CJPAE C.J. PETER ASSOCIATES ENGINEERING

MECHANICAL BUILDING SERVICES CONSULTING ENGINEERS

201 - 2113 SOUTH OGILVIE STREET, PRINCE GEORGE, B.C. V2N 1X2 (250) 562-7044 phone cjpae@mag-net.com email

May 31, 2013

E-FILE

Attention: Ms. Sheri Young

Secretary to the Joint Review Panel

Enbridge Northern Gateway Project

National Energy Board

444 Seventh Avenue SW

Calgary, AB T2P 0X8

Dear Ms. Young,

Re: Northern Gateway Pipelines Inc. (Northern Gateway)

Enbridge Northern Gateway Project Application of 27 May 2010

Hearing Order OH-4-2011

NEB File No: OF-Fac-Oil-N304-2010-01 01

Final Written and Oral Argument

Please find attached for submission to the Joint Review Panel the final written argument of

C.J. Peter Associates Engineering (CJPAE) with respect to the Northern Gateway Project.

Please be advised that we intend to present oral argument at the final hearings in Terrace, BC

beginning on June 17, 2013. CJPAE’s oral argument will be presented by:

Dr. Hugh Kerr

Dr. Ricardo Foschi

Mr. Brian Gunn

We anticipate that CJPAE’s oral argument will take one hour.

Please advise the undersigned at (250) 562-7044 if you require any additional information.

Yours very truly,

C.J. PETER ASSOCIATES ENGINEERING

Chris Peter, P.Eng. LEED® AP

Attachment

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E-FILE

IN THE MATTER OF NEB FILE: OF-Fac-Oil-N304-2010-01 01

NORTHERN GATEWAY PIPELINES INC.

Application for ENBRIDGE NORTHERN GATEWAY PROJECT

Certificate of Public Convenience and Necessity

OH-4-2011

FINAL WRITTEN ARGUMENT OF

C.J. PETER ASSOCIATES ENGINEERING

TABLE OF CONTENTS

Final Argument on Northern Gateway Proposal and JRP “Possible Conditions

Hugh W. Kerr.................................................................................................................................3

Preamble .......................................................................................................................................3

Pipe Composition .........................................................................................................................4

Confidentiality .......................................................................................................................4

Specific Comments ................................................................................................................6

Toughness Properties ...................................................................................................................7

Pipe Body ...............................................................................................................................7

Selection of Pipe Category by Northern Gateway ...........................................................7

Comparison with PHMSA Recommendation ................................................................10

Minimum Test Temperatures .........................................................................................11

Longitudinal Welds ..............................................................................................................11

Field Circumferential Welds ................................................................................................13

Adherence to Weld Procedure Specifications ......................................................................14

Hydrogen–Assisted Cracking ..............................................................................................13

Storage Tanks .............................................................................................................................17

Toughness Requirements .....................................................................................................17

Secondary Containment .......................................................................................................17

Weld Inspection During Construction ........................................................................................18

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Corrosion ....................................................................................................................................21

General Internal Corrosion ..................................................................................................21

Underdeposit Internal Corrosion ..........................................................................................23

External Corrosion and Pipe Coatings .................................................................................25

Main Pipe Body .............................................................................................................25

Pipe Weld Coatings ........................................................................................................26

Pipe Inspection In Service ..........................................................................................................27

Repair Welds ..............................................................................................................................31

Summary and Conclusions .........................................................................................................32

Final Argument on Shipping and Navigational Issues

Concerned Engineers ...................................................................................................................37

Issue No. 1: Risk Analysis I .......................................................................................................37

Issue No. 2: Risk Analysis II ......................................................................................................41

Issue No. 3: Impact of LNG Tanker Traffic ...............................................................................43

Issue No. 4: Risk of Dilbit Product to the Environment as a Result of a Spill ..........................44

Issue No. 5: Accuracy of Environmental Data Used in the Risk Analysis ................................45

Low Wind Speeds ................................................................................................................45

Issue No. 6: Additional Potential Conditions .............................................................................47

Summary and Conclusions .........................................................................................................47

Final Argument on Energy Return on Investment for the Northern Gateway Pipeline

Norman Jacob ..............................................................................................................................49

Summary ....................................................................................................................................49

Introduction ................................................................................................................................49

Energy Return is Not Tangential to the Decision of the Joint Review Panel ............................50

Supporting Evidence ..................................................................................................................51

The Relationship between EROI and Net Energy ......................................................................52

Where EROI Intersects Monetary Return on Investment and the Overall Canadian Economy.54

Energy Sprawl and the Northern Gateway Pipeline ...................................................................57

Conclusion ..................................................................................................................................60

References ..................................................................................................................................62

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Final Argument on Northern Gateway Proposal and JRP “Possible Conditions”

Hugh W. Kerr, BASc, MASc, PhD

(Distinguished Professor Emeritus, University of Waterloo

Fellow American Welding Society, Fellow ASM)

Preamble

The Joint Review Panel Agreement requires that the Panel, among other things,

“ consider measures that are technically and economically feasible to mitigate any

adverse environmental effects, the need for and the requirements of any follow-up

programs with respect to the project;

consider comments from the public and Aboriginal peoples that are received during the

review;

Northern Gateway’s (NG’s) proposal must be considered from many perspectives. The

likelihood of a serious leak depends, among other things, on the materials which would be used

for the pipeline, the processes used to fabricate it, and possible problems arising with the

material; as-received, as-welded and in service. In order for the public to comment on the

project, the public needs detailed information about these aspects.

As discussed below, there are many important aspects of the Northern Gateway proposal which

have not been revealed. Some of these have been addressed to some extent by the JRP’s

proposed “Possible Conditions”. Comments on some of the Possible Conditions are included,

including support for some of them but perceived omissions.

It may be worth noting that I recognize the importance of pipelines to Canada and our economy.

I was instrumental in setting up a “Welding Specialization” within the Faculty of Engineering at

the University of Waterloo, since there was, and is, a need for more engineers who understand

both welding processes and their possible effects on material properties. Finding financial

support for this program in order to add a faculty member specializing in welding and joining

involved interacting with a wide range of companies, including pipe companies and pipeline

companies.

My academic career at the University of Waterloo involved materials engineering, including the

effects of welding and joining on the microstructure and properties of a wide range of alloys. I

have done research on the welding of pipeline steels, partly funded by a pipe company.

In carrying out this work I became well aware how complex the interaction of alloy composition

and welding process conditions are in trying to optimize the properties.

Since retiring I have moved to British Columbia, where I joined the local streamkeepers, who are

focused on maintaining the habitat and protection of the wild salmon which return each year, but

with decreasing numbers. Initially I expected that the Northern Gateway proposal was probably

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sound. But as I listened to the concerns of my new friends, I began to ask myself how safe the

pipeline would in fact be, and started to examine the proposal in more detail. During this time

Minister Oliver labelled those opposing the NG pipeline as “enemies of the state”. This led to me

contacting people to see if I might help to examine the proposal.

I remain opposed to the NG proposal. It still includes many risks to a unique part of British

Columbia, indeed to Canada.

Northern Gateway has not been forthcoming about many aspects of their proposal.

On the contrary, they have fought hard to keep the public from knowing about these

aspects, and about what regulators have said about previous spills.

I am not convinced that the risks which the Northern Gateway proposal entails have been

adequately met in the proposal.

Pipe Composition

(a) Confidentiality

The information supplied by the Northern Gateway application about the composition of the pipe

material is very limited. Vol. 3 of the application by NG states simply: “The line pipe for the oil

and condensate pipelines will be manufactured to CSA Z245.1, Steel Pipe or to American

Petroleum Institute standard American Petroleum Institute (API) Spec 5L, Specification for Line

Pipe.”

Reference to either of these standards, such as Table 5 in CSA Z245.1, Steel Pipe, shows limits

(in weight percent) for various elements including carbon (C), sulphur (S) and many others. It is

important to realize that these limits are maxima, and that more limited composition ranges may

be needed, depending on several aspects. The pipe location affects various factors, such as

temperature, which directly influence pipe and weld properties. Construction of the pipeline will

take place under a range of conditions, including very humid conditions and very cold

temperatures. Welding of the pipe during pipeline construction can introduce various defects or

weak or brittle zones. The pipeline route also determines the pipe and weld properties required to

withstand potential threats such as earthquakes, mudslides or boulder impacts, as well as external

corrosion. Furthermore, the type of product to be carried in the pipeline influences internal

corrosion threats, which also are affected by pipe and weld properties.

Steel linepipe properties are sensitive functions of composition and the mechanical and thermal

histories of the material. Pipe purchased by a pipeline company will have been manufactured

with a composition and thermomechanical history which is often unique to the pipe company,

and may be patented by the pipe company. For a large project, such as the NG project, it is very

possible that pipe must be purchased from several companies in order to meet the pipeline

schedule. Therefore the linepipe chemical specifications for the NG project must be broad

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enough to be feasible for more than one pipe company. On the other hand, too broad a range of

acceptable compositions can lead to problems either during welding of the pipe or in service.

Section 16.1 of the NEB Act authorizes the Panel to issue a confidentiality order in two

instances. The first is if the Panel is satisfied that disclosure could reasonably cause loss or

prejudice to a person’s competitive position, as set out in subsection 16.1(a). The second,

described in subsection 16.1(b), is if the Panel is satisfied that the information is financial,

commercial, scientific or technical information that has consistently been treated confidentially,

and the Panel considers that the person’s interest in confidentiality outweighs the public interest

in disclosure. If the Panel is satisfied on either basis, it may treat a document confidentially.

NG successfully argued that its specification for pipe, EES102-(2010), is confidential. The Panel

agreed to this request, and ordered its filing on the record as Exhibit B64-9 with redactions,

except that all clause numbers and corresponding titles had to be disclosed (Exhibit A118-1).

In this ruling the Panel did not state which subsection, 16.1 (a) or (b), was the basis for its

decision. Nor is it clear why the Panel would require the clause numbers and corresponding titles

to be divulged, without requiring the publication of associated actual numerical specifications.

As discussed below, the wide range of compositions given in Table 5 of CSA Z245.1 ought to be

unacceptable. It is possible that a narrower range is given in the actual Pipe Specification EES

102. Nevertheless, the public cannot comment on the specified composition range and properties,

since they have been kept secret.

If the public cannot comment on these important specifications, then it is argued that NG

has not complied with the spirit of the Hearings, since, as listed above, the Panel is in fact

seeking comments.

Pipeline steels, both the basic compositions and initial thermomechanical treatments, and the

effects of welding, are the subjects of ongoing research by companies, government laboratories

and university researchers. The results of much of this research are published in the open

literature. This work has led to a good understanding of compositional effects, and the

optimization of properties for pipeline steels.

It is up to individual pipe and pipeline companies to arrive at their own range of acceptable

compositions. But it is incumbent on NG to show that it understands these developments,

and that it has arrived at a suitable composition range for the present application. The broader

composition range given in, for example, CSA Z245.1, is also meant to cover less demanding

conditions than those to be encountered by the proposed NG pipeline. Failing to reveal their

composition range is contrary to the public interest, and leads to a lack of trust in NG.

Sharing of such information is of benefit both to the industry, and to the public, in ensuring that

optimum compositions and properties will be attained. When one pipeline fails due to poor

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properties or an undesirable composition, the reputation of the industry suffers, as well as the

company which is directly responsible.

The steelmaking and rolling / cooling capabilities are different for different pipe companies.

Thus in arriving at optimum compositions for properties, it is the pipe companies, rather than the

pipeline companies, which decide on which compositions are feasible and optimum for their own

facilities. The pipe companies then compete in quality and price, and may have specific patented

compositions which they reveal to the pipeline companies. But since the pipeline company will

entertain quotations from several pipe companies, their acceptable range of compositions will be

broader than for any specific pipe company, and making it public therefore does not harm the

pipeline company. Furthermore, each pipe company will reveal its particular composition range

to the pipeline companies in trying to sell pipe to them. Therefore every pipeline company in fact

knows the compositions sold by each pipe company. When a pipeline company decides which

pipe they will purchase, their competitors also will learn this from the pipe company, since the

pipe company will use this information to try to increase sales further. Therefore it is argued

that divulging the NG specifications does not cause loss of a competitive position.

Furthermore, withholding information about the pipe composition specifications makes it

very difficult for the public to suggest “measures that are technically and economically

feasible to mitigate any adverse environmental effects”, as required in the Joint Review Panel

Agreement.

(b) Specific Comments

Since Northern Gateway has not revealed their own composition specifications, one can only

comment on the standards on which they say they base their specifications.

The maximum carbon content permitted in Table 5 of CSA Z245.1, namely 0.25 wt. %, is high

enough to permit several welding problems, and a lower limit should be specified. The level

permitted for sulphur in this standard (0.035 wt.%) also is too high compared to modern

steelmaking capabilities. Furthermore, even at low sulphur contents it often is required that

certain elements, such as calcium (Ca) are used to “treat” the steel in order to control what type

of sulphides are formed. The maxima permitted in CSA Z245.1 for each of niobium (Nb – called

Columbium (Cb) in the US), titanium (Ti) and vanadium (V) is 0.11wt.%. If each of these were

at this limit, as-welded properties would be poor. No maxima are given in CSA Z245.1 for

several other elements commonly found in steel pipe, such as copper (Cu), chromium (Cr),

nickel (Ni) and molybdenum (Mo). No maximum is given for either total nitrogen or “free”

nitrogen (N). Nitrogen can contribute to “strain-aging”. These observations give rise to important

questions about NG’s pipe specifications.

Failure to reveal the required Product Analysis (section 6.3.1 of EES102-(2010) B64-9 Page

8) prevents more detailed comments on the proposed pipe compositions.

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Predicting the combined effects of various elements is often attempted using a “carbon

equivalent” formula. For example #’s 31-32 of the Possible Conditions of Hearing Order

OH-4-2011 refers to a maximum carbon equivalent (CE).

Various equations for carbon equivalents have been proposed. For example,

CE = C + [(Mn + Si )/6] + [(Cr + Mo + V) / 5] +[( Ni + Cu) / 15] (also known as CEIIW )

Another is:

CEII = C + [(Mn + Cr + V) / 5 ] + Si / 24 + Cu / 10 + Ni / 18 + Mo / 2.5 + Nb / 3

For C < 0.16 % an equation proposed by Ito and Bessyo, termed PCM, is quoted by some codes,

where:

PCM = C + Si / 30 + [(Mn + Cu + Cr)/ 20 + Mo/ 15 + Ni / 60 + V / 10 + 5B]

The CE equivalent in the CSA standard Z245.1, as a footnote to Table 5, p. 53, (let's call it

CECDN ), is:

CECDN = C + F (Mn/6 + Si/24+ Cu/15 + Ni / 20 + [Cr+ Mo + V + Nb]/ 5 + 5 B)

where F is a 'compliance factor' that depends on carbon content, given in Table 6 of the

standard.

The PHMSA recommendations to the State Department regarding the Keystone pipeline,

discussed in the Hearings on October 11, 2012 by Mr. C. Peter, (Volume 87 Line 7132 et seq.),

includes reference to both CEIIIIWW and PCM , but not CECDN.

It is important that the NEB is specific when referring to a “carbon equivalent (CE)”, and

is satisfied that it is the best.

Toughness Properties

(a) Pipe Body

(i) Selection of Pipe Category by Northern Gateway

As well as chemical composition limits, CSA Z245.1 contains various requirements with respect

to mechanical properties, including notch toughness. Volume 3 of the NG application, including

the updated version, indicates that in general CSA Z245.1 Category I type pipe will be

employed.

In CSA Z245.1, section 8.4.3 reads:

“8.4.3 Category I Pipe Notch-Toughness Requirements : Category I pipe has no requirements

for proven notch toughness.”

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Two other categories are given in CSA Z245.1.

Category II, defined in section 8.4.4, requires proven notch toughness, shown by drop weight

tear test (DWTT) fracture appearance for pipe diameters greater than 457 mm or Charpy V-notch

test fracture appearance and absorbed energy requirements for smaller pipes. DWTT and

Charpy-V test results are similar in that they both reveal a transition from ductile to brittle

behaviour with decreased temperature. However the transition temperature is increased as the

specimen thickness is increased, so that the DWTT is a more demanding test for pipe thicker

than 1 cm (the standard Charpy-V specimen width). For Category II pipe the required Charpy-V

toughness is 40J for pipe diameters greater than 457 mm.

Category III, defined in section 8.4.5, has no fracture appearance requirements, but requires that

full-size Charpy-V tests show energy absorption of at least 18 J at a test temperature defined in

the purchase order. Therefore Category III toughness requirements are inferior to those of

Category II.

The redacted version of the NG specification for pipe, EES102-(2010), contains two sections for

notch-toughness requirements for the pipe body: 8.4.3 – Category I, and 8.4.5 – Category III

(B64-9 Page 12). The Panel decision to permit redaction of all the numbers in the pipe

specification stated that all clause numbers and corresponding titles must be disclosed.

The absence of section 8.4.4 (Category II) in the redacted pipe specification was discussed in the

Panel Hearing of October 11, 2012, by Mr. C. Peter, specifically in Volume 87 Lines 7080,

7085, 7086. In response NG gave a long explanation of codes, and stated that the need for

Category II pipe “would be established during detailed engineering” (Line 7090). However the

absence of any reference to Category II pipe in the redacted NG pipe specification was not

explained.

It is possible that this was an unintentional omission. If so, why was this not admitted

during the hearings ?

Alternatively, does NG intend to use only Category I and III pipe ?

The lack of information in failing to reveal specific toughness requirements again leads to a

lack of public trust in the NG proposal.

NG has indicated that it will comply with CSA Z662 in deciding which category of toughness to

employ. Table 5.1 of CSA Z662 lists categories required under various conditions. Category I

pipe is permitted for Low Vapour Pressure (LVP) fluids for all design stresses, when a liquid is

used as the pressure test medium. If air is used as the pressure test medium, then Category I pipe

can only be used up to the pipe threshold stress value for this category (PTSV1). Table 5.2 gives

the relevant PTSV1 values. For pipe of 914 mm in diameter, PTSV1 = 150 MPa, and for pipe of

diameter 508 mm, the PTSV1 value is 180 MPa for Category I. The maximum design operating

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stress for the oil pipeline is 348 MPa. Therefore when air is used as the pressure test medium,

Category II pipe must be used.

JRP Information Request #3, Section 3.1 (c) (A44-1 Page 4) asked for “a discussion of the

specific notch toughness requirements for pipe sections used in aerial crossings and pipe

sections which may be subject to air testing”. Section 3.15 (b) asked for “ the locations along

the pipeline where Category I and/or II pipe will be used indicating whether it is in a

geotechnical hazard or seismic area” (A44-1 Page 20).

In response to 3.15 (b) (B32-2 Page 51) NG stated: “The locations where Category II pipe will

be considered will be determined during detailed engineering….” . It also stated “Although

Category I pipe may be specified….it is expected that this material will have sufficient

toughness.” And also “preliminary analysis indicates that notch toughness as low as 10 Joules

would be sufficient to sustain a through wall defect approximately 50 mm in length.” This

suggests that instead of no toughness requirements for Category I pipe, a Charpy-V test might be

used to determine the toughness of the pipe body in the NG Category I (section 8.4.3)

specification for pipe, EES102-(2010). Using only Charpy-V tests is not consistent with the

requirement, in CSA 245.1, for successful DWTT fracture appearance results in such large

diameter and thick pipe. The redacted NG specification for pipe toughness for Category I,

EES102-(2010), section 8.4.3 (B64-9 Page 12), states “Replace”, but the numbers and any

insertions are blacked out. As indicated earlier, the transition temperature for ductile to brittle

fracture is higher in thicker materials. Hence the transition temperature according to a Charpy-V

test would be lower than that determined using the DWTT for a given material, if it is thicker

than the 1 cm width used in the Charpy-V test. Since the NG proposed wall thickness is now

close to 2 cm, use of Charpy-V tests as a specification for a toughness transition temperature

may be misleading and therefore insufficient.

Furthermore, clause 5.2.2.2 of CSA Z662 states, in footnote (2), “Specified minimum absorbed

energy values higher than those required by Table 5.1 should be considered for pipe with both a

design operating stress greater than 72% of its minimum yield strength and a nominal wall

thickness exceeding 12.7 mm.” For a pipe of yield strength 483 MPa, 72% is 348 MPa which is

very close (by less than 1%) to the design stress of 345 MPa. In other words, with thick pipe

used at relatively high stresses, it is recommended by CSA Z662 to be conservative with

respect to toughness.

Potential Conditions #31-32 at present only refer to welds. Impact loads on the pipe body

during construction or by third party damage are possible. Potential Conditions #31-32 should

include determining the minimum acceptable CVN and CTOD values for the lowest

installation temperature and most severe deformation possible during construction or

operation for the pipe body, including third party damage, mud or rock slides or seismic

events.

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(ii) Comparison with PHMSA Recommendation

The above recommendation is consistent with the recommendation made by PHMSA in the US

regarding the proposed Keystone pipeline. PHMSA, the US equivalent regulatory agency to the

NEB, wrote to the State Department on February 11, 2011, as indicated in the Hearings on

October 11, 2012 by Mr. C. Peter, (Volume 87 Line 7132 et seq.) when he read into the record

the following.

“Final PHMSA Recommendations for Keystone XL State Department Presidential Permit

Document Version February the 10th, 2011:

"The Pipeline and Hazardous Material Safety Administration[…] recommends that the U.S.

[State] Department of State impose the following conditions if a Presidential Permit will be

granted to TransCanada Keystone Pipeline […] to construct and operate the Keystone XL

Pipeline. Specifically, the State Department should require Keystone to include all of the

following in its written design, construction, and operating and maintenance plans and

procedures:

Steel properties: The skelp/plate must be micro-alloyed, fine grain, fully killed steel with

calcium treatment and continuous casting.

2) Manufacturing Standards: Pipe must be manufactured according to American Petroleum

Institute Specification 5L, Specification for Line Pipe (API 5L 44th Edition), product

specification level 2 (PSL 2), supplementary requirements […] for maximum operating pressures

and minimum operating temperatures…”

PSL 2 of API 5L 44th

edition is very similar to Category II in CSA 245.1. For pipe of diameter

904 mm, grade 483, a Charpy-V energy absorption of 40 J is required at the specified

temperature. Therefore the PHMSA recommendation for PSL 2 pipe in the Keystone

pipeline is more conservative than the proposal to use Cat I pipe for much of the Northern

Gateway pipeline.

The Northern Gateway pipeline is more northerly than the Keystone pipeline, and is expected to

encounter lower temperatures in winter. It also proposes to cross through a region subject to

earthquakes, unlike the Keystone pipeline. Consequently we suggest that the NG pipeline

should be even more conservative in its selection of pipe than the Keystone pipeline.

NG has also argued that since much of the pipe will be buried, Category I pipe is suitable.

However pipeline failures are often caused by third party damage, such as backhoes excavating

too close to a pipeline. Indeed, on November 2, 2012, Dr Kresic, in response to a question about

whether corrosion is the main cause of failures, stated (Volume 99 Line 23,956): “I know that for

the longest time, third-party damage was the number one cause..”.

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Enbridge has stated that it, as a company, is building “a world-class safety culture”. If its

toughness criteria, i.e. using category I pipe, are weaker than those required by the US

government for a pipeline which traverses less dangerous conditions, it is difficult to see

how Northern Gateway is “world-class”. Moreover, if the seismic, or thermal, or geohazard

conditions or third-party damage do cause a serious spill which turns out to be due to a lack of

toughness, there would be many questions about why Category II pipe was not specified.

(iii) Minimum Test Temperatures

Test temperature for toughness tests also is an important consideration. CSA 245.1, section

8.4.2.1, refers to the test temperature for the applicable DWTT and Charpy-V tests specified in

the purchase order. The redacted NG specification, section 8.4.2. (B64-9 Page 12) simply states

“Test Temperatures: Applicable”, without giving the specified test temperatures. However Table

5-1 in Volume 3 of the NG application (B56-2 Page 12) gives the minimum design temperature

as -5oC.

Temperatures much lower than -5oC can be expected during construction of the pipeline, when

sections of the pipe are being shipped and moved into location. Low temperatures of the pipeline

during winter would also be expected at aerial crossings and other places where it is exposed,

especially during any shutdown due to a leak or for inspection. Therefore it is argued that test

temperatures below -5oC ought to be specified for the pipe body. This was briefly discussed

on October 13, 2012, (Volume 89 Lines 9624 to 9629), when it was argued that extrapolation of

results from, say, +25oC and -5

oC could result in toughness estimates which are above the actual

Charpy-V test results.

In response Mr Mihell stated:

9633. MR. JAMES MIHELL: “So I’ve just been advised that, in actual practice, even with

Category 1 pipe, when performing welding qualification tests and performing the Charpy tests

that are associated with that, what in actual practice tends to happen is that we’re still well on

the upper shelf at minus 25.”

It is encouraging that NG does have some results for tests at -25oC, but it is not clear that the

NG pipe specification includes such test temperatures.

This again shows the lack of respect for the public’s input on pipe specifications. Nor does

the comment that what “tends to happen” guarantee that all pipes and welds tested in fact have

such good toughness.

(b) Longitudinal Welds

There are two orientations of welds in the pipeline: longitudinal welds used to fabricate the pipe,

and girth welds to join different pipe sections together. The microstructures and compositions of

the weld metal (the part originally liquid) and heat affected zone (or HAZ- the part of the

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original pipe raised to elevated temperatures by the welding process) can be different and

therefore have different properties.

The longitudinal welds often employ submerged arc welding. No weld toughness requirements

are specified for Category I pipe in CSA 245.1. However separate Charpy-V tests in each of the

weld metal and the HAZ are required for Categories II and III, if the test temperature is less than

– 50 C, or where specified in the purchase order. The NG pipe specification does include

headings of the relevant CSA specification; 8.5, 8.5.1.2 and 8.5.1.3 (“Applicable” B64-9 Page

12) but again the test temperature and energy requirements were not divulged. It should be noted

that a Charpy-V test specimen has a notch machined into it prior to testing. Very careful

placement of the notch is required in order to detect brittle regions, especially in the HAZ, since

the weld edges are at an angle to the pipe surface, and the HAZ is narrow. In response to

questions about the weld metal and HAZ properties on October 11, 2012, Mr. Mihell stated

(Volume 87 Lines 7109 and 7110): .”the materials properties in the heat-affected zone can be

highly variable. It depends – on a large case, exactly which microstructure you might be putting

your notch in, and that microstructure can vary greatly in the heat-affected zone.”

The implication of this is that if the notch is not carefully located in the most brittle region, then

falsely high toughness results for HAZ regions will be measured.

In parts of NG’s response to questions it was stated that “CTOD (crack tip opening

displacement) tests are employed for weld procedure qualification” (Volume 89 Line 9637, Oct

13, 2012).

And in Line 9647. Mr. Mihell stated: “Nevertheless, it is Enbridge’s practice to do CTOD tests

in the weld zone. It’s -- the CTOD specimen is oriented in a number of different orientations

such that the fatigued pre-cracked tip of the CTOD specimen is catching a variety of local

regions within the weld including the base metal, including the heat affected zone, including the

weld metal centre line, including the hardest microstructure that could be observed and a

number of these CTOD tests are done in the weld zone.”

These comments appear to be referring to specifications for the longitudinal weld used to make

the pipe. However there is no reference to CTOD tests in the redacted version of the NG

pipe specification. This makes it impossible for the public to comment on any numerical

aspect of CTOD testing, such as test temperature or required strain.

However the fact that there is a “fatigued pre-cracked tip” in each CTOD test raises similar

concerns similar to those stated earlier about placement of the notch in Charpy-V tests. If the

crack tip is not in exactly the right section of the HAZ microstructure, the CTOD result will be

too high (i.e. nonconservative) and will not properly test the HAZ. Proper testing requires having

the crack tip located within a distance of about 0.30 mm. Every CTOD test of the HAZ which

is carried out must be checked very carefully to ensure that the prefatigued crack tip was

properly placed, before the test is accepted. Any specification in the NG pipeline about HAZ

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(or Weld Metal) CTOD testing therefore must include microscopic analysis of the location of the

tip of the prefatigued notch. This verification should be done by an independent third party.

#’s 31-32 of the proposed “potential conditions” includes:

(a) determine the Charpy V-Notch toughness (CVN) value and the minimum acceptable

value for crack tip opening displacement (CTOD) for weld metal and heat-affected zone

of mill circumferential, helical (if practicable), and longitudinal welds, for the lowest

installation temperature and the most severe deformation during construction or

operation.

We support this requirement if it is edited to read:

“determine the minimum acceptable values for Charpy V-Notch toughness (CVN) and crack tip

opening displacement (CTOD) for weld metal and heat-affected zone of mill circumferential,

helical (if practicable), and longitudinal welds, for the lowest installation temperature and the

most severe deformation during construction or operation.”

(c) Field Circumferential Welds

Field circumferential welds are not part of the pipe specifications, and are therefore not referred

to in CSA 245.1. They may be made either with Gas Metal Arc (GMA) welding or manual

SMAW. In JRP-IR 11, Section 11.5 (A219-1 Page 8) the Panel asked for “a confirmation that

the majority of welding for both the condensate and oil pipelines will use the GMAW”. In

response Enbridge stated (B101-2 Page 20) that “it has not yet determined that mechanized

welding (GMAW) is suitable to be routinely employed for higher D/T micro-alloyed steel

pipelines ≤ NPS 24”. If GMAW welding is found unsuitable for this diameter (24 inches), then

the condensate pipeline will be welded manually, using SMAW or FCAW ( Flux Cored Arc

Welding).

#’s 31-32 of the “possible conditions”, part (b), includes:

“determine the minimum acceptable values for the CVN and CTOD for field circumferential

welds for the lowest installation temperature and the most severe deformation during

construction or operation.”

CTOD testing is not carried out by Enbridge in determining the WPS for manual SMAW welds,

as admitted on Oct 13 by both Mr. Mihell (Volume 89 Line 9713) and Mr. Fiddler (Line 9716).

Besides possibly using SMAW for all of the condensate pipeline, SMAW is “often” used for tie-

in welds. Mr. Fiddler agreed that the tie-in welds “can be very challenging” (Line 9720). Tie-in

welds can include joining pipe lengths of two different wall thicknesses. The presence of two

thicknesses, in addition to the challenge of achieving proper fit-up, increases the complexity of

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selecting a proper welding preparation (geometry of the prepared weld ends), proper welding

procedure specifications, and finally achieving them consistently.

We support the above possible conditions (#31-32 (b)), but suggest that the conditions

include a specific reference to manual welds based on likely tie-in weld preparations and

fitups, for both the oil and condensate pipelines.

(d) Adherence to Weld Procedure Specifications

In the response to JRP IR #11 (B101-2 Page 21), NG commented: “ It is generally agreed that

cracks in girth welds are currently the most significant construction integrity concern for higher

grades of micro-alloyed steels, which are generally characterized as ≥ grade 448/X65 in

specification and/or actual manufactured properties. Potential threats that may arise in welds

performed utilizing the SMAW process can generally be classified as being the result of

deficiencies in either welder skills or the welder and welding crew's non-compliance with

Construction and/or Welding Procedure Specifications.” Later in the same response, NG

remarked: “Proven to be critical is the diligence by individual welders, the contractors' welding

foreman and quality control personnel as well as Enbridge's welding inspectors. They all have a

primary objective of assuring strict adherence to the Welding Specifications for Construction

and the WPS.”

However, maintaining adherence to written WPS appears to be an ongoing difficulty in the

pipeline industry. As briefly referred to in the JRP hearings, on October 13, (Volume 89 Line

9803), a welding engineer working for TransCanada recently has alleged that construction crews

failed to properly follow WPS’s, leading to many cracked welds. These allegations have resulted

in the NEB undertaking an audit of the records of TransCanada for the relevant pipeline. It is not

yet clear why a strict audit was not carried out prior to the complaints to the NEB by the former

TransCanada employee. This raises concerns about the inspection and auditing procedures by the

NEB on Canadian pipelines, during welding, after welding and for repair welds.

Our concern is that there be strict enough WPS for all of the welds which NG would make,

sufficient and accurate NDE of all welds, very thorough independent third party on-site

inspection during welding and inspection, and proper auditing of all the testing. It is easy to

say that strict requirements will be achieved. But in the rush to meet construction schedules it is

often difficult to ensure that they actually are met. From the TransCanada case it is clear that

the NEB needs to review its procedures for monitoring and reporting the actual welding

conditions in the field. The NEB also needs to ensure timely followup in repairing any

observed deficiencies.

In the response to JRP IR #11 (B101-2 Page 21), NG also comments that: “There are two

primary mechanisms of construction girth weld cracking. Those caused by excessive stress being

applied prior to adequate weld reinforcement and those caused by hydrogen trapped in the weld,

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then migrating out of the weld coincidental to weld cooling and resulting in HAC” (Hydrogen-

Assisted Cracking).

The first type, “excessive stress being applied prior to adequate weld reinforcement” suggests

that sometimes sections of pipe are moved improperly after only a few passes of the girth weld

have been completed, in order to speed up construction. This suggests that either the WPS or

pipe movement specifications are inadequate, or the construction crews do not always

follow the WPS or pipe movement specifications.

(e ) Hydrogen–Assisted Cracking

The second type, Hydrogen-Assisted Cracking, occurs most readily close to about 25oC: i.e. it

requires higher stresses to cause HAC both at higher temperatures and at lower temperatures than

it does at 25oC. NG makes reference to HAC in its response to JRP IR # 11 in several places. On

(B101-2 Page 22) it states: “Proprietary R&D that Enbridge has completed regarding weld heat

decay rates with thin wall grade X-70 pipe has resulted in enhanced 'cold weather' requirements

and other continuous improvements to construction specifications, NDT procedures and

specifications, including delayed NDT practices. For practical field purposes "cold weather" has

been defined as ambient conditions <+5C inclusive of wind chill effects.”

Since the condensate pipeline has a thinner wall, these wind chill effects will be particularly

important for it, especially if the pipe section being welded is open to the environment at the

other end.

Further up on the same page NG comments: “Practically speaking this means assuring a field

focus on avoiding residual hydrogen in welds, mitigating the residual stresses from weld joint

fitup related to ovality and/or high-low alignment and designed differential wall thicknesses,

applying the required preheat, maintaining the required inter-pass temperatures and controlling

the rate of cooling; all so as to avoid the potential for entrapment of hydrogen and limit the

formation of a weld microstructure susceptible to hydrogen and/or construction stress

cracking.”

On B101-2 Page 26 of the response to JRP IR # 11, NG comments:” Generally, pipe with ≥16

mm (0.625 inch) wall thickness has been identified as having some increased risk of Welding

Construction Specification and WPS non compliance due to involving significantly increased

multiples of overlaid and adjacent weld passes in order to fill the bevel dimensions as welders

work from the root to final cap passes on such materials. Such welds are often characterized as

having increased risk of joint alignment challenges, construction stresses and HAC during

colder ambient conditions involving higher grades of microalloyed pipe in particular. Welds

with such wall thicknesses in high stress design or circumstantial field situations/locations,

and/or winter season construction may therefore be specified with low hydrogen WPS and/or

delayed NDT.”

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Since the NG proposal for the dilbit pipeline now involves such thick pipe, the need for

strict WPS and careful NDE is worth reiterating. SMAW electrodes can absorb moisture if

they are exposed to humid conditions, raising the hydrogen content in the weld. Low hydrogen

WPS, as suggested above by NG, employ “low hydrogen” electrodes. However low hydrogen

electrodes, compared to higher hydrogen electrodes, present increased difficulties for many

welders to achieve both proper penetration by the welding arc and optimum geometry of the

weld bead root. Tie-in welds, which may have worse “fit-up” and constraint conditions than

other girth welds, are particularly problematic. ALL of “applying the required preheat,

maintaining the required inter-pass temperatures and controlling the rate of cooling” are

required to avoid HAC with cellulosic (high hydrogen) SMAW. Especially in cold weather

these requirements complicate and slow the welding, and impatient welders can fail to

properly apply the WPS.

Besides controlling the actual procedure, controlling the subsequent cooling rate in the field is

attempted by first preheating the pipe ends, then covering the weld area with an insulating

blanket. This requires timely and careful action by the welders, especially in cold windy weather.

As noted earlier, NG personnel admitted that tie in welds can be “more challenging”. Tie in

welds are more difficult to preheat since the preheating torch(es) can only be done from the

outside. This usually is done by one or two operators, who then check the external surface

temperatures, but only at about the 90o and 270

o locations, prior to the actual welding. Hence

other locations can have lower temperatures, such as the starting location at the top. This can

allow hydrogen cracking.

The ambient temperature also is important. Diffusion of hydrogen is slowed as the temperature

decreases. The slow diffusion below 25oC delays the onset of HAC. Hence with low

temperatures during construction it becomes possible that a delay of 18 hours or so before

carrying out NDE, as suggested by NG, may be insufficient to avoid HAC at a later time. This

possibility appears to have been recognized by the NEB in Possible Condition #159:

“Northern Gateway must delay NDE of final tie-in welds for 48 hours following weld

completion. Northern Gateway must include this requirement in the NDE specification of its

Joining Program (required by Conditions 35-37).”

We support this Possible Condition, to better guard against hydrogen-assisted cracking,

but suggest that ALL tie-in welds be included.

We also suggest that a similar requirement be given for repair welds, which also are highly

constrained, can have faster cooling rates than butt welds, and conceivably could be made

under wetter conditions or with higher hydrogen electrodes.

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In response to a question about the electrodes used for the root of the repair welds (Volume 99

Line 23,766, Nov 2, 2012) NG replied that low hydrogen electrodes are used even for the root

(first) pass. This is reassuring, but welders find cellulosic (high hydrogen) electrodes make it

easier to achieve a suitable geometry with no defects at the root. This detail is another example

where proper supervision and third party observation – beyond the written WPS – is

critical.

Storage Tanks

(a) Toughness Requirements

The influences of welding and cold temperatures on the properties of storage tanks were not

discussed in detail during the hearings. However in Exhibit D80-27-14 Malhotra suggests that

code-based design, as proposed by NG for the storage tanks, does not provide enough

information to make a risk-informed decision. Figure 5 (page 12) of this exhibit shows a tank

which was deformed by an earthquake in California. The amount of deformation is considerable

near the bottom of the tank. Such tanks are welded, and have vertical and circumferential welds

which intersect. Depending on the thickness of the steel, the tanks may be welded with a variety

of processes, including SMAW. As discussed on October 13, (Volume 89 Lines 9838 to 9897),

the inclusions (small hard oxide particles) in SMAW welds initiate failure at relatively low

strains in the ductile regime, leading to a lower energy absorption in the “upper shelf” than in the

plate material. At low temperatures the fracture energy can also be lower in the welds than in the

base plate. An earthquake is akin to a toughness test. Consequently the specifications for welds

in the storage tanks and pumping stations and other above ground installations should

include toughness tests over a broad temperature range, including the low temperatures

which can be experienced in Kitimat and at pumping stations.

The Possible Conditions, #37, Joining Program, includes specific reference to welding

procedure qualification tests for Project facilities. These should include at least Charpy tests,

with similar temperature conditions to those required for pipeline welds in Possible

Conditions #31-32.

(b) Secondary Containment

NG has recently proposed to increase the number of storage tanks. If there were an earthquake

strong enough to cause failure, it is possible that ALL of the tanks would rupture.

According to Mr. Wong, on October 10 (Volume 86 Lines 6435-6): “the containment definition

is actually regulated by code; it’s the National Building Code, as well as the Fire Code, and as

well as the NFPA 30. Now, in that code it defines that the containment requirement for a single

tank being in an open type area and the 110 percent is based on a single tank in an open type

arrangement. But however, if you have what we call multiple tanks in a containment area the

total containment requirement by code is 100 percent of the largest tank in the containment farm

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and 10 percent of the aggregate total volume of the remaining tanks.” Therefore such multiple

failures caused by an earthquake would overwhelm the proposed containment system

around the storage tanks.

Possible Condition #134 would require that the secondary containment be able to contain

six times the volume of the largest tank. While this is an improvement to the original NFPA 30

compliant design by Northern Gateway, the rationale behind requiring containment for only six

tanks, and the practicality of doing so on the available site is not clear. If the remote

impoundment reservoir for the 14 tank terminal in the original application (B1-23 Page 3) is

compared with the 19 tank terminal in application Route V update (B184-10), it is questionable

whether there is enough level ground below the tank farm for containment of 100% of the

largest, plus 10% of the aggregate of the remaining tanks, much less six times the volume of the

largest tank, since the area delineated in the updated site plan for the remote impoundment

reservoir is so vague.

On tank farm cross section B184-13 the tanks are shown at the same height as in the original

application and with heights measured on the horizontal, which is one half the vertical scale. If

they were to be shown accurately to scale, they would be nearly three times the heights shown.

Clause 2.3.2.3.2 (b) of NFPA 30, referred to by Mr. Peter Wong in Volume 86 Line 6434 states:

(b)“The volumetric capacity of the diked area shall not be less than the greatest amount of liquid

that can be released from the largest tank within the diked area, assuming a full tank.”

If the area within the concrete berms between tanks shown on B184-10 is measured, the height

of the berms required to contain a spill of 550,000 barrels would be over 5 metres. Since this

exceeds 3.6 metres, NFPA 30 Clause 2.3.2.3.2 (e)(a) would require elevated walkways for

access to the tank roofs. None of this is discussed in the application or detailed on the

drawings.

Since it is argued above that all of the tanks might fail in a worst case situation, the secondary

containment should include the bitumen and condensate in ALL of the tanks. If this is not

possible in the available area, the project should be rejected.

Weld Inspection During Construction

Final requirements for nondestructive inspection of the pipe during construction are not clear.

Possible Conditions #35-37 (Joining Program) would require that Northern Gateway develop a

joining program which includes non-destructive examination specifications.

In IR #11, section 11.5 (A219-1 Page 8), the JRP asked “a confirmation that Northern Gateway

intends to use phased array ultrasonic inspection for the GMAW welds and radiography for the

FCAW and SMAW welds. If Northern Gateway intends to use phased array ultrasonic inspection

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for the inspection of FCAW and SMAW welds, please elaborate on the suitability of this

technique and what acceptance criteria will be used for any imperfections identified.”

In response to IR #11 NG stated: (B101-2 Page 23) “Consistent with all applicable North

American codes and industry best practices both RT and AUT are suitable for the identification

of weld flaws in pipeline girth welds.”, and, (later on the same page); “In order to preserve the

option for either RT or UT use as a primary NDT method……”.

It is not clear whether “UT” here and elsewhere refers to manual (fixed probe) UT

(sometimes termed MUT), or phased array UT with a variety of inspection angles, or some

other variety of Automated Ultrasonic Testing (AUT). Automated UT involves fixing a track

to hold the UT probe head which then is moved in a very controlled manner with a very focused

beams. It has better resolution than the more traditional MUT, collects more data about the weld,

and is subject to less human error due to actual UT path or interpretation.

There are various models of AUT equipment, with different probe designs, different capabilities

of frequency generation and detection, and different interpretative software. Selection and

optimization of such equipment requires detailed knowledge, often beyond that of the

salespersons of the equipment. It also is important to have flexibility in the capabilities of the

equipment and computing. For example it can be important to obtain and/or modify the software

used to interpret the signals. Since Enbridge is responsible for the operation of the pipeline, it is

not sufficient to rely on a third party for inspection, without a clear knowledge of how the

equipment works, and its limitations. Very knowledgeable Enbridge employees must take

responsibility for ensuring that the equipment can measure possible defects, is used properly, and

remains calibrated.

We argue that it is not sufficient to simply require that “AUT” or “phased array” testing

be employed. This is analogous to require a working auto, without specifying if it is a

Mercedes or an inferior brand. Enbridge must be required to demonstrate that they would

employ the best equipment, i.e. the best resolution and best flexibility.

It also is critical that the operators are properly trained in the operation of the equipment and

interpretation of the signals.

On Page 24 of B101-2, NG said: “RT techniques using external x-ray tubes and Class I film (D5

or equivalent) are preferred to inspect tie-in and repair welds.” Then, on Page 25 it is stated, as

an example of their practice: “Routinely employ DWX RT techniques with more than minimum

number of film for exposure.” DWX RT (Double Wall Thickness Radiographic Testing) employs

external radiation going through both sides of the pipe. Because of scatter and more attenuation

of the rays of energy, it is less sensitive than single wall thickness radiography. Some workers on

pipelines have labeled RT as the “welder’s friend”, since it is less likely to reveal some weld

defects than AUT, and therefore less likely to slow them down and reduce their pay. It is

recommended that RT not be relied on for weld inspection.

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The sensitivity of RT is less than that of AUT, as admitted by NG in their response to IR #11:

(B101-2 Page 24) “AUT has proven to be superior in sizing of critical planar weld flaws and

provides specific flaw depth and height information that is able to be used to characterize a flaw

for accurate removal/repair.”

Enbridge has previously had at least one serious spill caused by a crack in a weld. Exhibit

D66-3-2 Page 43 refers to a spill of up to about 250,000 litres of oil which occurred in a pipeline

(Enbridge line 21) near Norman Wells, in May 2011. It has been reported that this spill was

found by hunters, not by Enbridge. The NEB File OF-Surv-Inc-2011 7401 Page 3 reports that the

leak began at a crack in a girth weld.

There are at least three important points to make about this leak: (i) the defect should have been

detected during construction and repaired; (ii) the crack was not found during in-service

inspections; and (iii) the leak was not detected by Enbridge, but by the public. The fact that the

leak was found first by the public is reminiscent of the leak which occurred near Marshall

Michigan.

Another recent leak on an Enbridge pipeline (Line 14) occurred July 27, 2012 near Grand Marsh,

Wisconsin. It was referred to on both September 20 (Volume 77 Line 25,154) and January 8

(Volume 120 Line 20,373). The leak was about 1200 barrels.

PHMSA’s Correction Action Order noted that the pipe was installed in 1998, and that the failure

was a split over 4 feet long in the longitudinal Electric Resistance Weld (ERW) used to fabricate

the pipe. PHMSA also noted that “During construction of the Affected Pipeline in 1998,

radiography of girth welds revealed lack-of-fusion defects in the ERW seams at multiple

locations”. It is not explained whether any such defects close to girth welds were removed.

However the observation of such defects emphasizes the fact that pipe may be purchased from

various suppliers, and that some may have defects or inferior properties, despite NDE tests

performed by the pipe company.

An earlier leak of about 1500 barrels occurred on the same line in 2007. It began at a lack-of-

fusion defect in the ERW seam and grew to a crack due to the cyclic loads. Subsequent In

Service NDE testing, prior to the 2nd

leak, is discussed under In Service Pipe Inspection, below.

Clearly, despite Enbridge’s claims that they are “world-class”, there have been serious

leaks in their pipelines, and their NDE and leak detection systems have been inadequate.

The proposed type and frequency of NDE during construction for different types of welds are

given in Table 1 of NG’s response to JRP IR #11 (B101-2 Page 28). Only Mechanized GMAW

would use 100 % Circumference UT + 100% Circumference Visual. For both “mainline or

section” SMAW, as well as tie-in SMAW, it is proposed to use 100 % circumference RT or UT

+ 100% Circumference Visual + 20% next day delay RT or UT. Only “Final Tie-in” SMAW

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welds are proposed to have 100% next day delay RT or UT, in addition to 100 % circumference

RT or UT + 100% Circumference Visual on the day of welding.

This table leads to several points. First, it is not clear how the decision is taken whether to use

RT versus UT, other than convenience. Second, it is not clear whether “UT” means AUT or

Manual UT. As noted above, AUT is able to size a flaw more accurately, and provides more

data. Third, it is not clear why only “Final” Tie-in welds, and not (ordinary ?) tie-in SMAW

welds will require 100% delayed NDE. Tie-in welds in general join two long sections of pipe,

which are more constrained from moving (as the pipe shrinks after welding) than in the case of

attaching a single section of pipe. Thus any tie-in welds can reach higher levels of stress on

cooling, and are more likely to crack. Joining of two pipe sections by SMAW involves at least 3

and perhaps 4 welders (Volume 89 Line 9751, Oct 13, 2012), with possibly somewhat different

levels of skill. Consequently ALL SMAW welds are more subject to human error, and hydrogen

cracking, than are automated GMAW welds.

RT also can fail to reveal a defect such as lack of fusion (when the molten weld metal fails to

melt the underlying metal, leaving an unjoined interior surface, but no gap), or a “tight” crack

having little or no gap. Therefore it would be better to require 100 % AUT, not 20%, on ALL

tie-in SMAW welds, including repair welds, both soon after welding and after sufficient

delay to investigate delayed Hydrogen Assisted Cracking.

Corrosion

(a) General Internal Corrosion

During the Hearings conflicting testimony has been presented about whether dilbit corrodes steel

pipelines more quickly than traditional sour crude oil. Exhibit B50-2 is a paper by Zhou and

Been which attempts to refute a paper by NRDC claiming that dilbit corrodes pipe more quickly.

For example in section 5.6.3 (B50-2 Page 17), Zhou and Been state “The above illustrates that

the dilbit properties as displayed in Figure 1 are not significantly different from the conventional

heavy crude oils for pipeline transportation.” But in the next sentence they state “However,

internal pipeline corrosion has occurred in some dilbit lines whereas others have enjoyed a long

trouble free existence [28].” Reference [28] of their paper is “private communication”.

Therefore there are differences in corrosion rates for different pipelines which have carried dilbit.

The paper by Zhou and Been also discusses the claim in the NRDC paper that Alberta pipelines

have shown more leaks than American pipelines. They quote another report in which “PHMSA

and the ERCB adjusted the statistics to comparable crude oil systems”, where the oil sands

derived crude oil consisted of a much larger percentage in Alberta than in the entire U.S.

According to these revised data, the number of failures for the pipelines, per thousand miles of

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pipeline per year, due to internal corrosion, was found to be 0.32 in Alberta and 0.42 in the US

(Table 2 Exhibit B50-2 Page 19).

It is worth noting that the proposed pipeline is about 1000 km long, or 690 miles. Therefore these

numbers alone suggest – using the lower Alberta number- about 0.32 X 0.69 = 0.22 failures due

to internal corrosion in the NG pipeline per year, or about one failure every five years.

However the failure rate due to internal corrosion due to dilbit may in fact be greater. Zhou and

Been comment that the Alberta data in fact does not separate data for conventional crude oil

pipelines from those which have carried dilbit. They state (p. 18 of B50-2) “The publicly

available ERCB data do not separate the statistics for dilbit and conventional crude pipelines or

for upstream gathering lines and long distance transmission pipelines. Whereas the ERCB

licenses pipelines for the use of crude oil, they may not be aware of what type of crude is shipped

through the lines, which is further complicated by the fact that lines can transport dilbit and

conventional crude at different points in time. It is recommended that better statistics be

provided as an improved presentation of the integrity of the Alberta pipeline system and to

facilitate continuous monitoring of the performance of dilbit pipelines.”

This means that in fact Zhou and Been were unable to separate data for lines carrying

dilbit from those carrying only conventional crude oils, so that a direct comparison is not

available. This point was discussed on November 2, (Volume 99 Line 23,832) In reply NG (Mr

Kresic) said (Line 23,836): “That being said, the experience that we work from comes from the

many other pipelines we have in our system where we have been transporting dilbit for many

years. And we can monitor with a real-life laboratory of experience on how these crudes behave

within our pipeline systems under the various flow behaviors and temperatures and so on.”

Further he said (Lines 23,838-9) “And over the many years of operation, we have had internal

corrosion happening in some places and we’re able to monitor that with inline inspection and

also apply inhibition to abate the existence of internal corrosion. And I’m not -- I don’t think

we’ve ever had a mainline rupture because of internal corrosion, over 60 years of operation.” In

reply to a question about releasing this data, Mr. Kresic referred to a study being undertaken by

the US National Academy of Sciences, and stated: “Generally the National Academy of Sciences

would be viewed to be the fully independent review panel for something like this and Enbridge

just elected to let that process take its course. So rather than us supply our information, we

prefer just to have the public committee sort that out for themselves.”

Northern Gateway’s failure or reluctance to release information about previous spills, as

well as other details relevant to this proposal, has been encountered by many intervenors.

As noted during this discussion, the results of the NAS study are not expected for 2 years, and

therefore will not be available to the present Panel. Stating that: “I don’t think we’ve ever had

a mainline rupture because of internal corrosion, over 60 years of operation.” is not a

definitive statement, and is inconsistent with the data by Zhou and Been discussed earlier.

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Internal corrosion therefore remains a major concern.

(b) Underdeposit Internal Corrosion

The dilbit will include up to 0.5 % basic sediment and water (BS&W). In the threat assessment

presented as part of Exhibit B75-2 (Page 68, Report by Dynamic Risk), it is stated: “As rule of

thumb, for large diameter pipelines, it is known that flow velocities lower than 1.2 m/s, as well as

conditions of intermittent flow direction are associated with accelerated deposit of solids

particles. The hydraulic model contained in the DBM illustrated that the fluid velocity of the oil

pipeline at ultimate phase target design capacity will be 2.90 m/s.” This velocity corresponds to

the operating flow rate (944,444 bpd) of Phase IV, which is given in section 2.1 of the NG

Hydraulic Design Proposal (Response to JRP IR 3.1(e) B64-2 Page 4). For Phase I, given in the

same document, the operating flow rate of 583,333 bpd gives a fluid velocity 1.63 m/s, and the

“annual” flow rate of 525,000 bpd corresponds to a flow velocity of only 1.47 m/s. These latter

flow velocities are much closer to the flow velocity of 1.2 m/s given as the lower limit for

avoiding “accelerated” deposit of solids (and water, which tends to stick to the solid particles).

Furthermore on the same page it is admitted that “it should be expected that these solids will

precipitate during extended shut-down conditions.” It is claimed that “Upon restart, however,

these solids should be readily transported away once the velocity threshold is exceeded.”

However, as read into the Hearings on October 10, (Volume 86 Line 6790), a paper co-authored

by Mr. Trevor Place, who works for Enbrdge, states: “For heavy oil, it has been found that

corrosion also occurs on the pipe floor downstream of over-bends. ... Place et al.[1] attributed

this deposition to inertial forces that increased the thickness of the boundary layer at the pipe

floor thereby reducing the flow forces responsible for mobilizing solids. Similar behaviour has

been reported by others. It was reported [2] that a crude oil pipeline that had low corrosion

rates by conventional corrosion monitoring was found to have locally severe underdeposit

pitting”. (As read)

Therefore under deposit corrosion remains a concern.

Under deposit corrosion was also discussed by Zhou and Been, in Exhibit B50-2 Page 22, who

stated “Questions remain regarding the controlling corrosion parameters and little is known

with regard to the sludge deposition mechanism and the role of the dilbit chemistry.”

Mr. Kresic during the Hearings characterized internal corrosion as “an ongoing maintenance

activity that we monitor and manage.” (Volume 99 Line 23,856). As discussed further later, the

NTSB report on the Marshall spill was very critical about Enbridge’s Integrity Management

program on that pipeline.

On November 2 selected statements were quoted from a paper by Richard Kuprewicz, an

American consultant with many years of experience in the pipeline industry. In particular

(Volume 99 Line 23,969) he said: “MIC can have much higher corrosion rates than the general

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corrosion rates often cited and such selective corrosion can cause pipeline failure [as] well

before the next five-year integrity management re-assessment.” [As quoted]

This raises questions about the type and frequency of inspection proposed by NG. On the same

day, Line 23,971, Mr. Kresic stated: “We would inspect regularly, for example, anywhere

between three and five years for corrosion”. In an earlier statement (Line 23,961) Mr. Kresic

said: “The smart tools -- the smart pigs, if you will, aren’t intended to pick up the sediment

although they do help with that process.”

Three years before the first inspection is a long time. If there are regions such as overbends

where under deposit corrosion begins, it is important to find and measure the internal corrosion.

Inspection tools which pick up sediment and deliver it so that it can be analyzed for corrosion

products are important. This is especially true early in the life of a pipeline, so that unexpected

locations of corrosion can be identified, before leaks can develop.

The Keystone pipeline being proposed in the US has been reviewed by PHMSA. As indicated

on October 11 (Volume 87 Line 7132), and also noted in a letter to the JRP by CJ Peter

Associates on September 20, 2011 (Exhibit D25-2-1 Page 2), PHMSA has recommended 57

special conditions for the pipeline. One of these, condition 34, includes: (a) Keystone must run

cleaning pigs twice in the first year and as necessary in succeeding years based on the analysis

of oil constituents, liquid test results, weight loss coupons located in areas with the greatest

internal corrosion threat and other internal corrosion threats. At a minimum in the succeeding

years following the first year Keystone must run cleaning pigs once a year, with intervals not to

exceed 15 months. (b) Liquids collected during cleaning pig runs, such as BS&W, must be

sampled, analyzed and internal corrosion mitigation plans developed based upon lab test results.

Therefore as a condition to approval of the NG application it is recommended that similar

conditions be imposed if the NG pipeline is approved. That is, NG should be required to

run cleaning pigs in the first year of the pipeline, and at least every 15 months thereafter.

It should also be required that NG analyze sediment removed during cleaning operations

for corrosion products, especially downstream of overbends, as well as at legs or other

deviations where deposition can occur due to a local decrease in velocity. Suitable

corrosion mitigation plans should then be submitted to the NEB for approval, with specific

time schedules for their implementation.

The NEB then must ensure that the schedules are adhered to, with significant penalties to

both Enbridge as a corporation and its senior managers if they are not.

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(c) External Corrosion and Pipe Coatings

(i) Main Pipe Body

External corrosion has been the source of many pipeline leaks. In the NTSB report on the

Marshall spill, it was stated: “Based on Enbridge’s 1984–2010 leak report database, the review

concluded that external corrosion had caused 14 percent of the past failures.” (Exhibit B92-3

Page 51).

For example, the spill from the Enbridge Marshall spill, on “Line 6B”, occurred at a crack which

initiated from “the bottom of the individual corrosion pits at the external surface.” In the case of

that spill, access of water from the wetlands to the pipe surface was permitted by disbonding of a

polyethylene wrap coating (Exhibit B92-3 Page 98). The coating also “tented” adjacent to a

longitudinal seam weld, which permitted the corrosive liquid to run along this path, eventually

leading to “clusters of cracks” emanating from corrosion pits.

NG relies on the combination of two aspects to prevent external corrosion. First, the pipe will be

coated to try to prevent contact between the pipe and moisture in its surroundings. The bulk of

the pipe will be coated with fusion-bonded epoxy (FBE) prior to delivery. For regions which

require “rough handling” or require “higher resistance to damage”, however, NG Response to

JRP IR #3 (Exhibit B32-2) indicates that a three-layer polyethylene may be used.

Second, the pipe will be protected by cathodic protection (CP) afforded by a voltage applied at

various locations along the pipe. CP was also applied to Line 6B. However in that case it was

claimed that the “disbonded tape coating can shield the CP current from reaching the exposed

pipe wall, allowing corrosion to form on the external pipe surface.” (Exhibit B92-3 Page 49)

In response to questions by the JRP about a comparison of the two coating options (Exhibit

B32-2 Page 22), NG indicated:

“Three-layer polyethylene may be the preferred coating system where a higher resistance to

coating damage is required”.

And “The potential for encountering a highly corrosive environment, specifically in locations

where ARD is encountered, that could impact the long term corrosion resistance of FBE will be

further evaluated during detailed engineering. The potential for encountering environments with

combined wet conditions, high temperatures, and abrasive backfill that could impact the

resistance to cathodic disbondment of FBE will also be further evaluated during detailed

engineering. Additional coating system protection layers beyond those described above will also

be required for specific construction situations. Line pipe for HDD and bored sections of the

pipelines will receive an additional abrasive resistant coating to protect the base fusion bond

epoxy coating. Rock jacket or concrete coating could also be used in more severe terrain

conditions with handling and backfill challenges.”

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Possible Conditions #7-8 are “Northern Gateway must use a three-layer composite coating

or High Performance Composite Coating for the entire pipeline.”

It is not clear from these Possible Conditions what specifications for the coatings are

required, with respect to strength, resistance to cracking (for example during bending),

impact / gouging resistance, temperature, long term resistance to water and possible

contaminants, repair methods in the field, and NDE both under the coating and of the

coating itself. Such specifications for the pipe body coatings should be determined by the

NEB and released to the public.

(ii) Pipe Weld Coatings

“The regions adjacent to the pipe ends, close to the girth welds and over the girth welds, will be

coated after welding”.

This response quoted from Exhibit B32-2 above does not address how the regions over girth

welds are coated. However in Exhibit B32-11, a table was provided which included the

following comments on joint coating. “FBE joint coating is effective and provides seamless

transition from pipe coating to joint coating.” And, for the 3-layer polyethylene (PE): “Shrink

sleeve type joint coating is effective, however requires more care during installation.”

Exhibit B32-11 also addresses the Cathodic Protection issue, stating that both FBE and 3-layer

PE are “resistant to CP disbondment”, and that FBE does not shield CP, whereas 3-layer PE is

“compatible with CP”.

Taken together, Exhibits B32-2 and B32-11 indicate that the coatings are “resistant” to damage

and CP disbondment, but do not definitively state that damage or CP disbondment are not

possible. Few details were given about the coating materials over the girth welds, other than the

above comments. The problems in the Marshall spill with disbonding of polyethylene coatings,

combined with the shielding of CP as a result, give rise to concerns about these field applied

coatings. The comment that “more care” is needed with the shrink sleeve coating used for the 3

layer PE coating is a warning flag. As noted above in discussing girth welds, impatient

workers, especially in winter when the polymers are stiffer and harder to work with , or in

wet weather, can spoil what seems a relatively simple coating operation in better weather

conditions.

More details about the coatings for girth welds were elicited on November 2, (Volume 99)

starting at Line 23,583, including inspection technologies to detect defects in the coatings.

Possible Conditions #124-125 would require that “Northern Gateway must file with the

NEB, at least 60 days prior to commencing construction, its specifications for field-applied

coatings.”

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We support this Possible Condition, but note that it will not be possible for the public to

comment on the specifications. For example, some plastics, (such as epoxy), have low fracture

toughness and therefore could be damaged during handling to lift the welded pipe into the trench,

during field bending or by third party damage. Possible defects or lack of strength at the interface

between the applied coatings and the bare pipe and coated pipe substrates are a concern,

especially at low temperatures, and need to be addressed by a specified test. Other aspects of

importance are minimum required thickness, repair quality, moisture permeation and training of

field coating applicators.

Details about how the girth weld coatings are tested also are important. On Nov 2, Volume 99

Lines 23,613-4, Mr. Kresic referred to some specification, but it has not been revealed to the

public. In Line 23,621 Mr. Kresic referred to a coatings conductance test, but also commented

that “It’s a fairly crude test..”

Details of the specifications for the materials and their application used to coat repair welds also

are important. Repair welds are often made under more difficult and dirtier conditions than the

original welds, but protection from corrosion is just as important for them.

Testing of the girth weld coating during service also is important. In Lines 23,634 -8 there was

limited discussion of a “CPCM tool” and voltage gradient testing. In that discussion it was

stated (Line 23,647) that Voltage Gradient tests were able to detect defects “the size of a dime”.

Clearly defects of this size could allow liquid to penetrate to the pipe and perhaps between the

coating and the pipe, initiating corrosion. Moreover, the report that the Marshall spill was

initiated where disbonding of a polyethylene wrap occurred raises questions about the

effectiveness and accuracy of the voltage gradient testing.

The timing requirements for service inspection were not discussed. The PHMSA recommended

requirements for the Keystone pipeline included a requirement ( # 39) of carrying out a

Direct Current Voltage Gradient survey or Alternating Current Voltage Gradient survey

within 6 months after operation. A similar requirement should be made for the Northern

Gateway pipeline, including specifications of the test resolution (minimum observable

defect size, and possible error in sizing).

Pipe Inspection In Service

Possible Conditions #193-194 include requirements for (b) “in-line ultrasonic crack

detection inspection” and (c) “in-line corrosion magnetic flux leakage inspection” and (d)

“in-line ultrasonic wall measurement inspection”, all within two years after commencing

operations.

No specifications are given for the resolution or error of such measurements.

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In its proposal, Northern Gateway places great emphasis on inspection during the life of the

pipeline, to try to argue that leaks will not occur. However there is strong evidence that

inspections do not always detect cracks, or that the inspection was not interpreted correctly, or

was not often enough.

The best known recent example of this is the spill at Marshall, Michigan in 2010.

The NTSB report on the Marshall Spill (Exhibit B92-3 Page 50 et seq) gives considerable detail

on the various types of tools used to detect cracks and other defects on Enbridge’s line 6B prior

to the spill. They included three types of tools: “UltraScan Wall Measurement (USWM),

Ultrasonic Crack Detection (USCD), and MFL (Magnetic Flux Leakage). The USWM tool,

which is an Elastic Wave tool, works by sending ultrasound in two directions through the pipe

wall and is useful for detecting wall thickness lost to corrosion. The USCD tool detects

longitudinal defects (cracks) in a pipe wall using the reflected ultrasonic signals from the defects

in the pipe wall to locate and size cracks. The transverse MFL tool relies on magnetic fields to

detect defects (cracks and corrosion) in the pipe wall and longitudinal seams.”

The report also summarizes the findings of various defects with these tools during inspection

runs prior to the spill. Inspection carried out in June 2009, about one year before the spill showed

“6791 features which predicted failure pressures less than 1.39 MOP and met the Enbridge

excavation criteria”. This illustrates the magnitude of the inspection reporting and followup

required to keep an aging pipeline safe. The NTSB also notes that nineteen features (out of

273,759) were found in the section which eventually ruptured, but none of them met the

excavation criteria.

The two spills on Line 14, one of 1500 barrels in 2007 and the second of 1200 barrels in 2012,

have been referred to above. In between these two spills Enbridge carried out Ultrasonic Crack

Detection Testing, which found various “crack anomalies” associated with the ERW seam. This

testing did not appear to report a feature at the 2012 failure location. However after the 2012 leak

it was found that a “feature” there had been observed in 2007, but that it was “smaller than the

tool specifications for detection”. In other words, even sophisticated ILI , such as USCD, can fail

to identify defects or “features” which will cause failure about 5 years hence. Crack growth rate

calculations by Enbridge in 2008 predicted that the line would not fail for at least 10 years.

More ILI testing was carried out on Line 14 in 2011, prior to the 2nd

failure, using MFL and high

resolution Geometry tools. The Geometry inspection did not show any features or anomalies on

the joint which failed in 2012, just a year later. The MFL testing showed 5 features on the failed

joint, but none was coincident with the actual failure location.

Another example is the spill on January 8, 2010 of approximately 3000 barrels, from an

Enbridge pipeline near Neche North Dakota. (See Exhibit D66-4-42 Forest Ethics K-033 for the

PHMSA Corrective Order.) According to PHMSA the pipeline had been inspected as recently as

2009 with “ultrasonic crack-detection tools”.

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As the NTSB Marshall spill report notes (Exhibit B92-3 Page 50): “Despite their sophistication,

the detection capabilities of in-line inspection tools have limitations. Each tool technology has

a stated minimum defect size that can be detected and the tool can be subjected to interference

from nearby anomalies or geometry.”

In the case of the 2010 North Dakota spill, PHMSA also noted that the full results of the

ultrasonic tool runs had not been made available to PHMSA, but that the respondent (Enbridge)

“reported that a preliminary review of the tool data from the failure site may indicate a crack-like

feature”. This lack of information transfer to PHMSA underlines the comment by Richard

Kuprewicz, an experienced American expert on pipeline safety and inspection, from a

presentation which he made to the Committee on Transportation and Infrastructure of the US

House of Representatives, which was used as an AQ and quoted on November 2, (Volume 99

Line 23,903): “More public transparency is required in integrity management performance

data gathering reporting to assure basically that there are fewer problems.” Later in the same

document he explains that “it is imperative that IM (Integrity Management) data results be

reported in (this) more detailed and systematic approach to allow independent analysis,

verification, and ensure credibility and confidence in IM approaches with the public.” This

underlines the public perception that pipeline companies in general are secretive about the

dangers associated with pipelines, which partly explains the widespread opposition to the

Northern Gateway proposal.

In addition to the limitations of the various tools in detecting features below a certain size, or

with a certain orientation, other aspects such as errors of interpretation by the operators, or in

tool manipulation, or in setting a “window” or “gate” of a certain defect size, all contribute to

possible failure of NDE in locating defects which ultimately lead to failure.

NG has repeatedly assured the JRP and intervenors that inline inspection using ultrasonic and

other tools will ensure a safe pipeline. But the evidence is that even very recently Enbridge

has been unsuccessful in maintaining other pipelines safely.

Examples are the spill near Marshall, Michigan, the Wisconsin spills on Line 14 and that near

Norman Wells, NWT. In some cases Enbridge’s response to test results has been found to

be too slow. As reported in Exhibit D66-3-12 Page 14 (Exhibit List of Enbridge Infractions, Item

K-029B), on September 22, 2010 PHMSA noted about line 6B that on that date there were still

remaining 114 out of 140 anomalies identified by Magnetic Flux Leakage testing which had been

reported to Enbridge on June 4, 2008, and which should have been acted upon within 180 days

of the report. Similarly a 2009 in-line inspection using ultrasonic technology identified 250

anomalies, 35 of which were immediately repaired, but 215 still remained in September 2010.

There are various contributing factors to these failures. They include the inaccuracies of the

inspection tools, the large numbers of indications which require excavating the pipe, the

frequency of inspections versus the desire to minimize the number of shutdowns for inspections

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or repair, seasonal effects such as snow cover or frozen ground or environmental conditions

(such as fish spawning) impeding excavation, difficulties in predicting stresses associated with

crack-like indications, and difficulties in predicting rates of growth of complex clusters of

cracks. These factors all contribute to errors or uncertainties in risk-based analyses.

In the case of the Marshall spill, the NTSB concluded (Exhibit B92-3 Page 133) that:

“Enbridge’s delayed reporting of the ‘discovery of condition’ by more than 460 days indicates

that Enbridge’s interpretation of the current regulation delayed the repair of the pipeline.” This

means that the regulatory agency, i.e. the NEB, also has an important responsibility to ensure

that the regulations are clear to the pipeline companies.

The overall error of risk-based analysis is the SUM of individual errors. Very often major

engineering failures are found to be the combined effects of a series of small errors, each of

which can seem unimportant on its own. As Mr. Kuprewicz commented in the same presentation

to US politicians, partly quoted on Nov 2 (Volume 99 Line 23,915): “The Gulf of Mexico

offshore release tragedy, if it can teach anything, clearly underscores what can happen when

risk-based performance regulation approaches step into the realm of the reckless, and prudent

checks and balances don’t come into play to prevent such tragedies.”

In-Line Inspection (ILI) is purported by Enbridge to provide the answers to finding pipe defects,

corrosion and other potential problems. However, as discussed above, there are competing

inspection technologies with differing strengths and accuracy, and each has limitations.

Furthermore it is cheaper not to inspect, or not often. The proposed inservice inspection schedule

is more lenient that that proposed by PHMSA for the Keystone pipeline, and ignores analysis of

possible corrosion products.

Previous integrity management by Enbridge does not give confidence that their promises and

claims are sufficient to prevent a major spill in the Northern Gateway pipelines. For example the

report about the Marshall spill by the National Transportation Safety Board (Exhibit B92-3 Page

133) concluded that (among other things):

“7. Enbridge’s integrity management program was inadequate because it did not consider the

following: a sufficient margin of safety, appropriate wall thickness, tool tolerances, use of a

continuous reassessment approach to incorporate lessons learned, the effects of corrosion on

crack depth sizing, and accelerated crack growth rates due to corrosion fatigue on corroded

pipe with a failed coating.

8. To improve pipeline safety, a uniform and systematic approach in evaluating data for various

types of in-line inspection tools is necessary to determine the effect of the interaction of various

threats to a pipeline.”

Leak detection technologies and response systems are far from foolproof, as Enbridge

proved with both the Norman Wells and Marshall spills. Control rooms receive signals, or

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should, of pressure drops signaling… what ? As was well documented, the signals coming from

the Marshall spill were incorrectly interpreted by Enbridge, for many hours. The report by the

National Transportation Safety Board (Exhibit B92-3 Page 134) states (conclusion 15):

Enbridge’s control center staff placed a greater emphasis on the MBS analyst’s flawed

interpretation of the leak detection system’s alarms than it did on reliable indications of a leak,

such as zero pressure, despite known limitations of the leak detection system.

In the case of smaller leaks, the pressure drops would be smaller and more difficult to detect. But

a slow leak can lead to significant volumes of spills, as illustrated by the main Norman Wells

leak. Operation at partly full (“slack”) conditions also complicates interpretation of leak

detection systems.

Repair Welds

If cracks or excessive thinning are found during inspection, the pipeline must be repaired. One

way to do this is to cut out a length of the pipe and replace it. This clearly would require new tie-

in welds at each end of the section, with the attendant problems of coating and inspection

discussed above. In some cases “backing bars” made of copper are used to prevent excessive

melting at the root of the weld. If too much power is employed the backing bar will partially melt

at the weld root, and introduce copper, and possibly cracks.

However on Nov. 2, Volume 99 Line 23731, Mr Kresic indicated that “We’re able to do repairs

on the pipeline by applying a repair sleeve. It’s welded directly to the existing pipeline and it

becomes then- it becomes part of the pipeline essentially.” Further on the same day he stated that

SMAW welds would be used, with low hydrogen electrodes, making fillet welds.

The sleeves would normally have two halves which are placed around the leaking section,

welded longitudinally with butt welds, and circumferentially with fillet welds to the underlying

pipe. Because of the extra metal at the fillet welds, different welding conditions from those used

for the original butt welds would be required. At the same time the welding conditions must

maintain the properties of the welds and associated Heat Affected Zones.

These welds must have properties which are as good as those of the original pipeline, especially

if there is an actual crack which allows the liquid to leak out, since the liquid would have the

same pressure as within the main pipeline. The welds also would be subject to the same pressure

variations as the main pipeline, exerting new types of forces on the welds holding the sleeves in

place.

Consequently new tests are required to ensure proper WPS are documented and then applied in

the field. Serious accidents have occurred associated with such repair welds.

Furthermore, inspection of fillet welds in an existing pipeline is more limited than for the

original butt welds. The geometry does not permit easy AUT or MUT, and RT is complicated by

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the double wall thickness and the weld shape. Magnetic Particle Inspection can be employed,

which detects defects at, and to some extent near, the surface by discontinuities in the patterns of

magnetic particles applied to the surface. However this technique will not show cracks or other

defects near the weld root.

Hence the safety of the pipeline repair is very dependent on the skills of the welders, with less

opportunity to inspect the quality of the repair welds.

When asked whether the inspection companies “take responsibility if there’s a crack from the

weld ?” Mr Kresic replied “They identify that the crack is there and the weld is deficient and

would need to be repaired” (Nov 2, Volume 99 Lines 23787 and 23788). This does not answer

the question. Other questions on who takes responsibility if there were a leak were deemed

“legal questions” by the JRP and not allowed in sessions I was involved with.

Summary and Conclusions

Northern Gateway has gone to considerable lengths to convince the public and the JRP that it has

changed its culture, its inspection and control systems, its ability to prevent or identify and

respond to any leaks.

At the same time, as discussed above, it has failed to reveal many aspects about its proposed

pipeline. These failures lead to a lack of trust in its claims. Northern British Columbia cannot

afford to be the testing ground for new pipeline construction, inspection and control

technologies.

Despite the attempt by the NEB and the Joint Review Panel to suggest possible conditions for

approval of the Northern Gateway proposal, I remain opposed. Based on the information

available, there remain too many risks.

Some of the remaining risks stem from Northern Gateway’s refusal or reluctance to release

information to the public. In other cases the information supplied, including responses at the JRP

hearings, is vague or not definitive.

They have refused to release specifications about both the pipe composition and the required

properties, claiming that they are confidential. Yet it is the pipe companies who develop their

own confidential compositions, which they then release to interested pipeline companies. NG

will entertain proposals from several pipe companies, then decide which to buy from. Other

pipeline companies will learn who will supply to NG, and thus will know what compositions

they find acceptable. Therefore it is argued that the acceptable compositions are known to all

pipeline companies and are not confidential. Hence NG has not complied with the purpose of the

Hearings, to allow the public to comment on their proposal. The failure to publish these

specifications also leads to a lack of trust of NG by the public.

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Some comments are made about the acceptable compositional limits specified by CSA 245.1,

which are relevant to the (redacted) NG pipe specifications.

In Possible Conditions #31-2 reference is made to a “Carbon Equivalent” (CE). Since literature

contains several different equations for Carbon Equivalent, the Panel needs to clarify which one

is meant.

The NG proposal is to use “Category I” pipe for most of the pipeline. Category I has no

toughness requirements. There may be toughness requirements stated in the redacted NG pipe

specifications, but they are not available to the public.

CSA 245.1 and the present comments emphasize that conservative toughness requirements

should be adopted, because of possible cold temperatures, mud or rock slides, and third party

damage. For the Keystone pipeline PHMSA has recommended tougher standards, similar to

Category II pipe in CSA 245.1. A requirement for Category II pipe is suggested for the NG

pipeline.

Although some parts of the NG proposal refer to Category II pipe, only headings of those

sections of CSA 245.1 referring to Category I and Category III pipe are included in the redacted

specification. NG failed to clarify whether this was an unintentional omission, or whether in fact

it does not plan to use Category II pipe.

JRP IR #3 response by NG (B32-2) includes reference to Charpy V energy requirements, but it is

argued that with the thick pipe being proposed, Charpy tests alone are not consistent with CSA

Z245.1.

The redacted pipe specifications do not include any reference to CTOD tests, making it

impossible for the public to comment on any specified values.

Possible Conditions #31-2 would require Charpy-V and CTOD values be determined for both

longitudinal pipe welds and field welds. These conditions are supported, except for some

suggested rewording. In addition it is suggested that similar requirements should be instituted for

the pipe body.

Because of the redaction of the NG pipe specifications, the minimum test temperatures are not

known, but the design temperature is given as -5 0C. Since toughness can show a severe drop

below a certain temperature, which depends on the steel, it is argued that test temperatures below

-5 0C be used for the pipe. This is consistent with Possible Conditions #31-2 for the welds, which

would require testing “to the lowest installation temperature”.

In order for CTOD or Charpy tests to be valid for Heat Affected Zones, the fatigued crack tip

(for CTOD) or machined notch (for Charpy-V tests) must be located very precisely. It is

recommended that experimental verification of the correct location be carried out by an

independent third party, for every test specimen.

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Possible Conditions #31-2 (b) would require minimum acceptable CVN and CTOD for weld

circumferential welds, but according to NG’s response during the Hearings, they do not carry out

CTOD tests on manual SMAW welds, such as tie-in welds. The required toughness conditions

should be clearly defined for all manual tie-in SMAW (or Flux-Cored) welds, as well as more

automated GMA welds, for both oil and condensate pipelines.

Ensuring that welders adhere to written Weld Procedure Specifications (WPS) appears to be an

industry-wide problem. The NEB needs to review its procedures for monitoring and reporting

actual welding procedures, and inspection, and then making sure timely repairs are made. This

includes specifications about pipe movement during construction prior to weld completion.

Hydrogen-assisted cracking can occur in the weld metal or HAZ unless the WPS are properly

specified and followed. Hydrogen diffusion becomes slower as the temperature is lowered, but

HAC is most critical at around 25o C. Possible Condition #159 would require a waiting period of

48 hours prior to final NDE for final tie-in welds. This condition is supported, and should also be

specified for repair welds.

Toughness tests for the welds in storage tanks and above ground facilities should include the

lowest likely temperatures in Kitimat and other respective locations as in Possible Conditions

#31-2.

If there were a major seismic event it is possible that all of the storage tanks would fail.

Therefore the containment area should be large enough to contain the volume of all of the tanks,

rather than only six tanks’ volume as in Possible Condition #134.

The Panel and the public should be supplied with clarification of possible locations of the

containment area, details of the required berms, and related safety requirements.

The present NG proposal refers to RT or UT testing for some welded joints. It is not clear what

criteria would be used to decide which test method would be used.

RT is not capable of revealing or resolving some possible weld defects, and therefore should not

be relied on by itself.

UT includes both manual UT and AUT, but the latter is more reliable. The NDE requirements

should be specific, rather than allowing any type of UT.

The NDE requirements also should include specifications based on the most accurate AUT

equipment available, and ways to ensure that any operators are properly trained and then

monitored.

Inspection is carried out by third parties, but it is not clear what legal liability they have.

Reliance on a third party NDE company which holds no liability for failure to properly detect or

interpret defects is not sufficient.

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For all tie-in welds, not just final tie-in welds, 100% delayed AUT should be required, rather

than only 20%.

The statistics on number of failures per thousand miles of pipeline per year in Alberta (0.32)

imply about one failure every five years for the NG pipeline.

The failure statistics do not separate pipelines carrying dilbit from those carrying only other

crudes, but it is noted that there have been failures in some lines carrying dilbit.

NG has refused to release its corrosion failure data to the public, but instead intends to release it

to a US National Academy of Sciences committee whose report is only expected in about 2

years.

The average fluid velocity in Phase I of the NG pipeline (1.47 m/s) is much closer to the stated

critical velocity for deposition (1.2 m/s) than the quoted average velocity of 2.9 m/s in Exhibit

B75-2.

Local flow velocities close to overbends and other impediments to flow are less than the average

velocity, and allow deposition of BS&W.

Underdeposit corrosion remains a concern, as illustrated by the fact that Enbridge personnel

continue to do research on it. Local corrosion rates under deposits can be much faster than

average corrosion rates.

It appears that NG will use “smart pigs” which do not sample for corrosion.

It is suggested that NG be required to sample liquids and solids collected during cleaning runs

and analyze them for corrosion products within the first year of operation, and every 15 months

thereafter, with appropriate mitigation plans where corrosion is found. This is similar to a

PHMSA recommendation for the Keystone pipeline.

Timely followup, monitored by NEB, should be required for both observed significant corrosion

and other inspection findings, with meaningful penalties to Enbridge and senior managers if

there is failure to do so.

Possible Conditions #7-8 would require three-layer or composite coating for the pipe body, but it

is not clear what properties would be required for the coatings.

Possible Conditions #124-5 would require that specifications for the coatings over field welds be

supplied to the NEB. These conditions are supported, but the criteria will not be known to the

public, preventing comments. NG management described their conductance test for the girth

weld coatings as “fairly crude”.

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Voltage Gradient testing of the field coatings was claimed to find defects as small “as a dime”,

but even this size would permit liquid to be in contact with the outer diameter of the pipe and

possibly cause corrosion.

The required timing of the field coatings testing was not discussed in the Hearings. PHMSA in

its recommendations to the State Department about the Keystone pipeline has suggested that DC

or AC Voltage Gradient tests should be required within the first 6 months, and a similar

requirement is suggested as a condition for NG.

Possible Conditions #193-4 include requirements for in-line ultrasonic crack detection

inspection, corrosion magnetic flux inspection, and ultrasonic wall measurement inspection

within the first 2 years, but no specifications for resolution or error are given.

Previous spills on Enbridge pipelines, such as near Marshall Michigan and Norman Wells NWT,

were found first by the public.

The NTSB report on the Marshall spill documents errors in measurements, failure to correctly

identify the critical section which eventually ruptured, and slow response (460 days) in both

reporting inspection indications and making appropriate pressure reductions. Other anomalies

which should have been acted upon within 180 days had not been 2 years later.

Many factors contribute to errors in risk-based analyses. Defect inspection and analysis, and leak

detection technologies all have errors and limitations. Insufficient frequency of inspection,

failure to follow up on inspection anomalies, misinterpretation of control system signals, or the

inability of such systems to detect some leaks or defects have all have contributed to leaks from

other Enbridge pipelines.

Repair of NG pipeline is stated to be done by sleeves placed on the existing pipeline and welded

in place. This introduces new weld geometries which can permit more defects.

Repair welds are critical. Determination of welding procedures which ensure acceptable

properties are necessary. Field welds must be very carefully controlled and monitored. Inspection

of the repair welds is more difficult than for the construction welds. If the proposal is to be

approved, all of these aspects must be clearly demonstrated, and the NEB must enforce

procedure and inspection of the welds.

The failures by Enbridge on existing pipelines lead to a lack of trust in their current NG proposal.

I remain opposed to the NG proposal, even with the Possible Conditions proposed by the JRP.

(A52155)

37

Final Argument on Shipping and Navigational Issues

SUBMITTED BY: Concerned Engineers

Ricardo O. Foschi, P.Eng, PhD

Emeritus Professor, Civil Engineering, University of British Columbia,

Fellow Canadian Society of Civil Engineering)

Brian Gunn, P.Eng

Chris Peter, P.Eng

Peter Hatfield, P.Eng.

We would like to thank the Joint Review Panel of the National Energy Board (JRP) for allowing

us to submit this document forming the basis for final arguments regarding the proposed

Enbridge Northern Gateway project.

We recommend to the JRP that the Northern Gateway (NG) project, on the evidence presented

by Northern Gateway, not be approved.

Our conclusion is based on several critical issues which we raised in our Letter of Comment to

the JRP of August 21, 2012 A2X6G9 and which, in our opinion, remain unanswered. These

issues were also introduced during the NEB’s Northern Gateway Hearings in Prince Rupert of

March 21, 2013, at which time relevant questions were posed to Northern Gateway Witness

Panel 5 by CJPAE representatives Brian Gunn and Ricardo Foschi. These issues address the

shipping and navigational aspects of the NG project.

At this time we have also considered the JRP list of potential conditions for approval, as

described in Exhibit A346-5 Collection of Potential Conditions – Northern Gateway

Pipelines Inc. – Enbridge Northern Gateway Project. We find these conditions to be

comprehensive and representative of many concerns raised during the Hearings. In this

document we will present our issues and point out their relationship to specific JRP’s Potential

Conditions.

Issue No. 1: Risk Analysis I

We are concerned that the Quantitative Risk Analysis (QRA) produced by Northern Gateway is

flawed in that it does not clearly explain the assumptions made and the methodology followed.

Two types of analyses were made (here called I and II) and we consider both equally flawed.

Risk Analysis I, Exhibit B23-34 was based on incident rate data (published by Lloyds Register

Fair Play (IHS), adjusted to local conditions by subjective “scaling factors”, introducing risk

reduction coefficients due to the use of escort tugs, and a conditional probability of a spill given

that an incident has taken place.

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38

We could not properly evaluate this analysis without free access to the incident database, to

assess whether, for example, it applies to escorted vessels or whether the database could be

applied to the conditions of the BC coast. Although database access to the general public is

allowed, it carries a cost of the order of $40,000, a sum which is out of reach to us as intervenors.

Presumably, Northern Gateway paid this access fee but it is not agreeable to share the data for

evaluation. This is a basic flaw in the process, as we believe that Northern Gateway should make

the data freely available for a complete and fair evaluation of their submission. A Motion

D25-24-1 submitted to the JRP seeking free availability of the data was rejected. Thus, we are

left in a situation in which we have to evaluate a risk analysis without first being able to assess

the applicability of the data.

Further, during questioning of Mr Brandsaeter of DNV by Mr. Tollefson of the BC

Nature/Nature Canada on Monday March 18 Volume 155 Lines 31,278 – 31,450, it was pointed

out that studies had been done showing an underreporting of incidents by as much as 71%. Mr.

Brandsaeter did agree that underreporting was present in the data used. We believe that this

shows the database, that was not made available to us, to be of doubtful acceptability as the basis

for coming up with the predictions of DNV as to the probability of incidents, and the predicted

conditional probability conversion from incidents to spills.

However, with this disadvantage, we proceeded with an assessment of the risk analysis results

and encountered many deficiencies.

The world tanker incident data are modified in the QRA for the local conditions of the route

from Kitimat to the Pacific (a length of approximately 160 nm). The local conditions take into

account topography of the channels, wind, waves, additional traffic, possibility of collisions, etc.

The QRA introduces these local effects through a set of modification or “scaling factors”

B23-34 Page 65. The rationale for these factors is not clear: they are qualitative assessments by

mostly a small group of experts in Norway. The relevance of the values chosen for the scaling

factors cannot be truly evaluated without access to the reasons as to why they should be as given,

and this information is missing due to lack of transcripts of the discussions by the experts.

The QRA results for the calculation of risk are expressed in terms of return periods for spills of

different volumes. Since a return period is, by definition, just the average time between spills, it

provides no explicit information as to the probability that a spill will occur during a specified

time window. In fact, it provides an optimistic statistic. The following Table was submitted by us

October 31, 2012 in a Notice of Motion A3C8Y8 and presents the Northern Gateway-calculated

return periods considering either all spill sizes or only those greater than a substantial volume of

5000 m3, using either escort tugs or not:

(A52155)

39

Table of return periods, from Northern Gateway estimates, and associated probabilities of at least one

spill in 50 years

We calculated the associated probabilities of at least one spill during a 50-year operational

period. As can be seen, a return period of 200 years means that there is a 22% probability of a

spill greater than 5000m3

in a 50-year operating life when no tugs are used. If escort tugs are

introduced, the return period increases to 550 years, with an associated probability of 9% of a

spill greater than 5000m3 in 50 years.

For spills of all sizes, the corresponding probabilities are 47% and 18%. Yet, these are the

results that Northern Gateway uses to justify the safety of the project. In our opinion, these

probabilities are clearly too large and simply cannot be accepted.

The risk should be a combination of the probability of failure and the cost of the corresponding

consequence. In our opinion, no proper consequence model has been advanced. Given that, in

all likelihood, the consequences of a major spill will imply a very high cost, the acceptable or

tolerable probabilities should certainly be much smaller than those shown in the previous Table.

We asked, during the Hearings, which was the basis used to conclude that the results indicated a

“safe” operation. Our question was directed to Mr. Audun Brandsaeter of DNV. Here we show

his answer from the Transcript of the proceedings, Volume 158 Line 1885:

1885. MR. AUDUN BRANDSAETER: Madam Chair, Mr. Foschi and others, I would

just say that the purpose of performing this quantitative risk assessment was to estimate a

realistic risk level for the proposed operation. It was never part of my mandate to consider risk

acceptability. Though did we assess possible risk mitigation measures in order to see what could

be done to reduce the risk further independent of whether or not it was acceptable in the first

place or not.

It is obvious then that the risks, as calculated in the QRA, are too high and unacceptable. We

should highlight that DNV just provided return period results to Northern Gateway, and were not

asked to consider the acceptability of the answers.

Spill size Northern Gateway -

calculated return

period T (years)

Probability of at least

one spill in a 50-year

life (in %)

All sizes, not using

tugs

78 47 %

All sizes, with tugs 250 18 %

>5000 m3, not using

tugs

200 22 %

>5000 m3, with tugs 550 9 %

(A52155)

40

We believe that acceptability criteria should compare with an annual probability exceedence

level of the order of 1.0 x 10-4

, as usually specified in the design of infrastructure with high

consequences in the case of failure. Included in such infrastructure are offshore platforms for oil

exploration and extraction under the action of ice loadings, important bridges under the hazard of

vessel collision with the piers, and buildings under earthquake or high wind hazards. An annual

exceedence probability of 1.0 x 10-4

is equivalent to a return period of 10,000 years. Obviously,

this standard does not compare at all with the return periods submitted with the QRA and shown

in the previous Table, where the longest is just 550 years. We recommend that the issue of

acceptable level of risk demands a more careful study.

During the Hearings, the acceptability of the results was consistently defended on the basis of

existing accepted risks in other world operations (without a clear description of such operations

or a comparative risk analysis). Northern Gateway says that theirs will be a world-class

operation, with risks no greater than those accepted elsewhere. This is not substantiated by the

QRA results, and the justification that the risks will not exceed those already accepted by others

is a poor way of justifying the safety of the present project.

Northern Gateway has made continued reference to improving conditions for navigation: double-

hull tankers, radar, positioning and communication aids, etc. In our view, these inputs go beyond

those that were used in Risk Analysis I, Exhibit B23-34, and submitted with the QRA. We only

evaluated the analysis on the basis of the evidence presented, and we find a lack of clarity and

several gaps in the data used. For example, the database includes incidents occurring between

1990 and 2006. Presumably, all these incidents occurred without the help of escort tugs, because

only then would Northern Gateway be justified in reducing the calculated risk in the amount of

80% due to the enforcement of tugs (Table 8-1 B23-34 Page 132). However, since the tankers in

the database were double-hull vessels, we find it difficult to believe that these were navigating in

confined waters without the help of tugs. Some disasters, like the Braer major incident in 1993,

were not included in the database because it was a single-hull vessel. We believe that the

conditions which triggered this incident would have been sufficient to lead to a disaster even if

the Braer was double hulled. Thus, it should have been included in the database. We have also

difficulties in justifying the factor 0.3 as a conditional probability of a spill developing given

that an incident had taken place. The study on which this factor is based was not made available

by Northern Gateway because of confidentiality constraints. This added to the uncertainty in

evaluating results for which the input data were either not available nor clearly explained. If

Northern Gateway wanted, they could have updated their risk analysis taking into account new

information on tanker design, navigational aids, tugs, etc., but this was not done. We notice,

however, that these substantive issues are recognized in Potential Condition No. 5 by the JRP,

which essentially calls for a detailed plan for tugs, radar, positioning and communication aids at

different locations along the tanker route.

(A52155)

41

We are also concerned about the degree of responsibility that Northern Gateway will have over

these points, given that their basic focus is on the pipeline aspect of the project. In this regard, we

observe that Potential Condition No. 5 also stresses that voluntary commitments by Northern

Gateway regarding tanker design and navigational aids must be addressed prior to any operation.

Potential Condition No. 192 would emphasize the need for verification, continuing monitoring

of and compliance with any promised risk-reducing policy, with specific intervals for reporting

to the NEB.

Finally, the questioning during the Hearings of March 18 Volume 155 revealed that the incident

database used is not comprehensive and that it certainly suffers from a considerable amount of

underreporting. Thus, statistical analyses using the database should be subjected to correction

factors, the introduction of safety margins or expert judgement should be used on a case-by-case

basis. It is not clear how this underreporting was explicitly considered in the QRA.

Issue No. 2: Risk Analysis II

The second type of risk analysis conducted by Northern Gateway involved simulator studies,

Exhibit B23-19. These were carried out in Denmark, to assess the navigability of the channels

under different climatic and/or traffic conditions.

The simulator software utilized by the Danish contractors, Force Technology, was impressive

and useful. A first type of simulator output was called Fast Simulations.

During the Prince Rupert Hearings of March 21 we suggested that the Fast Simulations could

have been used to run the simulator software for many combinations of the random variables

(climatic and traffic), to estimate the probability of completing the journey without incident (the

equivalent of a Montecarlo simulation). The following is the exchange recorded in the

Volume 158 Transcript:

2108. MR. MICHAEL COWDELL: That was not the purpose of the simulations as

they were carried out.

2109. DR. FOSCHI: Yeah, so I asked whether there was -- sorry, it wasn’t but it could

have been used for this purpose.

2110. MR. JENS BAY: Our experience is that it’s not practical to use the fast-time

simulation system to do statistics so we -- we have never done that and -- and we would never

recommend to do that so that’s why it’s not done.

2111. DR. FOSCHI: So you couldn’t use the simulator so you do any Monte Carlo

simulations a sampling in the computer to simulate the behaviour of a system. That’s what my --

my question essentially meant.

(A52155)

42

2112. MR. JENS BAY: I mean what we call fast-time simulation other peoples call

Monte Carlo simulations; it’s the same thing. But I can only say that -- that we have never and we

would never recommend to use it for statistical purposes.

2113. The idea with the -- the fast-time is to give an overall view of, in this case,

highlighting areas that we should look closer into during the real-time simulations.

2114. DR. FOSCHI: So would it be fair for me to -- to think that then you could use

this fast-time simulation as a guideline, more or less, feeling your way as to how things go but

you cannot extrapolate from that any statement about the thing is safe or not in the end?

2115. MR. JENS BAY: I would agree with you. This is -- as I say, it’s not a tool used

for statistics, we have so much statistics else -- elsewhere that has been used, for example in the

QRA and -- and the fast-time is not suitable for trying to generate statistics.

2116. DR. FOSCHI: Thank you.

It follows from this exchange that the fast simulator studies, although highlighted in the Northern

Gateway QRA report as a sophisticated means of evaluating safety, did nothing of the sort. The

number of fast simulation run was very small (36) for that purpose. The “statistics”, as Mr. Jens Bay

called them, are precisely the type of information that would have permitted an evaluation of the

probability of failure, as affected by random inputs like wind, sea state, currents, type of vessel, route

topography, occurrence of a malfunction, etc. They had the tool, a sophisticated one at that, but did

not put it to use, perhaps because of time or cost constraints.

The second type of Simulator studies were called Real Time simulations. Again, sophisticated

software permitted a pilot or a captain to guide the tanker in the simulator, reacting to different

conditions of weather or different challenges. The number of situations considered was, again, a

relatively small number (176). Each of the situations simulated applied only to a particular segment

of the route and did not take into account that many similar challenges could occur along the long

route from Kitimat to the Pacific, and that all have to be overcome. We recognize that the Real Time

Simulator is useful for the training of pilots and captains, but that it did not serve any purpose or add

any real information insofar as evaluating overall safety.

General atmospheric conditions would change in time along the route, including storm fronts,

squalls, snow, sleet, fog, heavy rain, etc. These changing conditions adversely affect both

incoming and outgoing traffic, which increases the risk of collisions with other vessels or the

shore. The environmental conditions along the route did not change with time during in the

simulations, whereas in the 16 hour transit time from the open ocean to the terminal, or back, all

of the environmental conditions could and would change, including current speed and direction,

wind speed and direction, and wave heights and periods.

(A52155)

43

There are a number of situations where the Real Time bridge simulations would have failed, and

potentially resulted in the tanker colliding with the shore or another vessel, if the winds, waves

and currents were in the opposite direction to those chosen for the particular run, or if the vessels

were in a different position along the route when steering gear, engine, etc. failure occurred.

This implies that the simulations were designed for success, rather than applying a random set of

environmental conditions.

Examples of full bridge simulation runs for which either opposite environmental conditions to

those chosen, or different positions along the route where equipment failed, would have had

potentially grave consequences, are provided in the March 21 Transcript, Volume 158 Lines

2341 to 2592.

Issue No. 3: Impact of LNG Tanker Traffic

The QRA report does not explicitly consider the impact of the additional traffic due to LNG

tankers. When we raised this question during the Hearings, we essentially were told that the topic

had either already been canvassed or that it was of little concern. We copy here from

Volume 158:

1942. MR. AUDUN BRANDSAETER: Madam Chair, I think we discussed this fairly

thoroughly the day before yesterday.

1943. And the response from the -- the Project is that we applied a sensitivity analysis

to assess the uncertainty. As we also discussed this morning, for instance, for a grounding

frequency, we adjusted the -- or tested the results by increasing the scaling factors by 20 percent.

1944. So that was the way we assessed the uncertainty in the scaling factors.

2043. I -- I believe if they’re asking, do we believe -- do we feel that we have to revisit

the risk analysis based on -- on current forecasts of LNG projects, again, I go back to my

response a couple of days ago, I do not believe that we do.

2044. From our examination of those projects, I think I -- I talked about this a couple

days ago, but it’s perhaps one more ship per day beyond what was contemplated in the sensitivity

analysis -- that’s to Kitimat.

2045. And I don’t think, given the very -- already very low traffic densities in the area,

as we’ve talked about over the past few days, and the very low contribution of -- of collision to

risk, that it’s necessary to go back and revisit that particular part of the risk assessment,

particularly taking into account the fact that there’s a large number of projects proposed right

(A52155)

44

now and I -- as I stated before, I think it’s unlikely that all those projects would be -- one day be

approved and actually go ahead.

Northern Gateway thus tried to dismiss the additional risks due to LNG tankers sharing the same

traffic lanes. They relied on a “sensitivity study” in which they obtained the changes in return

periods when some of the scaling factors were artificially increased. Thus, they just re-calculated

the return periods when the scaling factor for grounding was increased by 20% (resulting in an

unmitigated return period reduction from 69 years to 59), or the factor for increased traffic

collision frequency was increased by 20-50% depending on the route segment. This latter

calculation resulted in a reduction in the umitigated return period from 69 to 67 years. What was

done was not a full sensitivity analysis, and does not explain the additional risk due to a 300%

increase in traffic, from 220 tankers to 652 tankers per year (including 220 for bitumen and 432

for LNG). We asked the question as to how the additional 432 tankers were equivalent to a 20-

50% increase in the collision factors, and the answer was evasive or non-informative. Again,

from Volume 158:

2051. MR. KEITH MICHEL: We’ve been through this a number of times over the last

couple of days. The sensitivity analysis was provided with 25 and 50 percent additional vessels in

the waterway. That was best estimates at the time that the analysis was done.

2052. We don’t know today which projects will come online, which will not. We don’t

know the increase in number, but as was just explained, even with all the increases, it’s a small

overall addition to the risk.

2053. We saw in the risk analysis with the sensitivity, the increases in traffic only added

a couple of percent to -- to the likelihood of a spill and so …

2054. I think we’ve been through this many times. I’m not sure we can add much more

to this.

These answers tell us that the LNG situation has not been studied in detail, and that Northern

Gateway is satisfied with, essentially, conjectures.

Issue No. 4: Risk of the Dilbit Product to the Environment as a Result of a Spill

Much time was spent during the Hearings considering the issue of the possible sinking of Dilbit

after a spill. We believe, from evidence available to date, that it is likely that the product

proposed to be shipped on the NG project will sink when exposed to water during a spill, and

that this can inflict damage much greater than spills of light crude or refined products.

(A52155)

45

The JRP transcript of April 24 discusses the Panel’s concerns about Dilbit. Please refer to the

questioning by JRP members of Environment Canada (EC) Volume 169 Lines 19,764 – 19,903.

We conclude from this transcript that the EC experts agree that further studies are needed to

determine the time it takes for the condensate to leave the Dilbit mixture, at which time it would

sink; and to develop effective ways to clean up the spill and minimize the damage to the

environment .

This study could take between 3-5 years. We also note that the JRP, in Potential Conditions No.

164 to169, specifies the need for better modelling of the behaviour of Dilbit after a spill, and of

the extension and cleaning of pollution after a spill incident.

Our concerns are based on our examination of the damage at Kalamazoo River spill in Michigan,

and on evidence developed by Environment Canada. We believe that, neither the NG project,

nor any other project, should be allowed to ship Dilbit in pipelines to be loaded in vessels off the

coast of BC, until such time that it can be proven that 1) it can effectively be cleaned up in a

timely fashion when it spills into fresh or salt water, and 2) that the resulting damage is no

worse than a spill of light crude.

In this regard, we also notice the thrust of Potential Conditions No. 127 to129, 172 and 176, all

of which deal with concerns about oil spill preparedness, responsibilities and continuing

monitoring of compliance with stated plans.

Issue No. 5: Accuracy of Environmental Data Used in the Risk Analysis

We are also concerned about the accuracy of the environmental data used in the risk analysis

(wind speeds, wave heights, etc.).

Low Wind Speeds

The wind speeds cited in the ASL Environmental Sciences Technical Data Report, were to be

used as follows (Exhibit B17-18 Page 9):

“These data are intended for use in developing oil spill countermeasures to respond to a

potential oil spill.”

Instead, they were used by DNV in their QRA, in assessing the shipping and navigation risks,

which results in a large error in calculating the wind forces on petroleum and LNG tankers, as

wind forces vary with the square of the wind speed.

(A52155)

46

Looking at one example of the maximum hourly wind speed recorded at buoy C46207 (Queen

Charlotte Sound) versus winds recorded at Cape St. James light house at the southern tip Haida

Gwaii, as discussed in the March 22, 2013 hearing transcript, the following adjustments can be

made to the recordings to arrive at a wind speed at a 10 m elevation above sea level:

1. The reduction for Cape St. James winds was provided by Mr. Fissel of ASL in

Volume 159 Line 2724:

2724. MR. DAIVID FISSEL: So taking the Cape St. James winds at 92 metres and

computing those -- what that wind speed would be at 10 metres is the reduction of 20.1 percent.

The way we do that is using very well-established principles and they are in the ISO standards

that relate to MetOcean.

2. Assuming that the buoy winds are for the anemometer height, and need to be increased to

the standard 10 metre elevation above sea level, Mr. Fissel states the following on Line 2726:

2726. So that’s the way we would make that adjustment and, similarly, adjusting from

the anemometer height on the buoy to 10 metres would result in an increase in the wind speeds by

14.5 percent.

It is not clear that the wind speeds provided in the ASL Report are not already adjusted for the 10

metre elevation, which they should have been as they were used verbatim by DNV in the QRA;

they should have been adjusted to meet the ISO 19901-1 standards quoted by Mr. Fissel on

Line 2725:

2725. The reference is ISO 19901 -- 19901-1 which are under the heading “Specific

Requirements for Offshore Structures, Part 1, MetOcean Design and Operating Conditions”.

For the case where just the Cape St. James wind is adjusted to provide the wind at 10 m

elevation, the buoy winds are low by 40%. If the buoy winds in the ASL Report have not been

adjusted, the buoy winds are low by 34.5%.

As the wind load on a vessel is proportional to the wind speed squared, the error in calculating

the forces is in the order of 75% to 100% too low for this example.

A further comparison of buoy C46183 (Hecate Strait) with Sandspit and Bonilla anemometers

was made, the buoy wind speed is low by 35% to 55%, for the cases where the buoy wind speed

does or does not require, respectively, further correcting to the standard 10 m elevation. The

resulting wind forces calculated using the buoy data would be low in the range of 80% to 140%.

(A52155)

47

In Volume 159 Lines 2794 – 2801, Mr. Fissel argued that data buoy wind speed measurement

errors are within 2 to 4%, for three sources of error, namely scalar versus vector averaged wind

speeds, anemometer type, and buoy motions, but these errors do not account for the large

differences provided above, which are due to wave sheltering of the data buoys in the highest

waves, which is when the highest winds occur.

Issue No. 6: Additional Potential Conditions

We believe that the following additional potential condition must be added to those detailed in

Exhibit A346-5 Collection of Potential Conditions – Northern Gateway Pipelines Inc. –

Enbridge Northern Gateway Project.

That Northern Gateway post a bond sufficient to handle spill cleanup from tankers

transporting their oil and condensate, should a spill occur and the tanker company not have

the funds available to cover the cleanup costs. We believe that such a bond should be in the

order of $10Billion and that it should be increased with the Canada inflation index.

That, as raised by Ms. Elizabeth Graf of the Province of British Columbia during the

Hearings of September 7, 2012, Volume 72 Line 18,544 et seq., the amended Northern

Gateway Pipelines Limited Partnership Agreement B101-10 be dissolved per Section 5 or

restructured per Section 14, to make parent company Enbridge Inc. fully liable for any spill

costs in excess of its equity investment.

Summary and Conclusions:

Based on our consideration of the Issues above, and the gaps we observed in the evidence

presented by Northern Gateway to justify the safety of the project, we conclude that this

evidence cannot substantiate the claim that the Northern Gateway project is safe. To the contrary,

we believe that there is a substantial argument to support the opposite, and thus we recommend

to the JRP that the Application by Northern Gateway for a Certificate of Public Convenience and

Necessity be denied. We reach this conclusion even after consideration of the list of

Potential Conditions proposed by the JRP.

This written submission focus on six (6) issues related to the safety of the shipping and

navigational aspects of the Northern Gateway Project. In particular, we discuss and express our

misgivings about the Quantitative Risk Analysis (QRA) B23-34 submitted by Northern Gateway

and carried out by Det Norske Veritas (DNV). In Issue No.1 and Issue No.2 we discuss,

respectively, the two types of risk analysis submitted: Risk Analysis I, based on a database of

tanker incidents, and Risk Analysis II, based on computer runs using a Simulator.

(A52155)

48

In reference to Risk Analysis I, we argue that the incident rate database has not been made freely

available for a complete assessment, that it may suffer from underreporting of incidents, and that

parameters such as the conditional probability of a spill after an incident has occurred is based on

studies which have not been made available for reasons of confidentiality. The Northern

Gateway results are expressed in terms of return periods for spills of different volume. We argue

that this is misleading, as more relevant information are the probabilities of at least one spill

occurring during the operational lifetime of the project. Such probabilities, associated with

Northern Gateway’s return periods, are shown to be clearly unacceptable. Northern Gateway

should state their acceptable level, although during the Prince Rupert Hearings they stated that

their QRA focussed on the calculation of the return periods and not on their acceptability.

Risk Analysis II references the use of a sophisticated computer Simulator. We argue that this

may be very useful for the training of captains or pilots but, as Northern Gateway has applied

this tool, it cannot really contribute to the estimation of the probability that the tankers would

complete their journey without incident.

Issue No. 3 addresses the impact of the increased LNG tanker traffic on the overall safety of the

project. We argue that Northern Gateway has not explicitly taken this impact into account and

that, in fact, dismisses its contribution to the overall risk. The QRA superficially considered the

impact by artificially increasing by 20% to 50% some scaling factors for traffic density. We

argue that this is not a complete sensitivity study, and that the artificial increase in some factors

is not explicitly related to the actual increase in tanker traffic.

Issue No. 4 considers the lack of evidence in relation to the potential sinking of Dilbit after a

spill, as the condensate evaporates over time. This issue is central to the likelihood that a spill

will be cleaned up, or to the difficulty of that task. We believe that this topic requires much

further study, as specified in the Potential Conditions 164 to 169 of the JRP recommendations.

Issue No. 5 refers to the environmental data used in the QRA. In particular we are concerned that

the wind speeds used are an underestimation of the actual data.

Finally, under Issue No.6, we submit two additional Potential Conditions. The first stems from

our concern that sufficient funds must be available to cover the cleanup costs in case of a spill.

Our concern addresses the possibility that spill responsibility may be shifted to the tanker

company, which may not be able to cover the cleanup costs. This requires, in our opinion, the

posting of an adequate bond by Northern Gateway, increased as required by Canadian inflation.

The second Potential Condition addresses the need for a clear legal definition of the corporate

structure of Northern Gateway that does not shield parent company Enbridge Inc. from liability

in the event of a spill disaster.

(A52155)

49

Final Argument on Energy Return on Investment for the Northern Gateway Pipeline

Norman Jacob, BASc, BSc, MSc

“It's all about the second law of thermodynamics” - Robert Skinner on "difficult oil"

Summary

CJPAE calculated an Energy Return on Investment (EROI) of 2.41:1 for the proposed Northern

Gateway (NG) pipeline project (Jan. 18, 2012, Volume 13). At the EROI that the NG pipeline

project will be operating, 41.5% of the extractable energy will be cost energy and 58.5% of the

extractable energy will be profit energy. The EROI that CJPAE presented has never been

questioned by NG. CJPAE concludes that the project proponent accepts this evidence as factual

and correct. The Joint Review Panel should be concerned that specifically net or profit energy is

in drastic decline among all fossil fuel energy sources. In the transition from high (i.e., sweet

crude oil) to low (i.e., bitumen and shale) EROI fuels, reinvestment in energy extraction -

including the NG pipeline - will tend to expand at the expense of the discretionary part of the

economy - including conservation and efficiency improvements - which will tend to contract.

Proceeding with the proposed NG pipeline will support a strategy of chasing EROI to the

bottom. This economic strategy is unsustainable and offers only a bleak and dismal future.

Another way must be found, one that creates the infrastructure for a sustainable society.

1. Introduction

CJPAE calculated an Energy Return on Investment of 2.41:1 for the proposed NG pipeline

project

(Volume 13 Line 7326). In the equation EROI = Eout / Ein, Ein consists of:

Ein1 = Extraction of bitumen (SAGD process) 49.0%

Ein 2 = Pipeline transport, diluted bitumen (dilbit) + condensate 1.6%

Ein 3 = Tanker transport (4 parts of journey) 2.1%

Ein 4 = (Pre)refining, diluent recovery + hydrogen 47.3%

addition to produce crude oil equivalent

The above percentages were calculate by CJPAE (May 22, 2012) and are based on GJ input per

item above (Exhibit D25-9-4). The indicated percentages are percent of total energy inputs (Ein

Total = En1 + Ein 2 + Ein 3 + Ein 4).

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Both terms Energy Return on Investment (EROI) and Energy Return on Energy Invested

(EROEI) are used in the literature and have been used by intervenors, presenters and

researchers. Most researchers using these terms mean the same thing by either term, thus they

may be viewed as interchangeable in the following argument.

2. Energy Return is Not Tangential to the Decision of the Joint Review Panel

Nine oral statements at JRP hearings in 2012-13 referred to CJPAE evidence or otherwise made

"energy return" part of their presentations. Every one of the nine presenters thought it alarming

that the proposed pipeline might proceed despite the low energy return obtainable by the project.

They showed an awareness that was generally absent from the testimony of expert witnesses that

the project proponent put forward.

We refer briefly to the oral statements of Ms. Anne Pacey, Karen Anderson, Ms. Emilia

Kennedy, and Mark Cunnington. The questions implied by these presenters' oral statements

serve as touchstones for our argument.

Ms. Anne Pacey (Jan. 15, 2012, Volume 125) is a chemical engineer who worked for many years

in Latin America. Her statement "Tar sands are a prime example of bottom-of-the-barrel,

expensive and destructive fossil fuel extraction” (Line 25407) is about inadequate energy returns.

Karen Anderson (Jul. 10, 2012, Volume 61) is a member of a family that has lived in Northern

BC for four generations. In stating "I feel like if this was a domestic project, if this was

something I was doing for my own household, I would have gone and done something else before

now. It doesn’t make sense to me” (Line 9787). Ms. Anderson seems to be asking whether the

proposed project is best for the household of Canada.

Ms. Emilia Kennedy (Jan. 30, 2013, Volume 130) states "So precisely when we need to be

shifting to investing in lower carbon energy systems, I believe the proposed pipeline would

represent a massive capital investment in a very high carbon system. It will be a multi-billion

dollar stranded asset in any future energy system that is not utterly suicidal” (Line 30627). Ms.

Kennedy seems to be asking for a broader economic analysis than the project proponent has

provided.

Mark Cunnington (Feb. 1, 2013, Volume 132) is a young engineer working with pipelines in

factories and is well aware of the linkage between energy returns and the economic viability of

the proposed project. Early in his presentation he asks "why ... are the Alberta oil companies

proposing to export oil from North America when North America already imports half of the oil

it consumes?” (Line 33043)

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to which he answers "..., because we can fetch a higher price in the Asian market than in North

America. That’s why. Why is that? Because North America supposedly has a glut of oil. But if we

have a glut of oil here, then why do we need to import half of the oil we consume? This doesn’t

make sense” (Line 33044). Mr. Cunnington's question has never been adequately addressed by

the project proponent.

Later in Mr. Cunnington’s presentation he addresses “net energy return” (Feb. 1, 2013, Volume

132). His conclusions are based on reading of a recent Royal Society of Canada report on the oil

sands and numerous National Energy Board reports. He observes that oil produced from the oil

sands “require[s] natural gas imports of about one-fifth of the energy contained in the final oil

produced” (Line 33062) and thereby concludes “the Alberta oil sand deposits have a net energy

return of five to one” (Line 33063) wherefrom he determines a “five to one net energy return

ratio [which] will continue to drop as the best oil sands deposits get developed first” (Line

33064). He states the implications of plummeting energy returns: “But the problem here is that

you can only go so low “…In order to provide enough surplus to run the rest of society, a

minimum net energy return of about four to one is required” (Line 33065). Mr. Cunnington

points to the centrality of EROEI in the decision over the proposed pipeline.

The project proponent has never questioned CJPAE's evidence. Neither has NG offered

alternate calculations to disprove our evidence. CJPAE can only conclude that NG accepts

our evidence as factual and correct.

We have underlined key points from each of the oral statements that have been inadequately

addressed by the project proponent. May we presume that NG views the above presenters'

concerns or the abysmally low EROI of the proposed project as irrelevant or tangential to the

decision the Panel must make? NG may think it unnecessary to address the questions of the four

presenters, however, other intervenors and independent researchers have addressed these

questions or have offered a direction for subsequent investigation of these questions. To David

Hughes (Nov. 22, 2011, D66-3-7) and every one of the oral statements above, questions of

energy return are not tangential to the purpose of the hearings.

3. Supporting Evidence

The EROI CJPAE obtained is somewhat lower than the 3.8:1 that Hughes calculated for in situ

oil sands to produce synthetic oil (Exhibit D66-3-7 Page 14). Hughes explains in his evidence

that inclusion of items in the recovery operation and embodied energy in production

infrastructure would result in a lower EROEI. Hughes explains in a follow up report that

inclusion of embodied energy, energy cost of importing diluent, or moving dilbit to markets

would reduce the EROEI of upgraded in situ bitumen to around 2.4:1 (DBD Feb. 2013, Page

118).

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Others have obtained similar EROIs for synthetic and crude oil equivalent obtained from in situ

(primarily SAGD) production (Murphy and Hall 2010, Table 2, Page 109; referenced by CJPAE

(Volume 13 Line 7348). There is no doubt that the EROI for which the pipeline is proposed to

be built will be in the lower range of EROIs for heavy crude oils.

It is widely accepted that the global average EROI for oil has been declining in past decades

(Cunnington, Volume 132 Lines 33,063-4); Hall, Balogh, Murphy 2009, Page 35; Hall and EROI

study team, Apr. 2008). This has not been a problem when the decline was from 100:1 to 30:1 or

even 30:1 to 15:1. However, it has been pointed out by various researchers (Mearns 2008) that

EROIs below 10:1 or 8:1 result in an exponential decline in net or surplus energy.

Oil sands reserves are often quoted as being vast - the comparison is made with Saudi reserves.

However, it is net or surplus energy - the energy that comes out of the energy conversion process

- that is crucial. The energy content of the resource extracted is secondary because most of the

touted vast reserves will have too low an EROI to justify recovering (Cunnington, Volume 132

Lines 33054-6).

The JRP should be concerned that specifically net energy is in drastic decline and be asking

what policies may best address this decline for the interest of the Canadian economy.

4. The Relationship between EROI and Net Energy

The relationship between EROI and net or surplus energy has been described by Euan Mearns

(2008) and others as the "net energy cliff". Hughes uses what he refers to as a "pyramid of oil

and gas resource volume versus resource quality" (DBD Figure 37, Page 44) to explain this

pattern of declining net energy. CJPAE has found the net energy cliff graph to be a powerful

tool for explaining the pattern of declining net energy and declining resource quality.

We have adapted Mearns' graph (2008) for the purpose of this argument (Figure 1). The average

EROEI for conventional oil for 2011 and the EROEI threshold (EROEI = 8:1) are superimposed

on the original graph. The relation between EROEI and Net Energy is indicated on the graph.

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Figure 1. "Net Energy Cliff" graph (source: Mearns 2008 modified by CJPAE May 22, 2012)

The black area is the energy we get; the grey area is the amount of energy we put in to get it. If

we look at the black area in monetary terms, it may be viewed as profit energy. If we look at

the grey area in monetary terms, it may be viewed as cost energy.

At the root of our argument is the placement of the Northern Gateway pipeline project EROEI on

the above graph. At an EROI of 2.41:1 the pipeline will be operating at a place on the graph

where 41.5% of the extractable energy is cost energy, and 58.5% of the extractable energy is

profit energy.

Cost and profit energy percentages may be derived from the EROI that CJPAE calculated

(Volume 13 Line 7326) using the equation for Net Energy shown in Figure 1. CJPAE (May 22,

2012) presented the calculation:

Net (or Profit) Energy = 100 * [(2.41 - 1)/2.41] = 58.5%

Cost Energy = 100 - Net Energy = 41.5%

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5. Where EROI Intersects Monetary Return on Investment and the Overall Canadian

Economy

Fundamental structural changes will happen to the economy when fossil fuel energy comes to be

obtained primarily from low quality and low net energy (minus 8:1 EROI) sources (King and

Hall 2011; and Hall, Powers and Schoenberg 2008 described by Murphy and Hall 2010, Page

112-3, referenced by CJPAE (Volume 13 Line 7348).

This basic change to our economy is an outcome of the relation between net energy and gross

domestic product (GDP). Energy cost as a percent of GDP will tend to increase exponentially as

EROI declines below 8:1.

Increasing energy cost as a percent of GDP is a consequence of declining net energy. King and

Hall (2011) and others have made this argument elsewhere. King and Hall relate the price of oil

in $2005/BBL to EROI using data sets from 1919-1972, 1987-2002, 1977, 1982, and 2007. See

Figure 2.

Figure 2. The price of a barrel of oil necessary for a firm to make a target profit is heavily

dependent upon the EROI of oil production. (source: King and Hall 2011)

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They conclude:

“The price of a barrel of oil necessary for a firm to make target profit is heavily dependent on

the EROI of oil production. As the EROI of production gets lower than approximately 10 [10:1]

the price of oil must increase dramatically for realistic profit ratios below MROI [Monetary

ROI]=1.5.”

(King and Hall 2011, Figure 3, Page 1820)

It is a known fact that each recession since the Great Depression has been preceded by a spiked

rise in the price of energy. This pattern has been preceded in a zig-zag fashion by GDP rising in

response to rising energy costs until energy costs eventually declined. Murphy and Hall (2010,

Figure 6, Page 113; referenced by CJPAE (Volume 13 Line 7348) show "year on year changes

in GDP, petroleum expenditures as a percent of GDP, and real oil prices" for 1970-2008 for the

US economy. A declining average EROI will arguably produce the outcome of exacerbating

this trend.

Other versions of Mearns' graph (Figure 1) have been presented. We have drawn on a graphical

presentation by Dr. Tim Morgan, an energy analyst for the UK-based Tullet Prebon financial

services company. One version of Mearns' graph used to illustrate our argument places a time

scale on Figure 1 - the upper half of Figure 3 below.

This overall trend will undoubtedly have a contracting effect on the overall economy.

It is simple to produce a graph of declining EROIs over time. Mr. Cunnington (Volume 132

Lines 33062 et seq.) summarizes the Royal Society of Canada and National Energy Board

reports from which it may be derived. Murphy and Hall (2010, Table 2, Page 109; referenced by

CJPAE (Volume 13 Line 7348) present the same trend using primarily U.S. sources.

When we combine the net energy cliff graph (Figure 1) with energy cost as a percent of GDP we

obtain Figure 3. The data from which Figure 3 is produced is obtained from UK and US sources.

Average global EROEI for oil and gas are placed for given years on the net energy cliff graph.

The lower half of Figure 3, energy cost as a percent of GDP, follows from Figure 2 (King and

Hall 2011) and other data available, for example, Murphy and Hall (2010, Page 112-3;

referenced by CJPAE (Volume 13 Line 7348). From such data it is possible to produce the

lower half of Figure 3.

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Figure 3. Nearing the energy returns cliff edge (source: Tullett Prebon 2013)

Figure 3 should be viewed as an idealized presentation of more basic data, which is not presented

in this final argument but is available from the above sources and elsewhere. The vertical axis is

energy cost as a percent of GDP (red line). The horizontal axis is average global EROEI for oil

for given dates (blue line).

The evidence presented by Robyn Allan for Alberta Federation of Labour (Exhibit D4-2-49) is

based on a classical economic analysis. The energetic analysis presented above is a departure

from Allan's work. However, there are notable resemblances in the outcomes projected by the

two approaches.

Allan presented evidence (Exhibit D4-2-49 Page 12) that the manufacturing part of the Canadian

economy will contract as more and more resources are put into production of fuels from low

quality energy resources. Allan comments on Crude Oil and Gasoline Prices Canada 2001-2009

(Graph 1, Page 11). The graph shows gasoline prices tracking crude oil prices. She makes the

following points (Pages 11-12):

Real incomes for most Canadians have remained constant for the past 30 years.

There is no reason to expect real income growth over the next 30 years - the life of the

proposed pipeline.

Consumers will respond to increasing oil prices by shifting consumption from one part of

their budgets to another.

This transfer in spending will result in a decline in demand in industries where reduced

spending takes place.

These parts of the economy will contract.

Our research on EROI leads us to a broader trend. As average net energy declines, energy

production will become an increasing drain on the overall economy. How this may unfold

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given the nonlinear behaviour of both EROI and energy cost as percent of GDP, at the far

right of Figure 3, should be of utmost concern to both the JRP and National Energy Board.

We agree with Allan that building pipelines to export low EROI fuel sources faster is good for

pipeline builders. Building pipelines to export our resources faster does not benefit the overall

Canadian economy. Oil produced from the oil sands should be saved for Canadian needs. This

is what every other oil-producing nation would be doing were they in possession of this resource.

6. Energy Sprawl and the Northern Gateway Pipeline

We face a dilemma - it appears we must grow our oil and gas energy extraction economy to

maintain our overall economy but growing this part of our economy will have the effect of

shrinking the consumption and investment part of the economy. This is not a solution to

the overall decline in EROI of all major oil and gas energy sources.

A way of describing the fundamental structural changes to the economy is in a pair of flow

charts (Figures 4 and 5) obtained from Tullet Prebon (2013). An important assumption of such a

model is a ceiling on global energy production, which has remained relatively constant since

2007. At the same time growth in GDP globally appears to be on a plateau. This perspective

describes three basic parts to the economy:

1. Discretionary part of the economy - consumption and reinvestment (dark blue arrow).

2. Essentials - food, welfare, government, law (light blue arrow).

3. Reinvestment in energy extraction (red arrow).

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Figure 4. High EROEI (source: Tullet Prebon 2013)

Figure 5. Low EROEI (source: Tullet Prebon 2013)

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Tullet Prebon's (2013) model has many similarities to the empirical model of Hall, Powers, and

Schoenberg (2008). These researchers looked at the impact of the diversion of the output [from

the overall economy] to the energy sector (described by Murphy and Hall (2010, Page 112-3);

referenced by CJPAE (Volume 13 Line 7348).

Murphy and Hall (2010, Pages 112-113) describe the research. Tullet Prebon's (2013) parts of

the economy are inserted into Murphy and Hall's presentation:

“They divided the output [of the U.S. economy] into investment and consumption, and

investment further into that for energy (red arrow), that for infrastructure maintenance

(light blue arrow), and that for discretionary investments (dark blue arrow), ... they

assume that energy inputs, maintenance, and basic human needs (light blue arrow) must

be met if the economy is to function, and only after that are discretionary investments or

consumption (dark blue arrow) possible. They found through empirical analysis of the

disposition of GDP (i.e., starting from 100% of GDP) that, during the "energy crises" of

the 1970s, i.e., by comparing 1970 and 1980, discretionary investments (dark blue arrow)

were reduced by about one-half as the increased cost of fuel during that decade went

from roughly 5 to 14% of GDP. Likewise, discretionary spending and investments (dark

blue arrow) were reduced during the increases in fuel costs from 2000 to 2007. Their

model of the U.S. economy suggests that discretionary spending (dark blue arrow) will be

reduced further and nearly disappear by 2050.”

In the transition from high to low EROI fuels, the discretionary part of the economy (dark blue

arrow) will shrink. If we assume that everything possible is done so that the essentials part of the

economy (light blue arrow) remains relatively the same (not a certainty), then reinvestment in

energy extraction (red arrow) will necessarily grow. Reinvestment in energy extraction (red

arrow) will grow by taking away from the discretionary part of the economy (dark blue arrow).

CJPAE discovered that the pipeline operation portion of the EROI equation looked pretty good,

amounting to only 1.6% of overall energy inputs. Extraction (SAGD process and dilution) at

49.0% and upgrading (to a crude oil equivalent) at 47.3% of overall energy inputs were the two

big energy consumers (CJPAE, May 2012, based on Exhibit D25-9-4). However, the pipeline is

the means by which reinvestment in energy extraction in Figures 4 and 5, (red arrows) will

enlarge and thereby result in a shrinkage in discretionary spending (dark blue arrow).

We emphasize that discretionary spending also includes expenditure on conservation and

efficiency improvements, which reduce the size of investment in energy infrastructure (red

arrow) and feed back the surplus into discretionary spending (dark blue arrow).

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Morgan of Tullet Prebon (2013) concludes his report with the following key indicators of decline

in the energy surplus economy:

Energy price escalation albeit in a zig-zag fashion.

Agricultural stress - more frequent spikes in food prices.

Energy sprawl - steadily rising investment in energy infrastructure (enlargement of the

red arrow) at the expense of discretionary spending (dark blue arrow) and possibly

essentials (light blue arrow).

Economic stagnation - world economy becoming increasingly sluggish.

Inflation - a squeezed energy surplus will combine with an over-extended monetary

economy to create escalating inflation.

Morgan's indicators underscore the oral statements in the record of evidence referred to in

Section 2. He observed that the first 4 items are already underway. Only the last item, to which

Mr. Cunnington spoke in his oral statement, (Volume 132 Line 33,046) remains to develop.

We should not fool ourselves that the pipeline will not thwart conservation and efficiency

improvements. Conservation and efficiency improvements fall within the discretionary part of

the economy (dark blue arrow) - the part of the economy that will shrink as more and more

financial resources become directed toward reinvestment in energy extraction (red arrow). This

is where we concur with evidence presented by Allan (Exhibit D4-2-49 Page 11) that shows how

the manufacturing part of the economy will contract in response to the redirection of financial

resources to energy production.

7. Conclusion

The request CJPAE made in its oral evidence presentation Jan 18, 2012 was that:

“the Joint Review Panel of the Canadian Environmental Assessment Agency and the National

Energy Board give substantial weight to the outcome of an EROI analysis in any arbitration of

the viability of a major energy transport system” (Volume 13 Line 7368).

Our request remains to be answered. In this final argument we have explained why the proposed

NG pipeline will result in an economic dis-benefit to the Canadian economy.

It can be argued that other sources of energy (i.e., natural gas) are also low EROI energy sources

(Hughes, DBD Feb 2013), and therefore that oil sands products are no worse than their

competitors. The project proponent may thereby argue that the EROI for the proposed bitumen

transport system would not differ substantially from that for an alternate natural gas (or liquified

natural gas) transport system. But this is only an argument for chasing EROI to the bottom. If

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we as a society continue on the path of exploiting lower and lower EROI energy sources and

continue descending the net energy cliff we will become incapable of sustaining basic human

needs (light blue arrow) let alone advanced industrial society. This economic strategy offers

only a bleak and dismal future.

As Ms. Kennedy argued Jan. 30, 2013, Volume 130 Line 30,627, the proposed pipeline will

amount to a massive capital investment in carbon producing infrastructure - enlarging

Morgan's red arrow - and only serve to impoverish efforts to build the sustainable infrastructure

that is now necessary.

Another way must be found, one that creates the infrastructure for a sustainable society.

Conservation and efficiency improvements are certainly at the core of the sustainable

infrastructure we need to be building today.

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8. References

Allan, Robyn. Jan 2012. An Economic Assessment of Northern Gateway filed on behalf of

Alberta Federation of Labour (Exhibit D4-2-49).

C.J. Peter Associates Engineering [CJPAE] Jan 18, 2012. Oral Evidence Presentation Slides

(Exhibit D25-9-4).

C.J. Peter Associates Engineering [CJPAE] May 22, 2012. BC Sustainable Energy Webinar:

Alberta to China: What's the Energy Return? BC Sustainable Energy Association, Victoria, BC.

Hall, Charles A. S., Balogh, Stephen, and Murphy, David J. R. 2009. What is the Minimum EROI

that a Sustainable Society Must Have? Energies 2009, 2, 25-47.

Hall, Charles A. S. and EROI study team, Apr. 2008. Table 1. Existing magnitude and

approximate EROI of energy resources for the U.S. from various sources in Provisional Results

from EROI Assessments The Oil Drum http://www.theoildrum.com/node/3810

Hall, C.A.S., Powers, R., and Schoenberg, W. 2008. In peak Oil, EROI, investments and the

economy in an uncertain future. In Renewable Energy Systems: Environmental and Energetic

Issues. D. Pimentel, Ed.: 113-136. Elsevier, London.

Hughes, J. David. The Northern Gateway Pipeline: An Affront to the Public Interest and Long-

Term Energy Security of Canadians filed on behalf of Forest Ethics (Exhibit D66-3-7).

Hughes, J. David. Feb. 2013. Drill, Baby, Drill [DBD]: Can Unconventional Fuels Usher in a

New Era of Energy Abundance? http://www.postcarbon.org/reports/DBD-report-FINAL.pdf

Post Carbon Institute, Santa Rosa, CA.

King, Carey W. and Hall, Charles A. S. 2011. Relating Financial and Energy Return on

Investment. Sustainability 2011, 3, 1810-1832.

Mearns, E. 2008. The Global Energy Crisis and its Role in the Pending Collapse of the Global

Economy. Presented at the Royal Society of Chemists, October 29, Aberdeen, Scotland.

Morgan, Tim (Tullet Prebon) 2013. The Perfect Storm: energy, finance and the end of growth.

https://www.tullettprebon.com/Documents/strategyinsights/TPSI_009_Perfect_Storm_009.pdf

Murphy, David J. and Hall, Charles A. S. 2010 Year in review - EROI or energy return on

(energy) invested. Ann. N.Y. Acad. Sci. 1185: 102-118. Referred to by CJPAE, Volume 13 Line

7348.

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