2007. The Joint Review Panel held a total of
Environmental Impact Review of the Mackenzie
115 days of hearings in 26 centres and northern
Our hearings for the Mackenzie Gas Project
Gas Project (Agreement), was to conduct an
communities. The Joint Review Panel heard
focused on safety, engineering and economic
Environmental Impact Review of the Mackenzie
directly from 558 presenters, either as
issues, but other matters were also heard
individuals or as representatives of groups or
including social, cultural and environmental
organizations. Matters presented to the Joint
issues and concerns. We heard directly from
the protection of the environment
Review Panel related primarily to the potential
people potentially affected by the project in the
from the significant adverse impacts
environmental, social and cultural impacts of
Mackenzie Delta and along the Mackenzie River,
of proposed developments, and to the
the project, but also included aspects related
in larger communities such as Yellowknife,
protection of the existing and future
to project design and construction, geohazards,
and in High Level, Alberta. Our hearing process
social, cultural and economic well-being
accidents, malfunctions and emergency
provided members of the public, governments,
of residents and communities.
response. These matters were addressed in
Aboriginal people and other interested parties
Gas Project, having regard to:
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202 Mackenzie Gas Project • Volume 2: Implementing the decision
with a number of opportunities to participate
evidence relating to the activities of the
9.5 Consideration of
in hearing sessions, and to provide input into the
Crown Consultation Unit. We also heard final
review of the project. Opportunities that were
Aboriginal concerns
argument directly from parties, with some
available included filing a letter of comment,
parties providing written final argument.
making an oral statement at a hearing session,
A range of views and concerns were expressed
providing written evidence, offering oral
by individuals, organizations, governments
testimony by elders and members of Aboriginal
and Aboriginal groups through our hearing.
groups, cross-examination of the Proponents
and other parties, and presenting final argument.
Given the importance of Aboriginal concerns
and considerations, this section discusses more
fully the concerns and issues raised by
Aboriginal groups.
Several parties raised a number of consultation-
9.5.1 Accommodation by the Proponents
related issues and requests with us. Alternatives
The List of Issues contained in the Hearing Order
A total of 129 individuals, groups and organiza-
North and Indian and Northern Affairs Canada
for our GH-1-2004 proceeding identified the
tions applied to be intervenors in our hearings.
recommended that we define ‘consultation’
adequacy of Aboriginal consultation as an issue
We also received eight letters of comment and
for the purposes of our conditions, and that
to be considered by us. Consultation efforts
21 requests to make oral statements. All of our
we adopt the definition of consultation
by the Proponents for the Mackenzie Gas
hearings were broadcast live by audio webcast-
described in Section 3 of the Mackenzie Valley
Project primarily involved Aboriginal people,
Resource Management Act. Environment
as members of communities, governments,
Canada requested that for conditions requiring
Aboriginal authorities, regulatory bodies, local
the Proponents to consult with Environment
businesses and as land claim beneficiaries.
Canada, that evidence of Environment Canada’s
The Proponents submitted detailed tables
level of satisfaction regarding consultation
and periodic updates summarizing all of their
We held public sessions of our hearings in
should be provided. The Government of Yukon
project-related consultation efforts, including
15 communities between 25 January and
requested that Condition 27 be amended so
the concerns that were raised during these
14 December 2006. Subsequent sessions were
that the plans for a formal issues resolution
consultations in the Inuvialuit, Gwich’in, Sahtu
also held in 2007 and 2010, including sessions
program would be prepared in consultation
and Dehcho regions and northern Alberta. Their
on the Proponents’ 2007 updated evidence and
with the Government of Yukon.
record of consultation highlighted the measures
ing, and were also available to participants via
a toll-free telephone service. Hearings were interpreted live, as appropriate, into English, French,
Inuvialuktun, Gwich’in, and the North Slavey,
South Slavey and Dene Tha’ languages.
that were taken, or will be taken, by the
Proponents to address the concerns raised
by Aboriginal groups as well as other affected
parties. The consultation record also indicated
how these concerns and the Proponents’
responses have influenced the design of the
Mackenzie Gas Project, and whether any
concerns remain outstanding. Examples of
the changes that have been made to the design
of the Mackenzie Gas Project by the Proponents
in response to concerns and community input
are listed in Table 9-1.
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12/6/10 11:02:52 AM
Chapter 9: Consultation 203
Table 9-1 Changes to project design
Changes in the Inuvialuit Settlement Region
• modifying the construction plan and schedule
near Storm Hills
• eliminating Storm Hills facility requirements
• reducing the number of borrow sites
• reducing the number of water sources
• relocating access roads
Some of the concerns raised by Aboriginal
The Gwich’in Tribal Council noted the
people were related specifically to the proposed
Mackenzie Gas Project will provide a range
general routing and the locations of proposed
of benefits to the Gwich’in, Northerners and
facilities. Details of these concerns, and the
other Canadians, including economic benefits,
measures proposed by the Proponents to
job creation, revenues and taxes to all levels of
address them, are found in Chapter 5.
government, and will help reinforce Canada’s
In addition to the Proponents’ specific measures
sovereignty in the North.
to address concerns raised by Aboriginal groups,
The Gwich’in Tribal Council encouraged
the Proponents noted that they have concluded
us to grant a Certificate for the Mackenzie
benefits and access agreements for the Inuvialuit
Gas Project, but requested that we review
Settlement Region and for the Gwich’in and
the Gwich’in Tribal Council’s comments on
Sahtu Settlement Areas. The Proponents noted
the Joint Review Panel recommendations, and
that such agreements have not been concluded
the concerns raised with the Joint Review Panel
for the Dehcho region, and stated they are
relating to environmental protection, cultural
Changes in the Sahtu Settlement Area
committed to concluding benefits and access
preservation, and economic development. Finally,
• withdrawing two borrow sites at Bear Rock
• reducing the number and size of borrow sites
• moving the Great Bear River compressor station
agreements for the Dehcho.
the Gwich’in Tribal Council recommended that
Changes in the Gwich’in Settlement Area
• moving the pipeline farther east of Travaillant Lake
• eliminating infrastructure requirements near
the Travaillant Lake–Thunder River Area
• reducing the number of borrow sites
• reducing the number of water sources
• relocating access roads
Changes in the Dehcho Region
• moving the Blackwater River compressor
station and associated infrastructure
• rerouting the pipeline near Wrigley and
Willowlake River
• moving the Willowlake River block valve site
• eliminating the Trail River compressor station
and associated all-weather road
• relocating the watercourse crossing
on the Mackenzie River upstream
• relocating the McGill station camp
and storage area
• rerouting the pipeline near Satellite Lake
• relocating the Trout River heater station
• withdrawing a borrow site in Shihndaakaa Tselaa
• rerouting the pipeline and relocating the camp
at Trainor (K’eotsee) Lake
• using an existing cutline as access to Trainor
(K’eotsee) Lake
9.5.2 Concerns raised in our hearing
the Proponents be required to commence project
construction within three years of receiving a
A number of Aboriginal groups and
Certificate, and that the Mackenzie Gas Project
organizations presented their views and
be available on appropriate commercial terms
concerns directly to us during our hearing.
to all potential shippers.
Gwich’in Tribal Council
Inuvialuit Regional Corporation
The Gwich’in Tribal Council stated that the
Ms. Nellie Cournoyea, Chair and Chief Executive
Mackenzie Gas Project can contribute to a
Officer of the Inuvialuit Regional Corporation
sustainable economy in the North, and provide
stated that throughout the public hearings
a greater and fulfilling role for the Aboriginal
of the National Energy Board and the Joint
peoples of the Dehcho, Sahtu and Mackenzie
Review Panel:
Delta regions. Gwich’in Tribal Council President
Richard Nerysoo stated that:
the Inuvialuit Regional Corporation has
been consistent in its recognition of the
the Gwich’in Tribal Council supports
extensive economic opportunities this
the Mackenzie Gas Project as a means
project would provide to not only the
to enable the Gwich’in to become
Inuvialuit and other residents of the
self-sufficient and full participating
Beaufort Delta, but also to the residents
members in a global society.
of other regions along the pipeline route,
and Canadians in general.
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204 Mackenzie Gas Project • Volume 2: Implementing the decision
The Inuvialuit Regional Corporation noted that
is the first step to regaining economic self-
Those issues raised by Dehcho communities
economic opportunity is limited in Beaufort
sufficiency for the regions. He stated that:
relating to socio-economic and environmental
Delta communities, and the Inuvialuit want
to be self-reliant and enjoy the benefits of
a thriving and sustainable economic base.
The Inuvialuit Regional Corporation stated the
Mackenzie Gas Project and ongoing exploration
and development would provide such economic
opportunity to Beaufort Delta communities
and other regions. Ms. Cournoyea also noted:
I don’t believe it’s in the Canadian interest
concerns are addressed in Chapter 3.
economy, like your own sons and
Agreements and settlements
daughters. They need quality education,
Concerns were raised by the Dehcho Elders
training and meaningful employment and
and Harvesters Councils and the Dehcho First
business opportunities. The Aboriginal
Nations regarding the status of key settlements
Pipeline Group is supporting this project
and agreements for the Dehcho Region.
to make sure they have those
On behalf of the Dehcho Elders and Harvesters
opportunities.
Councils, Mr. Herb Norwegian noted that:
North Slave Métis Alliance
unlike other regions in the Northwest
The North Slave Métis Alliance stated they
Territories affected by this project,
were not identified as an Aboriginal group for
the Dehcho Dene have not resolved our
consultation in the Proponents’ Environmental
outstanding land and self-government
in the absence of a land claim settlement
Impact Statement, that they should have been
relationships with Canada.
for the Dehcho region. The Inuvialuit Regional
included in the Proponents’ list of non-corridor
Corporation encouraged us to include in
communities, and that consultation by the
our approval terms that would direct the
Proponents was not adequate.
federal government to support ongoing
Dehcho communities
planning processes in the Beaufort region
The Dehcho Elders and Harvesters Councils,
through the release of the Mackenzie Gas
Dehcho First Nations, the Sambaa K’e Dene
Project Impacts Fund.
Band and the Liidlii Kue First Nation raised a
Mackenzie Valley Aboriginal Pipeline
number of unresolved concerns about the
Limited Partnership
project in their submissions to us. Some concerns
The Dehcho Elders and Harvesters Councils also
The Mackenzie Valley Aboriginal Pipeline Limited
were raised by more than one group from
expressed their disappointment and frustration
Partnership (otherwise known as the Aboriginal
the Dehcho region, while other concerns were
with the Government of Canada and the
Pipeline Group), representing the one-third
unique to the interests of specific communities.
Government of the Northwest Territories for
Overall, the concerns encompassed several broad
delay in adopting the Dehcho Land Use Plan,
issues related to the potential impacts and
which was ratified by the Dehcho First Nations
benefits arising from the approval, construction
in 2006. The Dehcho Elders and Harvesters
and operation of the Mackenzie Gas Project.
Councils stated that the land use plan is
that one group, or part of one group,
can hold up the economic opportunities
of a lot of other people…
Aboriginal ownership interest in the project,
also expressed its support for the Mackenzie
Gas Project. Mr. Fred Carmichael, Chair of the
Mackenzie Valley Aboriginal Pipeline Limited
Partnership noted the Mackenzie Gas Project
1249_NEB_MGP_Vol2_Text_ENG.indd 204
our youth are dependent on a wage
Mr. Norwegian further stated that:
the conclusion of the Dehcho Process
with a final agreement would provide the
Dehcho Dene with a clear and necessary
authority to ensure that this project could
only proceed in a manner acceptable
to us and with our full involvement.
an expression of the values and aspirations
12/6/10 11:02:52 AM
Chapter 9: Consultation 205
of the Dehcho Dene, and they have placed
Dehcho First Nations stated that the Proponents’
North Slave Métis Alliance about the adequacy
a high priority on the formal adoption
efforts were inadequate, and that many regional
of Crown consultation for the project. The
and implementation of the land use plan.
and community concerns about the project
Dehcho First Nations stated that Canada’s
remain unaddressed. Dehcho First Nations
consultation efforts were inadequate, and
Grand Chief Samuel Gargan expressed concern
that Canada’s evidence submitted to us
that the Proponents were “frequently referring
failed to acknowledge the submissions and
us to subsequent regulatory processes rather
recommendations made to the Joint Review
than directly dealing with us to resolve these
Panel by the Dehcho First Nations.
The Dehcho Elders and Harvesters Councils
and the Dehcho First Nations stated that they
cannot support the approval of the Mackenzie
Gas Project without a land use plan in place
for the Dehcho Region, and recommended
that access for construction in the Dehcho
territory be delayed until the Dehcho Process
issues” such as consultation regarding future
block valve locations.
The Sambaa K’e Dene Band stated Canada
did not fulfill its legal obligation to consult
has been concluded and the Dehcho Land
The Sambaa K’e Dene Band stated that the
with the intent of finding accommodation,
Use Plan has been implemented. This view
Proponents did not respect the Sambaa K’e
including compensation for the infringement of
was supported by the Sambaa K’e Dene Band.
Dene Band’s stated preference to independently
Section 35 rights and interests on Crown lands.
The Dehcho Elders and Harvesters Councils
negotiate an area-specific impact benefit
The Sambaa K’e Dene Band recommended that
further recommended that the project not
agreement, and expressed concern that
we not issue a Certificate for the project until
proceed to construction until the Proponents
the Proponents avoided their consultation
Canada has concluded its consult to modify
have concluded an Access Agreement
obligations within the National Energy
process in relation to the Joint Review Panel
and a Benefits Agreement for the Dehcho
Board’s regulatory process.
recommendations, particularly with respect
communities. The Dehcho First Nations noted
that the Proponents’ updated project schedule
indicated that a decision to construct the project
would be made in approximately 2013. Dehcho
First Nations Grand Chief Samuel Gargan noted
In response, the Proponents noted that, as a
consequence of consultation, many changes
were made to the design of the Mackenzie
Gas Project in the Dehcho region. The
to Section 35 issues, and has concluded
the process of substantive consultation with
the Sambaa K’e Dene Band to accommodate
outstanding rights issues.
Proponents also noted consultation did not
The North Slave Métis Alliance stated that
lead to agreement in every case, and that
it should be consulted regarding the Mackenzie
three and half years between now
some remaining issues can only be addressed
Gas Project, and that the North Slave Métis
and then is more than what is needed
at the permitting stage, following the collection
Alliance was not adequately consulted
to conclude the Dehcho Process, have
of additional information. Finally, the Proponents
by the Crown.
a final land use plan in place and resolve
affirmed that consultation for the project will
other outstanding matters.
continue, and the Proponents will continue to
that, in the Dehcho First Nations’ view:
Consultation by the Proponents
strive to address outstanding concerns.
Dene Tha’
We held a hearing session in High Level, Alberta
on 27 September 2006 to hear concerns
The Sambaa K’e Dene Band and the Dehcho
Adequacy of Crown consultation
from Northern Alberta communities. Although
First Nations raised concerns regarding the
Concerns were raised by the Dehcho First
the Dene Tha’ registered as an intervenor
adequacy of the Proponents’ consultation. The
Nations, the Sambaa K’e Dene Band and the
and filed evidence, they did not participate
1249_NEB_MGP_Vol2_Text_ENG.indd 205
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206 Mackenzie Gas Project • Volume 2: Implementing the decision
in this session or our other hearing sessions.
documented more than 1,500 meetings,
concerns have been addressed. With respect
In November 2006 the Dene Tha’ First Nation
described the concerns that were raised
to defining consultation in our conditions,
entered into a Settlement Agreement with
over years of consultation, and provided
we consider the recommendation by
Canada as settlement of litigation in relation to
details on how they have already or will
Alternatives North and Indian and Northern
the project. In that agreement Canada would
address the concerns they heard. The
Affairs Canada to be helpful. The definition
provide $25,000,000 to the Dene Tha’ First
Proponents responded to the concerns
of consultation contained in Section 3 of
Nation to, among other things, assist the Dene
and input they received through their
the Mackenzie Valley Resource Manage-
Tha’ First Nation in addressing the socio-eco-
consultations with numerous changes to the
ment Act is broadly consistent with the full
nomic impacts associated with the project.
design of the project, and through a range
guidance we provide to all applicants and
of commitments in the Socio-Economic
regulated companies in our Filing Manual.
Views of the Board
Agreement. They have committed to
A preamble that defines consultation has
The Proponents’ consultation program
continuing consultation throughout
therefore been included in our conditions.
When an application is filed, the National
the life of the Mackenzie Gas Project.
Regarding Environment Canada’s request
Energy Board’s Filing Manual requires
companies to demonstrate that they have
identified, contacted and consulted with
potentially affected groups and individuals
prior to filing their application. Companies
must learn about the concerns of people,
and attempt to address those concerns to
the fullest extent possible. They are also
expected to continue their discussions with
those who will be affected by their project
as the regulatory process unfolds, and
during the construction and operation
phases of their project. The project application must contain detailed information on
all aspects of company’s consultation work,
1249_NEB_MGP_Vol2_Text_ENG.indd 206
that evidence of their level of satisfaction
We find that the Proponents designed
and implemented an effective consultation
for consultation be provided, we note
that all interested and affected parties
program for the Mackenzie Gas Project. We
may contact us at any time regarding the
accept that agreement on how to address
Proponents’ activities, and we would give
concerns that were raised was not possible
appropriate consideration to any submission
in all instances, and we are confident
as it is received. In response to the Govern-
that some remaining issues will be further
ment of Yukon’s request, we have amended
addressed by other regulatory institutions,
Condition 27 so that the Government of
federal departments and Aboriginal
Yukon will be included in consultations
authorities at the permitting stage. In
for the preparation of plans for a formal
this regard, we will continue to work
issues resolution program.
cooperatively with and support northern
institutions and federal departments
throughout subsequent approval phases.
Potential impacts of the project
We rely on those with an interest in a
project to participate in our hearing
including a description of any unresolved
Where our own conditions require further
process, so that we can hear directly from
issues or concerns.
consultation by the Proponents, or require
them and consider their views and concerns.
The Proponents provided extensive details
the Proponents to provide the National
We also encourage all those who might
of their consultations with those groups,
Energy Board with evidence of consultation,
be affected by a project to engage early in
individuals, organizations, governments
the National Energy Board will continue to
the project planning and assessment stages
and Aboriginal people that will be affected
evaluate the appropriateness and effective-
with proponents, so that they may work
by the Mackenzie Gas Project. They
ness of their efforts, including how any
collaboratively to address any interests
12/6/10 11:02:52 AM
Chapter 9: Consultation 207
and concerns, including concerns related
to construction for the Proponents and
Through this process, as also discussed in
to the potential impacts of a project.
Dehcho organizations and communities
section 1.3 of Volume 1, and the Board’s
to make progress toward concluding any
assessment of the information it has
additional agreements, such as access and
received throughout, we have determined
benefits agreements, to address remaining
that our decision is consistent with section
mutual interests and concerns.
35 of the Constitution Act, 1982.
We heard directly from a number of parties
about the potential impacts and benefits
of the Mackenzie Gas Project, including
the views and concerns of people in the
Inuvialuit, Gwich’in, Sahtu and Dehcho
Through their commitments and
regions. The Dehcho organizations and
adjustments to the project, the Proponents
communities told us they would prefer that
have addressed many, but not all, of the
approval of the project be delayed until
concerns raised with them. We were also
their land claim is settled, and their land
made aware of unresolved concerns during
use plan has been implemented. But we
our hearing and through the Joint Review
also heard about the social and economic
Panel Report, including the specific concerns
aspirations of the people in the Inuvialuit,
raised by Aboriginal groups.
Gwich’in and Sahtu regions, and the
Throughout its hearing process, the
benefits the Mackenzie Gas Project would
National Energy Board requires an applicant
bring to them. As Gwich’in Tribal Council
to consult with Aboriginal groups in order
President Richard Nerysoo told us, the
to determine their concerns, and to attempt
Mackenzie Gas Project will “enable the
to address them to the extent possible. If
Gwich’in to become self-sufficient and full
there are concerns that remain unaddressed
participating members in a global society”.
after consultation, the National Energy
From the Government of the Northwest
Board can impose conditions to address
Territories, we also heard that the project
them. In our hearing, we considered
will allow the residents of the North to
the concerns of Aboriginal people
move toward economic self-sufficiency.
when making our decision, and our
We are encouraged by Grand Chief
Gargan’s view that sufficient time is
available before the project is constructed
to make concrete progress on, and perhaps
to finalize, a land claim agreement for the
Dehcho Region, and to implement a Dehcho
land use plan. We are further encouraged
conditions address these concerns. With
the Proponents’ measures and commitments, and the requirements contained
in our conditions, we believe the
concerns raised by parties and Aboriginal
groups have been or will be adequately
addressed, and identified impacts will
be effectively mitigated.
that sufficient opportunity would also
be available before the project proceeds
1249_NEB_MGP_Vol2_Text_ENG.indd 207
12/6/10 11:02:52 AM
Chapter 10
National Energy Board
lifespan regulation
The National Energy Board is committed to doing all it can in overseeing every stage of this project,
if it is built. This means that the National Energy Board will to see to it that the Proponents keep
their promises and that all conditions attached to the approvals will be implemented. If people of
the Northwest Territories have any concerns with the project, the National Energy Board will be
there to resolve those concerns. The National Energy Board will be there to inspect, audit and work
in collaboration with Northern agencies while the pipeline is operated and will still be there many
years from now when the pipeline needs to be abandoned. Abandonment will be approved when
it can be done safely while protecting the environment.
If people have concerns throughout the life
10.1 Regulation under the
of the project, and cannot resolve a matter
National Energy Board Act
directly with the company, they can speak
to a National Energy Board inspector or call toll
The National Energy Board is responsible for
free, 1-800-899-1265. Regulatory documents
assessing applications for pipeline projects to
including those filed as a result of National
determine if they are in the public interest. If a
Energy Board conditions can be found on
project is approved, the National Energy Board
the National Energy Board’s website at:
then regulates it throughout its entire lifespan,
www.neb-one.gc.ca. On the right side of
from the application phase, through
the page under the heading “Regulatory
construction and operation, and finally to
Documents” click on “View”.
the abandonment phase (see Figure 10-1).
Details on the National Energy Board’s lifespan
The primary tools used by the National Energy
approach to regulation follow.
Board to regulate the over 71,000 kilometres of
pipeline within its jurisdiction are the Onshore
Pipeline Regulations, 1999, the National Energy
Board Processing Plant Regulations; the National
Energy Board Pipeline Crossing Regulations
Part I and Part II; the Toll Information
1249_NEB_MGP_Vol2_Text_ENG.indd 208
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Chapter 10: National Energy Board lifespan regulation 209
Regulations, and the Gas Pipeline Uniform
Accounting Regulations or Oil Pipeline Uniform
Accounting Regulations. These regulations
require that a number of programs, plans and
manuals be established and information be
provided. As part of its overall responsibility for
regulating energy facilities the National Energy
Board also:
10.1.1 The application stage
National Energy Board. The company must meet
all of the conditions set by the National Energy
Applications for major projects are generally
heard by way of oral public hearing. This allows
• restrictions on the timing of construction;
the company proposing the project, and any
• imposing measures which limit impacts
other interested people or groups, a chance
on the land;
to provide information on the project and to
provide input in support of or against a project.
A hearing gives all of the people interested in a
• issues safety advisories;
• conducts inquiries or formal investigations
Board. Some examples of conditions include:
project an opportunity to provide evidence, ask
• requiring a noise level report;
• conducting a rare plant study; and
• requiring the filing of a joining program.
or answer questions and express their point of
During the hearing, the National Energy Board
view on the project. It also provides the National
considers all information that is relevant to
Energy Board with the information needed to
the question of whether or not the application
make a fair and objective decision.
should be approved.
When assessing an application the National
10.1.2 Monitoring and enforcement
In addition to the regulations, the National
Energy Board considers what additional
Pre-construction and construction
Energy Board’s Filing Manual provides guidance
measures should be required of a company
If the National Energy Board approves a project,
to companies on what information must be
during construction and operation of the project
its oversight is directed toward ensuring that the
filed in a project application and in financial
if it were to be approved. These measures
project is built in compliance with regulations
surveillance reports.
become conditions to an approval issued by the
and the conditions that were placed on the
into safety issues;
• addresses landowner complaints;
• inspects; and
• conducts financial, safety, environment
and security audits.
Decision to
construct
Typical
company
activities
NEB role
1249_NEB_MGP_Vol2_Text_ENG.indd 209
Begin
operation
End
operation
Scope and feasibility
Conceptual design
General route
Public engagement
Environmental
Impact Assessment
Preliminary design
Finalize route
Make applications
& attend hearing
Early land
acquisition
Finalize design
Obtain right of way
Place orders
Hire contractors
Detailed route
hearings
Construct pipeline
Comply with
codes &
commitments
Quality assurance
& quality control
Pressure test
Line fill
Pigging
Acceptance testing
of all equipment
Manuals & training
Operate facility
Maintenance, repair
Surveillance
Training
Incident response
Reporting
Project design
Regulatory
approval
Final design
Construction
Commissioning
Operation and
modification
Decommissioning
Filing guidelines
Public Hearing:
- Certificate with
conditions, or
- denial
Design &
Environmental
Protection Plan
approval
Compliance
Inspections
Leave to open
Inspections, audits
Integrity program
Crossings
Complaints
Public hearing
Figure 10-1
Regulation by the
National Energy Board
Remove surface
equipment
Isolate or remove
pipeline
Reclamation
throughout a project’s
lifespan
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210 Mackenzie Gas Project • Volume 2: Implementing the decision
approval. Conditions of approval are projectspecific and based on the hearing’s evidentiary
record and the experience of the National
Energy Board in dealing with pipeline matters.
The company is obligated to follow through
with all of these conditions and the National
Energy Board makes sure it does through
various means including the review of submitted
the specific construction spread at hand.
Inspection Officers appointed under the National
Energy Board Act can also issue an order where
work in collaboration with other regulators
there are reasonable grounds to believe that a
to ensure that there are no regulatory gaps
hazard to the safety of the public or employees
and to minimize regulatory overlap.
of a company, or a detriment to property or
from another party the nature of that input is
the National Energy Board include:
specified in the conditions and regulations.
• verifying compliance with, and
The company is expected to confirm that this
assessing the effectiveness of, mitigation
input has been received and incorporated as
measures, conditions, and environmental
appropriate. The company’s submissions and the
protection plans;
During the construction stage, the National
Energy Board conducts inspections to verify
that approved facilities meet the requirements
was achieved.
and above-ground facility locations. Inspectors
Inspections and monitoring activities by
are accessible from the regulatory repository.
company must later confirm that compliance
Inspections are focused on the right of way
plans, reports, and manuals. If input is required
correspondence of the National Energy Board
• verifying compliance with the appropriate
standards and regulations; and
• monitoring construction and operations,
the environment, is being or will be caused
by the construction, operation, maintenance
or abandonment of a pipeline. The order may
direct the company to undertake certain work
or stop its construction until that work has been
completed. These orders may be converted into
court orders to be enforced in the same manner
as an order of that court if the company does
not comply.
including verifying construction
Public concerns can vary throughout the
progress reports.
different stages of a project’s life. For example,
of the Acts, regulations, and conditions
If inspectors find that the company is not
a potential environmental issue may be noticed
associated with approvals. National Energy
meeting the conditions or the regulations,
first by people in the vicinity of the facilities.
Board inspectors document the results of
the National Energy Board takes action to
People who have concerns with a pipeline
the inspections, follow-up on outstanding
enforce them.
project may contact the National Energy Board
issues, and provide feedback on observations
in the field.
The National Energy Board enforces safety and
environmental commitments and requirements.
at any time for information on how to work
through their concerns with the company.
The National Energy Board provides various
The frequency and type of inspections depend
If we find a company is not meeting its commit-
on several factors, including the:
ments and requirements we immediately ask
• complexity of the project;
the company to voluntarily correct the situation.
• safety and environmental issues identified
If a situation cannot be corrected immediately,
The National Energy Board’s Complaint
during the application and the construction
or if additional information is required from a
Resolution Program and the Appropriate
phase;
company, the National Energy Board’s Inspection
Dispute Resolution process are options for
Officers may ask for a written assurance of
resolving outstanding issues. Appropriate
voluntary compliance from the company. The
Dispute Resolution could take the form of
• observed compliance history of the company;
and
1249_NEB_MGP_Vol2_Text_ENG.indd 210
• the performance of the company on
ways that these concerns can be brought
forward for resolution.
12/6/10 11:02:57 AM
Chapter 10: National Energy Board lifespan regulation 211
a meeting between a concerned person and
measures. This is usually done using inspections
The National Energy Board is as accessible
the company, which may be facilitated by
in the field as well as reviewing reports
to the public during operations activities
our National Energy Board staff or by another
submitted by the company.
as it is during construction, and will follow
neutral third party. During construction, National
Energy Board staff is often out in the field
inspecting the project and can be contacted
directly. As well, the National Energy Board can
be contacted by phone, mail, fax or e-mail.
Operations
Requirements for companies operating National
Energy Board regulated pipelines are set out in
the Onshore Pipeline Regulations, 1999. As
mentioned previously, specific programs, plans
After completion of construction, the National
and manuals are required under these regula-
Energy Board will continue to monitor the right
tions. For example, creating and implementing
of way to verify the ongoing success of
a Monitoring and Surveillance Program and
environmental and geotechnical mitigation
an Integrity Management Program are mandatory requirements of the Onshore Pipeline
Did you know?
Regulations, 1999.
Physical monitoring and surveillance program
Monitoring activities by National Energy Board
A monitoring and surveillance program consists of
staff during the operations phase include:
two parts. The monitoring is aimed at identifying any
up on any issues that are brought forward.
10.1.3 Abandonment
When a facility under the National Energy
Board’s jurisdiction comes to the end of its useful
life the company must apply for permission to
abandon it. A public hearing is required for an
abandonment application. This gives the public
an opportunity to express their views about
whether the proposed abandonment procedures
would provide for adequate safety and
protection of the environment. Before allowing
the abandonment to proceed the National
Energy Board must be satisfied that the
issues or potential concerns that may compromise
• inspections of the facilities and right of way;
abandonment will be carried out in a way
the pipeline, property, persons and the environment
• conducting management system audits to
that is safe, protects property and protects the
(e.g., pipeline integrity or erosion, and security).
It may include methods for developing measures
verify that National Energy Board regulatory
to prevent or mitigate the impact of the identified
requirements have been and will continue
issue(s). The program may also dictate:
to be met;
• follow-up monitoring of sites where mitigative
measures have been undertaken, in order to
determine their success or failure;
• a system for implementing additional mitigative
measures as needed; and
• a feedback system that allows for successful
mitigation to be adapted to future pipeline projects.
• assessment of safety practices and procedures
under the National Energy Board mandate
environment. The National Energy Board expects
that companies will discuss abandonment plans
with landowners to ensure that concerns are
dealt with at the planning stage.
as well as through the Canada Labour Code
In order to abandon a facility the company
Part II on behalf of Human Resources Skills
must comply with all regulations and conditions
Development Canada;
imposed by the National Energy Board.
• review and assessment of a company’s
Abandonment procedures typically involve
The surveillance component of the monitoring
integrity management and environmental
the removal of surface installations and the
program focuses on the company’s activities, its
protection programs;
restoration of the land. Buried pipe may either
contractors or the public. For example, ensuring that
contractors adhere to the environmental requirements of a task, that encroachments upon
rights-of-way are detected, and that adjacent
construction activities are known. A monitoring and
surveillance program can include aerial patrols, in-line
inspection, soil-to-pipe surveys, erosion monitoring,
• conducting financial audits to verify compli-
be removed or left in place, depending on the
ance with financial regulations and other
best way of addressing safety and environmental
National Energy Board requirements; and
concerns. The procedures are different for each
• review of financial surveillance reports
abandonment depending on the location of
and annual filings.
and slope stability monitoring. Relevant environmental practices such as those for managing materials
storage and waste, monitoring air quality and water
quality can all be contained within the monitoring
and surveillance program.
1249_NEB_MGP_Vol2_Text_ENG.indd 211
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212 Mackenzie Gas Project • Volume 2: Implementing the decision
the facility, the operating history of the facility,
to consider the financial issues related to
and the future uses proposed for the land. The
pipeline abandonment. As a result, all pipeline
company’s abandonment plan would typically
companies regulated under the National Energy
address key issues that relate to public safety,
Board Act will be required to file, for approval,
choice between them can depend on the nature of the activity being regulated.
environmental protection, and future land use.
a proposed process and mechanism to set aside
Prescriptive regulation works well to set compulsory requirements, such as design
These include:
funds for abandonment. Pipeline companies are
or the reporting of incidents where, regardless of the circumstances or the location
• land use management;
expected to demonstrate to the National Energy
regulation is its inflexibility. It can block the introduction of innovative new ideas
• ground settling;
Board how the mechanism they have chosen
and technology and can be insensitive to unique or changing circumstances.
• soil and groundwater contamination;
meets the goal of ensuring that adequate
Goal-based regulation allows the company to adapt required programs and manuals
• pipe cleanliness;
funds will be set aside to cover all pipeline
to suit its business and the environment in which it operates. It also encourages
• water crossings;
abandonment activities. Since the Mackenzie
• soil erosion;
Valley Pipeline was applied for pursuant to the
• utility and pipeline crossings;
National Energy Board Act, these requirements
• creation of water conduits, where water
would automatically apply to it.
Did you know?
Goal-oriented regulation
Methods of regulation are often characterized as either prescriptive or goal-based.
Both methods have strengths and weaknesses and both are in common use. The
of the facilities, the requirements should not vary. The main weakness of prescriptive
innovation and can lead to safer systems. Weaknesses include higher costs to
enforce and the potential lack of transparency to the public.
The National Energy Board has taken the best from both methods and called it
goal-oriented regulation. Prescription is used when compulsory means of compliance
are desired. Goals are used when circumstances can differ greatly among the
regulated companies or where superior outcomes are likely to be achieved through
innovation or new technology. For example, the National Energy Board’s Onshore
Pipeline Regulations, 1999 rely on CSA Standard Z662 – Oil and Gas Pipeline Systems,
in which most of the technical requirements are set out in prescriptive terms. Specific
travels through the pipeline; and
• related pipeline equipment (e.g. risers,
valves, piping, etc.).
The Mackenzie Gathering System was applied
for pursuant to the Canada Oil and Gas
Operations Act rather than under the National
programs, manuals and plans must be in place but the content of these documents is
When the National Energy Board is satisfied with
Energy Board Act. Our Condition 4 in the
guided by goals. The National Energy Board evaluates the company’s compliance with
what the company has done, the abandonment
Miscellaneous Order for Mackenzie Gathering
regulations using audits and inspections.
order takes effect. At this point the facility is
System Tolls (Appendix N) requires that, at least
considered abandoned and is no longer under
18 months prior to the Mackenzie Gathering
the jurisdiction of the National Energy Board.
System being placed in service, the Proponents
Prescriptive
Goal-oriented
Goal-based
To guide the development of abandonment
plans, the National Energy Board has several
proposed principles for the end state of land,
What to do
and how to do it
Best of
both methods
What result
is required
as shown in Table 10-1.
must prepare and file for approval, an estimate
of abandonment costs, a proposal for the
collection of funds and a proposed process
and mechanism to set aside the funds.
The requirements are therefore the same
In January 2008 as part of its Land Matters
for both the Mackenzie Gathering System
Consultative Initiative, the National Energy
and the Mackenzie Valley Pipeline.
Board convened a public hearing, RH-2-2008,
1249_NEB_MGP_Vol2_Text_ENG.indd 212
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Chapter 10: National Energy Board lifespan regulation 213
10.2 Economic regulation
Table 10-1
Principles for the end state of land post-retirement
Once a pipeline is approved, the National Energy
Board regulates the tolls and rules for transpor-
Concern
Principle
Responsibility
Facility owners and operators are responsible for the retirement of facilities
and reclamation of the right of way as well as any liabilities arising from those
facilities post-retirement.
Retirement and
reclamation planning
Persons and groups potentially affected by the retirement of facilities are invited
to be involved in the development of retirement and reclamation plans specific
to those facilities.
income and other taxes. Tolls can be set for a
A retirement and reclamation plan deals with the retired facility in such a manner
that the risk to public safety, property and the environment is at a level that is
acceptable in the public interest, with the agreement of affected parties where
possible, but ultimately as determined by the Board.
Energy Board adjudicates and sets tolls when
Consideration is given to reuse and recycling of facilities in identifying
retirement options.
negotiated settlement. However, the existence
Retirement and reclamation returns the right of way to a state comparable with
the surrounding environment. Facility owners and operators should accommodate
the desired land use of those who are affected when it is reasonable to do so.
authority of the National Energy Board. The
In natural environment areas, or where rare or sensitive native plant species
and communities are present, reclamation promotes the eventual re-establishment
of habitat quality on lands affected by right-of-way development to as native
a state as is consistent with the current and surrounding land use.
tolls are just and reasonable before it will accept
Measuring the performance of retirement and reclamation plans is required
to facilitate continual improvement and to assess effectiveness.
may be filed with the National Energy Board.
End state of land
Performance
measurement
tation on the pipeline. Some of the costs that
can be included in tolls include operating
expenses, depreciation, return on capital, and
year or for multi-year periods. The National
there is a disagreement between shippers
and the pipeline company, or it can accept a
of a negotiated settlement does not limit the
National Energy Board will determine that the
them. At any time, applications and complaints
about tolls, tariffs and access to the pipeline
The National Energy Board’s Gas Pipeline
Uniform Accounting Regulations and Oil Pipeline
Uniform Accounting Regulations establish
a uniform system of accounts for Group 1
companies. Group 1 companies are required
to file a surveillance report four times a year,
on the basis of the Toll Information Regulations.
These reports provide details of financial
performance and explain any significant
variations from approved amounts. The National
Energy Board will audit a pipeline company’s
records to verify the accuracy of filed documents
and compliance with the National Energy Board’s
decisions, regulations and other directives.
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214 Mackenzie Gas Project • Volume 2: Implementing the decision
10.3 Regulation, monitoring and
An authorization under paragraph 5(1)(b)
enforcement under the Canada
of the Canada Oil and Gas Operations Act is
Operations Act and its regulations,
Oil and Gas Operations Act
required for work and activities in relation to
which promote, for the exploration for
a Development Plan which may include drilling,
and exploitation of oil and gas:
The Mackenzie Gathering System, including
well completions, facilities construction,
–– safety, particularly by encouraging persons
gathering pipelines upstream of the Inuvik Area
production operations, and decommissioning.
exploring for and exploiting oil and gas
Facility, the Inuvik Area Facility and the natural
In accordance with section 6 of the Canada Oil
to maintain a prudent regime for
gas liquids pipeline, has been applied for under
and Gas Drilling and Production Regulations,
• complies with the Canada Oil and Gas
achieving safety;
paragraph 5(1)(b) of the Canada Oil and Gas
an application for an authorization under
–– protection of the environment;
Operations Act. By use of conditions these
paragraph 5(1)(b) of the Canada Oil and Gas
–– conservation of oil and gas resources;
facilities would be regulated in a manner that
Operations Act should contain the following:
–– joint production arrangements; and
is similar to regulation of the Mackenzie Valley
• a description of the scope of activities;
–– economically efficient infrastructures.
Pipeline under the National Energy Board Act.
• an environmental protection plan;
The National Energy Board would regulate
• a safety plan; and
the tolls and rules on the Mackenzie Gathering
• a contingency plan.
System under the Canada Oil and Gas Operations
Depending on the work or activity, the
environmental review of the proposed
paragraph 5(1)(b) work or activity may be
Act with toll and tariff legislation that is very
In accordance with section 5 of the Canada Oil
coordinated with other appropriate regulatory
similar to the National Energy Board Act.
and Gas Drilling and Production Regulations, an
bodies. A National Energy Board authorization
applicant for an authorization under paragraph
under paragraph 5(1)(b) of the Canada Oil
5(1)(b) is required to develop an effective
and Gas Operations Act would include any
management system that includes processes
appropriate terms and conditions.
for setting goals for the improvement of safety,
In order to drill, re-enter, work over, complete
environmental protection and waste prevention.
or recomplete a well or suspend or abandon
Governor in Council in relation to Part I of the
The National Energy Board would assess each
a well or part of a well a company requires
Development Plan pursuant to paragraph 5.1(4)
application for work or activity submitted under
a well approval from the National Energy Board
of the Canada Oil and Gas Operations Act,
paragraph 5(1)(b) including assessment of the
in accordance with section 10 of the Canada Oil
any work or activity relating to that field
accompanying environmental protection plan,
and Gas Drilling and Production Regulations.
can only commence after the operator submits
safety plan and contingency plan to verify that
The National Energy Board would assess
an application under paragraph 5(1)(b) of
the work or activity:
each application for a well approval to verify
the Canada Oil and Gas Operations Act for
• is within the scope of and consistent with
The Development Plans for the Niglintgak, Taglu
and Parsons Lake fields have also been applied
for under the Canada Oil and Gas Operations
Act. Upon National Energy Board approval
of a Development Plan and consent of the
that work or activity and obtains authorization
from the National Energy Board.
the approved Development Plan;
• complies with terms and conditions outlined
in the National Energy Board’s approval of
the following:
• compliance with the terms and conditions
of the authorization under paragraph 5(1)(b)
of the Canada Oil and Gas Operations Act;
the Development Plan;
1249_NEB_MGP_Vol2_Text_ENG.indd 214
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Chapter 10: National Energy Board lifespan regulation 215
• it is within the scope of and consistent
Enforcement of the Canada Oil and Gas
Inspections and monitoring activities by
with the Environmental Protection Plan,
Operations Act and its regulations for safety are
the National Energy Board include:
safety plan and contingency plan;
carried out by the Chief Safety Officer and
• verifying compliance with, and assessing
• it is within the scope of and consistent
with the approved Development Plan;
• compliance with terms and conditions
Safety Officers. Verifying compliance for
the effectiveness of, mitigation measures,
environmental protection and oil and gas
conditions, and Environmental Protection
conservation matters is within the mandate of
Plans and safety plans;
outlined in the National Energy Board’s
the Chief Conservation Officer and Conservation
approval of the Development Plan;
Officers. Conservation Officers and Safety
• compliance with the Canada Oil and Gas
Officers work in collaboration with other
Operations Act, the Canada Oil and Gas
regulators to ensure that there are no regulatory
Drilling and Production Regulations
gaps and to minimize regulatory overlap.
and other Canada Oil and Gas Operations
• verifying compliance with the appropriate
standards and regulations; and
• monitoring drilling, facilities construction,
production operations, and decommissioning.
If cooperative approaches to compliance are
Throughout the lifespan of a project, the
not successful, Safety Officers may issue orders
National Energy Board will monitor drilling,
about safety and the Chief Conservation
Any well approval granted under section 10
completions, facilities construction, production
Officer may order operations to be shut down,
of the Canada Oil and Gas Drilling and
operations, and decommissioning with
if necessary, to prevent damage to persons
Production Regulations by the National
inspections and management system audits.
or property, to protect the environment or
Energy Board would contain appropriate terms
Information on condition tracking, inspection
to prevent waste.
and conditions.
reports and other compliance information is
Act regulations.
After the National Energy Board issues an
authorization for a work or activity under
paragraph 5(1)(b) of Canada Oil and Gas
Operations Act including a well approval under
used by the National Energy Board to improve its
internal processes, track condition compliance
and non-compliances, and to establish the need
and frequency of future inspections and audits.
section 10 of the Canada Oil and Gas Drilling
The frequency and type of inspections depend
and Production Regulations, the National Energy
on several factors, including the:
Board will periodically conduct inspections and
• complexity of the project;
audits of field operations to verify compliance
• safety and environmental issues identified
with the applicable Canada Oil and Gas
during the application and prior activity
Operations Act regulations, terms and conditions
phases; and
of the Development Plan approval, the 5(1)(b)
• observed compliance history of the company.
authorization and/or well approval, and other
matters relating to environmental protection,
safety, and conservation of oil and gas resources.
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Chapter 11
Disposition
Volumes 1 and 2 constitute our Reasons for Decision approving the
Mackenzie Gas Project applications.
We are satisfied that the proposed Mackenzie Valley Pipeline is, and will
be, required by the present and future public convenience and necessity
provided the terms and conditions outlined in Appendix K of these
Reasons are met. Therefore, subject to the approval of the Governor in
Council, a certificate will be issued pursuant to Part III of the National
Energy Board Act. We have also made an Order setting toll and tariff
principles for the Mackenzie Valley Pipeline as set out in Appendix L.
We find that the Mackenzie Gathering System promotes safety,
environmental protection and conservation of oil and gas resources.
Accordingly, we will issue an authorization for the Mackenzie Gas System
under paragraph 5(1)(b) of the Canada Oil and Gas Operations Act.
This authorization will be issued once the proponents have complied
with the necessary provisions of the Canada Oil and Gas Operations Act.
This authorization will be subject to the conditions outlined in Appendix M.
We have also made an Order setting toll principles for the Mackenzie
Gathering System that are contained in Appendix N.
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Chapter 11: Disposition 217
We find that the Development Plans submitted by Shell Canada Limited
as managing partner of Shell Canada Energy for the Niglintgak field,
Imperial Oil Resources Limited for the Taglu field and ConocoPhillips
K.W. Vollman
Canada (North) Limited and ExxonMobil Canada Properties for the Parsons
Presiding Member
Lake field promote safety, environmental protection and conservation of oil
and gas resources. Accordingly, we will issue approvals of the Development
Plans for the Niglintgak, Taglu and Parsons Lake fields once the proponents
have complied with the necessary provisions of the Canada Oil and Gas
G. Caron
Member
Operations Act. These approvals will each be subject to the consent of
the Governor in Council in relation to Part I of each Development Plan.
In addition we will require that:
a) the conditions set out in Appendix O be met for the Niglintgak field;
D. Hamilton
Member
b) the conditions set out in Appendix P be met the Taglu field; and
c) the conditions set out in Appendix Q be met for the Parsons Lake field.
December 2010
In making our decision we have considered the Governments of Canada &
of the Northwest Territories Final Response to the Joint Review Panel
Report for the Proposed Mackenzie Gas Project and the comments
received from parties on that Response.
1249_NEB_MGP_Vol2_Text_ENG.indd 217
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Appendices
Contents
A List of Issues for Hearing GH-1-2004
219
B Recital and appearances
220
C Summary of events
223
D Development field reservoirs: characteristics and exploration history
226
E Conversion factors and energy content
231
F Authorization MO-13-2004
232
G Mr. Rowland J. Harrison’s subsection 15(1) report
234
H National Energy Board’s letter to Joint Review Panel regarding modifications
235
I
238
Concordance Table
J Joint Review Panel’s response to NEB’s consult to modify process
246
K Conditions for the Mackenzie Valley Pipeline
248
L Miscellaneous Order for Mackenzie Valley Pipeline Tolls and Tariff
265
M Conditions for the Mackenzie Gathering System 268
N Miscellaneous Order for Mackenzie Gathering System Tolls
285
O Conditions for the Shell Canada Limited (Shell) Development Plan for the Niglintgak field
287
P Conditions for the Imperial Oil Resources Limited (IORL) Development Plan for
the Taglu field
295
Q Conditions for the ConocoPhillips Canada (North) Limited (ConocoPhillips)
Development Plan for the Parsons Lake field
1249_NEB_MGP_Vol2_Text_ENG.indd 218
303
12/6/10 11:03:02 AM
Appendix A 219
Appendix A
List of Issues for Hearing GH-1-2004
1. The need for the proposed project.
2. The economic feasibility of the proposed project.
3. The potential commercial impacts of the proposed project.
4. The appropriateness of the general routes of the proposed pipelines.
5. The toll and tariff regulation of the proposed Mackenzie Gas Pipeline.
6. The suitability of the design of the proposed project.
7. The terms and conditions to be included in any approval
the NEB may issue.
8. The appropriateness of the Applicants’ public consultation
program and the adequacy of aboriginal consultation.
9. The ability of the Proponents to manage risk and financial
liabilities related to the construction, operation and decommissioning
of the proposed project.
10. The appropriateness of the Development Plans for the Taglu,
Parsons Lake and Niglintgak fields.
11. The estimated cost of construction of the Mackenzie Valley Pipeline
for the purpose of subsection 5.2(1) of the National Energy Board
Cost Recovery Regulations.
12. For the purpose of Phase 6 of the NEB process, the reports
from the Joint Review Panel process.
13. The appropriate tolls, access and tariff provisions for the
Mackenzie Gathering System and the methods for resolving
disputes on these matters.
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220 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix B
Recital and appearances
IN THE MATTER OF the National Energy Board Act (Act) and the
IN THE MATTER OF an application filed with the National Energy Board
Regulations made thereunder: and
on 20 October 2004 under file FieldOp SCL Niglintgak-07 for approval
IN THE MATTER OF an application filed with the National Energy Board
on 7 October 2004 under file PA-IOR 2004-001, for a Certificate of Public
of the COGO Act, filed by Shell; and
Convenience and Necessity under Parts III and IV of the Act by Imperial Oil
IN THE MATTER OF National Energy Board Hearing Order GH-1-2004
Resources Ventures Limited (IORVL) on behalf of itself, Mackenzie Valley
dated 24 November 2004;
Aboriginal Pipeline Limited Partnership (APG), ConocoPhillips Canada
(North) Limited (ConocoPhillips), Shell Canada Limited (Shell) and
ExxonMobil Canada Properties (ExxonMobil); and
HEARD in Inuvik, N.W.T. on 25, 26, 27, 28, 30, 31 January and 1 February
2006; Norman Wells, N.W.T. on 24, 25 and 26 April 2006; Fort Good
Hope, N.W.T. on 29 and 30 May 2006; Tulita, N.W.T. on 1 June 2006;
IN THE MATTER OF an application filed with the National Energy Board
Yellowknife, N.W.T. on 2 June, 24, 25, 26, 27, 28, 29, 31 July and
on 7 October 2004 under file FacPipe IRL MGS-04 for authorization for
1 August 2006; Fort Providence, N.W.T. on 25, 26 September 2006;
the Mackenzie Gathering System, pursuant to paragraph 5(1)(b) of the
High Level, Alberta on 27 September 2006; Hay River, N.W.T. on 29 and
Canada Oil and Gas Operations Act (COGO Act). The application was filed
30 September 2006; Deline, N.W.T. on 2 October 2006; Wrigley, N.W.T.
by Imperial on behalf of itself, ConocoPhillips, Shell and ExxonMobil; and
on 3 October 2006; Fort Simpson, N.W.T. on 4 and 5 October 2006;
IN THE MATTER OF an application filed with the National Energy Board
on 7 October 2004 under file FieldOp IRL Taglu-07 for approval of
the Development Plan for the Taglu field, pursuant to section 5.1
of the COGO Act, filed by Imperial Oil Resources Limited; and
IN THE MATTER OF an application filed with the National Energy Board
on 7 October 2004 under file FieldOp CPN Parsons-07 for approval of
the Development Plan for the Parsons Lake field, pursuant to section 5.1
of the COGO Act, filed by ConocoPhillips on behalf of itself and
ExxonMobil; and
1249_NEB_MGP_Vol2_Text_ENG.indd 220
of the Development Plan for the Niglintgak field, pursuant to section 5.1
Inuvik, N.W.T. on 22, 23, 24, 25, 27, 28, 29, 30 November and
1 December 2006; Tuktoyaktuk, N.W.T. on 4 December 2006;
Fort MacPherson, N.W.T. on 5 December 2006; Tsiigehtchic, N.W.T. on
6 December 2006; Inuvik, N.W.T. on 11, 12, 13 and 14 December 2006;
Yellowknife, N.W.T. on 10 and 11 October 2007, 29 March and 12, 13,
14, 15, 16 April 2010; and Inuvik, N.W.T on 20, 21 and 22 April 2010.
BEFORE:
K.W. Vollman
Presiding Member
G. Caron
Member
D. Hamilton
Member
12/6/10 11:03:02 AM
Appendix B 221
APPEARANCES:
Imperial Oil Resources Ventures Limited (IORVL): D.G. Davies, B. Ho,
T. Hughes, W. Shalagan
Witnesses: Dr. G. Angevine, B. Bleaney, R. Boivin, K.M. Braaten,
D. Brandes, D. Coolidge, B.J. Cunningham, K. Drysdale, R. Falconer,
D. Gough, D.G. Harris, C.E. Heuer, K. Johnson, L. Kennedy, J. Kingsbury,
B. Kohrs, G.L. Lee, R. Luckasavitch, H. Marreck, A. Martinson, D. Mazurek,
K. McShane, J. Oswell, R. Ottenbreit, G. Penrose, Dr. A. Safir, C. Saunders,
Chevron Canada Resources: K.F. Miller
Witnesses: R. Maier, M. Morand, K. Nahm, K. Starkey
Dehcho Elders Council: Grand Chief H. Nowegian
Dehcho First Nations: Grand Chief S. Gargan, J. Acorn
Dehcho Harvesters Council: Grand Chief H. Nowegian
Ecology North: D. Ritchie
E. van Beurden, W. Veldman, A. Watson, W. Williams, M.M. Zhang
EnCana Corporation: R.K. Powell
Imperial Oil Resources Limited: D.G. Davies, B.Ho
Environment Canada: B. Rattan, C.J. Thomas, J.R. Harvey
Witnesses: M. Curtin, D. Haeberle, B. Parent, M. Sykes, F. Yurkiw
Shell Canada Limited: S.H.T. Denstedt, M. Henderson,
B. Gilmour, R. Rodier
Witnesses: P.M. Davies, P. Johnson, R.K. Johnson, M.A. Read, R.J. Ritchie
ConocoPhillips Canada (North) Limited: S.H.T. Denstedt,
G. Teixeira, R. Rodier
Fort Simpson Métis Local No. 52: M. Lafferty
Gwich’in Tribal Council: R. Nerysoo
Indian and Northern Affairs Canada: S. Duke, R. Graw
Witnesses: Dr. A. Baumgard, Dr. C. Burn, T. Kaiser, D. Livingstone,
Dr. B. Roggensack, Dr. W. Savigny, E. Yaremko
Witnesses: R. Bleaney, A. Duguid, S. Kennedy, B. Plesuk, G. Prost
Inuvialuit Regional Corporation: N. Cournoyea
Alternatives North: K. O’Reilly
Ka’a’Gee Tu First Nation: Chief L. Chicot
Apache Canada Ltd: A.W. Carpenter, S. Carpenter
Lidlii Kue First Nations: Chief J. Antoine
Witnesses: B. Jackson, B. Kalynchuk
Ayoni Keh Land Corporation: L.D. Rae
France Benoit: F. Benoit
BP Canada Energy Company: B. Wallace
Mackenzie Explorer Group: D.E. Crowther, J. Farrell, R. Neufeld
Witnesses: Dr. L. Booth, J. Chipperfield, N. Deyell, M. Drazen, N. Dustan,
L. Germiquet, G. Hiltz, R. Maier, K. Milne, M. O’Blenes, R.K. Powell,
M. Scott, S. Willis
Mackenzie Valley Aboriginal Pipeline Limited Partnership: Canadian Parks & Wilderness Society: K. Brekke
L.E. Smith, Q.C., F. Carmichael
Government of Canada – Justice Canada: J.M. Shaw, R. Mack
MGM Energy Corp. (formerly Paramount Resources Ltd.): Witnesses: C.A. Brumwell, M. Chenier, L. Clayton, W. Fenton,
A.S. Hollingworth, N. Dilts, G. Bunio
C. Gibson, R. Hurst, F. Lefebvre, C. Leowen, B. MacDonald, P. Szkwarok
Witnesses: R. DeWolf, W. Rausch
Canadian Association of Petroleum Producers: N. Schultz
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222 Mackenzie Gas Project • Volume 2: Implementing the decision
Mosbacher Operating Ltd.: L.L. Manning
Written Final Argument: Acho Dene Koe First Nation, Alberta
Witnesses: H. Baird, R.G. Dingwall
Department of Energy, Apache Canada Ltd., Ayoni Keh Land Corporation,
North Slave Métis Alliance: S. Grieve
Northern Pipeline Projects Ltd.: D. Anguish
Pehdzeh Ki First Nation: Chief T. Lannie
Government of Northwest Territories: C.W. Sanderson, Q.C., K. Bergner, C. Ferguson, J. Fulford
Witnesses: Hon. B. Bell, R. Priddle, P. Vician
Chevron Canada Ltd., North Slave Métis Alliance, Suncor Energy
Marketing Inc.
Opening Remarks and Oral Statements: A. Andre, G. Andre, J. Andre,
L. André, Chief F. Andrew, J. Antoine, J. Arsenault, L. Azzolini, G. Barbaby,
D. Bayha, A. Beaudin, J. Bernard, P. Bhuggins, C. Brown, D. Campbell,
S. Carle, B. Clement, D. Codzi, L. Cooke, M. Cox, M. Dubeau,
Mayor D. Ehman, A. Elanik, J. Elleze, S. Elleze, M. Ellton, E. Erutse,
D. Etchinelle, E. Freeland Ballantyne, Chief C. Furlong, M. Gannon,
Sahdae Energy Ltd.: D. Evanchuk
S. Gargan, D. Gaudet, G. Gibson, R. Gordon, G. Grandjambe,
Witnesses: A. Chung, D. Grabke, R. Lawrence
J. Grandjambe, R. Grandjambe, T. Grandjambe, F. Gruben, R. Gruben,
Sambaa K’e Dene Band: J. Lojek, S. Morgan, P. Redvers
L. Jackson, W. Jackson, J. Kakfwi, T. Kakfwi, Chief J. Kay,
I. Katz, C. Kochon, G. Kochon, Chief R. Kochon, E. Koe, B. Kotchile,
Sierra Club of Canada: P. Falvo, K. Ferguson, S. Hazell
T.-L. Kuptana, J. Lacorn, E. Lamothe, W. Landry, M. Lavigne, P. Lélorey,
Witnesses: E. May; M. McCulloch
L. Lennie, Chief T. Lennie, L. Little, I. Manuel, T. Manuel, A. Martel,
Talisman Energy: F.C. Basham
World Wildlife Fund – Canada: P. Falvo, M. Hummel, Dr. R. Powell
Government of Yukon: J.H. Smellie, R.E. Smith, G.M. Nettleton
Witnesses: G. Engbloom; B. Love; K. Osadetz
National Energy Board: P. Enderwick, A. Hudson, D. Saumure
A. Masuzumi, H. McCauley, R. McCord, G. McMeekin, E. Menicoche,
K. Menicoche, L. Menicoche Moses, Mayor M. Mihaly, Elder E. Mitchell,
D. Nelner, Chief C. Neyelle, B. Nind, J. Norbert, Chief K. Norwegian,
J. Paulson, M. Phelan, F. Pierrot, Chief R. Pierrot, J. Pokiak, B. Ritias,
T. Remy-Sawyer, Chief P. Ross, B. Saunders, D.L. Simmons, D. Sipos,
D. Sonfrere, J.A. Snowshoe, S. Snowshoe, V. Teddy, M. Teya, J. Thomas,
A. Tobac, C. Tobac, Jim Tutcho, John Tutcho, A. Tuninge, D. Vital, J. Vital,
A. Williams, A. Yellee, A. Yallee for D’Arcy Moses
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Appendix C 223
Appendix C
Summary of events
Date
Event
June 2002
The Cooperation Plan for the Environmental Impact Assessment and Regulatory Review of a Northern Gas Pipeline
Project through the Northwest Territories (Cooperation Plan) was issued. The Cooperation Plan set out a joint
environmental impact assessment process to meet the requirements of the Canadian Environmental Assessment Act,
the Mackenzie Valley Resource Management Act and the Inuvialuit Final Agreement.
February 2003
The Plan for Public Involvement in the Environmental Assessment of the Proposed Mackenzie Valley Gas Pipeline
in the Northwest Territories was issued. The Plan provided general information to the public about opportunities
to participate in the environmental impact assessment and regulatory review of an anticipated gas pipeline project
through the Northwest Territories.
18 June 2003
The Preliminary Information Package for the Mackenzie Gas Project was submitted by the Proponents.
17 July 2003
The Mackenzie Gas Project was referred to the Minister of the Environment for the establishment of a review
panel under the Canadian Environmental Assessment Act.
21 July 2003
An application for a Type A Land Use Permit and Type B Water License for the Camsell Bend Development
was filed with the Mackenzie Valley Land and Water Board, triggering the environmental review process.
21 August 2003
The Minister of the Environment referred the Mackenzie Gas Project to a Joint Review Panel under
the Canadian Environmental Assessment Act.
October 2003
The Draft Terms of Reference for the Environmental Impact Assessment of the Mackenzie Gas Project was released
for comment by the Joint Secretariat for the Inuvialuit Settlement Region, the Mackenzie Valley Environmental Impact
Review Board and the Canadian Environmental Assessment Agency.
December 2003
A Memorandum of Agreement was signed by the National Energy Board, the Mackenzie Valley Land and Water Board,
the Northwest Territories Water Board, the Mackenzie Valley Environmental Impact Review Board, the Inuvialuit Game
Council, the Canadian Environmental Assessment Agency, and the Department of Indian Affairs and Northern
Development. The Agreement served to establish the Northern Gas Project Secretariat.
22 April 2004
The Agreement for the Coordination of the Regulatory Review of the Mackenzie Gas Project was released, setting
out details for the environmental impact assessment by a Joint Review Panel, the coordination of hearings between
regulatory agencies, and the maintenance of a public registry.
August 2004
The Environmental Impact Statement Terms of Reference for the Mackenzie Gas Project was issued by
the Joint Secretariat for the Inuvialuit Settlement Region, the Mackenzie Valley Environmental Impact Review Board
and the Canadian Environmental Assessment Agency.
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224 Mackenzie Gas Project • Volume 2: Implementing the decision
Date
Event
9 August 2004
The seven-member Joint Review Panel was created.
16 September 2004
The Joint Review Panel released its Rules of Procedure for the conduct of the Environmental Impact Assessment
of the Mackenzie Gas Project by a Joint Review Panel.
7 October 2004
The Environmental Impact Statement was submitted to the Joint Review Panel by the Proponents.
7 October 2004
Proponents submitted all but one of the applications for the Mackenzie Gas Project to the National Energy Board.
20 October 2004
Shell Canada Limited submitted its Niglintgak Development Plan Application to the National Energy Board.
24 November 2004
The National Energy Board issued Hearing Order GH-1-2004 including a schedule of events covering
the technical review phase of the proceeding.
November 2004 to
The National Energy Board, Joint Review Panel and Northern Gas Project Secretariat conducted public information
January 2006
sessions in communities along near the proposed pipeline route. Also during this period the National Energy Board
and Joint Review Panel carried out several rounds of information requests in their respective hearings.
23 December 2004
The National Energy Board finalized and issued its List of Issues for the proceeding.
13 July 2005
Imperial Oil Resources Ventures Limited announced that it would advise the National Energy Board
in late summer of its readiness to proceed to hearing.
15 September 2005
Imperial Oil Resources Ventures Limited stated it would advise the National Energy Board and
the Joint Review Panel in November 2005 of its willingness to proceed to hearing.
23 November 2005
Imperial Oil Resources Ventures Limited announced that it was willing to proceed to public hearings.
December 2005
The National Energy Board held a pre-hearing planning conference to assist parties in preparing for the National
Energy Board public hearing. The conference was held in Inuvik, Yellowknife, Fort Good Hope, and Fort Simpson.
20 December 2005
A coordinated hearing schedule was released for the National Energy Board and Joint Review Panel hearings.
25 January 2006 to
The National Energy Board held 47 days of hearings in 15 communities, starting and ending in Inuvik.
14 December 2006
The other locations were Norman Wells, Fort Good Hope, Tulita, Fort Providence, Yellowknife, High Level,
Hay River, Déline, Wrigley, Fort Simpson, Colville Lake, Tuktoyaktuk, Fort McPherson and Tsiigehtchic.
14 February 2006 to
The Joint Review Panel held 117 days of hearings in 26 communities, starting and ending in Inuvik.
29 November 2007
7 April 2006
The Mackenzie Explorer Group filed a motion with the National Energy Board for an order that, when constructed and
placed into service, the Mackenzie Gathering System and Mackenzie Valley Pipeline will be a single pipeline subject to
regulation under Part IV of the National Energy Board Act and that Imperial Oil Resources Ventures Limited prepare, file and
serve the toll principles and the tariff(s) for this single pipeline for approval under Part IV of the National Energy Board Act.
2 June 2006
An oral hearing was held in Yellowknife on the Mackenzie Explorer Group’s motion.
10 July 2006
The National Energy Board issued Ruling No. 16, denying The Mackenzie Explorer Group’s motion. The Mackenzie Explorer
Group subsequently appealed the National Energy Board’s decision to the Federal Court of Appeal in August 2006.
14 December 2006
1249_NEB_MGP_Vol2_Text_ENG.indd 224
The National Energy Board completed its initially scheduled evidentiary hearing in Inuvik.
12/6/10 11:03:02 AM
Appendix C 225
Date
Event
5 February 2007
The National Energy Board issued a list of potential conditions for comment by parties.
12 March 2007
Imperial Oil Resources Ventures Limited filed a project cost estimate and schedule update.
30 March 2007
Imperial Oil Resources Ventures Limited filed updated costs, tolls and fees.
15 May 2007
Imperial Oil Resources Ventures Limited filed supplemental information to its project updates.
10-11 October 2007
The National Energy Board held a hearing session in Yellowknife to examine updated evidence
filed in the National Energy Board hearing.
28-29 November 2007
The Joint Review Panel heard closing statements in Inuvik.
22 April 2008
In Anadarko Canada Corp. v. (National Energy Board) [2008] F.C.J. No. 664, the Federal Court of Appeal dismissed
Mackenzie Explorer Group’s appeal of the National Energy Board’s decision to dismiss the Mackenzie Explorer Group’s
motion that the Mackenzie Gathering System when built should be regulated under the National Energy Board Act.
7 October 2009
The National Energy Board issued information on the next steps in its hearing in anticipation of the Joint Review Panel
issuing its report.
30 December 2009
The Joint Review Panel issued its report.
30 December 2009
Mr. Rowland J. Harrison, Q.C. issued his subsection 15(1) report.
6 January 2010
The National Energy Board established a process to consult on the Joint Review Panel recommendations.
28 January 2010
The Proponents sent comments on the Joint Review Panel recommendations to National Energy Board
and parties to both hearings.
11 February 2010
Parties to both hearings sent comments on the Joint Review Panel recommendations to the National Energy Board,
the Proponents and other parties.
18 February 2010
The Proponents sent reply comments on the Joint Review Panel recommendations to National Energy Board
and parties to both hearings.
9 March 2010
The National Energy Board provided proposed modifications to the Joint Review Panel for written response.
9 March 2010
The National Energy Board issued a revised list of potential conditions for comment by parties.
15 March 2010
Updated evidence, including evidence on economic feasibility and further evidence on the adequacy
of Aboriginal consultation was filed with the National Energy Board.
29 March 2010
The Joint Review Panel responded to the National Energy Board’s proposed modifications to the Joint Review
Panel recommendations.
29 March 2010
National Energy Board held a hearing session in Yellowknife to examine the updated evidence that was filed in its hearing.
8 April 2010
Written final argument was filed with the National Energy Board.
12-16 April 2010
The National Energy Board heard final argument in Yellowknife.
20-22 April 2010
The National Energy Board heard final argument in Inuvik. The hearing ended after a total of 58 days of hearing
in 15 communities.
1249_NEB_MGP_Vol2_Text_ENG.indd 225
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226 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix D
Development field reservoirs:
characteristics and exploration history
The Niglintgak and Taglu reservoirs are both located in the Reindeer
Sands formed 60 million years ago during the Early Tertiary Period.
This rock is considered to be fairly young, or immature, and poorly
consolidated. This means that as gas is extracted, the rock may
compress and crumble and the earth can slowly sink. Gas from
Parsons Lake reservoir is found in the Kamik Formation of the Early
Cretaceous Period, which was formed 140 million years ago. The Kamik
Formation is more mature than the Reindeer Sands, and is consolidated.
Although the fields share some similar geological characteristics, the
reservoirs are all quite different. In the Niglintgak field, the gas is only
about one kilometre below the surface, making it a relatively shallow
field. In comparison, the Taglu and Parsons Lake fields contain gas
about three kilometres below the surface. Characteristics of the gas in
each reservoir also differ.
The Parsons Lake field covers a large widespread area with
Significant Discovery Licence 030 and 032 covering 104 sections
of land. The Niglintgak field’s Significant Discovery Licence 019
and Taglu’s Significant Discovery Licence 063 cover 12 and 20 sections
of land respectively. The Niglintgak and Parsons Lake fields are expected
to produce water immediately after gas production commences.
Table D-1
Gas characteristics for the development fields
Parameter
Niglintgak field
Taglu field
Parsons Lake field
Project life, years
25
30
25
Initial daily raw
natural gas production,
Mm3/d (MMcf/d)
4.3
(150)
12.6
(445)
9.0
(324)
Initial daily natural
gas liquids production,
m3/d (Bbl/d)
6
(40)
1,230
(7,700)
520
(3,271)
Expected commencement
of water production
12th year
of production
5th year
of production
1st year
of production
Carbon dioxide, CO2,
content (%) of gas
0.90%
0.27%
3.00% north pool
5.00% south pool
Hydrogen Sulphide,
H2S, content (%) of gas
0.00%
0.00%
0.00%
Projected depth of
production wells,
mTVD (ft)
850-2,100
(2,789-6,890)
2,992-3,335
(9,816-10,941)
2,923-2,943
(9,590-9,655)
Expected initial flowing
wellhead pressure,
MPa (psi)
9.651
17.80
23.002
(1,400)
(2,580)
(3,336)
Significant discovery
licence(s)
SDL-019
SDL-063
SDL-030, SDL-032
Imperial does not anticipate producing any water with its gas production
until approximately five years after the Taglu begins production.
Sections of land
12 sections
of land
20 sections
of land
104 sections
of land
The natural gas from both the Taglu and Parsons Lake fields is rich
containing large amounts of natural gas liquids whereas natural gas
from the Niglintgak field is lean. In addition, natural gas from the Parsons
Lake field contains significant amounts of carbon dioxide, 3 to 5 percent,
1249_NEB_MGP_Vol2_Text_ENG.indd 226
which may present corrosion issues. The gas from the Niglintgak
[1] Estimate for all wells except for the deep L, M and N sand well which is estimated to
be 15.45 MPa (2,241 psi).
and Taglu fields contains small amounts of carbon dioxide.
[2] Estimate for the north pool. The south pool is estimated to be 19.00 MPa (2,756 psi).
12/6/10 11:03:02 AM
Appendix D 227
A brief description of the history of exploration and the approach to
gas production follows for each field. Oil and gas companies have been
exploring Canada’s North since the 1950s. However, despite the lure
of rich deposits of hydrocarbons, exploration and discovery in the harsh
Arctic environment has proven to be a challenge.
Did you know?
Commercial discovery, significant discovery and significant discovery licence
A commercial discovery is a discovery of petroleum that demonstrates petroleum
reserves to justify the investment of capital and effort to bring the discovery to
production (Canada Petroleum Resources Act).
A production licence is a licence for oil and gas rights issued in respect of all
Niglintgak
Shell first obtained exploration land in the Mackenzie Delta in 1958.
The history of exploration for the Niglintgak field is shown in Table D-2.
portions of the commercial discovery area that are subject to an exploration licence
and/or a significant discovery licence by the Minister of Indian Affairs and Northern
Development Canada upon application of an interest holder of the exploration
licence and/or significant discovery licence where a commercial discovery is in force.
A significant discovery is a discovery indicated by the first well on a geological
Table D-2
feature that demonstrates by flow testing the existence of hydrocarbons in that
Niglintgak exploration history
Year
Activity
1960s and 1970s
2-D seismic surveys
1973
Drilling of discovery well H-30
1974 – 1977
Drilling of four additional exploratory and delineation wells
1988
SDL-019 issued
1988 – 1989
3-D seismic survey
2000
Declaration of a Commercial Discovery issued
feature and, having regard to geological and engineering factors, suggests the
existence of an accumulation of hydrocarbons that has potential for sustained
production (Canada Petroleum Resources Act).
A significant discovery licence is a licence for oil and gas rights issued in respect
of all portions of the significant discovery area that are subject to an exploration
licence by the Minister of Indian Affairs and Northern Development Canada upon
application of an interest holder of the exploration licence where a declaration of
significant discovery is in force.
The current model of the reservoir is based on information obtained from
seismic surveys and exploratory wells. Results of the model for Significant
Discovery Licence 019, which covers most of the Niglintgak field, are
shown in Table D-3.
Shell, the operator of the Niglintgak field, subdivided the Niglintgak
Reindeer Sands into 26 units, or layers, labeled sands A to Z.
In some other layers there is no gas present or not in quantities large
Table D-3
Reservoir model results for Significant Discovery Licence 019
enough to be commercially extracted. Of the 26 units, Shell plans to
Parameter
Unit
produce, or extract gas, from the gas bearing A sands, D to G sands
Original gas-in-place
34.0 Gm3
and the L to N sands. The model also indicates the reservoir is broken
Recoverable gas
27.0 Gm
into several compartments as a result of faulting.
1249_NEB_MGP_Vol2_Text_ENG.indd 227
(1.2 Tcf)
(0.95 Tcf)
3
Recoverable natural gas liquids
3
40,000 m
(250,000 Bbl)
Initial raw gas production rate
4.3 Mm /d
(150 MMcf/d)
3
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228 Mackenzie Gas Project • Volume 2: Implementing the decision
Taking into account this compartmentalization, Shell concluded that six
production wells could efficiently produce the reservoir. These six wells
would range in vertical depth from 850 to 2100 metres and from 1050
to 2550 metres in length and they would be directionally drilled from
three well pads. The well locations and the plan and cross-section views
of the well pad are shown in Figures 4-5 and D-1.
Did you know?
Definitions
Condensate – a liquid hydrocarbon mixture that may be separated from natural gas.
Natural gas liquids – a liquid hydrocarbon mixture that may be extracted
from natural gas.
Rich or wet gas – natural gas that contains significant amounts of
Four wells would produce the A sand, one well would produce the
condensate or natural gas liquids.
D to G sands, and one well would produce the L to N sands. Usually, gas
Lean or dry gas – natural gas that contains little or no condensate
from each unit is produced independently of the other units. However,
or natural gas liquids.
in some cases it is more efficient to mix, or commingle, gas from several
units when it is being extracted. Shell plans to make an application to
commingle production from the D to G sands and from the L to N sands
and well analysis. This information will be used to determine if additional
because of enhanced wellbore flow performance, improved ultimate
faulting and compartmentalization exist and whether any contingent
recovery and economic reasons. The four A sands wells and the D to G
wells would be required. This monitoring program would help ensure
sands well are expected to produce a lean sweet gas with little or no
the Niglintgak field operates effectively and that gas recovery and
natural gas liquids. The L to N sands well would produce a richer gas. Shell
production are optimized.
estimates the average gas composition to be lean, 98 percent methane
with the liquid-rich gas making up less than 5 percent of the total flow.
The locations for these initial six wells were chosen by Shell to optimize
gas recovery with minimal water production. However, as wells begin
to produce, the operators will have new reservoir data from flow tests
All original Niglintgak exploration and delineation wells were abandoned
in 1996.
Taglu
Natural gas in the Taglu field is found in three sand units, or layers, known
as the A, B, and C units of the Reindeer Formation in the Tertiary Period.
The A sands, the Upper C and the Lower C sands are estimated to contain
95 percent of the original gas-in-place.
Figure D-1
The history of exploration for the Taglu field is shown in Table D-4.
A NW-SE cross-section of the Niglintgak reservoir and proposed initial well locations
NW
0
SE
Table D-4
A-30
M-19
J-30
Disposal well O-08
C-08
Taglu exploration history
-500
-1,000
-1,500
H-30
Permafrost
M-19 M-19
LMN
Sand well
Iperk
Original wells abandoned (in black)
1249_NEB_MGP_Vol2_Text_ENG.indd 228
Fault
Richards
B-19
A to G sands
Fault
Fault E-58
Lower Taglu Sequence
C-58
Year
Activity
1969
Start of 2-D seismic surveys
1971
Drilling of discovery well G-33
1971 – 1985
Drilling of seven additional exploratory
and delineation wells
1987
SDL-063 issued
1987 – 1988
3-D seismic survey
2004
Declaration of a Commercial Discovery issued
Fault
0
1
kilometres
12/6/10 11:03:03 AM
Appendix D 229
Imperial used a computer model to estimate volumes of gas, natural gas
Parsons Lake
liquids and water from its proposed wells. Results are shown in Table D-5.
The history of exploration for the Parsons Lake field is shown in Table D-6.
Table D-5
Table D-6
Reservoir model results for the Taglu field
Parsons Lake exploration history
Year
Activity
(3.8 Tcf)
1950s, 1960s, 1970s
2-D seismic surveys
81.0 Gm
(2.8 Tcf)
1972
Drilling of discovery well F-09
4.85 Mm3
(30.0 MMBbl)
1973 – 1977
Drilling of 17 additional exploratory
and delineation wells
1988
SDL-030 & SDL-032 issued
Imperial’s reservoir modeling results describe the Taglu field as being one
2002
3-D seismic survey
fault block with minor faulting which is too small to compartmentalize the
2004
Declaration of a Commercial Discovery issued
Parameter
Unit
Original gas-in-place
109.0 Gm
Recoverable gas
Recoverable natural gas liquids
Initial raw gas production rate
12.6 Mm3/d
(445 MMcf/d)
3
3
reservoir. This means the Taglu field is not anticipated to be partitioned
and as a result Imperial is proposing to develop 10 to 15 production wells
Currently, ConocoPhillips believes the Parsons Lake field contains two
from a single well pad located near the centre of the reservoir. Imperial
main natural gas pools. The larger north pool contains approximately
has provided 11 potential well locations including four wells that would
85 percent of the reservoir’s natural gas and is partially located under
produce from the A sands, four wells that would produce the B2, upper
Parsons Lake itself while the rest of the pool stretches northeast of
C, lower C and LC2 sands, and three wells that would produce the A and
Parsons Lake. The smaller south pool is found southwest of Parsons Lake.
C sands. The vertical depth of these wells would range from about 2992
The main gas bearing interval in both pools is the Kamik Formation of
to 3335 metres. Imperial has indicated if production were not
the Lower Cretaceous Period. ConocoPhillips plans to produce from
commingled, the field would have a lower gas recovery, a decelerated
the Kamik A, A1, B and C sands. The A1, B and C sands each contain
production profile and a negative economic impact. Imperial also plans
roughly a third of the original gas-in-place for the entire Parsons Lake
to monitor the production wells to confirm the current reservoir model.
field. The results of reservoir simulation are shown in Table D‑7.
If faults are located that compartmentalize the reservoir, then contingent
wells would be developed. The original Taglu exploration and delineation
Table D-7
wells have been abandoned.
Reservoir model results for Parsons Lake
1249_NEB_MGP_Vol2_Text_ENG.indd 229
Parameter
Unit
Original gas-in-place
97.7 Gm3
(3.45 Tcf)
Recoverable gas
64.0 Gm
(2.3 Tcf)
Recoverable natural gas liquids
3.0 Mm3
(18.7 MMBbl)
Initial raw gas production rate
9.0 Mm3/d
(324 MMcf/d)
3
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230 Mackenzie Gas Project • Volume 2: Implementing the decision
ConocoPhillips is planning to drill the field in two phases. In phase one,
commingle the A1 and B sands in the south pool. The third well from the
crews would drill nine production wells, two disposal wells and 10
south pad would initially produce the C sands and then be re-completed
contingent production wells from the north pad. Phase two would occur
to produce from the B sands. The advantages of commingling as outlined
a few years later and would involve drilling three production wells and
by ConocoPhillips include reduced costs and longer production life.
four contingent production wells from the south pad. If drilling results
Commingling would reduce costs because of a lower well count,
and further exploration activities indicate additional surface locations are
a smaller project footprint and fewer re-completion programs and
required, ConocoPhillips is proposing three contingent satellite well pads,
associated production downtime. Commingling would enable recovery
each holding up to three wells. The vertical depth of these wells would be
from smaller reserve compartments and tighter and thinner sands.
about 3000 metres.
In addition, ConocoPhillips estimates the pressure differences are less
ConocoPhillips1 reservoir model of the Parsons Lake field shows it
than 0.30 MPa (43 psi) in the sands that would be commingled.
is subdivided into 42 compartments because of multiple faults and
multiple sands. Original gas-in-place estimates from the 19 compartments
containing gas range from 0.9 to 16.4 Gm3 (32 to 580 Bcf). Like the other
operators, ConocoPhillips is proposing to commingle production from
the lower permeability sands of the Kamik Formation to effectively and
economically deplete these compartments. This would include three wells
commingling the A, A1 and B sands, and, three wells commingling the A1
and B sands from the north pad. The north pad would also include two
ConocoPhillips has indicated that uncertainty in geological, geophysical
and reservoir engineering interpretations means the locations of wells
drilled after start-up depend on production and drilling results. Despite
the significant amount of information already known about the field,
production data is needed to verify much of the geological modeling.
Like Shell and Imperial, ConocoPhillips plans to monitor production
and evaluate the need for any contingent wells.
wells which would produce from the C sands only and one well which
As all original wells have been abandoned, new wells would need to be
would produce from the A1 sands only. Two wells are proposed to
drilled to develop the Parsons Lake field.
[1] ConocoPhillips has proposed that the B-19 well initially produce from the C sands
and be then recompleted to produce the A1 and B sands, commingled.
1249_NEB_MGP_Vol2_Text_ENG.indd 230
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Appendix E 231
Appendix E
Conversion factors and energy content
Abbreviation table
Energy content table
Metric prefixes
Equivalent
k
kilo
103
M
mega
106
G
giga
109
T
tera
1012
P
peta
1015
E
exa
1018
Metric to Imperial conversion table
Physical units
Equivalent
m
metre
3.2808 feet
km
kilometre
0.621 mile
m3
cubic metre
6.292 barrels (oil or NGL),
Energy measures
Energy content
MW.h
megawatt hour
3.6 GJ
GW.h
gigawatt hour
3600 GJ
TW.h
terawatt hour
3.6 PJ
MMBtu
million British thermal units
1.05 GJ
Mcf
thousand cubic feet
1.05 GJ
MMcf
million cubic feet
1.05 TJ
Bcf
billion cubic feet
1.05 PJ
Tcf
trillion cubic feet
1.05 EJ
Electricity
Natural gas
35.301 cubic feet (gas)
Natural gas liquids
MPa
megapascal
145.037 psi
m3
ethane
18.36 GJ
GJ
gigajoule
0.95 million Btu
m
propane
25.53 GJ
ha
hectare
2.47 acres
m
butanes
28.62 GJ
1249_NEB_MGP_Vol2_Text_ENG.indd 231
3
3
12/6/10 11:03:03 AM
232 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix F
Authorization MO-13-2004
IN THE MATTER OF Subsection 15(1) of the National Energy Board Act
AND IN THE MATTER OF an Authorization of a National Energy Board
Management Act and the Inuvialuit Final Agreement.
Member to Report and Make Recommendations to the National Energy
A Board Member, Mr. Rowland Harrison, has been appointed as
Board on Matters relating to the Mackenzie Gas Project Application
a member of the JRP.
BEFORE the Board on 15 October 2004.
The Board desires to authorize Mr. Harrison under subsection 15(1)
A. Background
Imperial Oil Resources Ventures Limited, the Aboriginal Pipeline Group,
of the NEBA to report and make recommendations on certain aspects
of the application.
ConocoPhillips Canada (North) Limited, ExxonMobil Canada Properties
B. Authorization
and Shell Canada Limited (Proponents) have applied or will be applying
In accordance with the provisions of subsection 15(1) of the NEBA,
to the National Energy Board (the Board) for a certificate under section 52
the Board hereby authorizes Mr. Harrison to report and make
of the National Energy Board Act (NEBA) for the natural gas transmission
recommendations to the NEB Panel regarding the matters set out in
pipeline, an approval under section 5.1 of the Canada Oil and Gas
Section C below for use by the NEB Panel in its consideration of the
Operations Act (COGOA) for the production facilities at the Taglu,
Mackenzie Gas Project .
Parsons Lake and Niglintgak natural gas fields and for authorizations
under paragraph 5(1)(b) of the COGOA for the Mackenzie gathering
system, collectively the Mackenzie Gas Project (MGP).
The Board will designate a Panel (NEB Panel) to consider the Mackenzie
Gas Project application pursuant to the NEBA.
1249_NEB_MGP_Vol2_Text_ENG.indd 232
Canadian Environmental Assessment Act, the Mackenzie Valley Resource
Mr. Harrison has all the powers of the Board for the purpose of taking
evidence and acquiring the necessary information for the purpose of
making the report and recommendations on the Mackenzie Gas
Project application.
This authorization allows Mr. Harrison to utilize the Joint Review
A Joint Review Panel (JRP) of seven members has been established by
Panel process to compile the evidence and information necessary
agreement of the Mackenzie Valley Environmental Impact Review Board,
for him to make his report and recommendations to the NEB Panel.
the Inuvialuit as represented by the Inuvialuit Game Council and the
Mr. Harrison will consider the matters identified in the Environmental
Minister of the Environment to conduct an environmental impact review
Impact Statement Terms of Reference for the Mackenzie Gas Project
of the Mackenzie Gas Project that will meet the requirements of the
dated August 2004 and any other matter that comes within
12/6/10 11:03:03 AM
Appendix F 233
Section C upon which information or evidence is presented to the Joint
Review Panel.
By virtue of this authorization, Mr. Harrison will consider all evidence
and material presented to or obtained by the Joint Review Panel regarding
the matters set out in Section C below in preparing and presenting his
report and recommendations to the NEB Panel.
C. Matters for Report and Recommendations
In relation to the facilities described in Annex 1 to the Schedule:
Project Description (which Schedule is appended to the Agreement for
an Environmental Impact Review of the Mackenzie Gas Project executed
July 27 to August 3 2004), Mr. Harrison’s report and recommendations
will have regard to the protection of the social, cultural and economic
well-being of residents and communities and will include a consideration
of the factors as set out in Annex 2 to the said Schedule: Joint Review
Panel Mandate.
This authorization was approved by the Board on the 15th of October, 2004.
National Energy Board
[original signed by]
Michel L. Mantha
Secretary
1249_NEB_MGP_Vol2_Text_ENG.indd 233
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234 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix G
Mr. Rowland J. Harrison’s subsection 15(1) report
30 December 2009
Ms. Anne-Marie Erickson
Acting Secretary
National Energy Board
444 – 7th Avenue S.W.
In accordance with the terms of the NEB Authorization and of the JRPA,
I participated fully in the joint review of the Mackenzie Gas Project
undertaken by the JRP and in preparing Foundation for a Sustainable
Northern Future: Report of the Joint Review panel for the Mackenzie
Gas Project (JRP Report).
Calgary, Alberta
On December 30, 2009, the JRP Report was posted to the JRP Registry.
T2P OX8
It can be accessed at http://www.ngps.nt.ca/registryDetail_e.asp.
Dear Ms. Erickson:
I am a signatory to the JRP Report and agree with its conclusions
Mackenzie Gas Project Hearing Order GH-1-2004
NEB Authorization Order MO-13-2004
I refer to the above Authorization approved by the National Energy Board
(NEB or Board) on October 15, 2004, in accordance with the provisions
of subsection 15 (1) of the National Energy Board Act (NEB Authorization).
On September 2, 2004, I was appointed by the federal Minister
of Environment (Minister) as a member of the Joint Review Panel
for the Mackenzie Gas Project (JRP), pursuant to the Agreement for
an Environmental Impact Review of the Mackenzie Gas Project (JRPA),
and recommendations.
I adopt the JRP Report as my report to the NEB for the purpose of fulfilling
the requirements of the NEB Authorization. Insofar as the JRP Report
recommendations are directed to and address matters within the
jurisdiction of the NEB, I recommend them for the Board’s consideration.
Yours truly,
[original signed by]
Rowland J. Harrison, Q.C.
between the Mackenzie Valley Environmental Impact Review Board,
the Inuvialuit Game Council and the Minister.
1249_NEB_MGP_Vol2_Text_ENG.indd 234
12/6/10 11:03:03 AM
Appendix H 235
Appendix H
National Energy Board’s letter to
Joint Review Panel regarding modifications
9 March 2010
Mr. Robert Hornal
Chair
the Proponents1. In accordance with subsection 137(2) of the MVRMA,
the NEB is identifying the comments received as new information
the NEB is considering that was not before the JRP.
Joint Review Panel for the Mackenzie Gas Project
The attached Table of Concordance for JRP Recommendations and
c/o Northern Gas Project Secretariat
NEB Proposed Conditions (Appendix 1) indicates how the NEB proposes
5114 – 49th Street
to address each JRP recommendation that was addressed to the NEB.
Yellowknife, NWT X1A 1P8
Some of the proposed modifications apply to more than one
Mackenzie Gas Project (MGP) – Hearing Order GH-1-2004
recommendation as described in the following categories.
Consult to Modify Process for the Recommendations Identified
Clarification of the Desired End Result
in the Joint Review Panel (JRP) Report on the Environmental
When the NEB prepares conditions it does so with a desired end result
Impact Review of the Mackenzie Gas Project
(DER) in mind. The DER is the goal or specific outcome expected in
The National Energy Board (NEB) is considering the JRP report (Report)
issued on 30 December 2009. Pursuant to section 137 of the Mackenzie
Valley Resource Management Act (MVRMA), the purpose of this letter
is to consult with the JRP on possible modifications to the specific
recommendations in the Report that were directed to the NEB. The
NEB will make final decisions in these matters after final argument.
On 6 January 2010 the NEB set out a comment process regarding
the Report and the JRP recommendations that were within the
NEB’s mandate. On 28 January 2010 the NEB received comments from
the Proponents of the Mackenzie Gas Project . On 11 February 2010 the
NEB received comments from parties to the NEB Hearings and the JRP
response to a condition. This way, the proponent can understand the
intent of the condition and the NEB can verify compliance. The NEB
prefers to use a goal-oriented approach in describing the DER, whereby
the NEB is clear as to the specific outcomes that must be produced.
The Proponent is left with flexibility in choosing how to best achieve
these outcomes. Verification of compliance with statutes, regulations and
conditions continues throughout the project lifespan from the approval
stage and continuing through construction, operation and abandonment.
The NEB is considering modifying some of the recommendations to create
conditions that have clearly stated desired end results, can be measured
for compliance, and are goal-oriented.
Hearings. On 18 February 2010 the NEB received reply comments from
[1] Documents from the comment process can be found on the National Energy Board’s
website by clicking on this hyperlink. Alternatively go to www.neb-one.gc.ca. On the
right side of the page under “Major Applications (s. 52)” click on Mackenzie Gas Project,
then click on the link under the heading “Regulatory Documents”. Go into the “6 - Joint
Review Panel Report, Mr. Harrison’s s. 15 Report and Consult to Modify Process” folder
and choose “C - Comments to NEB on Joint Review Panel Recommendations”.
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236 Mackenzie Gas Project • Volume 2: Implementing the decision
Prevailing Statutes and Regulations
Adjustments to the Timing for Implementation
Every certificate, authorization or approval issued by the NEB under the
The NEB regulates safety, security, environmental and economic matters
National Energy Board Act (NEBA) or the Canada Oil and Gas Operations
throughout a project’s life span. The NEB is considering reorganizing
Act (COGOA) must comply with the prevailing statutes and regulations.
several recommendations to reflect the normal sequence of project
Regulations have been issued requiring companies to:
activities and, accordingly, the filing of related manuals and plans.
• follow specified technical standards for the safety, security and
Within the Jurisdiction of Other Regulatory Authorities
protection of people, the environment and property (for example,
In the NEB’s view, some recommendations fall within the jurisdiction
the Onshore Pipeline Regulations, 1999 and the latest versions of
of other regulatory authorities. Conditions imposed by the NEB in such
relevant design codes, including the Canadian Standards Association
cases could conflict with existing and future regulatory requirements.
Z662, Oil and Gas Pipeline Systems)
Duplication serves no useful purpose and undermines an effective and
• follow toll and tariff requirements (for example, the Toll Information
Regulations and Gas Pipeline Uniform Accounting Regulations);
efficient regulatory process. Therefore, the NEB is considering not
including such recommendations as conditions.
• develop manuals, programs and plans to manage the operations of
pipelines, plants and field developments.
created by the land claim agreements in the Northwest Territories when
The NEB expects to see these requirements reflected in environmental
matters of mutual interests arise in the implementation of the respective
protection plans, design drawings and specifications filed pursuant
conditions attached to the various permits which may be issued in respect
to any approvals.
of the Mackenzie Gas Project .
Flexible and goal-oriented regulations such as those made under
Delegation of Authority
the NEBA and COGOA allow regulatory requirements and industry
Some of the JRP’s recommendations require other persons, groups
practices to improve and adapt efficiently over the life span of a facility.
or agencies to approve something in order for a proposed NEB condition
The Board issues guidance notes for its goal oriented-regulations which
provide assistance to interested parties in understanding the requirements
of the regulations and how requirements could be met. The NEB verifies
compliance through audits and inspections.
1249_NEB_MGP_Vol2_Text_ENG.indd 236
The NEB will continue to work in collaboration with the organizations
to be satisfied. In monitoring compliance with conditions it is important to
be clear on who is accountable for specific outcomes. The NEB is charged
by statute with making the decisions on whether the Mackenzie Gas
Project , taking into account the conditions that would be imposed, is in
the public interest. If the satisfaction of conditions must be approved by
In a number of instances recommendations require information to be filed
others, accountability becomes unclear. Multiple approvals for the same
which would come to the NEB through prevailing statutes and regulations.
requirement do not contribute to achieving concrete results. Accordingly,
In these cases, a condition would be duplicative. Accordingly the NEB is
the NEB considers it inappropriate to delegate these decisions to others by
considering not including such recommendations as conditions.
requiring their approval for conditions to be satisfied.
12/6/10 11:03:03 AM
Appendix H 237
However, the NEB strongly promotes consultation with those affected
Closing
by the decisions it makes and with those who have relevant expertise
Should the Mackenzie Gas Project be approved, the JRP recommendations
and information. Therefore the NEB is considering an approach whereby
directed to the NEB with the possible modifications set out herein could
the Proponents are required to consult with appropriate parties and file
be included as conditions in any approvals granted. For your reference a
the results of consultation with the NEB, rather than requiring other
complete list of potential NEB conditions for the Mackenzie Gas Project is
parties to approve the Proponents’ filings to the NEB.
attached (Appendix 2).
Outside the Scope of the Mackenzie Gas Project Applications
The NEB will proceed to final argument on 12 April 2010 and requests
Some JRP recommendations relate to future facilities for which
that the JRP provide any comments it may have on the proposed
applications have not yet been made to the NEB. Although some of
modifications by 31 March 2010.
these facilities were within the scope of the JRP’s environmental review,
they are not within the scope of the applications the NEB is currently
considering. The NEB is considering not including conditions that relate
Yours truly,
[Original signed by J. Morales]
to future applications in the decisions it must make in the GH-1-2004
proceeding. These recommendations will be available for consideration
by the NEB when applications for the future facilities come before it.
Operational Matters
for
Anne-Marie Erickson
Acting Secretary of the Board
Some JRP recommendations are directed to NEB operational matters
rather than to the Proponents of the Mackenzie Gas Project . The NEB will
consider these recommendations if it approves the project and if the
Attachments
Proponents decide to proceed, but they are not being considered for
cc: Parties to the JRP Hearing
inclusion as conditions.
Parties to the GH-1-2004 Hearing
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238 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix I
Concordance table
JRP No.
Title of JRP Recommendation
NEB Condition
5-1
Proponents’ Commitments
1, N1, T1, P1
Since the National Energy Board (NEB) may not adopt all of the recommendations in
the Joint Review Panel (JRP) report, it proposes removing the phrase "or except where
the Joint Review Panel for the Mackenzie Gas Project (the Panel) has recommended otherwise."
5-2
NGTL Approval Conditions
–
Outside the scope of the Mackenzie Gas Project (MGP) applications as it involves
future application(s).
6-1
Baseline
37
Addressed in Condition 37.
Timing adjusted to require earlier submission of information.
Adjusted to clarify desired end result.
6-2
Final Designs,
Impact Assessments,
Mitigation Plans
3, 6, 7, 14, 38, 39,
41, 42, 44, 45, 46,
47, 48, 49, 51, 70,
N7
The elements of this recommendation are addressed in the NEB conditions listed or
through prevailing statutes and regulations [monitoring and ongoing mitigation of integrity
and environmental issues would be dealt with during operation by the requirements
of the Onshore Pipeline Regulations, 1999 (OPR) sections 39, 40 and 48].
Timing adjusted to require earlier submission of information.
6-3
Impacts of Climate Change
6, 70, 72, N8, T7, P8
Addressed in the conditions listed.
Timing adjusted to allow for earlier submission of information.
Adjusted to clarify desired end result.
6-4
Construction and Operations
Plan – KIBS/Fish Island
3, 38, N11, T10, P10
Addressed in the conditions listed.
Kendall Island Bird Sanctuary (KIBS) – falls within the jurisdiction of other regulatory
authorities [Environment Canada].
Fish Island – addressed through prevailing statutes and regulations [sections 39 & 48 of the OPR].
This recommendation will also be addressed in the Environmental Protection Plan.
6-5
Fill and Ditch Subsidence
44
Addressed in Condition 44.
6-6
Frost Bulb and
Aufeis Mitigation
51
Addressed in Condition 51, which requires Proponents' consultation
with Department of Fisheries and Oceans.
Timing adjusted to allow for consultation.
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Appendix I 239
JRP No.
Title of JRP Recommendation
NEB Condition
6-7
Groundwater Mitigation
48, 49
Addressed in Conditions 48 and 49.
To be incorporated into the slope design report required in Condition 48.
The NEB has the required expertise to assess adequacy.
6-8
Sediment Mitigation
3, 38
Sediment control is routine for stream crossing design and construction and the NEB would expect
it to be part of stream crossing designs and incorporated within the Environmental Protection Plan
as required by Conditions 3 and 38.
Addressed through prevailing statutes and regulations [post-construction monitoring for issues
would be by overflights of the right of way undertaken as part of the monitoring and surveillance
requirements of OPR section 39].
6-9
Acid Rock Drainage Mitigation
3, 38, 43
Timing adjusted to obtain the information earlier.
Conditions 3 and 38 incorporate the need for an acid rock drainage prevention plan.
Condition 43 includes consideration of the environment in the replacement backfill
and padding specifications.
6-10
Taglu/Niglintgak
Subsidence and Flooding
N4, T3
6-11
Permafrost and
Terrain Research and
Monitoring Program
39, 71, 72, N7
Although this recommendation is not directed at the NEB, the effects monitoring plan
from recommendation 6-2 (Condition 39) as well as Conditions 71 and 72 will support
any government program.
6-12
Adoption of Proposed
NEB Conditions
9, 10, 37, 39, 43, 45,
46, 47, 48, 49, 51,
66, 70, 71, 72, N4,
T3
Addressed in the conditions listed.
Spill Contingency
Planning and Reporting
4, N20, T19, P19
The listed conditions require an Emergency Response Plan for the construction phase
of the project of a greater scope than what is proposed in this recommendation.
7-2
Addressed in Conditions N4 and T3.
Adjusted to clarify desired end result.
Outside the scope of the Mackenzie Gas Project applications to the extent it involves future
application(s).
Addressed through prevailing statutes and regulations [OPR sections 32 to 35 address
the operations phase].
Canada Oil and Gas Operations Act (COGOA) paragraph 5(1)(b) requires a contingency plan.
7-3
Spill Prevention
and Response – Highways
–
Falls within the jurisdiction of other regulatory authorities [Government of the Northwest
Territories].
7-4
Spill Prevention and Response
– Hazardous Materials
4
Addressed in Condition 4.
Addressed through prevailing statutes and regulations [the construction safety manual
(OPR section 18) contains training and handling requirements].
The Environmental Protection Plan required for construction addresses the remaining
issues as part of the general environmental protection measures.
During the operating phase, the training, handling and monitoring requirements
for hazardous materials are dealt with as part of the Environmental Protection Program
and Operations and Maintenance manuals.
COGOA paragraph 5(1)(b) requires safety plan, environmental protection plan
and contingency plan.
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240 Mackenzie Gas Project • Volume 2: Implementing the decision
JRP No.
Title of JRP Recommendation
NEB Condition
7-5
Spill Prevention
and Response – Bulk Fuel
Storage on Ice or Water
–
Falls within the jurisdiction of other regulatory authorities [Transport Canada].
7-6
Spill Prevention
and Response – Bulk Fuel
Storage on Land
–
Falls within the jurisdiction of other regulatory authorities [Indian and Northern Affairs Canada].
7-7
Environmental
Emergency Plans
4, 61, 62, N20, N21,
T19, T20, P19, P20
Addressed in conditions listed. Incorporated in Emergency Response Plans.
Timing adjusted to allow for earlier filing of plans.
Adjusted to clarify desired end result.
Addressed through prevailing statutes and regulations [OPR sections 32 to 35 address
the Operations phase].
COGOA paragraph 5(1)(b) requires safety plan, environmental protection plan
and contingency plan.
7-8
7-9
Accident and Malfunction
Plans –Earthquakes
4, 61, 62, N20,
T19, P19
Addressed in the conditions listed.
Transportation
Emergency Preparedness
and Response Plan
4, N20, T19, P19
Addressed in the conditions listed.
Addressed through prevailing statutes and regulations [accidents and malfunction
caused by an earthquake would be addressed in the Emergency Response Plan required
by OPR section 32 and Conditions 61 and 62 ].
Incorporated in the Emergency Response Plans.
Adjusted to clarify desired end result.
1249_NEB_MGP_Vol2_Text_ENG.indd 240
7-10
Local Spill Response Teams
61
The proponent would be required to assess the potential for local spill response teams
for pipeline operation as part of Condition 61.
7-11
Spills Management –
Mackenzie River
–
This will be considered in collaboration with the other parties to the Northwest Territories/
Nunavut Spills Working Agreement.
8-1
Regional Air Quality
Management Strategy
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
8-2
Final Design, Construction
and Operations Procedures
13, N14, N16, T13,
T15, P13, P15
Addressed in the conditions listed.
8-3
Air Quality and Emissions
Management Plan
11, 12, 13, 15, 59,
67, N10, N11, N14,
N15, N16, N17, T10,
T13, T14, T15, T16,
P10, P13, P14, P15,
P16
Addressed in the conditions listed.
12/6/10 11:03:04 AM
Appendix I 241
JRP No.
Title of JRP Recommendation
NEB Condition
8-4
Air Quality Impacts
Monitoring Program
15, 16, 59, N11,
N12, T10, T11,
P10, P11
Addressed in the conditions listed.
8-5
Waste Management Plan –
Incineration
12, 16, 59, N11,
N12, N15, T10,
T11, T14, P10, P11,
P14
Addressed in the conditions listed.
8-6
Greenhouse Gas
Emissions Targets
11, 13, 59, N11,
N14, N16, T10, T13,
T15, P10, P13, P15
Addressed in the conditions listed.
8-7
Greenhouse Gas
Emissions Monitoring
59, N11, T10, P10
Addressed in the conditions listed.
9-1
Fish and Fish Habitat
Decision Trees
50, N26, T25, P25
Addressed in the conditions listed.
A waste management plan is also part of the Environmental Protection Program
during operation.
Timing adjusted to allow Proponent more time for design and consultation.
Adjusted to clarify the desired end result.
Adjusted to replace the delegation of authority with consultation.
9-3
Stream Flow Mitigation
39, 51, 69
Addressed in the conditions listed.
Addressed through prevailing statutes and regulations [OPR 39 and 48].
Adjusted to replace the delegation of authority with consultation.
9-4
Fish Habitat
Compensation Plan
–
Falls within the jurisdiction of other regulatory authorities
[Department of Fisheries and Oceans].
9-6
Fish and Fish Habitat
Inspection and Enforcement
–
The NEB would work with other responsible agencies as appropriate to develop an
enforcement and inspection strategy.
9-7
Dredging and Barge
Landings Plans
T9
Mackenzie Gas Project - Falls within the jurisdiction of other regulatory authorities [Transport
Canada, Environment Canada & Department of Fisheries and Oceans].
Development plan applications - addressed in Condition T9 for the proposed
Taglu barge landing.
9-8
Dredging Plans – VLMs
–
Falls within the jurisdiction of other regulatory authorities [Environment Canada
and Department of Fisheries and Oceans].
9-9
Excavation/Dredging Plan –
Niglintgak
N10
Addressed in Condition N10.
9-10
Marine Mammal
Protection Plan
–
Falls within the jurisdiction of other regulatory authorities [Transport Canada,
Environment Canada & Department of Fisheries and Oceans].
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242 Mackenzie Gas Project • Volume 2: Implementing the decision
JRP No.
Title of JRP Recommendation
NEB Condition
10-1
Wildlife Protection and
Management Plans
29, 30, 31, N22,
N23, N24, N25, T21,
T22, T23, T24, P21,
P22, P23, P24
To address the recommendations in chapter 10 of the JRP's report, a systematic approach
to laying out the conditions is warranted to aid effective implementation and future compliance
verification. The NEB has included a condition that sets out the framework for a Wildlife Protection
and Management Plan based on the recommendations of the JRP, with species-specific details
found in subsequent conditions. Together, this set of conditions is intended to address
the JRP's recommendations related to wildlife protection and management.
Timing adjusted to allow for earlier filing of data.
Adjusted to clarify desired end result.
Adjusted to replace delegation of authority with consultation.
Outside the scope of the Mackenzie Gas Project applications to the extent that it involves future
application(s).
10-2
Yellow Rail and Western Toad
34
Included as species-specific details to Wildlife Protection and Management Plan(s) (see 10-1).
Adjusted to replace the delegation of authority with consultation.
10-4
Listed Species Assessments
29, N22, T21, P21
Addressed in the conditions listed (see 10-1).
Adjusted to clarify the desired end result.
Outside the scope of the Mackenzie Gas Project applications to the extent that it involves future
application(s).
10-6
Future Development and
Woodland Caribou
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
10-7
Parsons Lake Airstrip
Operating Procedures
P21
Addressed in Condition P21.
Porcupine Caribou Herd
Protection Plan
31, N23, T22, P22
10-8
Addressed in the Wildlife Protection and Management Plan(s) (see 10-1).
Addressed in the conditions listed.
Included as species-specific details to Wildlife Protection and Management Plan(s) (see 10-1).
Adjusted to replace delegation of authority with consultation.
10-11
Grizzly Bear Den Surveys
32, N27, T26, P26
Addressed in the conditions listed.
Included as species-specific details to Wildlife Protection and Management Plan(s) (see 10-1).
10-15
Future Development and
Polar Bears
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
10-16
Wildlife Protection
and Management Plans –
Listed Species
29, N22, T21, P21
Addressed in the conditions listed (see 10-1).
Wood Bison Plan
33
10-17
Outside the scope of the Mackenzie Gas Project applications to the extent that it involves future
application(s).
Addressed in Condition 33.
Included as species-specific details to Wildlife Protection and Management Plan(s) (see 10-1).
Adjusted to replace delegation of authority with consultation.
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Appendix I 243
JRP No.
Title of JRP Recommendation
NEB Condition
10-18
Short-Eared Owls and
Rusty Blackbirds Surveys
35, N24, T23, P23
Peregrine Falcon Protection
and Management Plan
36, N25, T24, P24
Raptor Protection and
Management Plan
36, N25, T24, P24
Air Operations Plan – Taglu
T21
10-19
10-20
10-24
Addressed in the conditions listed.
Included as species-specific details to Wildlife Protection and Management Plan(s) (see 10-1).
Addressed in the conditions listed.
Included as species-specific details to Wildlife Protection and Management Plan(s) (see 10-1).
Addressed in the conditions listed.
Included as species-specific details to Wildlife Protection and Management Plan(s) (see 10-1).
Addressed in Condition T21.
Addressed in the Wildlife Protection and Management Plan(s) (see 10-1).
10-25
De-Icing Fluid Management
16, N12, T11, P11
Addressed in the conditions listed.
Addressed in Waste Management Plan (see 14-3)
10-26
Noise Emissions – KIBS
N9, T8
Addressed in Conditions N9 and T8.
Alberta’s Energy Resources Conservation Board Directive 038 permissible sound level
of 40 dBA at 1.5 km may be adjusted to reflect “best management practices”
and “best available technologies”.
11-8
Approval of Community
Conservation Plans and
land use plans that
incorporate socio-cultural
and ecological thresholds
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
11-10
Legal enforceability of
approved Community
Conservation Plans in the
Inuvialuit Settlement Region
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
11-15
Interim protection of
Sahtu Settlement Area
lands identified as
having high conservation
value or traditional
and cultural importance
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
11-16
Approval of the
Sahtu Land Use Plan
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
11-18
Approval of the
Dehcho Land Use Plan
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
12-2
Harvester Compensation
Agreements (NWT) –
Communication
–
Falls within the jurisdiction of other regulatory authorities [specified within
the various Land Claim Agreements].
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244 Mackenzie Gas Project • Volume 2: Implementing the decision
JRP No.
Title of JRP Recommendation
NEB Condition
12-5
Harvester Compensation
Agreements (Alberta) –
Communication
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
12-6
Worst-Case Scenarios
MGS1, MGS75, N1,
N5, T1, T5, P1, P6
Addressed in the conditions listed.
13-2
Granular Management Plan
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
13-3
Merchantable Timber
MVP75
Addressed in Condition 75 for the Mackenzie Valley Pipeline.
Adjusted to clarify desired end result.
13-6
Heritage Resources
Management Plan
21
Addressed in Condition 21.
14-1
Transportation and
Logistics Plan
–
Falls within the jurisdiction of other regulatory authorities [GNWT].
14-2
Community Services/
Infrastructure
22
Addressed in Condition 22.
14-3
Waste Management Plan
16, N12, T11, P11
Addressed in the conditions listed.
15-9
Diversity Plans
23, N28, T27, P27
Addressed in the conditions listed.
Adjusted to clarify desired end result.
Adjusted to clarify desired end result.
Adjusted to clarify desired end result.
15-10
Employee Travel
to Work Sites
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
16-1
Closed Work Camps
24
Addressed in Condition 24.
16-2
Existing Camps
25
Addressed in Condition 25.
Adjusted to replace delegation of authority with consultation.
16-3
1249_NEB_MGP_Vol2_Text_ENG.indd 244
Worker Interactions –
Fort Good Hope and Tulita
26
Addressed in Condition 26.
12/6/10 11:03:04 AM
Appendix I 245
JRP No.
Title of JRP Recommendation
NEB Condition
16-4
Noise Monitoring
15, 68, N9, N11, T8,
T10, P9, P10
Addressed in the conditions listed.
16-23
Issues Resolution Program
27, N29, T28, P28
Addressed in the conditions listed.
Outside the scope of the Mackenzie Gas Project applications to the extent it involves future
application(s).
17-1
17-2
Extension of NEB
Decommissioning and
Abandonment Principles
MGS77, MGS78,
MGSTolls4, N5, N6,
T5, T6, P6, P7
Addressed in the conditions listed.
Coordination of
Decommissioning and
Abandonment Approvals
MGS77, MGS78,
MGSTolls4, N5, N6,
T5, T6, P6, P7
Addressed in the conditions listed.
Adjusted to clarify desired end result.
Adjusted to clarify desired end result.
The NEB will continue to work collaboratively with Northern agencies
to develop a coordinated and effective approach.
18-5
Adaptive Management
Components
–
The NEB subscribes to the principles of adaptive management.
18-7
Local NEB Office
–
This is an operational matter that the NEB will consider should the applications be approved
and the Proponents decide to proceed.
18-8
NEB Reports
–
The NEB will continue to work collaboratively with Northern agencies to develop a coordinated
and effective approach regarding compliance and inspection activities for the project.
All reports filed in compliance with conditions will be available on the NEB’s website.
18-9
Comprehensive
Environmental Management
Plans
3, 38, 59, N11, T10,
P10
Addressed in the conditions listed.
18-10
Coordination of Compliance
Monitoring
–
The NEB will continue to work collaboratively with Northern agencies to develop a coordinated
and effective approach regarding compliance and inspection activities for the project.
18-11
Local Monitors
28, N30, T29, P29
Addressed in the conditions listed.
18-21
Future Developments
–
Outside the scope of the Mackenzie Gas Project applications as it involves future application(s).
1249_NEB_MGP_Vol2_Text_ENG.indd 245
Addressed through prevailing statutes and regulations [OPR and Canada Oil and Gas Drilling
and Production Regulations].
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246 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix J
Joint Review Panel’s response
to NEB’s consult to modify process
March 29, 2010
Ms. Anne-Marie Erickson
Secretary
National Energy Board
444 – 7th Avenue S.W.
Calgary, Alberta
T2P 0X8
In the absence of guidance, the Panel has concluded that its role
is to provide overall comments directed at whether, in the Panel’s
view, any modifications that are proposed to be made to the Panel’s
recommendations would have the effect of nullifying or undermining
the Panel’s overall conclusions with respect to the likely significance
of the impacts of the Mackenzie Gas Project and its contribution
to sustainability. In the Panel’s view, it is not the Panel’s role to “pass
judgment” on the drafting of measures that appear to be directed
Dear Ms. Erickson:
at implementing the Panel’s recommendations.
Mackenzie Gas Project (MGP) – Hearing Order GH-1-2004
It appears to the Panel that, generally, and subject to the following
Consult to Modify Process for the Recommendations Identified in
the Joint Review Panel (JRP) Report on the Environmental Impact
Review of the Mackenzie Gas Project
two paragraphs, the NEB Proposed Conditions have not rejected any
of the Panel’s recommendations that are directed to the NEB and that
the modifications proposed by the NEB are primarily for the purpose
of ensuring that the implementation of those recommendations conforms
The Joint Review Panel for the Mackenzie Gas Project (JRP or Panel)
to established NEB protocols and procedures, operational requirements
acknowledges receipt of the letter of March 9, 2010 from the National
and other statutes and regulations. Where the proposed modifications
Energy Board (NEB) for the purpose of “consult[ing] with the JRP on
might affect the interests of other parties (for example, where information
possible modifications to the specific recommendations in the [JRP]
is to be provided to other regulators), the Panel notes that those parties
Report that were directed to the NEB” (the “NEB letter to consult”).
may present their views to the NEB.
The JRP has considered the NEB letter to consult and provides the
In the Table of Concordance forwarded with the NEB letter to consult, the
following comments.
NEB has noted in several instances that the relevant JRP recommendation
The JRP first notes that neither the Panel’s Terms of Reference nor
the Mackenzie Valley Resource Management Act (MVRMA) provide the
Panel with any guidance on the Panel’s role in the “consult to modify”
process, which, the Panel notes, is unique to the MVRMA. The Panel
has considered the Mackenzie Valley Environmental Impact Review Board
Reference Bulletin of June 5, 2005 but has found it to be of limited
is “[o]utside the scope of the Mackenzie Gas Project (MGP) applications
as it involves future application(s).” The JRP does not understand this
notation to be a rejection by the NEB of the relevant recommendation.
The relevant JRP recommendations stand and the Panel expects that
they would, accordingly, be considered by the NEB in the specific context
of any future applications.
assistance in guiding the Panel.
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Appendix J 247
In several other instances, the NEB has noted in its Table of Concordance
that certain JRP recommendations are “within the jurisdiction of other
regulatory authorities…” In these instances, the substance of the Panel’s
recommendations stands and the specific recommendations should be
read as being directed to the relevant regulatory authority.
The Panel understands that the Government of Canada will, pursuant to
section 135 of the MVRMA, consult the Panel in the event the Government
proposes to make any modifications or rejections to the Panel’s
recommendations. The Panel may make further comments at that time.
The Panel reaffirms its overall conclusion that the adverse impacts of
the Mackenzie Gas Project and the Northwest Alberta Facilities would
likely not be significant and that the project and those Facilities would
likely make a positive contribution towards a sustainable northern future,
“subject to the full implementation of the Panel’s
recommendations.”
Sincerely,
[Original signed by]
Robert Hornal
Joint Review Panel Chair
cc: All Parties to the Environmental Impact Review conducted
by the Joint Review Panel for the proposed Mackenzie Gas Project
Mr. Joe Acorn
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248 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix K
Conditions for the Mackenzie Valley Pipeline
Unless otherwise specified in the condition, pre-construction activities
Unless otherwise specified in a condition best available technology (BAT)
include activities such as: clearing and grading for infrastructure develop-
means technology with superior emissions performance which is commer-
ment; construction and operation of camp facilities; the development
cially available at a reasonable cost at the time it is required for the project
of borrow pits, roads, and airstrips; snow pad construction; the transpor-
which meets the goals of pollution prevention and energy efficiency.
tation and stockpiling of fuel and material; and geotechnical investigations
necessary for the construction of the pipeline project. Pre-construction
activities may include other activities such as clearing of the right of way
if approved by the National Energy Board. Pre-construction activities do
not include activities associated with normal surveying operations or
data collection activities.
Unless otherwise specified in the condition, pipe-laying operations
include the clearing of vegetation in proximity of water crossings and
on thaw sensitive slopes, as well as grading and trenching and other
Unless otherwise specified in a condition best management practices
(BMP) are innovative, dynamic, and improved environmental protection
practices and procedures that help ensure that development is conducted
in an environmentally responsible manner. BMP may exist as formal
guidelines or generally accepted procedures that are recognized by
regulators and industry associations as best practices.
Conditions that correspond for the Mackenzie Valley Pipeline
and the Mackenzie Gathering System
forms of right of way and station site preparation that may have
General
an effect on the environment through to final clean-up and reclamation.
1.
the approved facilities to be designed, located, constructed,
Unless otherwise specified, Proponent consultation referred to in
installed and operated in accordance with the commitments,
a condition must be carried out in a manner that includes the Proponent:
a)
specifications, standards, policies, mitigation measures, procedures,
providing, to the party to be consulted,
and other information referred to in its application or in the
i) notice of the matter in sufficient form and detail to allow
Environmental Impact Statement or other filings, or as otherwise
the party to prepare its views on the matter,
agreed to during the GH-1-2004 Hearing and during the review
by the Joint Review Panel.
ii) a reasonable period for the party to prepare those views, and
iii) an opportunity to present those views to the party conducting
the consultation; and
b)
1249_NEB_MGP_Vol2_Text_ENG.indd 248
Unless the NEB otherwise directs, the Proponent shall cause
2.
Unless the NEB otherwise directs, the Proponent shall comply with
all filing timelines and completion dates set out in these conditions.
considering, fully and impartially, any views so presented.
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Appendix K 249
Prior to Pre-Construction Activities
3.
To compile and communicate all of the Proponent’s environmental
protection procedures, mitigation measures, and monitoring
commitments pertaining to pre‑construction activities to its field staff
and to the NEB inspectors, the Proponent shall file with the NEB an
Environmental Protection Plan (EPP) for approval at least 90 days prior
to the start of pre-construction activities. The EPP may be divided
into separate plans by region or project area as deemed necessary.
The pre-construction EPP shall include:
a) the scope and area of application of the EPP;
b) environmental protection procedures and measures, including
decision criteria for timing and implementation of these
measures, site-specific plans and drawings, mitigation measures,
and monitoring applicable to pre-construction activities;
c) an acid rock drainage prevention plan incorporating the testing
of quarried and exposed rock during infrastructure, borrow pit
and quarry development and provisions for the safe disposal or
treatment of unsuitable material if required;
d) references to other plans and manuals for environmental
protection required by field staff and inspectors; and
e) evidence of consultation with appropriate regulatory
authorities and government subject matter experts in
the area of application of the EPP.
4.
To address worker and public safety and environmental protection
during construction in the unique northern environment, the
Proponent shall file an Emergency Response Plan with the NEB
at least 60 days prior to the start of pre-construction activities
which shall address 24-hour medical evacuation, fire response
and hazardous chemical and fuel spill response and security issues.
The Emergency Response Plan shall be prepared in consultation
with Indian and Northern Affairs Canada, the Canadian Coast
Guard, Transport Canada, Environment Canada, the Government
of the Northwest Territories and the Inuvialuit Land Administration,
as applicable, and shall include:
a) the scope of the plan detailing the project infrastructure,
geographic and time period covered by the plan;
b) training and orientation requirements of company
and contractor staff;
c) an inventory of petroleum products, chemicals and other
hazardous substances, together with corresponding MSDS
sheets, that will be transported, stored and/or used during
the pre‑construction and construction phases;
d) storage facilities and locations of the above inventoried
products and substances;
e) identification of resources (equipment and staff)
to be on-site and/or available to respond to emergencies;
f) identification of mutual aid partners and the location
of their resources (equipment and staff) available to
respond to emergencies;
g) procedures for responding to spills, releases, fires, medical
emergencies and security issues including the incident reporting
and notification system;
h) location of fire and spill response equipment stores and
the spill kit requirements for vehicles;
i) a phone list of company, contractor, government agency
and community representatives outlining their respective roles
and information needs;
j) clean-up and disposal procedures for generated clean-up wastes;
k) identification of muster points for emergency evacuations
from camps and facilities;
l) location of emergency medical treatment locations
and capabilities;
m)the requirement for 24-hour emergency medical
evacuation capability; and
n) maps showing the location of the right of way and
infrastructure such as camps, access roads, material storage
areas, barge landing sites and borrow pits to facilitate
the dispatch of first responders.
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250 Mackenzie Gas Project • Volume 2: Implementing the decision
5.
To address worker and public safety in the unique northern
The manual shall include:
environment, the Proponent shall file a construction safety
a) required road width, clearing and grading requirements, grade,
manual with the NEB at least 60 days prior to the start
of pre-construction activities.
6.
To confirm consideration of the effects of climate change on
specific geohazard mitigation, slope and stream crossing designs
and terrain stability for the overall design life of the project, the
Proponent shall file a report six months prior to the start of
pre-construction activities which includes:
a) an analysis of the impacts of climate change and variability on
permafrost and terrain stability for a series of representative
locations and conditions using potential upper limit temperature
scenarios which may occur along the Mackenzie Valley;
b) a description of how these upper limit temperature scenarios
c) safe ice thickness criteria for lake, river and stream crossing
including the frequency of ice profiling;
d) local regulatory requirements;
e) installation and removal requirements for snow fills, culverts,
corduroy and temporary bridges; and
f) objective and measurable environmental and engineering
criteria for closure.
10. To demonstrate that the pipeline and project winter roads will be
constructed and operated in a safe and environmentally acceptable
manner, the Proponent shall file with the NEB a copy of any
applicable permits, authorizations and letters of advice issued by the
potential change in precipitation patterns in the detailed design
Federal departments, the Government of the Northwest Territories, or
of slopes and water course crossings for the project; and
local regulatory organizations that are referred to in an EPP or winter
and government departments.
To facilitate NEB inspections, the Proponent shall file with
the NEB updated environmental alignment sheets at least 90 days
prior to pre-construction activities, and shall file with the NEB any
modifications as they become available.
road manual at least 90 days prior to pre-construction activities.
11. The Proponent shall evaluate the technologies and practices
available to reduce emissions of particulate matter (PM) and PM
and ozone precursors from its facilities and construction related
activities, and incorporate the BMP and BAT to reduce emissions of
PM and precursors of PM and ozone to the extent practicable. The
Proponent shall file a report of its findings and how it will implement
To facilitate NEB inspections, the Proponent shall file with the
its findings to the NEB at least six months prior to construction
NEB a detailed construction schedule or schedules identifying major
of the Inuvik Area Facility, compressor stations and heater stations.
activities at least 30 days prior to pre‑construction activities and
pipe-laying operations, and shall notify the NEB of any modifications
to the schedule or schedules as they occur.
9.
criteria to determine when the winter road will be ready for use;
Mackenzie Valley;
d) the results of consultation with other appropriate regulators
8.
b) objective and measurable environmental and engineering
may impact precipitation and stream flows along the
c) a description of how the Proponent will account for the
7.
allowable speed, signage, maximum vehicle weight;
12. The Proponent shall evaluate and implement technologies and
practices available to reduce mercury, dioxin and furan emissions
from incinerators operating at construction camps and its station
To demonstrate that project winter roads will be constructed
facilities to the extent practicable. The Proponent shall file a report
and operated in a safe and environmentally acceptable manner,
of its findings and how it intends to implement its findings to the
the Proponent shall file with the NEB a manual for the construction,
NEB at least 60 days prior to the operation of its construction camps
operation, maintenance and closure of project winter roads
and station facilities.
at least 30 days prior to the start of project winter road construction.
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Appendix K 251
13. The Proponent shall file with the NEB at least 60 days prior
d) a description of the processes for the implementation
to the start of station facility construction, a report outlining:
of changes that may occur between the design information
a) the specific design and operational measures it has implemented
and material specifications submitted to the NEB as a result
and will implement to minimize methane leakage and venting
of Conditions 14 and 18, and the detailed design and
through the system’s operation taking into account BMP
the actual material properties.
developed by CAPP, Environment Canada, the Canadian
15. The Proponent shall file with the NEB for approval, at least 30 days
Energy Partnerships for Environmental Innovation and the
prior to the start of pre-construction activities an Air Quality
Canadian Gas Association;
Monitoring Program developed in consultation with Environment
b) how the Proponent has utilized waste heat energy
Canada, Health Canada and the Government of the Northwest
to minimize natural gas fuel consumption in the design
Territories, to be undertaken immediately prior to and during
of the Inuvik Area Facility;
construction. This program shall include:
a) identification of the baseline, pre-construction conditions;
c) the use of BAT when specifying compressor units used on
the project including size, efficiency and their conformity with
b) the location of monitoring sites on a map or diagram, the
Canadian Council of Ministers of the Environment National
purpose for the locations selected, and the timing for installation;
Emissions Guidelines for Stationary Combustion Turbines
c) methods and schedule of constituent monitoring
(CCME,1992); and
(PM, O3, NO2 and noise);
d) results of consultation with Environment Canada and the
d) data recording, processing and reporting details;
Government of Northwest Territories.
e) the process for public communication and complaint response; and
14. To demonstrate that the design is experimentally verified
f) details of the additional measures that would be implemented
and that the inputs and outputs of the design calculations
as a result of monitoring data or ongoing concern, and
are clearly determined for overland, slope and water crossing
the criteria or thresholds that would require these measures.
designs, the Proponent shall file with the NEB at least six months
prior to the start of pipe manufacture:
a) a stress/strain analysis, including all inputs, assumptions,
outputs, methods, and outline of process of calculation;
b) a detailed description and results of all verification tests
performed in support of the stress/strain analysis;
c) an explanation and reconciliation of any differences and
uncertainties that may result among:
The Proponent shall include a legacy plan detailing the measures
that would be continued through the operation phase as a result
of monitoring undertaken or ongoing concern and the criteria
or thresholds that are used to determine when they would no
longer be required.
16. In order that the right of way, camps and supporting infrastructure
are maintained, operated and left in an environmentally acceptable
condition following the construction phase of the project, the
i) stress/strain analysis inputs and outputs;
Proponent shall file a Waste Management Plan with the NEB for
ii) results of verification tests;
approval 90 days prior to the start of pre-construction activities.
iii) final material properties specifications; and
This plan shall be developed in consultation with the Government
iv) loads, stresses and strains pipelines may experience
of the Northwest Territories, Indian and Northern Affairs Canada
during transportation, construction, and operation; and
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252 Mackenzie Gas Project • Volume 2: Implementing the decision
and Environment Canada. The Waste Management Plan shall
17. To mitigate potential localized low fracture toughness in or adjacent
address all wastes associated with the construction of the project
to the welds which could be detrimental during anticipated pipeline
with the objectives of minimizing impacts to the environment and
deformation at low operating temperatures, the Proponent shall:
ensuring worker and public safety. The plan shall address air, land
a) determine the minimum acceptable value for the crack
and water quality; measures to minimize animal attraction; and
tip opening displacement (CTOD) for weld metal and heat
preventing uncontrolled fires. The scope of the plan shall include:
affected zone of mill circumferential, helical (if practicable) and
a) disposal or treatment of potentially hazardous and dangerous
longitudinal welds, for the lowest installation temperature and
materials, including petroleum products, toxic or persistent
the most severe deformation during construction or operation.
chemicals, oily wastes, de-icing fluids and fuel barrels;
The CTOD tests shall be conducted for all combinations
b) solid waste management including metals, plastics, recyclables,
of pipe steel producers and pipe mill manufacturers and be
incinerator ash, equipment, equipment parts, batteries, building
representative of applicable project pipe with the maximum
materials and construction waste;
Carbon Equivalent (CE) heat;
c) food waste management;
d) management of contaminated soil, snow and ice from spills
and de-icing activities;
e) treatment and disposal of waste water (including domestic
sewage and grey water); and
f) incinerator emissions monitoring.
The plan shall address:
i) incineration and evaporator technology choices
and rationale for selection;
ii) training requirements for operators;
iii) waste segregation requirements;
iv) interim waste storage;
v) treatment;
vi) testing method for waste streams proposed for release
to the environment (e.g. air and water);
vii) disposal method for waste streams proposed for release
to the environment; and
viii)final off-site waste disposal locations and facilities
including evidence of facility approvals and compliance
with regulations.
b) determine the minimum acceptable value for the CTOD for field
circumferential welds for the lowest installation temperature and
the most severe deformation during construction or operation.
The CTOD tests shall be conducted at the welding procedure
development phase, for all combinations of pipe steel producers
and pipe mill manufacturers and be representative of applicable
project pipe with the maximum CE heat. Deviations in the
essential changes as specified in CSA Z662-07, Table 7.3 and
Table K1 will require weld procedure requalification and retesting
to determine the minimum acceptable value for the CTOD; and
c) file with the NEB minimum acceptable CTOD values and results
of the tests:
i) for the mill qualification welds, at least 60 days prior
to the pipe manufacture; and
ii) for the field circumferential qualification welds,
at least 60 days prior to the field welding.
18. To demonstrate compliance with appropriate regulations,
standards and engineering practices and to facilitate NEB audits,
the Proponent shall file with the NEB the following documents,
to be finalized prior to the procurement of materials:
a) project-specific material specifications for pipe, fittings, valves,
and pig launchers and receivers, at least 90 days prior to the
start of manufacture of each of these elements;
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Appendix K 253
iv) locations and proposed timing of any planned pressure tests;
b) specifications for plant-applied coatings for buried and exposed
and
pipeline(s) and valves, at least 90 days prior to the application of
each coating. The specifications shall include coating materials,
v) locations of any unsuccessful pressure tests and their cause.
application methods, and verification test results;
c) specifications for materials to be used for the manufacture
20. To demonstrate the effective management of safety and
environmental protection matters during pre-construction and
of stations, the Inuvik Area Facility, and the Trout Lake Heater
construction, the Proponent shall file with the NEB at the start of field
Station, including applicable standards, and non-destructive
pre-construction activities, a diagram of the project’s organization,
examination methods and frequency, at least 60 days prior
clearly identifying roles, responsibilities and reporting structure.
to the start of the manufacture of each of these facilities;
d) joining program for mill welding, at least 90 days prior
21. The Proponent shall file with the NEB, at least 30 days prior
to the start of pre-construction activities, the Heritage Resources
to the start of manufacture of pipe, components or facilities
Management Plan as reviewed by the Prince of Wales Northern
in the plant;
Heritage Centre.
e) non-destructive examination specifications for the mill
non-destructive examinations at least 90 days prior
22. The Proponent shall file with the NEB, at least 90 days prior
to the start of pre-construction activities, the results of consultations
to the start of each non-destructive examination; and
regarding the conclusion of fee-for-service agreements with
f) project-specific quality assurance programs for all materials,
affected communities respecting the use of community services
components, and processes at least 90 days prior to
or infrastructure facilities.
manufacture of pipe components and facilities.
19. Unless the NEB otherwise directs, to facilitate NEB monitoring,
23. The Proponent shall file, at least 90 days prior to the start
of pre-construction activities, diversity plans, inclusive of gender
the Proponent shall file with the NEB project progress reports that
equality, for both the construction and operations phases
summarize major activities by construction spread, as follows:
of the Mackenzie Gas Project. The plans shall include:
a) every month during active construction periods; and
a) methods for determining diversity goals;
b) every two months during pre-construction and inactive
b) identification of diversity goals;
construction periods.
c) steps to achieve the identified goals;
These reports shall also provide:
d) commitments to the provision of a healthy
i) the description of any significant pipeline and facilities
and safe work environment;
design changes;
e) steps to create a Diversity Management Committee; and
ii) the list of any current and cumulative number of incidents,
f) a monitoring and reporting system.
accidents, or hazardous occurrences as defined in
regulations pursuant to the National Energy Act and
the Canada Labour Code Part II;
The Proponent shall require its contractors and subcontractors
to comply with the Proponent’s diversity plans.
iii) a description of any major activities planned for the next
reporting period;
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254 Mackenzie Gas Project • Volume 2: Implementing the decision
24. To minimize and address adverse impacts of any interactions
27. The Proponent shall file with the NEB, at least six months prior
between the construction workforce on the Mackenzie Gas Project
to the start of pre-construction activities, plans for a formal issues
and the communities in proximity to the project, the Proponent
resolution program that will be implemented during construction
shall implement closed work camps. This requirement shall
and operations of the Mackenzie Gas Project. The plans shall be
apply to all new work camps proposed by the Proponent,
prepared in consultation with the government of the Northwest
its contractors and subcontractors.
Territories, the Government of Yukon and Aboriginal authorities,
25. To minimize and address adverse impacts of any interactions
between workers in existing open camps that may be used
and include:
a) a description of the process by which any complaints or issues
for the project and the communities in proximity to those camps,
related to the Mackenzie Gas Project would be raised with
the Proponent shall identify to the NEB whether any of the existing
the Proponent or governments;
open construction camps will be used, either directly or indirectly,
b) a description of the process by which any received complaints
in relation to project construction. Where existing open camps are
or issues would be allocated among those with responsibility
to be used and are to remain open, the Proponent shall develop
for action and a description of the roles and responsibilities
a plan to minimize and address adverse impacts of any interactions.
of any party involved in assessing or responding to any
The plan should be developed in consultation with affected
complaint or issue;
communities, identify the specific measures to be employed to
address adverse impacts, and comply with the commitments made
by the Proponent. The plan shall be filed with the NEB at least six
months prior to the start of pre-construction activities.
26. To minimize and address potential adverse impacts of any
interactions between the construction workforce on the Mackenzie
Gas Project and the communities of Fort Good Hope and Tulita, the
Proponent shall file with the NEB, at least six months prior to the
start of pre‑construction activities, a plan to monitor the interactions
between the construction workforce and the communities.
The plan shall be developed in consultation with the leadership
c) a description of the process by which any received complaints
or issues would be resolved;
d) a description of any protocols developed for referral and
resolution of any complaints or issues;
e) a description of the recourse mechanisms for any unresolved
complaints or issues or any unsatisfactorily resolved complaints
or issues; and
f) a description of the process for communicating and informing
communities about the issues resolution program.
28. The Proponent shall file, prior to the start of pre-construction
of Fort Good Hope and Tulita, and include:
activities, information related to the hiring of local residents
a) plans for monitoring interactions;
as monitors to carry out compliance and environmental impact
b) the specific measures that will be employed to address
adverse interactions, should any be identified; and
c) plans for regular consultation and reporting on interactions
with both potentially affected communities.
monitoring for the Mackenzie Gas Project including:
a) the nature of the activities to be monitored;
b) clearly defined job descriptions for the positions as monitors;
c) identification of the training that will be offered to monitors
to enable them to perform their duties; and
d) confirmation that monitors have been hired.
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Appendix K 255
29. To minimize project-related impacts on wildlife species, the
Proponent shall file with the NEB for approval, before the detailed
pipeline route is filed with the NEB and at least 90 days prior
to the start of pre-construction activities, a Wildlife Protection and
Management Plan or Plans to address general wildlife protection
and specific protection of woodland caribou, barren ground
caribou, grizzly bear, polar bear and wolverine. The Wildlife
Protection and Management Plan(s) shall specify goals, area
covered by the plan(s), and assumed zones of influence of project
activities and rationales for these assumptions. The Wildlife
Protection and Management Plan(s) may be divided into separate
plans by region or project area as deemed necessary.
iv) measures to limit predator travel along right of ways;
v) procedures to avoid disturbance of potential maternal
denning areas;
vi) access management, including provisions for public
consultation;
vii) protocols and education/awareness activities for managing
human-wildlife interactions, including measures to limit
harvesting and to deter wildlife, especially bears, from
entering camps and other facilities;
viii)measures to reduce the impacts of access road, right
of way, and other project-related vehicle and air traffic
on wildlife and migratory birds; and
The Wildlife Protection and Management Plan(s) shall include:
a) results of pre-construction surveys, including surveys for species
at risk listed on Schedule 1 of the Species at Risk Act public
registry (listed species) except where the Minister has
determined that recovery for the species is not feasible,
and locations of any observations of species classified as at risk
or may be at risk on the most recent Committee on the Status
of Endangered Wildlife in Canada assessment and NWT General
Status Ranks;
ix) any wildlife protection measures included in other project
management plans, or references to those measures;
d) protocols for monitoring and adaptive management including:
i) establishing and maintaining linkages to regional programs;
ii) survey protocols to be employed to avoid or prevent impacts
to wildlife;
iii) plans for monitoring responses of wildlife to project activities
during all phases of the project;
b) updated impact assessments for listed species in consideration
iv) protocols for documenting habitat loss and habitat change
of the Species at Risk Act, conducting the impact assessments
as well as wildlife incidents, interactions and mortality; and
directly on the listed species where possible rather than using
one or more indicator species;
c) mitigation measures including:
i) measures to avoid or minimize disturbances including
linear disturbance and effects of habitat fragmentation,
sensory disturbance, and barriers to movement;
ii) scheduling of project activities to minimize wildlife
disturbance;
iii) measures to minimize the development footprint
in habitats known to support listed species;
v) measures to determine the effectiveness of mitigation
measures, criteria to determine when and how mitigation
measures should be adapted, as well as the responses
proposed to address unforeseen effects;
e) implementation plans, including:
i) details on how the plans will be implemented
by the Proponent;
ii) the measures the Proponent will take to enable
the participation of local monitors; and
iii) the process for updating the protection plan
as information gaps are addressed, including
listed species’ recovery strategies and action plans;
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256 Mackenzie Gas Project • Volume 2: Implementing the decision
f) processes for oversight and reporting with respect
to the Wildlife Protection and Management Plan(s)
and how those processes will be implemented; and
g) evidence of consultation with the Government of the
b) proposed mitigation measures for avoiding disturbance
to grizzly bear dens; and
c) a commitment to file the results of the surveys annually during
pre-construction activities and pipe-laying operations, prior to
Northwest Territories, Environment Canada and appropriate
the commencement of work planned for the coming season,
wildlife management boards or comparable organizations.
with the Government of the Northwest Territories and
To support the Wildlife Protection and Management Plan(s),
the Proponent shall implement the following species-specific
requirements, set out in Conditions 30 to 36, in addition
to the specifications of Condition 29.
30. The Proponent shall include in its Wildlife Protection
and Management Plan(s) (Condition 29) with respect
appropriate wildlife management boards.
33. The Proponent shall include in its Wildlife Protection
and Management Plan(s) (Condition 29):
a) mitigation measures to avoid creation of preferred
bison habitat; and
b) a monitoring program to detect wood bison use of
to woodland caribou:
the Mackenzie Gas Project’s right of way and a process
a) timing and dates during which project-related activities
to develop mitigation measures in consultation with
would occur so as to avoid or minimize conflict with caribou
the Government of the Northwest Territories if wood bison
movement or sensitive feeding or calving time; and
start using the project right of way.
b) evidence of consultation with the Dehcho Boreal
Caribou Working Group.
31. The Proponent shall include in its Wildlife Protection
34. The Proponent shall include in its Wildlife Protection and
Management Plan(s) (Condition 29):
a) the results of a survey in those parts of the Local Study Area
and Management Plan(s) (Condition 29) with respect
where, based on the most recent assessment by the Committee
to barren ground caribou:
on the Status of Endangered Wildlife in Canada, the yellow rail
a) timing and dates during which project-related activities
and western toad might occur, to confirm the presence or
would occur so as to avoid or minimize conflict with
caribou movement or sensitive feeding or calving time;
b) plans to address any impacts from the project on
the Porcupine caribou herd resulting from increased
use of the Dempster Highway by project-related traffic; and
c) evidence of consultation with the Porcupine Caribou
Management Board and the Government of Yukon.
32. The Proponent shall include in its Wildlife Protection and
Management Plan(s) (Condition 29) with respect to grizzly bear:
a) a plan to conduct annual grizzly bear den surveys during
pre-construction activities and pipe-laying operations prior
absence of those species;
b) proposed mitigation and monitoring measures specific to yellow
rail and western toad, based on the results of this survey; and
c) evidence of consultation with Environment Canada and the
Government of the Northwest Territories.
35. The Proponent shall include in its Wildlife Protection and
Management Plan(s) (Condition 29) a commitment to conduct
pre-construction, construction and post‑construction surveys
and monitoring programs in relation to short-eared owls
and rusty blackbirds and to file this information with the
Government of the Northwest Territories.
to the commencement of work planned for the coming season;
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Appendix K 257
36. The Proponent shall include in its Wildlife Protection and
Management Plan(s) (Condition 29) mitigation measures specific
The EPP for pipe-laying operations shall include:
a) the scope and area of application of the EPP;
to raptors, including peregrine falcon and bald and golden eagles,
b) environmental protection procedures and measures,
that include the following restrictions on project-related activities
including decision criteria for timing and implementation
or facilities, unless the NEB otherwise directs:
of these measures, site-specific plans and drawings, mitigation
a) for permanent structures, long-term habitat disturbance
measures, and monitoring applicable to pipe-laying operations;
including pipeline right of way, road, quarry, camp, etc.,
c) an acid rock drainage prevention plan incorporating the testing
ground and air access, and blasting maintain a setback
of quarried and exposed rock during trenching, borrow pit and
of 1000 m from nest sites between April 15 and September 1
quarry development and provisions for the safe disposal or
for peregrine falcons and between March 30 and July 31
treatment of unsuitable material if required;
for all other raptors; and
d) a reclamation plan which includes a description of the condition
b) for aircraft overflight, maintain a setback of 760 m above
to which the Proponent intends to reclaim and maintain the
ground level from nest sites between April 15 and September 1
right of way, a description of measurable goals for reclamation,
for peregrine falcons and between March 30 and July 31
methods to minimize invasive plant introduction and measures
for all other raptors.
to maximize vegetation recovery;
e) references to other plans and manuals for environmental
Prior to Pipe-laying Operations
protection required by field staff and inspectors; and
37. The Proponent shall undertake a geotechnical verification program
to support the final design and construction of the project facilities
f) evidence of consultation with appropriate regulatory authorities
and shall file with the NEB 90 days prior to pipe-laying operations or
and government subject matter experts in the area of application
station construction:
of the EPP.
a) copies of all borehole logs and the results of geophysical surveys
39. To promote safety of the pipeline and protection of the environment
completed; and
and to advance knowledge of the effects of pipeline construction
and operation in permafrost environments the Proponent shall
b) an updated assessment of permafrost, ground ice and terrain
develop an effects monitoring program for the project. The purpose
conditions along the Mackenzie Valley Pipeline including, as
of this program is to:
applicable, copies of all published information regarding
permafrost conditions, ground ice and terrain conditions used in
a) monitor the effects of the environment on pipeline integrity;
the assessment.
b) monitor the long-term effects of the construction and operation
of pipeline on the physical environment; and
38. To compile and communicate all of the Proponent’s environmental
protection procedures, mitigation measures, and monitoring
c) validate design assumptions and approaches and monitor
commitments pertaining to pipe-laying operations to its field staff
the effects of construction and operations practices used
and to the NEB inspectors, the Proponent shall file with the NEB
on the project.
an Environmental Protection Plan (EPP) for approval at least 90 days
prior to the start of pipe-laying operations. The EPP may be divided
This program shall take into account the results of the geotechnical
verification program, the geohazard assessment and observations
into separate plans by region or project area as deemed necessary.
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258 Mackenzie Gas Project • Volume 2: Implementing the decision
made during construction and shall be developed in consultation
with Indian and Northern Affairs Canada, Natural Resources Canada
and the Department of Fisheries and Oceans. The program shall
address and identify changes in thermal regimes and their
environmental effects, including existing and potential thaw
settlement, frost heave, slope stability, river crossing scour, aufeis,
drainage and fish passage impedance and erosion issues, and how
these would be affected by successive changes in compressor station
with the NEB any modifications as they become available.
43. The Proponent shall file with the NEB for approval the replacement
backfill and padding specifications at least 60 days prior to the start
of pipe-laying operations. The specifications shall include provisions
to ensure the replacement backfill and padding do not contain
materials injurious to the pipeline, its coating and the environment.
44. Unless the NEB otherwise directs, to determine the effectiveness
configuration. The program shall outline the monitoring methods to
of the Proponent’s plans for remediating ditch fill settlement
be used, instrumentation locations and the frequency of monitoring.
for the project, the Proponent shall file a report with the NEB 90 days
The results shall be integrated into the Proponent’s integrity
prior to the start of pipe-laying operations, which addresses:
management program and environmental protection program. The
Proponent shall file with the NEB:
i) a report for approval, at least 90 days prior to the start of
pipe-laying operations, which outlines the scope, objectives,
monitoring methodologies and frequencies and the criteria
for the selection of instrumentation sites for the program;
ii) on 1 April of each subsequent year of pipeline
construction, locations it has chosen to monitor,
the rationale for selection, the instrumentation required
and the time of its installation; and
iii) a report by 30 November of each year describing the results
of this program, and its mitigation/intervention plans to
a) its methods for determining the quality and quantity
of imported fill required to remediate excess ditch settlement;
b) the timing and methods for hauling and stockpiling
the fill materials;
c) the methods it will use to assess and address the need
for additional replacement backfill or manage any excess
backfill during final clean up and reclamation;
d) methods and locations for the disposal of excess excavated
material not required for backfill; and
e) evidence of consultation with land managers and
appropriate regulators.
address issues identified.
45. To demonstrate that it has adequately assessed and mitigated
40. The Proponent shall file with the NEB for approval the
Construction Safety Manual at least 60 days prior to the start
of pipe-laying operations.
41. The Proponent shall file with the NEB the final Pipeline Construction
and Facility Specifications at least 60 days prior to the start
against geohazards and to facilitate NEB monitoring during
operations, the Proponent shall file with the NEB, at least 90 days
prior to the start of pipe-laying operations, a Geohazard Assessment
for the project describing:
a) its geohazard assessment methodology and the specific
of construction. The specifications shall be of sufficient scope
and combined geohazards identified along the route that
and detail to demonstrate the suitability of the specifications prior
have a reasonable probability of impacting the project;
to the start of pipe-laying operations and facility construction.
42. To facilitate NEB inspections, the Proponent shall file with the NEB
b) specific measures to be implemented to mitigate individual
and combined geohazards;
updated engineering and environmental alignment sheets at least
90 days prior to the start of pipe-laying operations, and shall file
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Appendix K 259
c) decision criteria for the implementation of mitigation
for geohazards identified during construction;
d) the qualifications of the staff making decisions regarding
design and implementation; and
e) the ongoing monitoring requirements.
46. To demonstrate that the pipeline design can accommodate an
increase in compressor stations over time and is sufficient to
withstand anticipated frost heave and thaw settlement loadings,
the Proponent shall file with the NEB at least 90 days prior to the
start of pipe-laying operations:
a) a report summarizing the findings of the final design frost
heave and thaw settlement analysis for overland areas
demonstrating that the pipeline design is sufficient to withstand
anticipated frost heave and thaw settlement loadings. Where
analysis indicates that the strain demand over the design life
may exceed the strain capacity of the pipeline materials
(omitting the effect of secondary mitigation measures), the
with the NEB at least 60 days prior to the start of construction of
an HDD watercourse crossing. The plans shall identify and address,
where applicable, site-specific concerns such as the presence
of ice-rich permafrost and other potentially unfavorable
geotechnical conditions.
48. To facilitate NEB inspection during construction and monitoring
during operations, and to confirm that there have been no
significant changes to the slope design methodology, the Proponent
shall file for approval with the NEB a Slope Design Methodology
Final Report following the completion of final design and at least 90
days prior to the start of pipe-laying operations.
The Slope Design Methodology Final Report shall include:
a) the slope design methodology, data requirements, assessment
techniques and pre‑construction slope inventory;
b) revisions to threshold slope angles, critical longitudinal and
critical cross slope criteria based on findings from final design
and further geotechnical investigations;
report shall describe the site specific secondary measures
c) target Factor of Safety for longitudinal and cross slope designs;
incorporated into the design or integrity management program
d) details of selected passive ground cooling systems including the
to prevent the pipeline from exceeding the critical threshold
proposed number, location, type, refrigerant, typical drawings,
strain limits.
corrosion protection and installation method;
b) an assessment of the impacts of changing pipe operating
e) details of the selected surface insulation(s) including type,
temperatures associated with an increase in compressor stations
source, thickness and specified mitigation against the
over time, on the right of way. Where the assessment indicates
introduction of noxious weeds (if applicable);
that significant impacts may occur, the secondary measures
required to mitigate these impacts shall be identified and
reflected in the design prior to construction.
47. The Proponent shall undertake a hazard analysis identifying
f) details of erosion control requirements including typical drawings
and spacing requirements for berms, plugs and ditches;
g) results of thermal analysis showing 10 and 25 year thaw depth
predictions for the startup, 3, 7 and 14 station configurations
reasonably foreseeable hazards or problems with horizontal
based on selected thermal mitigation options for thaw sensitive
directionally drilled (HDD) activities, based on site specific data,
slopes exceeding critical slope length, slopes identified as
and develop specific contingency plans for each HDD crossing.
potential concerns from a stability perspective which cannot be
The Proponent shall file the hazard analysis and contingency plans
avoided by route refinements, and slopes that have or will have
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260 Mackenzie Gas Project • Volume 2: Implementing the decision
slope instrumentation installed during the construction phase;
h) typical design drawings for various slope conditions;
i) specific designs for thaw sensitive slopes exceeding critical
slope length;
j) a tabular summary of sites requiring site-specific slope designs,
indicating the location and identification number of the slope,
slope angle, slope length, slope height, orientation, actual
or assumed soil conditions, nature of the site-specific issue
and proposed mitigation measures; and
k) a slope stability response plan describing the actions the
Proponent shall take, and the timing of those actions, should
monitoring indicate that the Factor of Safety for a slope falls
below the design Factor of Safety or thaw depth exceeds
predicted values.
49. The Proponent shall file with the NEB for approval a Field Changes
Manual, for Slopes at least 90 days prior to the start of pipe-laying
operations. The manual shall include:
a) specific criteria for the implementation of changes to the designs,
grading, materials, installation procedures, thermal stabilization
measures, erosion mitigation measures and monitoring;
b) details regarding the required qualifications of its field staff
implementing the manual; and
c) consultation required with other experts and regulatory
authorities and the scope of that consultation.
50. To protect traditional harvesting of fish from adverse impacts related
to project stream crossings, the Proponent shall file with the NEB,
at least 90 days prior to the start of pipe‑laying operations,
the final suite of decision trees proposed to manage the impacts
of the Mackenzie Gas Project on fish and fish habitat including:
a) an explanation of the decision-making process, the criteria
for decision-making and the mitigation options;
b) a description of how the Proponent will address the importance
of fish habitat and fish populations to local communities and
c) evidence of consultation with Fisheries and Oceans Canada
and the relevant management boards and agencies with regard
to the decision trees.
51. To demonstrate the adequacy of scour protection and thermal
mitigation measures of watercourse crossing designs and facilitate
NEB inspection during construction, the Proponent shall file
for approval with the NEB at least 90 days prior to the start
of pipe‑laying operations:
a) a revised Watercourse/Waterbody Crossing Inventory,
in both PDF and MS Excel spreadsheet format, describing
the watercourse name and numerical identifier, coordinates,
stream class, width of wetted channel, construction method,
design type, minimum pipeline cover, navigability and fish
habitat status and level of assessment;
b) detailed final design drawings and plans for all watercourse and
waterbody crossings requiring site specific designs, including
HDD crossings, showing the design flood level, calculated vertical
and lateral scour potential and detailing proposed thermal,
erosion, scour control and ground water flow mitigation
measures;
c) detailed final design drawings of typical designs for open cut
and isolated crossings of Lakes, Active I, Active II and Vegetated
Channel watercourses detailing proposed thermal, erosion, scour
control and ground flow mitigation measures;
d) 25 year frost bulb growth/thaw settlement analysis (for the start
up, 3, 7 and 14 station configuration), including predicted strain
demand/ available strain capacity and frost bulb dimensions, for
all Large, HDD, Active I and Active II watercourse crossings which
demonstrates that changes in the thermal regime of the pipe
associated with changes in compressor station configurations or
degraded insulation effectiveness will not result in aufeis
conditions or unacceptable pipe strains; and
e) evidence of consultation with the Department of Fisheries
and Oceans in regards to the design of stream crossings.
harvesters; and
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Appendix K 261
52. To facilitate NEB monitoring, the Proponent shall notify the NEB
reasonable cost to the NEB. (For clarity, the scope of this support is
at least 30 days prior to qualifying the automated ultrasonic
limited to transportation of NEB staff and vehicles to isolated camp
non-destructive examination procedures for mill and field
locations, vehicle fuel and maintenance, meals and accommodation,
circumferential welds.
office space and communications support.)
53. The Proponent shall develop the joining program and file it with
57. Unless the NEB otherwise directs the Proponent shall pressure test
the NEB at least 30 days prior to conducting welding procedure
the approved facilities with a liquid medium and submit the Pressure
qualification tests for:
Testing Program, demonstrating compliance with applicable codes,
a) field circumferential production, tie-in and repair pipeline
standards and regulatory requirements, to the NEB for approval at
welds; and
b) welding of project facilities.
The joining program shall include:
least 60 days prior to the start of pressure testing; or in the event
that a hydrostatic test is not practicable, the Proponent shall file
with the NEB for approval, at least 60 days prior to the start
of any air testing activities, the Proponent’s air testing measures.
i) requirements for the qualification of welders;
The program shall include:
ii) requirements for the qualification and duties
a) information demonstrating the ability of the leak test to
of welding inspectors;
iii) welding procedure specifications;
iv) non-destructive examination specifications;
v) quality assurance program for field welds
and welding procedures; and
vi) any additional information which supports
the joining program.
54. To facilitate NEB inspection, the Proponent shall file with the NEB
detect the same size leak as a comparable hydrostatic test;
b) information demonstrating that the pipeline has adequate
notch toughness;
c) a description of the specific safety precautions to be
implemented during the pressure test; and
d) a confirmation of successful leak test of pipeline sections prior
to their installation under watercourses, lakes and ponds.
58. To verify implementation of the Proponent’s quality assurance
procedure qualification records for welding and non-destructive
and control plans and procedures, the Proponent shall file monthly
examination within 30 days of the completion of procedure
summary reports during construction outlining non-conformances
qualification tests.
with its design, materials, and construction specifications and
55. To facilitate NEB inspection, the Proponent shall file with
the disposition of these non-conformances.
the NEB the specifications for field applied coatings at least
Prior to Operation
60 days prior to the start of pipe-laying operations.
59. The Proponent shall file with the NEB for approval, at least
During Construction
56. To facilitate NEB inspection of all phases of construction, the
Proponent shall provide when requested, logistical support to NEB
staff undertaking inspection of construction and reclamation, at a
1249_NEB_MGP_Vol2_Text_ENG.indd 261
90 days prior to the planned start of operation, the elements
of the Environmental Protection Program for the operation and
maintenance of the pipeline pursuant to section 48 of the Onshore
Pipeline Regulations, 1999. The elements to be submitted include
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262 Mackenzie Gas Project • Volume 2: Implementing the decision
but are not limited to policies, practices and procedures for:
which outlines:
a) ongoing environmental training for employees/operators;
i) the potential for the establishment of local, communitybased spill response teams to assist in responses to
b) handling and disposal of all wastes associated with the operation
Mackenzie Gas Project incidents;
and maintenance of the project;
ii) a discussion of the opportunities and constraints of
c) management of air emissions, including:
establishing local spill response teams including a training
i) maximum Proponent-identified and/or legislated discharge
and equipment needs assessment; and
limits for PM and NOx;
iii) the Proponent’s commitment to work with local
ii) maximum Proponent-identified greenhouse gas targets;
communities to build and maintain community spill
iii) reduction strategies for air emissions including PM, NOx,
and greenhouse gases;
iv) monitoring and measurement methods; and
v) record keeping including annual reporting of greenhouse
gases to the NEB;
d) public communication program (non-emergency); and
e) program review and consultation with Environment Canada
and the Government of Northwest Territories.
60. To demonstrate that in-line inspection tools will be able to support
effective integrity management programs, the Proponent shall submit
to the NEB at least 90 days prior to the start of system operation:
a) the type, description, specifications, operating limits and
In preparing its Emergency Preparedness and Response Plan, the
Proponent shall have regard to:
1) the NEB letter dated 24 April 2002 entitled Security and
Emergency Preparedness Programs addressed to all oil and gas
companies under the jurisdiction of the NEB and subsequent
amendments made thereafter; and
2) emergency responses required as a result of significant
earthquakes which may require a broader scope of response.
62. To demonstrate that it is prepared to respond to an emergency
at the outset of operation, the Proponent shall hold an emergency
response exercise to evaluate the effectiveness of the Emergency
detection limits of all in‑line inspection tools which can
Preparedness and Response Plan at least 10 days prior to the start
be used by the Proponent during operation of its pipelines;
of system operation and file a letter of notification with the NEB
b) data on the inertial curvature in-line inspection tool(s) developed
for the project indicating the detectable level of displacement
and associated strain, the recommended pig velocity, and the
relationship between pig velocity and strain resolution; and
c) intervention values for all parameters that will be monitored
by in-line inspection tools.
61. The Proponent shall prepare:
a) an Emergency Preparedness and Response Plan for the project
prior to the start of system operation and file with the NEB
the Emergency Procedures Manual at least 30 days prior
to the start of operation; and
b) a report, to be filed with the Emergency Procedures Manual,
1249_NEB_MGP_Vol2_Text_ENG.indd 262
response capacity.
upon the successful completion of the exercise.
63. Unless the NEB otherwise directs the Proponent shall file with
the NEB a report describing the final design of the SCADA and leak
detection system for the Mackenzie Valley Pipeline at least 90 days
prior to the start of operation of the Mackenzie Valley Pipeline. The
report shall include information suitable for establishing a base line
for the quality program for its SCADA and leak detection system
and shall include:
a) a description of the SCADA and leak detection system;
b) the location and type of pressure, temperature and flow
monitoring and control devices and remote terminal units;
c) the location of remotely operated valves;
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Appendix K 263
d) the target detect ability (e.g., amounts leaked, time to detect,
leakage rate);
e) the target sensitivity (i.e., minimum leak size);
f) the target reliability (i.e., false alarm rate, failure to alarm rate);
g) the expected system robustness (i.e., system availability
in light of the system operating conditions);
h) the target accuracy (i.e., size and location of a detected leak);
and
i) a description of the quality program using both direct and
b) locations where passive cooling systems were installed;
c) locations where slope instrumentation including thermistors,
piezometers and slope inclinometers were installed;
d) slopes exceeding the critical slope length which were identified
during construction as being thaw sensitive or exhibiting
evidence of soil movement;. and
e) locations where slope design changes were made in accordance
with the Field Change Manual for Slopes and the reasons for
the design change.
inferred methods that the Proponent shall implement during the
67. To minimize or reduce air emissions from flaring, the Proponent
operational phase of the project to ensure optimal performance.
shall meet the Guideline for Ambient Air Quality Standards
64. To demonstrate that the SCADA and leak detection system are
calibrated to actual system conditions, the Proponent shall file
with the NEB, reports describing the results of the Proponent’s
quality program for its SCADA and leak detection system and how
in the Northwest Territories and Alberta’s Energy Resources
Conservation Board Directive 60: Upstream Petroleum Industry
Flaring, Incinerating and Venting.
68. To minimize noise disturbance from pipeline facilities,
identified issues were addressed. Unless the NEB otherwise directs,
the Proponent shall:
the reports shall be filed one year, three years and five years after
a) design pipeline facilities to meet the requirements of Alberta’s
the start of system operation.
During Operation
65. Within 30 days of the date that the approved project is placed in
service, the Proponent shall file with the NEB a confirmation, by
an officer of the company, that the approved project was completed
and constructed in compliance with all applicable conditions in this
Certificate. If compliance with any of these conditions cannot be
confirmed, the officer of the company shall file with the NEB details
as to why compliance cannot be confirmed. The filing required by
this condition shall include a statement confirming that the signatory
to the filing is an officer of the company.
66. To facilitate monitoring during operation, the Proponent shall file
with the NEB, within six months of the start of system operation,
a geotechnical construction report including maps and drawings,
which identifies and describes:
a) longitudinal and cross slopes identified during construction
as requiring ongoing monitoring;
Energy Resources Conservation Board Directive 038; and
b) file with the NEB, 90 days following the start of operation,
a post construction noise assessment report.
69. To aid NEB inspectors in confirming the effectiveness of mitigation
techniques and any adaptation required, as well as to identify
effects that were not predicted and appropriate adaptive
management to address these effects, the Proponent shall file
with the NEB a post-construction environmental report that reflects
any monitoring or follow-up program developed, including:
a) identification on a map or diagram of any environmental
issues which arose during construction;
b) the criteria used or to be used to verify the accuracy
of the environmental assessment predictions;
c) the determination of the accuracy of the environmental
assessment predictions;
d) discussion of the effectiveness of the mitigation applied
pre-, during and post- construction and where adaptive
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264 Mackenzie Gas Project • Volume 2: Implementing the decision
management was necessary;
e) identification of the current status of the issues identified
describing whether those issues are resolved or unresolved; and
f) proposed measures and schedule that the Proponent
shall implement to address any unresolved concerns.
The report shall be filed on or before the 31 of January of each
monitoring data collected during project planning and design.
Numerical records shall be submitted in both PDF and MS Excel
spreadsheet format.
Planning Clause
73. The Proponents shall file updated cost estimates and report
on their decision to construct by 31 December 2013.
of the first, third, fifth and tenth years following the start of project
Sunset Clause
operation, unless the NEB otherwise directs.
74. Unless the NEB otherwise directs, this Certificate shall expire
70. Unless the NEB otherwise directs, to demonstrate the management
of pipeline integrity and thermal effects on the right of way
on 31 December 2015 unless construction in respect of
the Mackenzie Gas Project has commenced by that date.
the Proponent shall monitor geotechnical and thermal effects
Conditions that apply only to the Mackenzie Valley Pipeline
on the pipeline(s) with respect to thaw subsidence, frost heave
75. The Proponent shall notify and consult with Aboriginal
and slope stability by:
and municipal authorities in each community proximate
a) undertaking a detailed as-built survey prior to backfill which
to the Mackenzie Valley Pipeline right of way with regard to
documents the position of the pipeline for comparison with
community use of merchantable timber that would be cleared
future in-line inertial inspection data, the location of pipe
along the Mackenzie Valley Pipeline right of way, and shall provide
specification changes, the location of each circumferential
the NEB with a report on its consultations and any agreements that
weld, buoyancy control devices, depth of cover; and
have been reached 90 days prior to the start of pre-construction
b) undertaking an inertial in-line inspection within one month
of the start of operations and on an annual basis thereafter.
71. To facilitate monitoring, the Proponent shall record ditch wall
geotechnical information during construction and shall file
the ditch wall logs with the NEB within one year of the start
of system operation.
72. To facilitate monitoring, the Proponent shall file with the NEB, within
one year of the start of system operation, copies of all stream flow
monitoring, ice thickness measurements and ground temperature
activities for the relevant spread.
76. To facilitate local access to gas, the Proponent shall file with
the NEB at least 90 days prior to the start of pipe‑laying operations
a report identifying:
a) details of any expressions of interest it has received for
connections to a gas delivery lateral or in having a delivery lateral
constructed to connect to a local gas distribution system;
b) technical details regarding the tie-in, valves, regulating
and metering equipment required to satisfy the request; and
c) the expected timing for the installation of the facilities.
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Appendix L 265
Appendix L
Miscellaneous Order for
Mackenzie Valley Pipeline Tolls and Tariff
ORDER MO-17-2010
IN THE MATTER OF Part IV of the National Energy Board Act and
IN THE MATTER OF the applications by Imperial Oil Resources Ventures Limited (the Proponent), on behalf of
Imperial Oil Resources Ventures Limited, the Mackenzie Valley Aboriginal Pipeline Limited Partnership, ConocoPhillips
Northern Partnership, ExxonMobil Canada Properties and Shell Canada Limited as managing partner of Shell Canada
Energy filed with the National Energy Board (Board) for the Mackenzie Valley Pipeline under file numbers: OF-FacGas-I017-2004-1, OF-EP-FacPipe-I003-MAC 04, OF-EP-FieldOp-I003-TL 07, OF-EP-FieldOp-C648-PL 07, OF-EPFieldOp-S245-NIG 07.
WHEREAS the Proponent filed an application in October 2004 under
AND WHEREAS the National Energy Board has issued, subject to the
Part III of the National Energy Board Act for the 1196 kilometre long,
approval of the Governor in Council, a certificate of public convenience
750 millimetre (30 inch) diameter Mackenzie Valley Pipeline to carry
and necessity for the Mackenzie Valley Pipeline;
natural gas from the a processing plant near Inuvik, Northwest Territories
to northwestern Alberta;
IT IS ORDERED pursuant to Part IV of National Energy Board Act
that the toll and tariff principles for the Mackenzie Valley Pipeline
AND WHEREAS the Proponent applied for approval of toll and tariff
proposed by the Proponent in the GH‑1‑2004 proceedings be approved
principles for the Mackenzie Valley Pipeline pursuant to Part IV of
subject to the following:
the National Energy Board Act;
AND WHEREAS the application was set down for hearing in Hearing
1.
The Mackenzie Valley Pipeline shall be accessible to all shippers
that meet the terms of the tariff.
Order GH‑1‑2004;
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266 Mackenzie Gas Project • Volume 2: Implementing the decision
2.
The Proponent shall file, for Board approval, a Code of Conduct
5.
for the Mackenzie Valley Pipeline for all phases of development
reflecting the principle of a 221 basis point premium over other
including pre-construction, construction and operation. The Code
Group 1 companies that were subject to the formula immediately
of Conduct is to be filed as soon as possible but in any event no
prior to 9 October 2009. The total return will be set taking into
later than 31 December 2011. At a minimum, the Code of Conduct
account both return on equity and equity thickness.
should address in detail:
6.
rate of the project debt financing provided by the senior lenders for
b) governance of the interactions between shippers
the Mackenzie Valley Aboriginal Pipeline Limited Partnership as long
as this reflects the cost of debt that would apply to a stand-alone
Mackenzie Valley Pipeline.
c) independence of transmission operations from
affiliate operations;
7.
Pipeline over the first 20 years of the Mackenzie Valley Pipeline’s
e) protection of confidential and commercially-sensitive
operation unless the Board determines that this methodology no
information;
longer reflects the economic life of the Mackenzie Valley Pipeline.
f) mechanisms and methodologies related to the design
of an acceptable transfer pricing mechanism;
8.
h) penalties for breaches of the Code of Conduct and recourse
to a third party arbitrator.
At least 90 days prior to the start of pre-construction activities
The Proponent shall initially establish two tolling zones for
the Mackenzie Valley Pipeline.
g) a Code of Conduct compliance plan with independent audits;
and
The Proponent shall use a depreciation method that would allow it
to recover 80 percent of its asset costs for the Mackenzie Valley
d) governance of separation of business;
9.
The appropriate toll treatment for future expansions shall
be determined at the time of the expansion after considering
the specific circumstances.
10. The Proponent shall remove the clause in Section 20.4 of the
the Proponent shall demonstrate to the National Energy Board’s
Tariff Principles that states “As all foreseeable expansions are
satisfaction that the necessary long-term transportation service
expected to reduce existing tolls”.
contracts have been executed for the Mackenzie Valley Pipeline.
4.
The cost of debt shall be deemed as the weighted average interest
a) prevention of undue preferential treatment;
and transporters;
3.
The return on equity for the Mackenzie Valley Pipeline shall be set
11. As soon as possible but, in any event, no later than 31 December
The Proponent shall be designated as a Group 1 company and shall
2011, the Proponent shall remove from any document the words
file quarterly Surveillance Reports as outlined in the Toll Information
that preclude shippers from raising concerns about the toll and tariff
Regulations and Section BB, Financial Surveillance Reports in the
principles before the Board.
National Energy Board’s Filing Manual.
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Appendix L 267
12. Prior to operation, the minimum contract term for service
16. By 31 December 2011, and following consultation with potential
on the Mackenzie Valley Pipeline is not required to be shorter
shippers and the Government of the Northwest Territories,
than 15 years.
the Proponent shall develop and file the details of an economic
13. The Proponent may choose to offer interruptible service
only to shippers with firm service contracts on the Mackenzie
Valley Pipeline.
14. A specific proposal for a special interruptible service for gas
which fails to meet the tariff specifications for minimum heat
content is not required.
15. For gas flowing the full distance under a 15 year contract,
test for delivery laterals which are to be constructed and owned
by the Mackenzie Valley Pipeline and rolled into its rate base.
17. The Proponent shall incorporate in its toll and tariff principles
the requirement that metering and pressure reducing facilities
will be rolled into the Mackenzie Valley Pipeline’s cost of service.
18. The Proponent shall file a tariff as soon as reasonably possible but,
in any event, no later than 31 December 2011.
the Proponent shall charge a toll premium of $0.15 per gigajoule
over the toll for a 20 year contract.
NATIONAL ENERGY BOARD
Anne-Marie Erickson
Secretary of the Board
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268 Mackenzie Gas Project • Volume 2: Implementing the decision
Appendix M
Conditions for the Mackenzie Gathering System
Unless otherwise specified in the condition, pre-construction activities
Unless otherwise specified in a condition best available technology (BAT)
include activities such as: clearing and grading for infrastructure
means technology with superior emissions performance which is
development; construction and operation of camp facilities; the
commercially available at a reasonable cost at the time it is required for the
development of borrow pits, roads, and airstrips; snow pad construction;
project which meets the goals of pollution prevention and energy efficiency.
the transportation and stockpiling of fuel and material; and geotechnical
investigations necessary for the construction of the pipeline project.
Pre-construction activities may include other activities such as clearing
of the right of way if approved by the National Energy Board. Preconstruction activities do not include activities associated with normal
surveying operations or data collection activities.
Unless otherwise specified in the condition, pipe-laying operations
include the clearing of vegetation in proximity of water crossings
and on thaw sensitive slopes, as well as grading and trenching and
Unless otherwise specified in a condition best management practices
(BMP) are innovative, dynamic, and improved environmental protection
practices and procedures that help ensure that development is conducted
in an environmentally responsible manner. BMP may exist as formal
guidelines or generally accepted procedures that are recognized by
regulators and industry associations as best practices.
Conditions that correspond for the Mackenzie Valley Pipeline
and the Mackenzie Gathering System
other forms of right of way and station site preparation that may have
General
an effect on the environment through to final clean-up and reclamation.
1. the approved facilities to be designed, located, constructed,
Unless otherwise specified, Proponent consultation referred to in a
installed and operated in accordance with the commitments,
condition must be carried out in a manner that includes the Proponent:
a)
specifications, standards, policies, mitigation measures, procedures,
providing, to the party to be consulted,
and other information referred to in its application or in the
i) notice of the matter in sufficient form and detail to allow
Environmental Impact Statement or other filings, or as otherwise
agreed to during the GH-1-2004 Hearing and during the review
the party to prepare its views on the matter,
by the Joint Review Panel.
ii) a reasonable period for the party to prepare those views, and
iii) an opportunity to present those views to the party conducting
the consultation; and
b)
1249_NEB_MGP_Vol2_Text_ENG.indd 268
Unless the NEB otherwise directs, the Proponent shall cause
2. Unless the NEB otherwise directs, the Proponent shall comply with
all filing timelines and completion dates set out in these conditions.
considering, fully and impartially, any views so presented.
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Appendix M 269
Prior to Pre-Construction Activities
3.
To compile and communicate all of the Proponent’s environmental
protection procedures, mitigation measures, and monitoring
commitments pertaining to pre‑construction activities to its field
staff and to the NEB inspectors, the Proponent shall file with the
NEB an Environmental Protection Plan (EPP) for approval at least
90 days prior to the start of pre-construction activities. The EPP
may be divided into separate plans by region or project area as
deemed necessary.
The pre-construction EPP shall include:
a) the scope and area of application of the EPP;
b) environmental protection procedures and measures, including
decision criteria for timing and implementation of these
measures, site-specific plans and drawings, mitigation measures,
and monitoring applicable to pre-construction activities;
c) an acid rock drainage prevention plan incorporating the testing
of quarried and exposed rock during infrastructure, borrow pit
and quarry development and provisions for the safe disposal or
treatment of unsuitable material if required;
d) references to other plans and manuals for environmental
protection required by field staff and inspectors; and
e) evidence of consultation with appropriate regulatory authorities
and government subject matter experts in the area of application
of the EPP.
a) the scope of the plan detailing the project infrastructure,
geographic and time period covered by the plan;
b) training and orientation requirements of company and
contractor staff;
c) an inventory of petroleum products, chemicals and other
hazardous substances, together with corresponding MSDS
sheets, that will be transported, stored and/or used during
the pre‑construction and construction phases;
d) storage facilities and locations of the above inventoried products
and substances;
e) identification of resources (equipment and staff) to be on-site
and/or available to respond to emergencies;
f) identification of mutual aid partners and the location
of their resources (equipment and staff) available to respond
to emergencies;
g) procedures for responding to spills, releases, fires, medical
emergencies and security issues including the incident reporting
and notification system;
h) location of fire and spill response equipment stores and
the spill kit requirements for vehicles;
i) a phone list of company, contractor, government agency
and community representatives outlining their respective roles
and information needs;
j) clean-up and disposal procedures for generated clean-up wastes;
4.
To address worker and public safety and environmental protection
during construction in the unique northern environment, the
Proponent shall file an Emergency Response Plan with the NEB
at least 60 days prior to the start of pre-construction activities
which shall address 24-hour medical evacuation, fire response and
hazardous chemical and fuel spill response and security issues.
The Emergency Response Plan shall be prepared in consultation with
Indian and Northern Affairs Canada, the Canadian Coast Guard,
Transport Canada, Environment Canada, the Government of
the Northwest Territories and the Inuvialuit Land Administration,
as applicable, and shall include:
1249_NEB_MGP_Vol2_Text_ENG.indd 269
k) identification of muster points for emergency evacuations from
camps and facilities;
l) location of emergency medical treatment locations
and capabilities;
m)the requirement for 24-hour emergency medical evacuation
capability; and
n) maps showing the location of the right of way and infrastructure
such as camps, access roads, material storage areas, barge
landing sites and borrow pits to facilitate the dispatch
of first responders.
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270 Mackenzie Gas Project • Volume 2: Implementing the decision
5.
To address worker and public safety in the unique northern
environment, the Proponent shall file a construction safety
manual with the NEB at least 60 days prior to the start of
pre-construction activities.
6.
To confirm consideration of the effects of climate change on specific
geohazard mitigation, slope and stream crossing designs and terrain
stability for the overall design life of the project, the Proponent shall
file a report six months prior to the start of pre-construction
activities which includes:
a) an analysis of the impacts of climate change and variability on
permafrost and terrain stability for a series of representative
locations and conditions using potential upper limit temperature
scenarios which may occur along the Mackenzie Valley;
b) a description of how these upper limit temperature scenarios
may impact precipitation and stream flows along the Mackenzie
Valley;
c) a description of how the Proponent will account for the potential
change in precipitation patterns in the detailed design of slopes
and water course crossings for the project; and
d) the results of consultation with other appropriate regulators
and government departments.
7.
8.
grade, allowable speed, signage, maximum vehicle weight;
b) objective and measurable environmental and engineering criteria
to determine when the winter road will be ready for use;
c) safe ice thickness criteria for lake, river and stream crossing
including the frequency of ice profiling;
d) local regulatory requirements;
e) installation and removal requirements for snow fills, culverts,
corduroy and temporary bridges; and
f) objective and measurable environmental and engineering
criteria for closure.
10. To demonstrate that the pipeline and project winter roads will be
constructed and operated in a safe and environmentally acceptable
manner, the Proponent shall file with the NEB a copy of any
applicable permits, authorizations and letters of advice issued by the
Federal departments, the Government of the Northwest Territories, or
local regulatory organizations that are referred to in an EPP or winter
road manual at least 90 days prior to pre-construction activities.
11. The Proponent shall evaluate the technologies and practices
available to reduce emissions of particulate matter (PM) and PM
and ozone precursors from its facilities and construction related
To facilitate NEB inspections, the Proponent shall file with
activities, and incorporate the BMP and BAT to reduce emissions
the NEB updated environmental alignment sheets at least 90 days
of PM and precursors of PM and ozone to the extent practicable.
prior to pre-construction activities, and shall file with the NEB any
The Proponent shall file a report of its findings and how it
modifications as they become available.
will implement its findings to the NEB at least six months prior
To facilitate NEB inspections, the Proponent shall file with the NEB
to construction of the Inuvik Area Facility, compressor stations
a detailed construction schedule or schedules identifying major
and heater stations.
activities at least 30 days prior to pre‑construction activities and
9.
a) required road width, clearing and grading requirements,
12. The Proponent shall evaluate and implement technologies and
pipe-laying operations, and shall notify the NEB of any modifications
practices available to reduce mercury, dioxin and furan emissions
to the schedule or schedules as they occur.
from incinerators operating at construction camps and its station
To demonstrate that project winter roads will be constructed and
facilities to the extent practicable. The Proponent shall file a report
operated in a safe and environmentally acceptable manner, the
of its findings and how it intends to implement its findings to
Proponent shall file with the NEB a manual for the construction,
the NEB at least 60 days prior to the operation of its construction
operation, maintenance and closure of project winter roads at least
camps and station facilities.
30 days prior to the start of project winter road construction.
The manual shall include:
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Appendix M 271
13. The Proponent shall file with the NEB at least 60 days prior
d) a description of the processes for the implementation
to the start of station facility construction, a report outlining:
of changes that may occur between the design information
a) the specific design and operational measures it has implemented
and material specifications submitted to the NEB as a result
and will implement to minimize methane leakage and venting
of Conditions 14 and 18, and the detailed design and
through the system’s operation taking into account BMP developed
the actual material properties.
by CAPP, Environment Canada, the Canadian Energy Partnerships
15. The Proponent shall file with the NEB for approval, at least 30 days
for Environmental Innovation and the Canadian Gas Association;
prior to the start of pre-construction activities an Air Quality
b) how the Proponent has utilized waste heat energy to
Monitoring Program developed in consultation with Environment
minimize natural gas fuel consumption in the design of the
Canada, Health Canada and the Government of the Northwest
Inuvik Area Facility;
Territories, to be undertaken immediately prior to and during
construction. This program shall include:
c) the use of BAT when specifying compressor units used on the
project including size, efficiency and their conformity with
a) identification of the baseline, pre-construction conditions;
Canadian Council of the Ministers of the Environment National
b) the location of monitoring sites on a map or diagram, the
Emissions Guidelines for Stationary Combustion Turbines
purpose for the locations selected, and the timing for installation;
(CCME,1992); and
c) methods and schedule of constituent monitoring
d) results of consultation with Environment Canada and
(PM, O3, NO2 and noise);
the Government of Northwest Territories.
d) data recording, processing and reporting details;
14. To demonstrate that the design is experimentally verified and
e) the process for public communication and complaint response; and
that the inputs and outputs of the design calculations are clearly
f) details of the additional measures that would be implemented
determined for overland, slope and water crossing designs,
the Proponent shall file with the NEB at least six months prior
as a result of monitoring data or ongoing concern, and
to the start of pipe manufacture:
the criteria or thresholds that would require these measures.
a) a stress/strain analysis, including all inputs, assumptions,
outputs, methods, and outline of process of calculation;
b) a detailed description and results of all verification tests
performed in support of the stress/strain analysis;
c) an explanation and reconciliation of any differences
and uncertainties that may result among:
i) stress/strain analysis inputs and outputs;
ii) results of verification tests;
The Proponent shall include a legacy plan detailing the measures
that would be continued through the operation phase as a result
of monitoring undertaken or ongoing concern and the criteria
or thresholds that are used to determine when they would
no longer be required.
16. In order that the right of way, camps and supporting infrastructure
are maintained, operated and left in an environmentally acceptable
condition following the construction phase of the project, the
Proponent shall file a Waste Management Plan with the NEB for
iii) final material properties specifications; and
approval 90 days prior to the start of pre-construction activities.
iv) loads, stresses and strains pipelines may experience
This plan shall be developed in consultation with the Government
during transportation, construction, and operation; and
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of the Northwest Territories, Indian and Northern Affairs Canada
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272 Mackenzie Gas Project • Volume 2: Implementing the decision
and Environment Canada. The Waste Management Plan shall
17. To mitigate potential localized low fracture toughness in or adjacent
address all wastes associated with the construction of the project
to the welds which could be detrimental during anticipated pipeline
with the objectives of minimizing impacts to the environment and
deformation at low operating temperatures, the Proponent shall:
ensuring worker and public safety. The plan shall address air, land
a) determine the minimum acceptable value for the crack
and water quality; measures to minimize animal attraction; and
tip opening displacement (CTOD) for weld metal and heat
preventing uncontrolled fires. The scope of the plan shall include:
affected zone of mill circumferential, helical (if practicable) and
a) disposal or treatment of potentially hazardous and dangerous
longitudinal welds, for the lowest installation temperature and
materials, including petroleum products, toxic or persistent
the most severe deformation during construction or operation.
chemicals, oily wastes, de-icing fluids and fuel barrels;
The CTOD tests shall be conducted for all combinations of pipe
b) solid waste management including metals, plastics, recyclables,
steel producers and pipe mill manufacturers and be
incinerator ash, equipment, equipment parts, batteries, building
representative of applicable project pipe with the maximum
materials and construction waste;
Carbon Equivalent (CE) heat;
c) food waste management;
d) management of contaminated soil, snow and ice from spills
and de-icing activities;
e) treatment and disposal of waste water (including domestic
sewage and grey water); and
f) incinerator emissions monitoring.
The plan shall address:
i) incineration and evaporator technology choices
and rationale for selection;
ii) training requirements for operators;
iii) waste segregation requirements;
iv) interim waste storage;
v) treatment;
vi) testing method for waste streams proposed for release
to the environment (e.g. air and water);
vii) disposal method for waste streams proposed for release
to the environment; and
viii)final off-site waste disposal locations and facilities
including evidence of facility approvals and compliance
with regulations.
b) determine the minimum acceptable value for the CTOD for field
circumferential welds for the lowest installation temperature and
the most severe deformation during construction or operation.
The CTOD tests shall be conducted at the welding procedure
development phase, for all combinations of pipe steel producers
and pipe mill manufacturers and be representative of applicable
project pipe with the maximum CE heat. Deviations in the
essential changes as specified in CSA Z662-07, Table 7.3 and
Table K1 will require weld procedure requalification and retesting
to determine the minimum acceptable value for the CTOD; and
c) file with the NEB minimum acceptable CTOD values and results
of the tests:
i) for the mill qualification welds, at least 60 days prior
to the pipe manufacture; and
ii) for the field circumferential qualification welds,
at least 60 days prior to the field welding.
18. To demonstrate compliance with appropriate regulations,
standards and engineering practices and to facilitate NEB audits,
the Proponent shall file with the NEB the following documents,
to be finalized prior to the procurement of materials:
a) project-specific material specifications for pipe, fittings,
valves, and pig launchers and receivers, at least 90 days prior
to the start of manufacture of each of these elements;
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Appendix M 273
iv) locations and proposed timing of any planned pressure
b) specifications for plant-applied coatings for buried and exposed
tests; and
pipeline(s) and valves, at least 90 days prior to the application of
each coating. The specifications shall include coating materials,
application methods, and verification test results;
v) locations of any unsuccessful pressure tests and their cause.
20. To demonstrate the effective management of safety and
c) specifications for materials to be used for the manufacture
environmental protection matters during pre-construction and
of stations, the Inuvik Area Facility, and the Trout Lake Heater
construction, the Proponent shall file with the NEB at the start of field
Station, including applicable standards, and non-destructive
pre-construction activities, a diagram of the project’s organization,
examination methods and frequency, at least 60 days prior
clearly identifying roles, responsibilities and reporting structure.
to the start of the manufacture of each of these facilities;
d) joining program for mill welding, at least 90 days prior
21. The Proponent shall file with the NEB, at least 30 days prior
to the start of pre-construction activities, the Heritage Resources
to the start of manufacture of pipe, components or facilities
Management Plan as reviewed by the Prince of Wales Northern
in the plant;
e) non-destructive examination specifications for the mill
non-destructive examinations at least 90 days prior to
Heritage Centre.
22. The Proponent shall file with the NEB, at least 90 days prior
to the start of pre-construction activities, the results of consultations
the start of each non-destructive examination; and
regarding the conclusion of fee-for-service agreements with
f) project-specific quality assurance programs for all materials,
affected communities respecting the use of community services
components, and processes at least 90 days prior to manufacture
or infrastructure facilities.
of pipe components and facilities.
19. Unless the NEB otherwise directs, to facilitate NEB monitoring,
23. The Proponent shall file, at least 90 days prior to the start of
pre-construction activities, diversity plans, inclusive of gender
the Proponent shall file with the NEB project progress reports
equality, for both the construction and operations phases of the
that summarize major activities by construction spread, as follows:
Mackenzie Gas Project. The plans shall include:
a) every month during active construction periods; and
a) methods for determining diversity goals;
b) every two months during pre-construction and inactive
b) identification of diversity goals;
construction periods.
c) steps to achieve the identified goals;
These reports shall also provide:
d) commitments to the provision of a healthy
i) the description of any significant pipeline and facilities
and safe work environment;
design changes;
e) steps to create a Diversity Management Committee; and
ii) the list of any current and cumulative number of incidents,
f) a monitoring and reporting system.
accidents, or hazardous occurrences as defined in
regulations pursuant to the National Energy Act,
the Canada Oil and Gas Operations Act and the Canada
The Proponent shall require its contractors and subcontractors
to comply with the Proponent’s diversity plans.
Labour Code Part II;
iii) a description of any major activities planned for
the next reporting period;
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274 Mackenzie Gas Project • Volume 2: Implementing the decision
24. To minimize and address adverse impacts of any interactions
27. The Proponent shall file with the NEB, at least six months prior to
between the construction workforce on the Mackenzie Gas Project
the start of pre-construction activities, plans for a formal issues
and the communities in proximity to the project, the Proponent shall
resolution program that will be implemented during construction
implement closed work camps. This requirement shall apply
and operations of the Mackenzie Gas Project. The plans shall be
to all new work camps proposed by the Proponent, its contractors
prepared in consultation with the government of the Northwest
and subcontractors.
Territories, the Government of Yukon and Aboriginal authorities,
25. To minimize and address adverse impacts of any interactions
and include:
between workers in existing open camps that may be used for
a) a description of the process by which any complaints or issues
the project and the communities in proximity to those camps,
related to the Mackenzie Gas Project would be raised with
the Proponent shall identify to the NEB whether any of the existing
the Proponent or governments;
open construction camps will be used, either directly or indirectly,
b) a description of the process by which any received complaints
in relation to project construction. Where existing open camps are
or issues would be allocated among those with responsibility
to be used and are to remain open, the Proponent shall develop
for action and a description of the roles and responsibilities
a plan to minimize and address adverse impacts of any interactions.
any party involved in assessing or responding to any complaint or
The plan should be developed in consultation with affected
issue;
communities, identify the specific measures to be employed
to address adverse impacts, and comply with the commitments
made by the Proponent. The plan shall be filed with the NEB
at least six months prior to the start of pre-construction activities.
26. To minimize and address potential adverse impacts of any
interactions between the construction workforce on the Mackenzie
Gas Project and the communities of Fort Good Hope and Tulita, the
Proponent shall file with the NEB, at least six months prior to the
start of pre‑construction activities, a plan to monitor the interactions
between the construction workforce and the communities.
The plan shall be developed in consultation with the leadership
c) a description of the process by which any received complaints
or issues would be resolved;
d) a description of any protocols developed for referral and
resolution of any complaints or issues;
e) a description of the recourse mechanisms for any unresolved
complaints or issues or any unsatisfactorily resolved complaints
or issues; and
f) a description of the process for communicating and informing
communities about the issues resolution program.
28. The Proponent shall file, prior to the start of pre-construction
of Fort Good Hope and Tulita, and include:
activities, information related to the hiring of local residents
a) plans for monitoring interactions;
as monitors to carry out compliance and environmental impact
b) the specific measures that will be employed to address
adverse interactions, should any be identified; and
c) plans for regular consultation and reporting on interactions
with both potentially affected communities.
monitoring for the Mackenzie Gas Project including:
a) the nature of the activities to be monitored;
b) clearly defined job descriptions for the positions as monitors;
c) identification of the training that will be offered to monitors
to enable them to perform their duties; and
d) confirmation that monitors have been hired.
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Appendix M 275
29. To minimize project-related impacts on wildlife species, the Proponent
shall file with the NEB for approval, before the detailed pipeline
route is filed with the NEB and at least 90 days prior to the start
of pre-construction activities, a Wildlife Protection and Management
Plan or Plans to address general wildlife protection and specific
protection of woodland caribou, barren ground caribou, grizzly
bear, polar bear and wolverine. The Wildlife Protection and
Management Plan(s) shall specify goals, area covered by the plan(s),
and assumed zones of influence of project activities and rationales
for these assumptions. The Wildlife Protection and Management
Plan(s) may be divided into separate plans by region or project area
as deemed necessary.
The Wildlife Protection and Management Plan(s) shall include:
a) results of pre-construction surveys, including surveys for
species at risk listed on Schedule 1 of the Species at Risk Act
public registry (listed species) except where the Minister has
iv) measures to limit predator travel along right of ways;
v) procedures to avoid disturbance of potential
maternal denning areas;
vi) access management, including provisions for
public consultation;
vii) protocols and education/awareness activities for
managing human-wildlife interactions, including measures
to limit harvesting and to deter wildlife, especially bears,
from entering camps and other facilities;
viii)measures to reduce the impacts of access road, right
of way, and other project-related vehicle and air traffic
on wildlife and migratory birds; and
ix) any wildlife protection measures included in other project
management plans, or references to those measures;
d) protocols for monitoring and adaptive management including:
determined that recovery for the species is not feasible, and
i) establishing and maintaining linkages to regional programs;
locations of any observations of species classified as at risk
ii) survey protocols to be employed to avoid or prevent impacts
or may be at risk on the most recent Committee on the Status
of Endangered Wildlife in Canada assessment and NWT General
Status Ranks;
b) updated impact assessments for listed species in consideration of
the Species at Risk Act, conducting the impact assessments
directly on the listed species where possible rather than using
one or more indicator species;
c) mitigation measures including:
i) measures to avoid or minimize disturbances including
linear disturbance and effects of habitat fragmentation,
sensory disturbance, and barriers to movement;
ii) scheduling of project activities to minimize wildlife
disturbance;
iii) measures to minimize the development footprint
to wildlife;
iii) plans for monitoring responses of wildlife to project activities
during all phases of the project;
iv) protocols for documenting habitat loss and habitat change
as well as wildlife incidents, interactions and mortality; and
v) measures to determine the effectiveness of mitigation
measures, criteria to determine when and how mitigation
measures should be adapted, as well as the responses
proposed to address unforeseen effects;
e) implementation plans, including:
i) details on how the plans will be implemented by
the Proponent;
ii) the measures the Proponent will take to enable
the participation of local monitors; and
in habitats known to support listed species;
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276 Mackenzie Gas Project • Volume 2: Implementing the decision
iii) the process for updating the protection plan as information
gaps are addressed, including listed species’ recovery
Management Plan(s) (Condition 29) with respect to grizzly bear:
strategies and action plans;
a) a plan to conduct annual grizzly bear den surveys during
f) processes for oversight and reporting with respect to
the Wildlife Protection and Management Plan(s) and how
those processes will be implemented; and
g) evidence of consultation with the Government of the Northwest
Territories, Environment Canada and appropriate wildlife
management boards.
pre-construction activities and pipe-laying operations prior to the
commencement of work planned for the coming season;
b) proposed mitigation measures for avoiding disturbance to grizzly
bear dens; and
c) a commitment to file the results of the surveys annually during
pre-construction activities and pipe-laying operations, prior to
To support the Wildlife Protection and Management Plan(s), the
the commencement of work planned for the coming season,
Proponent shall implement the following species-specific
with the Government of the Northwest Territories and
requirements, set out in Conditions 30 to 36, in addition to the
appropriate wildlife management boards.
specifications of Condition 29.
30. The Proponent shall include in its Wildlife Protection
and Management Plan(s) (Condition 29) with respect
to woodland caribou:
a) timing and dates during which project-related activities
33. The Proponent shall include in its Wildlife Protection and
Management Plan(s) (Condition 29):
a) mitigation measures to avoid creation of preferred bison habitat;
and
b) a monitoring program to detect wood bison use of the
would occur so as to avoid or minimize conflict with caribou
Mackenzie Gas Project’s right of way and a process to develop
movement or sensitive feeding or calving time; and
mitigation measures in consultation with the Government
b) evidence of consultation with the Dehcho Boreal Caribou
Working Group.
31. The Proponent shall include in its Wildlife Protection and
of the Northwest Territories if wood bison start using
the project right of way.
34. The Proponent shall include in its Wildlife Protection and
Management Plan(s) (Condition 29) with respect to barren
Management Plan(s) (Condition 29):
ground caribou:
a) the results of a survey in those parts of the Local Study Area
a) timing and dates during which project-related activities would
where, based on the most recent assessment by the Committee
occur so as to avoid or minimize conflict with caribou movement
on the Status of Endangered Wildlife in Canada, the yellow rail
or sensitive feeding or calving time;
and western toad might occur, to confirm the presence or
b) plans to address any impacts from the project on the Porcupine
caribou herd resulting from increased use of the Dempster
Highway by project-related traffic; and
c) evidence of consultation with the Porcupine Caribou
Management Board and the Government of Yukon.
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32. The Proponent shall include in its Wildlife Protection and
absence of those species;
b) proposed mitigation and monitoring measures specific to yellow
rail and western toad, based on the results of this survey; and
c) evidence of consultation with Environment Canada and the
Government of the Northwest Territories.
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Appendix M 277
35. The Proponent shall include in its Wildlife Protection and
and to the NEB inspectors, the Proponent shall file with the NEB an
Management Plan(s) (Condition 29) a commitment to conduct
Environmental Protection Plan (EPP) for approval at least 90 days
pre-construction, construction and post‑construction surveys
prior to the start of pipe-laying operations. The EPP may be divided
and monitoring programs in relation to short-eared owls
into separate plans by region or project area as deemed necessary.
and rusty blackbirds and to file this information with the
Government of the Northwest Territories.
The EPP for pipe-laying operations shall include:
a) the scope and area of application of the EPP;
36. The Proponent shall include in its Wildlife Protection and
Management Plan(s) (Condition 29) mitigation measures specific
to raptors, including peregrine falcon and bald and golden eagles,
that include the following restrictions on project-related activities
or facilities, unless the NEB otherwise directs:
a) for permanent structures, long-term habitat disturbance
including pipeline right of way, road, quarry, camp, etc.,
ground and air access, and blasting maintain a setback
of 1000 m from nest sites between April 15 and September 1
for peregrine falcons and between March 30 and July 31
for all other raptors; and
b) for aircraft overflight, maintain a setback of 760 m above
ground level from nest sites between April 15 and September 1
for peregrine falcons and between March 30 and July 31
for all other raptors.
Prior to Pipe-Laying Operations
37. The Proponent shall undertake a geotechnical verification program
to support the final design and construction of the project facilities
and shall file with the NEB 90 days prior to pipe-laying operations or
station construction:
a) copies of all borehole logs and the results of geophysical surveys
completed; and
b) an updated assessment of permafrost, ground ice and terrain
conditions along the Mackenzie Gathering System including, as
applicable, copies of all published information regarding
permafrost conditions, ground ice and terrain conditions used in
the assessment.
38. To compile and communicate all of the Proponent’s environmental
b) environmental protection procedures and measures, including
decision criteria for timing and implementation of these
measures, site-specific plans and drawings, mitigation measures,
and monitoring applicable to pipe-laying operations;
c) an acid rock drainage prevention plan incorporating the testing
of quarried and exposed rock during trenching, borrow pit and
quarry development and provisions for the safe disposal or
treatment of unsuitable material if required;
d) a reclamation plan which includes a description of the condition
to which the Proponent intends to reclaim and maintain the
right of way, a description of measurable goals for reclamation,
methods to minimize invasive plant introduction and measures
to maximize vegetation recovery;
e) references to other plans and manuals for environmental
protection required by field staff and inspectors; and
f) evidence of consultation with appropriate regulatory authorities
and government subject matter experts in the area of application
of the EPP.
39. To promote safety of the pipeline and protection of the environment
and to advance knowledge of the effects of pipeline construction
and operation in permafrost environments the Proponent shall
develop an effects monitoring program for the project. The purpose
of this program is to:
a) monitor the effects of the environment on pipeline integrity;
b) monitor the long-term effects of the construction and operation
of pipeline on the physical environment; and
c) validate design assumptions and approaches and monitor
protection procedures, mitigation measures, and monitoring
the effects of construction and operations practices used
commitments pertaining to pipe-laying operations to its field staff
on the project.
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278 Mackenzie Gas Project • Volume 2: Implementing the decision
This program shall take into account the results of the geotechnical
90 days prior to the start of pipe-laying operations, and shall file
verification program, the geohazard assessment and observations
with the NEB any modifications as they become available.
made during construction and shall be developed in consultation
with Indian and Northern Affairs Canada, Natural Resources Canada
and the Department of Fisheries and Oceans. The program shall
address and identify changes in thermal regimes and their
environmental effects, including existing and potential thaw
settlement, frost heave, slope stability, river crossing scour, aufeis,
drainage and fish passage impedance and erosion issues, and how
backfill and padding specifications at least 60 days prior to the start
of pipe-laying operations. The specifications shall include provisions
to ensure the replacement backfill and padding do not contain
materials injurious to the pipeline, its coating and the environment.
44. Unless the NEB otherwise directs, to determine the effectiveness
these would be affected by successive changes in compressor station
of the Proponent’s plans for remediating ditch fill settlement for
configuration. The program shall outline the monitoring methods to
the project, the Proponent shall file a report with the NEB 90 days
be used, instrumentation locations and the frequency of monitoring.
prior to the start of pipe-laying operations, which addresses:
The results shall be integrated into the Proponent’s integrity
a) its methods for determining the quality and quantity
management program and environmental protection program. The
Proponent shall file with the NEB:
i) a report for approval, at least 90 days prior to the start of
pipe-laying operations, which outlines the scope, objectives,
monitoring methodologies and frequencies and the criteria
for the selection of instrumentation sites for the program;
ii) on 1 April of each subsequent year of pipeline construction,
locations it has chosen to monitor, the rationale for
selection, the instrumentation required and the time
of its installation; and
iii) a report by 30 November of each year describing
the results of this program, and its mitigation/intervention
plans to address issues identified.
40. The Proponent shall file with the NEB for approval the
Construction Safety Manual at least 60 days prior to the start of
pipe-laying operations.
41. The Proponent shall file with the NEB the final Pipeline
Construction and Facility Specifications at least 60 days prior to
the start of construction. The specifications shall be of sufficient
scope and detail to demonstrate the suitability of the specifications
prior to the start of pipe-laying operations and facility construction.
42. To facilitate NEB inspections, the Proponent shall file with the NEB
updated engineering and environmental alignment sheets at least
1249_NEB_MGP_Vol2_Text_ENG.indd 278
43. The Proponent shall file with the NEB for approval the replacement
of imported fill required to remediate excess ditch settlement;
b) the timing and methods for hauling and stockpiling
the fill materials;
c) the methods it will use to assess and address the need
for additional replacement backfill or manage any excess
backfill during final clean up and reclamation;
d) methods and locations for the disposal of excess excavated
material not required for backfill; and
e) evidence of consultation with land managers and appropriate
regulators.
45. To demonstrate that it has adequately assessed and mitigated
against geohazards and to facilitate NEB monitoring during
operations, the Proponent shall file with the NEB, at least 90 days
prior to the start of pipe-laying operations, a Geohazard Assessment
for the project describing:
a) its geohazard assessment methodology and the specific
and combined geohazards identified along the route that
have a reasonable probability of impacting the project;
b) specific measures to be implemented to mitigate individual
and combined geohazards;
c) decision criteria for the implementation of mitigation
for geohazards identified during construction;
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Appendix M 279
d) the qualifications of the staff making decisions regarding
design and implementation; and
e) the ongoing monitoring requirements.
46. To demonstrate that the pipeline design is sufficient to withstand
anticipated frost heave and thaw settlement loadings, the Proponent
b) revisions to threshold slope angles, critical longitudinal and
critical cross slope criteria based on findings from final design
and further geotechnical investigations;
c) target Factor of Safety for longitudinal and cross slope designs;
d) details of selected passive ground cooling systems including the
shall file with the NEB a report summarizing the findings of the final
proposed number, location, type, refrigerant, typical drawings,
design frost heave and thaw settlement analysis for overland areas
corrosion protection and installation method;
at least 90 days prior to the start of pipe-laying operations. Where
e) details of the selected surface insulation(s) including type,
analysis indicates that the strain demand over the design life may
source, thickness and specified mitigation against
exceed the strain capacity of the pipeline materials (omitting the
the introduction of noxious weeds (if applicable);
effect of secondary mitigation measures), the report shall describe
the site specific secondary measures incorporated into the design
or integrity management program to prevent the pipeline from
exceeding the critical threshold strain limits.
47. The Proponent shall undertake a hazard analysis identifying
f) details of erosion control requirements including typical drawings
and spacing requirements for berms, plugs and ditches;
g) results of thermal analysis showing 10 and 25 year thaw depth
predictions for the start up configurations based on selected
thermal mitigation options for thaw sensitive slopes exceeding
reasonably foreseeable hazards or problems with horizontal
critical slope length, slopes identified as potential concerns
directionally drilled (HDD) activities, based on site specific data,
from a stability perspective which cannot be avoided by route
and develop specific contingency plans for each HDD crossing.
refinements, and slopes that have or will have slope
The Proponent shall file the hazard analysis and contingency
instrumentation installed during the construction phase;
plans with the NEB at least 60 days prior to the start of construction
of an HDD watercourse crossing. The plans shall identify and
address, where applicable, site-specific concerns such as the
presence of ice-rich permafrost and other potentially unfavorable
geotechnical conditions.
48. To facilitate NEB inspection during construction and monitoring
during operations, and to confirm that there have been no
significant changes to the slope design methodology, the Proponent
shall file for approval with the NEB a Slope Design Methodology
Final Report following the completion of final design and
h) typical design drawings for various slope conditions;
i) specific designs for thaw sensitive slopes exceeding critical
slope length;
j) a tabular summary of sites requiring site-specific slope designs,
indicating the location and identification number of the slope,
slope angle, slope length, slope height, orientation, actual
or assumed soil conditions, nature of the site-specific issue
and proposed mitigation measures; and
k) a slope stability response plan describing the actions
at least 90 days prior to the start of pipe-laying operations.
the Proponent shall take, and the timing of those actions,
The Slope Design Methodology Final Report shall include:
should monitoring indicate that the Factor of Safety for a slope
a) the slope design methodology, data requirements, assessment
techniques and pre‑construction slope inventory;
1249_NEB_MGP_Vol2_Text_ENG.indd 279
falls below the design Factor of Safety or thaw depth exceeds
predicted values.
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280 Mackenzie Gas Project • Volume 2: Implementing the decision
49. The Proponent shall file with the NEB for approval a Field Changes
b) detailed final design drawings and plans for all watercourse and
Manual, for Slopes at least 90 days prior to the start of pipe-laying
waterbody crossings requiring site specific designs, including
operations. The manual shall include:
HDD crossings, showing the design flood level, calculated
a) specific criteria for the implementation of changes
vertical and lateral scour potential and detailing proposed
to the designs, grading, materials, installation procedures,
thermal, erosion, scour control and ground water flow
thermal stabilization measures, erosion mitigation measures
mitigation measures;
and monitoring;
c) detailed final design drawings of typical designs for open cut
and isolated crossings of Lakes, Active I, Active II and Vegetated
b) details regarding the required qualifications of its field staff
Channel watercourses detailing proposed thermal, erosion, scour
implementing the manual; and
control and ground water flow mitigation measures;
c) consultation required with other experts and regulatory
d) 25 year frost bulb growth analysis for the start up configuration,
authorities and the scope of that consultation.
including predicted strain demand/available strain capacity and
50. To protect traditional harvesting of fish from adverse impacts related
frost bulb dimensions, for all Large, HDD, Active I and Active II
to project stream crossings, the Proponent shall file with the NEB,
watercourse crossings; and
at least 90 days prior to the start of pipe‑laying operations,
e) evidence of consultation with the Department of Fisheries
the final suite of decision trees proposed to manage the impacts
and Oceans in regards to the design of stream crossings.
of the Mackenzie Gas Project on fish and fish habitat including:
a) an explanation of the decision-making process, the criteria
52. To facilitate NEB monitoring, the Proponent shall notify the NEB
at least 30 days prior to qualifying the automated ultrasonic
for decision-making and the mitigation options;
non-destructive examination procedures for mill and field
b) a description of how the Proponent will address the importance
circumferential welds.
of fish habitat and fish populations to local communities
and harvesters; and
53. The Proponent shall develop the joining program and file it with the
NEB at least 30 days prior to conducting welding procedure
c) evidence of consultation with Fisheries and Oceans Canada
and the relevant management boards and agencies with
qualification tests for:
regard to the decision trees.
a) field circumferential production, tie-in and repair pipeline welds;
and
51. To demonstrate the adequacy of scour protection and thermal
b) welding of project facilities.
mitigation measures of watercourse crossing designs and facilitate
NEB inspection during construction, the Proponent shall file for
approval with the NEB at least 90 days prior to the start of
pipe‑laying operations:
a) a revised Watercourse/Waterbody Crossing Inventory, in both PDF
and MS Excel spreadsheet format, describing the watercourse
name and numerical identifier, coordinates, stream class, width
of wetted channel, construction method, design type, minimum
pipeline cover, navigability and fish habitat status and level
of assessment;
1249_NEB_MGP_Vol2_Text_ENG.indd 280
The joining program shall include:
i) requirements for the qualification of welders;
ii) requirements for the qualification and duties
of welding inspectors;
iii) welding procedure specifications;
iv) non-destructive examination specifications;
v) quality assurance program for field welds
and welding procedures; and
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Appendix M 281
vi) any additional information which supports
the joining program.
54. To facilitate NEB inspection, the Proponent shall file with
the NEB procedure qualification records for welding and
non-destructive examination within 30 days of the completion
of procedure qualification tests.
55. To facilitate NEB inspection, the Proponent shall file with
the NEB the specifications for field applied coatings at least
60 days prior to the start of pipe-laying operations.
58. To verify implementation of the Proponent’s quality assurance and
control plans and procedures, the Proponent shall file monthly
summary reports during construction outlining non-conformances
with its design, materials, and construction specifications and
the disposition of these non-conformances.
Prior to Operation
59. The Proponent shall file with the NEB for approval, at least
90 days prior to the planned start of operation, the elements
of the Environmental Protection Program for the operation
and maintenance of the pipeline pursuant to section 48 of the
During Construction
Onshore Pipeline Regulations, 1999. The elements to be submitted
56. To facilitate NEB inspection of all phases of construction, the
include but not be limited to policies, practices and procedures for:
Proponent shall provide when requested, logistical support to NEB
staff undertaking inspection of construction and reclamation, at a
reasonable cost to the NEB. (For clarity, the scope of this support is
limited to transportation of NEB staff and vehicles to isolated camp
locations, vehicle fuel and maintenance, meals and accommodation,
office space and communications support.)
57. Unless the NEB otherwise directs the Proponent shall pressure test
a) ongoing environmental training for employees/operators;
b) handling and disposal of all wastes associated with the operation
and maintenance of the project;
c) management of air emissions, including:
i) maximum Proponent-identified and/or legislated discharge
limits for PM and NOx;
the approved facilities with a liquid medium and submit the Pressure
ii) maximum Proponent-identified greenhouse gas targets;
Testing Program, demonstrating compliance with applicable codes,
iii) reduction strategies for air emissions including
standards and regulatory requirements, to the NEB for approval at
least 60 days prior to the start of pressure testing; or in the event
that a hydrostatic test is not practicable, the Proponent shall
file with the NEB for approval, at least 60 days prior to the start
of any air testing activities, the Proponent’s air testing measures.
The program shall include:
a) information demonstrating the ability of the leak test
to detect the same size leak as a comparable hydrostatic test;
b) information demonstrating that the pipeline has adequate
notch toughness;
c) a description of the specific safety precautions
to be implemented during the pressure test; and
d) a confirmation of successful leak test of pipeline sections
prior to their installation under watercourses, lakes and ponds.
1249_NEB_MGP_Vol2_Text_ENG.indd 281
PM, NOx, and greenhouse gases;
iv) monitoring and measurement methods; and
v) record keeping including annual reporting
of greenhouse gases to the NEB;
d) public communication program (non-emergency); and
e) program review and consultation with Environment Canada
and the Government of Northwest Territories.
60. To demonstrate that in-line inspection tools will be able to support
effective integrity management programs, the Proponent shall submit
to the NEB at least 90 days prior to the start of system operation:
a) the type, description, specifications, operating limits and
detection limits of all in‑line inspection tools which can
be used by the Proponent during operation of its pipelines;
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282 Mackenzie Gas Project • Volume 2: Implementing the decision
b) data on the inertial curvature inline inspection tool(s) developed
for the project indicating the detectable level of displacement
and associated strain, the recommended pig velocity, and the
relationship between pig velocity and strain resolution; and
c) intervention values for all parameters that will be monitored
by in-line inspection tools.
61. The Proponent shall prepare:
a) an Emergency Preparedness and Response Plan for the project
63. Unless the NEB otherwise directs the Proponent shall file with the
NEB a report describing the final design of the SCADA and leak
detection system for the Mackenzie Gathering System at least 90
days prior to the start of operation of the Mackenzie Gathering
System. The report shall include information suitable for establishing
a base line for the quality program for its SCADA and leak detection
system and shall include:
prior to the start of system operation and file with the NEB
a) a description of the SCADA and leak detection system;
the Emergency Procedures Manual at least 30 days prior to
b) the location and type of pressure, temperature and flow
the start of operation; and
b) a report, to be filed with the Emergency Procedures Manual,
which outlines:
i) the potential for the establishment of local, communitybased spill response teams to assist in responses
to Mackenzie Gas Project incidents;
ii) a discussion of the opportunities and constraints
of establishing local spill response teams including
a training and equipment needs assessment; and
iii) the Proponent’s commitment to work with local
communities to build and maintain community spill
response capacity.
upon the successful completion of the exercise.
In preparing its Emergency Preparedness and Response Plan, the
Proponent shall have regard to:
1) the NEB letter dated 24 April 2002 entitled Security and
monitoring and control devices and remote terminal units;
c) the location of remotely operated valves;
d) the target detect ability (e.g., amounts leaked, time to detect,
leakage rate);
e) the target sensitivity (i.e., minimum leak size);
f) the target reliability (i.e., false alarm rate, failure to alarm rate);
g) the expected system robustness (i.e., system availability in light
of the system operating conditions);
h) the target accuracy (i.e., size and location of a detected leak); and
i) a description of the quality program using both direct and
inferred methods that the Proponent shall implement during the
operational phase of the project to ensure optimal performance.
64. To demonstrate that the SCADA and leak detection system are
calibrated to actual system conditions, the Proponent shall file
Emergency Preparedness Programs addressed to all oil and gas
with the NEB, reports describing the results of the Proponent’s
companies under the jurisdiction of the NEB and subsequent
quality program for its SCADA and leak detection system and how
amendments made thereafter; and
identified issues were addressed. Unless the NEB otherwise directs,
2) emergency responses required as a result of significant
earthquakes which may require a broader scope of response.
62. To demonstrate that it is prepared to respond to an emergency
at the outset of operation, the Proponent shall hold an emergency
response exercise to evaluate the effectiveness of the Emergency
Preparedness and Response Plan at least 10 days prior to the start
the reports shall be filed one year, three years and five years after
the start of system operation.
During Operation
65. Within 30 days of the date that the approved project is placed in
service, the Proponent shall file with the NEB a confirmation, by an
officer of the company, that the approved project was completed
of system operation and file a letter of notification with the NEB
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Appendix M 283
and constructed in compliance with all applicable conditions in this
69. To aid NEB inspectors in confirming the effectiveness of mitigation
Certificate. If compliance with any of these conditions cannot be
techniques and any adaptation required, as well as to identify
confirmed, the officer of the company shall file with the NEB details
effects that were not predicted and appropriate adaptive
as to why compliance cannot be confirmed. The filing required by
management to address these effects, the Proponent shall file
this condition shall include a statement confirming that the signatory
with the NEB a post-construction environmental report that reflects
to the filing is an officer of the company.
any monitoring or follow-up program developed, including:
a) identification on a map or diagram of any environmental
66. To facilitate monitoring during operation, the Proponent shall file
issues which arose during construction;
with the NEB, within six months of the start of system operation,
b) the criteria used or to be used to verify the accuracy
a geotechnical construction report including maps and drawings,
of the environmental assessment predictions;
which identifies and describes:
a) longitudinal and cross slopes identified during construction
c) the determination of the accuracy of the environmental
as requiring ongoing monitoring;
assessment predictions;
b) locations where passive cooling systems were installed;
d) discussion of the effectiveness of the mitigation applied
pre-, during and post- construction and where adaptive
c) locations where slope instrumentation including thermistors,
management was necessary;
piezometers and slope inclinometers were installed;
e) identification of the current status of the issues identified
d) slopes exceeding the critical slope length which were identified
describing whether those issues are resolved or unresolved; and
during construction as being thaw sensitive or exhibiting
evidence of soil movement;. and
f) proposed measures and schedule that the Proponent shall
implement to address any unresolved concerns.
e) locations where slope design changes were made in accordance
with the Field Change Manual for Slopes and the reasons for
the design change.
67. To minimize or reduce air emissions from flaring, the Proponent
shall meet the Guideline for Ambient Air Quality Standards
The report shall be filed on or before the 31 of January of
each of the first, third, fifth and tenth years following the start
of project operation, unless the NEB otherwise directs.
70. Unless the NEB otherwise directs, to demonstrate the management
in the Northwest Territories and Alberta’s Energy Resources
of pipeline integrity and thermal effects on the right of way the
Conservation Board Directive 60: “Upstream Petroleum
Proponent shall monitor geotechnical and thermal effects
Industry Flaring, Incinerating and Venting”.
on the pipeline(s) with respect to thaw subsidence, frost heave
68. To minimize noise disturbance from pipeline facilities,
the Proponent shall:
a) design pipeline facilities to meet the requirements of Alberta’s
Energy Resources Conservation Board Directive 038; and
b) file with the NEB, 90 days following the start of operation,
a post construction noise assessment report.
and slope stability by:
a) undertaking a detailed as-built survey prior to backfill which
documents the position of the pipeline for comparison with
future in-line inertial inspection data, the location of pipe
specification changes, the location of each circumferential
weld, buoyancy control devices, depth of cover; and
b) undertaking an inertial in-line inspection within one month
of the start of operations and on an annual basis thereafter.
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284 Mackenzie Gas Project • Volume 2: Implementing the decision
71. To facilitate monitoring, the Proponent shall record ditch wall
77. Unless the NEB otherwise directs, to ensure that safety, integrity,
geotechnical information during construction and shall file
and environmental protection will be at an equivalent level for the
the ditch wall logs with the NEB within one year of the start
Mackenzie Gathering System as for the Mackenzie Valley Pipeline,
of system operation.
the Proponent shall comply with the following regulations:
72. To facilitate monitoring, the Proponent shall file with the NEB, within
one year of the start of system operation, copies of all stream flow
monitoring, ice thickness measurements and ground temperature
monitoring data collected during project planning and design.
Numerical records shall be submitted in both PDF and MS Excel
spreadsheet format.
Planning Clause
73. The Proponents shall file updated cost estimates and report
on their decision to construct by 31 December 2013.
a) the Onshore Pipeline Regulations, 1999, as amended from
time to time;
b) the National Energy Processing Plant Regulations, as amended
from time to time; and
c) those sections of the National Energy Board Pipeline Crossing
Regulations Part I and Part II and as amended from time
to time that would be applicable to the Proponent.
78. To ensure the NEB is satisfied that the pipeline may be safely opened
for transmission the Proponent shall file for approval the information
Sunset Clause
referred to in NEB Filing Manual, 2004, for opening the pipeline for
74. Unless the NEB otherwise directs, this Certificate shall expire on
operation (Guide “T”).
31 December 2015 unless construction in respect of the Mackenzie
Gas Project has commenced by that date.
79. The authorization for the Mackenzie Gathering System under
paragraph 5(1)(b) is subject to the Minister of Indian Affairs and
Conditions that apply only to the Mackenzie Gathering System
Northern Development Canada providing confirmation that the
75. Prior to leave to open, the Proponent shall provide financial
Proponents have satisfactorily met the Benefits Plan requirements
responsibility pursuant to subsection 13(14) of the Inuvialuit Final
Agreement in the amount of $6,028,200 to be held in trust by
of section 5.2 of the Canada Oil and Gas Operations Act.
80. Prior to commencement of pre-construction activities, the
the NEB in a form satisfactory to the NEB and to remain in place
Proponents shall provide a declaration pursuant to subsection
until all facilities located within the Inuvialuit Settlement Region
5.11(1) of the Canada Oil and Gas Operations Act in a form
are abandoned in accordance with NEB requirements.
satisfactory to the NEB.
76. Prior to the start of pre-construction activities, the Proponent shall
81. Prior to commencement of the related activities, the Proponents
provide financial responsibility pursuant to the Canada Oil and Gas
shall provide any necessary certificates pursuant to subsection
Spills and Debris Liability Regulations and subsection 27(1) of
5.12(1) of the Canada Oil and Gas Operations Act in a form
Canada Oil and Gas Operations Act in the amount of $25,000,000
satisfactory to the NEB.
in a form satisfactory to the NEB, to remain in place until all facilities
are abandoned in accordance with NEB requirements.
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Appendix N 285
Appendix N
Miscellaneous Order for
Mackenzie Gathering System Tolls
ORDER MO-18-2010
IN THE MATTER OF Part 0.1 of the Canada Oil and Gas Operations Act; and
IN THE MATTER OF an application by Imperial Oil Resources Ventures Limited (the Proponent), on behalf
of Imperial Oil Resources Ventures Limited, ConocoPhillips Canada (North) Limited, ExxonMobil Canada
Properties and Shell Canada Limited as managing partner of Shell Canada Energy filed with the National
Energy Board (Board) for the Mackenzie Gathering System under file numbers: OF-Fac-Gas-I017-2004-1,
OF-EP-FacPipe-I003-MAC 04, OF-EP-FieldOp-I003-TL 07, OF-EP-FieldOp-C648-PL 07, OF-EP-FieldOpS245-NIG 07.
WHEREAS the Proponent filed an application in October 2004 under
AND WHEREAS the application was set down for hearing in Hearing
the Canada Oil and Gas Operations Act for the Mackenzie Gathering
Order GH‑1‑2004;
System which consists of:
• 190 kilometres of pipeline to carry the natural gas and natural
gas liquids from the Niglinktak, Taglu and Parsons Lake fields
to a processing plant near Inuvik, Northwest Territories;
AND WHEREAS the appropriate tolls, access and tariff provisions for
the Mackenzie Gathering System and the methods for resolving disputes
on these matters was on the List of Issues for the Hearing;
• the processing plant near Inuvik, Northwest Territories; and
AND WHEREAS the National Energy Board has indicated that it intends
• a 457 kilometre long, 250 millimetre (10 inch) diameter pipeline
to issue an authorization for the Mackenzie Gathering System;
to carry natural gas liquids from the processing plant near Inuvik,
Northwest Territories to the existing crude oil pipeline at Norman Wells
operated by Enbridge Pipelines (NW) Inc.;
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286 Mackenzie Gas Project • Volume 2: Implementing the decision
IT IS ORDERED pursuant to Part 0.1 of the Canada Oil and Gas
e) protection of confidential and commercially-sensitive
Operations Act that the method for determining tolls for the Mackenzie
information;
Gathering System agreed to by the Proponent in the GH‑1‑2004
f) mechanisms and methodologies related to the design
proceedings be approved subject to the following:
1.
of an acceptable transfer pricing mechanism;
The Mackenzie Gathering System shall be accessible to all shippers
g) a Code of Conduct compliance plan with independent audits;
that meet the terms of the contractual arrangements.
2.
and
Tolls for the Mackenzie Gathering System, including the natural gas
h) penalties for breaches of the Code of Conduct and recourse
liquids line, shall be negotiated and regulated on a complaint basis.
3.
The Proponent shall file, for National Energy Board approval, a Code
to a third-party arbitrator.
4.
Consistent with the requirements for all pipelines to set aside funds
of Conduct for the Mackenzie Gathering System for all phases of
to cover all abandonment activities as set out in RH-2-2008, at least
development including pre-construction, construction and
18 months prior to the pipelines being placed in service the
operation. The Code of Conduct is to be filed as soon as possible
Proponent shall prepare and file for approval:
but in any event no later than 31 December 2011. At a minimum,
the Code of Conduct should address in detail:
a) prevention of undue preferential treatment;
b) governance of the interactions between shippers
and transporters;
c) independence of transmission operations from affiliate
a) an estimate of abandonment costs and the amount required to
be set aside using pipeline-specific assumptions or a combination
of pipeline-specific assumptions and Base Case assumptions
from the National Energy Board’s RH-2-2008 proceeding; and
b) a proposal for the collection of funds and a proposed process
and mechanism to set aside the funds.
operations;
d) governance of separation of business;
NATIONAL ENERGY BOARD
Anne-Marie Erickson
Secretary of the Board
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Appendix O 287
Appendix O
Conditions for the Shell Canada Limited (Shell)
Development Plan for the Niglintgak field
Many of the proposed conditions reference an application for an
Unless otherwise specified in a condition best management practices
authorization under paragraph 5(1)(b) of the Canada Oil and Gas
(BMP) are innovative, dynamic, and improved environmental protection
Operations Act (COGOA). Before any drilling or construction activity
practices and procedures that help ensure that development is conducted
relating to a development plan may commence, authorizations under
in an environmentally responsible manner. BMP may exist as formal
paragraph 5(1)(b) would be required. Section 6 of the Canada Oil and
guidelines or generally accepted procedures that are recognized by
Gas Drilling and Production Regulations states that an operator shall
regulators and industry associations as best practices.
provide the following in an application for an authorization under
paragraph 5(1)(b): a description of the scope of activities; an environmental
protection plan; a safety plan; and a contingency plan. The activities in
relation to a development plan may include drilling, completions, facilities
construction, production, and decommissioning.
N1. Unless the National Energy Board (NEB) otherwise directs, Shell
shall design, implement or cause to be implemented all of the
policies, mitigation measures, procedures, specifications, standards
and recommendations for any work or activity referred to in the
Development Plan application or in the Environmental Impact
Unless otherwise specified, Proponent consultation referred to in a
Statement or other filings with the Joint Review Panel or as
condition must be carried out in a manner that includes the Proponent:
otherwise agreed to during the GH-1-2004 Hearing and during the
a)
review by the Joint Review Panel.
providing, to the party to be consulted,
i) notice of the matter in sufficient form and detail to allow
the party to prepare its views on the matter,
ii) a reasonable period for the party to prepare those views, and
iii) an opportunity to present those views to the party conducting
the consultation; and
b) considering, fully and impartially, any views so presented.
N2. To promote potential joint development with a minimal
environmental footprint, the north, central and south well pads of
the Niglintgak field shall each be designed so they may be expanded
to allow for the drilling of at least one well by third party adjacent
subsurface rights interest holders.
N3. To prevent coalescence of the well permafrost thaw bulbs,
the interwell spacing on a well pad shall not be less than 15 m
Unless otherwise specified in a condition best available technology
unless Shell utilizes mitigation measures approved by the NEB.
(BAT) means technology with superior emissions performance which
is commercially available at a reasonable cost at the time it is required
N4. To confirm the estimates of subsidence due to gas extraction,
for the project which meets the goals of pollution prevention and
Shell shall submit a program employing BMP and BAT to
energy efficiency.
quantitatively measure and monitor accumulated subsidence, and to
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288 Mackenzie Gas Project • Volume 2: Implementing the decision
monitor flooding for the life of the field with the initial application
a) a hazard analysis and contingency plan for the proposed
for an authorization under paragraph 5(1)(b). For this condition BAT
horizontal directional drill crossing. The plan shall identify
means technology with superior accuracy and measurement
and address site-specific concerns such as the presence
performance which is commercially available at a reasonable cost at
of ice-rich permafrost and other potentially unfavourable
the time it is required for the project which meets the goals of
geotechnical conditions;
pollution prevention and energy efficiency. The program shall
b) detailed final design drawings of the proposed HDD showing the
include:
design flood level, calculated vertical and lateral scour potential
a) a description of proposed survey area or the proposed
and detailing proposed thermal, erosion, scour control and
number and the proposed locations of the elevation survey
points within the projected gas-extraction-subsidence-area;
b) the proposed number and the proposed locations of the
elevation benchmarks to be situated outside the projected
gas-extraction-subsidence-area in order to estimate natural
subsidence;
c) the expected elevation accuracy of the surveys;
d) a proposed baseline survey to be conducted prior
to the commencement of natural gas production;
e) the proposed measurement frequency and the proposed
reporting frequency to the NEB; and
f) the results of consultation with Environment Canada.
N5. Prior to the commencement of drilling, Shell shall provide financial
ground water flow mitigation measures;
c) detailed final design drawings of the contingent open cut
detailing proposed thermal, erosion, scour control and ground
water flow mitigation measures;
d) a monitoring program for slope stability, scour, drainage
impedance and erosion issues for the crossing; and
e) evidence of consultation with other appropriate regulators
and government departments.
N8. To confirm adequate consideration of the effects of climate change
has been incorporated into the facilities design, Shell shall submit
the following information with the initial application for an
authorization under paragraph 5(1)(b):
a) an analysis of the impacts of climate change and variability on
responsibility pursuant to subsection 13(14) of the Inuvialuit Final
permafrost and terrain stability for the Niglintgak facility using
Agreement in the amount of $30,072,000 to be held in trust
potential upper limit temperature scenarios which may occur
by the NEB in the form satisfactory to the NEB and to remain
during the operational life of the facilities;
in place until all wells and facilities are abandoned in accordance
with NEB requirements.
N6. All financial responsibility provided pursuant to the Canada Oil and
Gas Spills and Debris Liability Regulations and subsection 27(1) of
b) a description of how these upper limit temperature scenarios
may impact precipitation, rise in sea level, storm surges, ice floes
and flood levels;
c) a description of how the proposed facilities design, including
Canada Oil and Gas Operations Act shall remain in place until all wells
water course crossing design, accounts for the potential changes
and facilities are abandoned in accordance with NEB requirements.
outlined in b); and
N7. To promote safety of the pipeline and protection of the environment
with respect to the design, construction and operation of the
proposed flow line crossing of the Kumak Channel, Shell shall
d) the results of consultation with appropriate regulators and
government departments.
N9. To minimize noise disturbance from facilities inside the Kendall Island
provide the following with the corresponding application for
Bird Sanctuary, Shell shall:
an authorization under paragraph 5(1)(b) of COGOA:
a) design the facilities to meet, as a minimum, the requirements of
Alberta’s Energy Resources Conservation Board Directive 038;
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Appendix O 289
b) incorporate BMP and BAT related to noise abatement into
the facilities design;
c) continue to evaluate noise mitigation options in consultation
with Environment Canada and submit the results of consultation
with the corresponding application for an authorization under
paragraph 5(1)(b); and
d) submit an independent noise impact analysis report
on the proposed design and the feasibility of further reductions
in noise emissions with the corresponding application for
an authorization under paragraph 5(1)(b).
N10. Shell shall provide the following with the corresponding application
for an authorization under paragraph 5(1)(b):
a) the plans for excavation and dredging at the site of the bargebased gas conditioning facility set-down location;
e) a reclamation plan which includes a description of the condition
to which Shell intends to reclaim, a description of measurable
goals for reclamation, methods to minimize invasive plant
introduction, and measures to maximize vegetation recovery.
f) management of air emissions, including:
i) maximum Proponent-identified and/or legislated discharge
limits for particulate matter (PM) and NOx;
ii) maximum Proponent-identified greenhouse gas targets;
iii) reduction strategies for air emissions including PM, NOx,
and greenhouse gases;
iv) monitoring and measurement methods;
v) location of monitoring sites on a map or diagram, the
purpose for the locations selected, and timing of installation;
vi) details of the additional measures that would be
b) a dredging spoil management plan;
implemented as a result of monitoring data or ongoing
c) the results of consultation with Environment Canada,
concern, and the criteria or thresholds that would require
Department of Fisheries and Oceans and Transport Canada.
N11. To compile and communicate all of Shell’s environmental protection
procedures, mitigation measures, and monitoring commitments
these measures; and
vii) record keeping including annual reporting of greenhouse
gases to the NEB;
pertaining to the facilities operations, to its field staff, and to
g) public communication program (non-emergency);
the NEB inspectors, Shell shall file with the NEB an Environmental
h) program review and consultation with Environment Canada
Protection Plan (EPP). The EPP is to be submitted with the initial
application for an authorization under paragraph 5(1)(b) and shall
and the Government of Northwest Territories; and
i) evidence of consultation with appropriate regulatory authorities
include policies, practices and procedures for:
and government subject matter experts in the area of application
a) the scope and area of application of the EPP;
of the EPP.
b) environmental protection procedures and measures, including
N12. In order that the facilities, camps and supporting infrastructure are
decision criteria for timing and implementation of these
maintained and operated in an environmentally acceptable condition
measures, site-specific plans and drawings, mitigation
during construction and production operations, Shell shall submit
measures, and monitoring applicable to construction
a Waste Management Plan with the initial application for the
and drilling operations;
authorization under paragraph 5(1)(b). This plan shall be developed
c) ongoing environmental training for employees/operators;
in consultation with the Government of the Northwest Territories,
d) references to other plans and manuals for environmental
Indian and Northern Affairs Canada and Environment Canada.
protection required by field staff and inspectors;
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290 Mackenzie Gas Project • Volume 2: Implementing the decision
The plan shall address:
a) all wastes associated with construction and production
operations with the objectives of minimizing impacts to
the environment and ensuring worker and public safety;
b) objective and measurable environmental and engineering
criteria to determine when the winter road will be ready for use;
c) safe ice thickness criteria for lake, river and stream crossing
including the frequency of ice profiling;
b) training requirements for company and contractor staff;
d) local regulatory requirements;
c) the prevention of uncontrolled fires;
e) installation and removal requirements for snow fills, culverts,
d) disposal or treatment of potentially hazardous and dangerous
materials, including petroleum products, toxic or persistent
chemicals, oily wastes, aircraft de-icing fluids and fuel barrels;
e) solid waste management including metals, plastics, recyclables,
corduroy and temporary bridges; and
f) objective and measurable environmental and engineering
criteria for closure.
N14. Shell shall evaluate the technologies and practices available to
incinerator ash, equipment, equipment parts, batteries, building
reduce emissions of particulate matter (PM) and precursors of PM
materials and construction waste;
and ozone from its facilities and construction related activities, and
f) food waste management including measures to minimize
animal attraction;
g) management of contaminated soil, snow and ice from spills
and aircraft de-icing;
h) treatment and disposal of domestic sewage and grey water;
i) incineration/evaporator technology choices and rationale for
selection;
j) waste segregation requirements, interim storage and treatment;
k) testing methods and disposal for waste streams proposed for
release to the environment; and
l) the results of consultation.
N13. To demonstrate that winter roads will be constructed and operated
incorporate BMP and BAT to reduce emissions of PM and precursors
of PM and ozone to the extent practicable. Shell shall file a report
of its findings and how it will implement its findings with the initial
application for an authorization under paragraph 5(1)(b).
N15. Shell shall evaluate and implement technologies and practices
available to reduce mercury, dioxin and furan emissions from
incinerators operating at construction camps and facilities to
the extent practicable. Shell shall file a report of its findings and
how it intends to implement its findings with the initial application
for an authorization under paragraph 5(1)(b).
N16. Shell shall file with the initial application for an authorization under
paragraph 5(1)(b) a report outlining:
a) the specific design and operational measures it has implemented
in a safe and environmentally acceptable manner, Shell shall submit
and will implement to minimize methane leakage and venting
a manual for the construction, operation, maintenance and closure
through the system’s operation taking into account BMP
of winter roads with the initial application for an authorization
developed by Canadian Association of Petroleum Producers,
under paragraph 5(1)(b). The manual shall include:
Environment Canada, the Canadian Energy Partnerships for
a) required road width, clearing and grading requirements,
Environmental Innovation and the Canadian Gas Association;
grade, allowable speed, signage, maximum vehicle weight;
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Appendix O 291
b) how Shell has utilized waste heat energy to minimize natural
gas fuel consumption in the design of the facilities;
c) the use of BAT when specifying compressor units used including
c) identification of resources (equipment and staff) to be
on-site and/or available to respond to emergencies;
d) identification of mutual aid partners and the location
size, efficiency and their conformity with Canadian Council
of their resources (equipment and staff) available to respond
of Ministers of the Environment National Emissions Guidelines
to emergencies;
for Stationary Combustion Turbines (CCME,1992); and
e) procedures for responding to spills, releases, fires, medical
d) the results of consultation with Environment Canada and
emergencies and security issues including the incident
the Government of the Northwest Territories.
N17. To minimize or reduce air emissions from flaring, Shell shall meet
the Guideline for Ambient Air Quality Standards in the Northwest
Territories and Alberta’s Energy Resources Conservation Board
reporting and notification system;
f) location of fire and spill response equipment stores
and the spill kit requirements for vehicles;
g) a phone list of company, contractor, government agency
Directive 60: Upstream Petroleum Industry Flaring, Incinerating
and community representatives outlining their respective roles
and Venting.
and information needs;
N18. Unless the NEB otherwise directs, Shell shall submit an updated
resource management plan within 18 months after production
commences or prior to the drilling of contingent wells.
N19. To protect the correlative rights of adjacent subsurface rights
interest holders, Shell shall comply with to the NEB’s Draft Spacing
Requirements dated 31 December 2009 or any orders dealing
with spacing units that may supersede it.
N20. To address worker and public safety and environmental protection,
h) clean-up and disposal procedures for generated clean-up wastes;
i) identification of muster points for emergency evacuations from
camps and facilities;
j) location of emergency medical treatment locations
and capabilities;
k) the requirement for 24-hour emergency medical
evacuation capability;
l) maps showing the location of infrastructure such as camps,
Shell shall prepare its contingency plans in consultation with Indian
access roads, material storage areas, aircraft landing sites,
and Northern Affairs Canada, the Canadian Coast Guard, Transport
barge landing sites and borrow pits to facilitate the dispatch
Canada, Environment Canada, the Government of the Northwest
of first responders;
Territories and the Inuvialuit Land Administration. The contingency
plans shall include:
a) training and orientation requirements of company and
contractor staff;
m)consideration of high flood and high ice floe scenarios;
n) consideration of earthquakes; and
o) the results of consultation.
b) an inventory indicati