LETTER DECISION
File OF-Tolls-Group1-M124-2016-01 01
22 January 2018

To:

All Parties to Hearing Order RHW-001-2017
Maritimes & Northeast Pipeline Management Ltd. (M&NP)
Application for Approval of MNLRS-IOL Service (Load Retention Service or LRS)
and Toll (LRS Toll) (Application)
Reasons for Decision RHW-001-2017

This letter provides the reasons for decision with respect to M&NP’s Application.

1. Introduction and Background
1.1 Overview of the Application and Hearing
On 17 November 2016, M&NP applied to the National Energy Board (NEB or Board) pursuant
to Part IV of the National Energy Board Act (Act) for approval of a new Load Retention Service
(LRS) offering, including a new toll (LRS Toll) (Application), and such further or other relief as
M&NP may request or the Board may deem appropriate. M&NP also asked that the Board find
the Application in the public interest.
The LRS and LRS Toll is for Irving Oil Commercial G.P. (Irving Oil) for gas transmission
service from the Canada-U.S. border to Irving Oil’s Refinery and cogeneration facility (Cogen)
located in Saint John, New Brunswick. The LRS is a negotiated service intended to retain the
Irving Oil load on the M&NP system. M&NP stated that Irving Oil was considering alternative
service for the Oil Refinery and Cogen load pursuant to a service offering from Emera
Brunswick Pipeline Company Ltd. (EBPC) (the EBPC Alternative). M&NP offered Irving Oil
the LRS in direct response to this competitive offer.
The key terms and conditions of the LRS and LRS Toll are:
•

Firm service for a primary term of 13 years, estimated to commence on
1 December 2019;
…/2

 •
•
•
•
•
•
•

Contract quantity of 68,579 gigajoules per day (GJ/d) (65,000 million British Thermal
Units per day (MMBtu/d));
Primary receipt point at the M&NP interconnection with the M&NP U.S. system on the
Canada-U.S. border at St. Stephen, New Brunswick and primary delivery point at the
M&NP custody transfer station at the Irving Oil Refinery;
Specific to deliveries to the Irving Oil Refinery and Cogen; not a general M&NP service
offering;
Toll of $0.2417 per GJ/d ($0.2550 per MMBtu/d) for a fixed term of 13 years, and only
applicable at the designated primary receipt and delivery points;
Irving Oil to pay the full M&NP abandonment cost toll surcharge;
Irving Oil may only assign its agreement for LRS to an assignee that meets M&NP's
normal tariff criteria and is a successor to Irving Oil's interest in the Oil Refinery and
Cogen;
The LRS is subject to M&NP's NEB Gas tariff provisions, provided such provisions are
not inconsistent with the LRS and with the exception of Articles 21 (Inventory Transfer),
22 (Periodic Toll Adjustments) and 24 (Turnback).

On 5 December 2016, the Board invited comments on M&NP’s Application and the appropriate
process for considering it. The Board received four letters of comment: Enbridge Gas New
Brunswick (EGNB); Heritage Gas Limited (Heritage Gas); Nova Scotia Power Inc. (NSP); and
Imperial Oil Resources (Imperial) and ExxonMobil Canada Properties (ExxonMobil).
On 17 March 2017, the Board announced its decision to establish a written hearing process to
assess the Application and established a schedule of events.
In addition, on 17 March 2017, the Board invited any interested parties other than those parties
that has previously submitted letters of comments to participate in this process.
On 31 March 2017, the Board issued the List of Participants, consisting of M&NP and
Intervenors.
On 22 September 2017, the Board announced the schedule for final argument (A86249). On
16 October 2017, written argument was completed and the hearing record for this proceeding
was closed.

Letter Decision
RHW-001-2017
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 Figure 1-1: Map showing both M&NP and EBPC pipelines

1.2 Background
The M&NP System
M&NP stated that, originally, gas on the its system only flowed west, predominantly from the
offshore Sable gas fields (at Goldboro N.S.) east to the interconnection point with the M&NP
U.S. system at Baileyville, Maine, feeding the Maritimes market along the way. M&NP
explained that the direction of gas flow has changed, with declining gas flows to Canadian
markets from Goldboro being supplemented with gas flowing from the border interconnection
with M&NP U.S. While the percentage of gas flows from the U.S. to the domestic market is
increasing, the Goldboro to Baileyville path represents 92 per cent of the firm service contracts
on M&NP.
M&NP currently employs a postage stamp (rolled-in) toll design methodology. The 2016 firm
service toll (MN365 toll) in 2016 was $0.7554 MMBtu/d. M&NP stated that the 2016 actual
domestic throughput was 176,119 MMBtu/d, which is approximately 41 per cent of M&NP’s
existing 434,000 MMBtu/d firm service contracts.
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 The Emera Brunswick Pipeline (EBPC) System
M&NP filed background information on the EBPC system in its evidence in support of the
Application. M&NP noted that the EBPC system was placed into service in 2009, which
established a new natural gas transportation path between Saint John, New Brunswick and a U.S.
border interconnection with M&NP U.S., duplicating a portion of the M&NP system. M&NP
explained that the EBPC system is not interconnected to the M&NP Canada system at any point
but is interconnected to the M&NP U.S. system at Baileyville, Maine. M&NP understands that
EBPC currently only has one receipt point, at the interconnection with Repsol Energy Canada
Ltd (Repsol)’s Canaport LNG facility (Canaport) in Saint John, and one delivery point, at the
interconnection with the M&NP U.S. system.
M&NP explained that the EBPC system can provide 850,000 MMBtu/d of transportation on a
firm basis and an additional 150,000 MMBtu/d on an interruptible basis. Transportation service
on the EBPC system is currently contracted to one shipper, Repsol. Repsol currently holds
750,000 MMBtu/d of firm service which expires in 2034 and is responsible for all of the
pipeline’s demand charges including return on investment through 2034. M&NP stated its
understanding that Repsol may exercise certain rights with respect to EBPC capacity above
750,000 MMBtu/d.

2. The Natural Gas Market in the Maritimes
Views of M&NP
M&NP stated that Nova Scotia and New Brunswick, along with Maine and New Hampshire,
form a distinct natural gas market. M&NP further stated that natural gas prices in the Maritimes
are higher and more volatile than in the rest of Canada, particularly in winter months when
demand increases. M&NP cited limited regional natural gas production and pipeline bottlenecks
in the U.S. Northeast as the primary reasons for this.
M&NP stated that it expects average daily throughput levels in 2017-2019 to be equal to the
actual 2016 domestic demand. However, M&NP submitted that post-2019 there are too many
unknown variables to accurately forecast demand. M&NP explained that one of these unknowns
is the local distribution company (LDC) gas market in New Brunswick and Nova Scotia, taking
into consideration competing fuels, and whether gas storage will be constructed which would
assist in meeting peak winter LDC demands. Another unknown M&NP cited is the level of
future domestic gas supply available from the Sable Offshore Energy Project (SOEP), Deep
Panuke and McCully fields and whether future shale development occurs in New Brunswick
given the existing significant shale reserves in place in the province. M&NP further provided
that another unknown is the level of gas demand associated with the New Brunswick Power and
NSP loads, given the uncertainty of their existing and future electrical generation fuel mix.
Finally, M&NP included the possibility of LNG exports from the east coast post-2019 as an
unknown, limiting its ability to provide an accurate future demand forecast.
M&NP stated that, for 2017-2019, domestic demand and domestic production is expected to be
stable at current levels. For the two subsequent years, 2020 and 2021, M&NP expected reduced
NS offshore gas supply and no appreciable onshore domestic gas production. M&NP did not
Letter Decision
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 expect any domestic shale production exceeding domestic market demand from 2017-2021, and
the timing of development to be based on many unknown factors, including political, technical,
and market-based.
Regarding EBPC and the Maritimes market, M&NP submitted that Canadian market access
featured prominently in the Board’s approval of the EBPC Pipeline (GH-1-2006):
“As previously found, the Board is of the view that one aspect for the justification of this
Project is its ability to provide an opportunity for access to a new source of natural gas
supply to the Maritimes.” 1
Views of Intervenors
Nova Scotia Power Inc.
NSP stated that it currently purchases natural gas primarily from local supply sources such as
SOEP and Deep Panuke. However, with the wind down of both SOEP and Deep Panuke, NSP
contended that the Maritimes continues to evolve from a gas supply region to a gas consumption
region. In the future, NSP stated that it will have to continue to shift its gas supply sources to
outside the region, and transport gas from much further afield. NSP asserted that its customers
will be increasingly exposed to the “pancaking” of upstream pipeline transportation tolls that has
already begun in the province. NSP stated that this supply shift will be happening at the same
time that the ExxonMobil backstop agreement with M&NP expires in 2019 and M&NP’s
revenue requirements are spread over remaining shippers, including NSP, thus increasing cost to
its customers. NSP further stated that individually, each of these events will have a major impact
on NSP’s gas supply costs and thus its customers’ electricity costs. Furthermore, in combination,
they will have an even more significant impact. NSP stated that it may be forced to move away
from natural gas in order to contain costs for its customers.
NSP commissioned ICF, consultants, to examine the market context in which the LRS has been
proposed. The ICF Report submitted by NSP summarizes the natural gas market context in
which M&NP and EBPC were first developed and approved, the changes that have occurred
since then, and the future prospects for the relevant markets, the pipelines, and their shippers.
NSP submitted that the ICF Report summarizes the number of changes to the natural gas market
context in which M&NP and EBPC were first developed and approved as well as changes that
have occurred since then and the future prospects for the relevant markets, the pipelines, and
their shippers. Given this context, NSP explained that ICF has illustrated that converting the
Canaport-dedicated EBPC to now service other Maritimes load would be tantamount to
introducing a new pipeline into a small and already oversupplied market.
ICF submitted that M&NP was designed to carry Canadian offshore gas production to Northeast
U.S. markets and also provide opportunities to develop a natural gas market in the Maritimes.
The major shippers on the pipeline were Nova Scotia’s offshore producers exporting into U.S.
markets. ICF explained that the offshore supply feeding into M&NP is in decline, and that
1

GH-1-2006, page 34

Letter Decision
RHW-001-2017
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 ExxonMobil is scheduled to begin decommissioning the Sable Island gas field in 2018, and
Encana has announced that well plugging at Deep Panuke will be completed between 2019 and
2021. ICF noted that M&NP must now reverse its flows and transport natural gas from the U.S.
into Canada in order to continue to serve its Canadian customers. ICF further stated that one
main benefit of the Canadian portion of the M&NP system is that it now connects the Maritimes
to the wider North American gas grid providing access to supplies from other regions. ICF noted
that through M&NP Canada, the Maritimes has access to gas supplies, subject to limited pipeline
capacity in the U.S. Northeast that connects the Maritimes to the rest of the North American
pipeline network. These supplies are already flowing into the market and are expected to
increase towards 2030.
ICF stated that EBPC, on the other hand, was designed to transport gas from LNG imported at
Canaport to Northeast U.S. markets. Although recognizing that EBPC could potentially provide
incremental gas supply to the Maritimes via backhaul from its interconnection with M&NP U.S.,
ICF stated that EBPC has never been a part of the Maritimes gas market and has never had, and
currently does not have, delivery points in Canada.
ICF explained that the aggregate volumes for both pipelines have been in decline and the
likelihood of a rebound in volumes on either pipeline appears to be extremely remote. ICF
asserted that the prospects for new domestic supplies of offshore Canadian gas to serve U.S.
Northeastern markets via M&NP are grim. ICF stated that the growth of shale gas production in
the Appalachian region of the U.S. created economic conditions (lower gas prices) that do not
support additional and expensive investments to bring on new fields in the Scotian offshore.
Shale producers have flooded the Northeast with low cost gas against which new SOEP and
Deep Panuke production cannot compete.
ICF stated that the declining throughput from the offshore, and the small size of the Maritimes
gas market, exposes this market to the risk that the costs of the M&NP pipeline, originally
designed with New England as an anchor market, must be borne by an ever shrinking number of
shippers as it reverses flow. ICF further asserted that by the end of 2019, with the expiration of
the ExxonMobil backstop contract, the problem will become more acute.
ICF also stated that, like many LNG terminals in the U.S. that have switched from their original
purpose as import terminals to LNG export terminals by the addition of liquefaction facilities,
Repsol was considering this option for Canaport. Such a conversion would have reversed flows
on EBPC. In March 2016, however, Repsol announced that it would put its export plans on hold.
Nova Scotia Department of Energy (NSDOE)
NSDOE submitted that the natural gas market in the Maritimes is still in its infancy, and faces
challenges that do not exist in more mature and robust markets elsewhere in North America.
NSDOE stated that in the short term, the Maritimes natural gas market will have to overcome
serious obstacles to continue to develop and thrive.
NSDOE submitted that if the Board were to approve the construction of facilities to permit
Irving Oil to take service from EBPC, it would result in a shifting of costs that would exacerbate
matters for customers in the local market (other than Irving Oil).
Letter Decision
RHW-001-2017
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 NSDOE noted that EBPC has not enhanced the development of the Maritimes natural gas market
at all, and has not hurt it either, because it has never established a direct connection with the
Maritimes market. NSDOE asserted that the EBPC Alternative would not compete with M&NP
in the regional market because it is not a regional pipeline. Rather, it would select a few
beneficial customers located near its shorter pipeline, and leave the rest of the market the worse
off.
NSDOE submitted that, in addition, the EBPC pipeline was not approved by the Board to
compete with the M&NP pipeline. NSDOE cited the GH-1-2006 Decision approving EBPC (also
referred to as the Brunswick Pipeline or the Project), in which the Board stated:
“On the basis of the evidence, the Board is persuaded that the intended purpose of the
Brunswick Pipeline is to connect a new incremental supply source to existing markets
and is of the view that the Project as proposed does not duplicate existing facilities in the
region.
“[R]egarding potential future underutilization of regional pipeline infrastructure as a
result of the introduction of the Brunswick Pipeline, the Board did not find reasonable
grounds in the evidence to support this concern.” 2
Reply of M&NP
M&NP did not provide a reply regarding the natural gas markets in the Maritimes.

3.

Whether the LRS is Required and the EBPC Alternative is
Well Founded

Views of M&NP
M&NP explained that Irving Oil has had two firm service agreements with M&NP, but that one
had expired when the Application was filed (30,000 MMBtu/d terminated effective
20 December 2015) and one not renewed (18,000 MMBtu/d terminated effective 31 October
2017). With respect to the contract that had expired when the Application was filed, M&NP
submitted that Irving Oil has been meeting its needs for transportation service on M&NP by
using non-firm services or the secondary market. M&NP explained that Irving Oil advised M&NP
that it was offered long term firm service on the EBPC system that would meet the needs of the
Oil Refinery and Cogen.
M&NP submitted that the EBPC Alternative is a credible bypass threat. M&NP explained that it
took steps to obtain information independently of Irving Oil regarding the EBPC Alternative and
did not rely solely on information provided by Irving Oil. M&NP explained that it conducted the
following due diligence to assess the EBPC Alternative:

2

GH-1-2006, page 27

Letter Decision
RHW-001-2017
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 •

Verification that the EBPC is currently located on the Irving Oil Refinery property and
that EBPC offers an existing direct transportation path from Baileyville, Maine to the
Irving Oil Refinery property;

•

Verification that EBPC has existing sufficient capacity to offer firm service to Irving Oil
at the 65,000 MMBtu/d level;

•

Verification that, given the current line of EBPC running on the Irving Oil Refinery
property, modest capital cost would be required on the EBPC system to construct an
interconnection and meter station to serve the Irving Oil load;

•

Verbal notification from Irving Oil that EBPC had formally offered firm transportation
service;

•

Receipt of formal notice from Irving Oil that it did not wish to renew expiring firm
contract commitments on M&NP Canada;

•

Confirmation that other existing M&NP large industrial loads in close proximity to EBPC
in Saint John have formally been provided offers of firm transportation service on EBPC.

M&NP noted that although the EBPC system is not currently a full bypass alternative, it could
become so with a modest incremental investment. M&NP noted that the EBPC facilities
modifications required to make simultaneous deliveries at Saint John and Baileyville would
include a mainline tap and meter station at the Irving Oil refinery site at a cost estimated by
M&NP at $5.4 million.
M&NP stated that EBPC would require Board approval of the connection facilities necessary to
provide service to Irving Oil. M&NP suggested that given the modest nature of such facilities,
EBPC could apply for their approval under Section 58 of the Act, possibly under the NEB’s
section 58 streamlining procedure.
In response to a request by Heritage Gas, M&NP stated that it reviewed a copy of the Negotiated
Toll Agreement made between Repsol and EBPC dated 15 May 2006, and a copy of the
Settlement Agreement made between Repsol and EBPC dated 31 May 31 2016. M&NP also
filed links to the Negotiated Toll Agreement and the Settlement Agreement on the record.
M&NP stated that it understands Repsol to have certain rights that could affect EBPC's
willingness or ability to provide service to Irving Oil. Nevertheless, given that EBPC has offered
Irving Oil firm service, M&NP concluded that EBPC has cleared its ability to do so with Repsol.
M&NP explained that it has no reason for believing that EBPC is not a reliable transporter and
concluded that the EBPC service would be comparable to M&NP service in terms of service
priority and reliability.
M&NP stated that it would prefer not to have to deal with the EBPC competitive threat and
simply retain the Irving Oil load at the M&NP regular system toll. M&NP submitted that in
GH-1-2006, the Board commented on competition and the public interest and provided that the
Board’s mandate is neither to protect parties from competition nor protect specific private
interests. M&NP further stated that in the GH-1-2006 Decision, the Board stated that it
believes that the public interest is best served by allowing competitive forces to work unless
there is clear evidence of significant market dysfunction.

Letter Decision
RHW-001-2017
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 Views of Intervenors
Nova Scotia Power Inc.
NSP stated that the Application is premature and should be denied. NSP explained that the Board
should first determine whether approval for EBPC bypass facilities and service to Irving Oil, and
any other customers, would be in the public interest. If the Board determines that such approvals
are not in the public interest, then there is no need for the Application.
NSP disagreed with the premise of M&NP’s Application, namely that retaining Irving Oil at the
LRS Toll is preferable to losing the Irving Oil load altogether. NSP noted this assessment ignores
the primary question which is whether the EBPC Alternative, and competing facilities, is in the
overall public interest.
NSP explained that in order to serve Irving Oil or any other Maritimes gas transportation
customer, EBPC would require approval from the Board to reverse flow and provide both the
physical connection and Board-approved service and associated toll to Maritimes gas customers.
Any such approval, in NSP’s view, would be tantamount to an approval to convert the dedicated,
sole purpose, fully paid for EBPC pipeline into what would effectively be new transportation
capacity to serve the Maritimes market
ICF stated that M&NP has failed to justify the LRS, and that the bypass threat from EBPC has
not been shown to be credible. ICF asserted that no steps have been taken by EBPC to reverse
flows and otherwise serve Canadian consumers, and EBPC has not applied to the Board to
initiate such a service. Absent these steps, ICF stated that the bypass is simply a possibility.
ICF emphasized that if the EBPC Alternative is found to be realistic, the Board should not
approve it. ICF asserted that EBPC’s bypass of M&NP offers no advantage other than a lower
rate to a few customers, at the expense of other customers, and would result in harm to local gas
markets as rates on M&NP would significantly increase due to allocation of costs over a smaller
contract volume.
ICF concluded that the appropriate action at this point should be to determine the credibility and
the desirability of any EBPC reversal to serve Irving Oil and other gas users in the vicinity. In
considering such, the Board should take into account that EBPC was built to carry Canaport
volumes to the United States and has never had any delivery points in Canada. ICF explained
that as a result, EBPC would not be introducing incremental supply as was envisioned when it
was authorized; rather, it would be taking gas from the same spigot that M&NP Canada receives
gas for the Maritimes market. ICF added that EBPC does not face the imminent loss of revenue
from the expiration of the major contracts on the pipeline like M&NP does because the Repsol
contract on EBPC does not expire until 2034.
Irving Oil
Irving Oil confirmed that it was offered long term firm service on the EBPC system that would
meet the needs of its Oil Refinery and Cogen. Irving Oil also confirmed that, based on its general
knowledge of the EBPC system, EBPC has the available capacity, reliability, and level of risk
profile required to provide it with firm transportation service, assuming the addition of a hot tap
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 connection and new meter station. Irving Oil also confirmed that with EBPC offering firm
service, Irving Oil concluded that EBPC cleared its ability to make an offer for firm service with
Repsol and that Repsol has no further rights over the capacity required to provide such service, at
least not rights that would affect Irving Oil’s ability to use the capacity on a firm basis.
Irving Oil stated that the EBPC Alternative is a credible competitive alternative. Irving Oil
asserted that if the LRS applied for by M&NP is not approved, it is reasonable for the Board to
expect Irving Oil to pursue the EBPC Alternative rather than MN365 transmission service on
M&NP.
Heritage Gas
Heritage Gas stated that EBPC was approved by the Board to transport natural gas received as
LNG at the Canaport LNG Terminal in Saint John and to be a new source of gas supply for
market in the Northeast U.S. and the Maritimes. Heritage Gas submitted that in the decision to
approve the EBPC pipeline, the Board specifically concluded that the EBPC pipeline would not
be a bypass of the M&NP Canada system.
Heritage Gas submitted that there is no basis to suggest that the Board would have approved
EBPC in the first place if the evidence in GH-1-2006 indicated that EBPC would bypass and
offload volumes from the M&NP Canada system. Heritage Gas also noted that M&NP would not
have supported approval of the EBPC application in the GH-1-2006 proceeding had EBPC been
considered a bypass of M&NP.
Heritage Gas submitted that in the current circumstance, although EBPC is now constructed and
in service, this does not mean that EBPC can now just choose to compete with M&NP Canada to
transport gas from M&NP U.S. to the Irving Oil Refinery. Heritage Gas asserted that EBPC can
only bypass and offload Irving Oil volumes from M&NP Canada if the Board allows it to do so
and furthermore, EBPC cannot provide service to Irving Oil without constructing additional
facilities that require Board approval.
Heritage Gas stated that M&NP’s proposed LRS is not required if the EBPC Alternative is in
fact not in the public interest and would not be approved by the Board. Heritage Gas noted that
consideration needs to be given to the benefits and costs of the EBPC Alternative.
Heritage Gas argued that there would be two beneficiaries of the EBPC Alternative, namely,
Irving Oil and Repsol. Heritage Gas explained that Irving Oil would benefit by paying a lower
toll to EBPC than the toll charged by M&NP. Furthermore, Heritage Gas stated that Repsol
would benefit by receiving a credit to the toll that it pays to EBPC in the amount of the charges
received by EBPC from Irving Oil. Heritage Gas calculated Repsol’s toll savings in 2020 to be
approximately $6.0 million.
Heritage Gas concluded that allowing EBPC to bypass and offload volumes from M&NP would
cause a transfer of significant wealth to Irving Oil and Repsol from electricity and gas end-users
in the Maritimes.

Letter Decision
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 Nova Scotia Department of Energy
NSDOE submitted that the LRS and LRS Toll should be denied. NSDOE noted that any
approval from the Board that would facilitate the interconnection of Irving Oil to EBPC would
not be in the public interest because competition for M&NP customers by EBPC would not be
beneficial. NSDOE asserted that EBPC was not approved to compete with M&NP, and has not
helped to develop the regional market in the Maritimes. NSDOE concludes that it should not be
permitted to harm it now.
In NSDOE’s view, the broader natural gas market will be worse off if the Board were to approve
facilities for the interconnection of Irving Oil to EBPC. NSDOE explained that those impacted
will not only be sophisticated industry parties but also many small business and residential users
of natural gas.
NSDOE asserted that before Irving Oil could take up service on EBPC, interconnection facilities
would have to be built and this would require an approval from the Board. NSDOE stated that
when considering such an application, the Board would have to consider the public interest, and
weigh the benefits and costs of the application. NSDOE further asserted that as the few benefits
of such an application would be enjoyed by a small number of large customers, and the balance
of the developing and already challenged Maritimes market would be worse off, it would not be
in the public interest for the Board to grant such an approval. NSDOE concluded that if it is not
likely that a competitive service on EBPC would be approved, there is no need for the LRS and
LRS Toll.
Reply of M&NP
In reply, M&NP explained that once EBPC offered competitive service to Irving Oil, M&NP had
a choice: it could do nothing and hope that EBPC would not be successful in implementing such
service, or it could compete actively to retain the Irving Oil load. M&NP asserted that it has
proceeded with the Application on the basis of its understanding that the Board expects pipelines
to respond to changing market conditions and that competition, as represented by the EBPC
Alternative, is in the public interest. Recognizing that EBPC service to the Maritimes market was
contemplated at the time EBPC was constructed (albeit not service that would directly compete
with M&NP), and considering the guidance from the Board provided to TransCanada in the RH003-2011 Decision, in which the Board stated that it would not shield pipelines from competition
and expected pipelines to address the underlying competitive reality in which they operate,
M&NP chose to proactively compete to retain the Irving Oil load.
M&NP indicated that while it would expect that EBPC would require some Board approval of
the connection facilities required to serve the Irving Oil load, M&NP explained that this is not a
certainty. M&NP stated that it cannot confirm whether EBPC would consider it necessary to
apply for advance Board authorization for a hot tap and meter station. M&NP noted that a
streamlining procedure, which does not require advanced Board approval, may be an option. In
response to NSP’s argument that in order to serve Irving Oil or any other Maritimes gas
transportation customer, EBPC would require an NEB approved service and associated toll to
Maritimes gas customers, M&NP replied that EBPC is a Group 2 company and therefore is
regulated on a complaint basis. M&NP asserted that while Group 2 companies must file their
Letter Decision
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 tolls and tariffs with the Board prior to charging tolls to any shippers, no advance approval of
such tolls and tariffs is required, as they are regulated on a complaints basis.
In response to NSP’s argument that EBPC has never been part of the Maritimes natural gas
market, and has never had, and currently does not have, delivery points in Canada, M&NP said
that NSP’s argument ignored the importance the Board places on service to the Canadian market
in certificating EBPC. M&NP submitted that EBPC was viewed from the beginning as a
potential service provider to the Maritimes market, albeit the expectation was that EBPC would
provide such service in conjunction with offshore LNG supplies and not in direct competition
with M&NP.
In response to ICF’s position that in order to be credible, a bypass threat must be fully mature
and not just a possibility, M&NP submitted that this position is not correct. In M&NP’s view, the
purpose of a load retention service is to pre-empt the competitive threat and prevent any
competitive facilities from being applied-for and built in the first instance. Furthermore, M&NP
argued that the position that a credible bypass threat must be fully mature is incorrect since
competitive threats are typically only possibilities at the time they need to be addressed. M&NP
requested that the Board provide regulatory certainty and clarity in its decision on the
Application.

4. Impact of the LRS and LRS Toll on Existing Shippers
Views of M&NP
M&NP stated that the LRS provides a benefit to other M&NP shippers compared to the loss of
the Irving Oil load. M&NP explained that the LRS Toll revenue significantly exceeds the long
run incremental cost of service for the LRS since it is not required to construct any new facility
for Irving Oil. M&NP stated that the economic advantage benefiting all M&NP shippers if
Irving Oil contracts with M&NP are retained because of the LRS is $6 million per year for 13
years. M&NP further explained that the $6 million equates to a toll reduction of 13 cents using
MN365 contract determinants of 128,946 MMBtu/d (based on the actual average throughput
levels in 2016 (excluding export volumes) of 176,119 MMBtu per day projected to continue in
2020, reduced by actual average throughput at the Irving Oil Refinery of 47,173 MMBtu/d in
2020).
M&NP summarized that the proposed LRS provides an additional $79 million in revenue to the
system over the 13 years of the LRS contract as well as an additional 65,000 MMBtus of billing
determinants to support M&NP’s abandonment toll surcharge, which is to the benefit of all
shippers on the M&NP system. These benefits would be lost if the Irving Oil load leaves the
M&NP system.
M&NP stated that it does not know with any certainty what post-2019 tolls will look like for any
of its customers. M&NP submitted evidence demonstrating its efforts to alleviate upward
pressure on 2020 tolls, notably through a significant reduction in its forecasted revenue
requirement.

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 M&NP stated that that it continues to discuss load retention services with existing loads and is
actively competing with EBPC for these loads. M&NP added that each of these large industrial
customers has terminated its firm service contracts with M&NP and has large enough loads and
is close enough to the EBPC system that they would be eligible for a load retention service,
assuming there is a written firm offer for service from EBPC. M&NP confirmed that it has had
discussion over the past 12 to 18 months with each of these customers regarding the potential for
load retention services.
M&NP stated that it is aware of the potential impact on its general system tolls of load retention
service tolls being offered for similarly situated shippers other than Irving Oil, however, M&NP
concluded that this impact will be positive. M&NP explained that in its view, absent load
retention service offerings, the potential for system tolls to exceed what the market could bear
may be increased as a result of lost loads and lower throughput. M&NP emphasized that load
retention service tolls provide an opportunity to reduce tolls compared to the alternative of losing
loads.
Views of Intervenors
Nova Scotia Power Inc.
NSP submitted that the impact on NSP and its customers of the LRS and LRS Toll is significant,
will lead to higher electricity rates in the future, and may drive NSP to substitute natural gas with
some other source of energy. NSP stated that natural gas will likely be the most expensive
dispatchable generation source in the future.
NSP explained that the more expensive the delivered price of natural gas, the more likely that
other less expensive alternatives will be sourced for generating electricity. NSP asserted that if
the Application is approved, the resulting shortfall in revenue to M&NP from Irving Oil will be
recovered from M&NP’s remaining shippers and the foregoing electricity price pressures on
NSP’s customers will be exacerbated. NSP considers itself, along with Enbridge New Brunswick
and Heritage Gas, a captive demand shipper on the M&NP system.
NSP estimated the toll increase on M&NP post-2019 to be 30 per cent more than the current toll
of $0.755/MMBtu/d based on expected contract determinants. NSP further stated that the
discount proposed for the LRS Toll is $176 million, which, in its view, is significant considering
that it amounts to 25 per cent of expected M&NP revenue for the next 13 years. NSP is of the
view that the $176 million shortfall in revenue relative to costs will have to be made up
exclusively by existing and future shippers on M&NP.
The ICF Report stated that there are two major implications for captive shippers on the Canadian
portion of the M&NP system arising from the LRS Toll. First, lowering of the toll for Irving Oil,
and potentially other customers in the vicinity, is expected to shift the cost of service to the other
shippers who will remain on the system. Second, the LRS Toll would increase the cost of getting
gas from U.S. production in the Marcellus by approximately $0.80 /MMBtu/d. ICF conceded
that securing supplies from the south at prices that can compete with propane and fuel oil, while
adding more costs, will further burden captive customers.

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 Irving Oil
Irving Oil submitted that the M&NP system and its shippers will be better off with approval of
the LRS and LRS Toll as compared to the EBPC Alternative.
Nova Scotia Department of Energy
NSDOE stated that the LRS and LRS Toll are not necessary and should not be approved.
NSDOE asserted that it supports the development and use of load retention services and tolls
where they are necessary and sufficient.
Heritage Gas
Heritage Gas submitted that it is generally in favour of load retention tariffs, but believes that it
is important to examine the particular facts and circumstances of each proposal.
Heritage Gas categorizes itself as a captive customer to M&NP for its natural gas demand.
Heritage Gas explained that it is directly affected by the tolls charged from service on M&NP
and that increases in M&NP tolls increases the delivered cost of gas to Heritage Gas customers
in Nova Scotia. Heritage Gas explained that this adversely impacts the ability of Heritage Gas to
develop the natural gas distribution system in Nova Scotia.
Heritage Gas cited M&NP’s estimate that the 2020 M&NP toll, based on contract determinants
of 176,119 MMBtu/d, would be $0.83/MMBtu/d. The offload of 65,000 MMBtu/d by EBPC
would result in a 2020 toll on M&NP of $1.14/MMBtu/d. Heritage Gas asserted that this
represents a toll increase of $0.31/MMBtu/d – an increase of more than 37 per cent.
Heritage Gas further argued that two other large industrial customers in New Brunswick have
already received formal transportation service offers from EBPC. Heritage Gas asserted that if
these loads were also lost to EBPC, it would result in an estimated 2020 toll on M&NP of
$1.70/MMBtu/d. Heritage Gas asserted that in comparison to the toll of $0.83/MMBtu/d that
would result from contract determinants of 176,119 MMBtu/d, this represents a toll increase of
more than 100 per cent.
Reply of M&NP
In reply, M&NP stated that none of the opposing Intervenors challenged M&NP’s evidence that
retaining the Irving Oil load with the LRS and LRS Toll will offer net revenues to the system
compared to losing that load. M&NP reiterated that the incremental cost of providing the LRS is
negligible and almost all revenues from the service would be an incremental benefit to the
system. M&NP submitted that none of the opposing Intervenors challenged its evidence that no
cost sharing or asset write-off in conjunction with the LRS and LRS Toll is warranted or
appropriate. M&NP also asserted that none of the opposing Intervenors challenged its evidence
that retaining the Irving Oil load is preferable to losing it.

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 M&NP acknowledged and agreed with Heritage Gas’ assessment of the cost of losing the Irving
Oil load, and the loads of similarly situated customers, versus retaining those loads the full
system toll. M&NP also acknowledged that the impact of retaining the Irving Oil load, and the
loads of similarly situated customers, at load retention tolls versus retaining these customers at
the full system toll, entails a significant cost to the M&NP system. M&NP further stated that the
cost to the M&NP system of losing these customers altogether is even greater.
Views of the Board
Requirements of the NEB Act
Part IV of the Act sets out the Board’s mandate in respect of traffic, tolls and tariff matters.
Section 62 provides that all tolls shall be just and reasonable and shall always, under
substantially similar circumstances and conditions with respect to all traffic of the same
description carried over the same route, be charged equally to all persons at the same rate.
Section 67 prohibits a company from making any unjust discrimination in tolls, service or
facilities against any person or locality. Further, under section 63 of the Act, the Board may
determine as questions of fact whether or not traffic is or has been carried under substantially
similar circumstances and conditions as referred to in section 62 or whether there is unjust
discrimination within the meaning of section 67.
Decision
The Board denies the Application for the reason that it is premature for the reasons explained
below. It makes no finding as to whether the proposed toll would be just and reasonable and
whether there would be unjust discrimination.
In assessing the Application, the Board considered whether the LRS is required and whether the
EBPC Alternative is well-founded. M&NP’s evidence indicated that the EBPC system has
sufficient existing capacity to serve the Irving Oil load with small facility additions; that the
reversal of the EBPC would require minimal Board regulatory review before approval; and that
the service quality on EBPC would be expected to be comparable to that on M&NP. Irving Oil
supported M&NP’s submissions regarding the EBPC Alternative. The evidence also shows that
Irving Oil would be expected to pursue the EBPC Alternative to meet its service needs if this
Application were denied.
From this narrow perspective, the EBPC Alternative arguably represents a credible alternative to
service the Irving Oil load. However, while the Board agrees with M&NP that an alternative
service option need not be fully mature to be considered a credible threat, M&NP’s assertion that
the reversal of the EBPC system would require minimal Board regulatory review before it could
be undertaken does not appear to be accurate. The evidence on the record of this proceeding
suggests that an application by EBPC for the Section 58 facilities that would accompany the
reversal and repurposing of its system would not be eligible to use the Board's Section 58
Streamlining Order (A43203).
The Streamlining Order applies to certain classes of oil and gas projects, and the facility
component of the EBPC reversal may fall within one of those classes; however, it may only be
Letter Decision
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 used when all the criteria in Schedule A thereof are met, which does not appear to be the case
with respect to a future facilities application for reversal by EBPC. Among those criteria is the
requirement that “directly affected persons or those persons with relevant information or
expertise (e.g., might include Aboriginal groups; directly affected landowners; shippers; federal,
provincial, municipal agencies) have been consulted on the project and all issues and concerns
have been resolved.” 3
Furthermore, the Settlement Agreement between EBPC and Repsol, and the Board’s 2016
decision approving the Settlement Agreement (A80602), require EBPC to file an application
with the Board should it wish to reverse service on the pipeline. The regulatory steps described
in the Board’s letter and Settlement Agreement were not fully explored on the record.
Specifically, the Board notes that the Board’s letter 4 cites the Settlement Agreement:
The Settlement Agreement states that Emera [EBPC] shall file an application with the
Board seeking approval of the modifications to the Pipeline to reverse service on the
Pipeline, as well as amendments to the Settlement Agreement and the [Negotiated Toll
Agreement] NTA, if necessary.
And, the Board’s letter concludes that:
The Board reminds Emera [EBPC] that this approval does not constitute a decision on
any future applications, including the potential reversibility of the Pipeline.
The Application for the LRS and LRS Toll was limited to a request for approval of that service
and toll, and the Board correspondingly established a process to assess the Application as applied
for. However, as the hearing process and evidentiary record evolved, significant broad concerns
and uncertainties were raised about the future of the natural gas market in the Maritimes and the
impact on shippers, in particular those captive to M&NP.
Intervenors raised concerns about current and future supply and markets of M&NP and EBPC;
the respective roles of the two systems historically, currently and in the future; and the benefits
and costs of inter-pipeline competition. The evidence indicates that splitting the domestic market
demand between the two pipelines post-2019 may challenge the viability of M&NP, which, as a
result, could affect the Maritime natural gas market unfavourably. The evidence showing that
other load retention service applications to serve industrial loads in the Saint John area have been
discussed, raises further concerns about the long-term future of the natural gas market in the
Maritimes and the potential impact of load retention services on M&NP’s captive shippers.
The Board notes that, in light of those broad concerns and uncertainties having been identified by
parties participating in this proceeding, it appears that not all parties with a potential interest in
these broader matters – such as all potentially impacted LDCs, large industrial gas consumers,
3

1 August 2012, Streamlining Order XG/XO-100-2012, Schedule A - Step 2.1, Adobe page 7 of 7 (A43203)

4

14 November 2016, Board letter to Emera Brunswick Pipeline Company Ltd. Re: Application for Approval of
Settlement Agreement and Tariff Revisions, Adobe page 2 of 3 (A80602).

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 and pipelines in the Maritime natural gas market - participated or submitted evidence in this
proceeding.
The Board recognizes that pipelines must adapt to changing conditions in their markets and that
M&NP has proactively developed the LRS proposal to respond to the perceived competition
from EBPC. The Board views the LRS and LRS Toll Application as a premature response that
gives rise to significant concerns among affected parties. Furthermore, the Board notes an
examination of possible alternative toll and tariff approaches would be more fruitful when
M&NP’s supply, markets and contract billing determinants post-2019 are known.
In conclusion, for the reasons set out above, the Board denies the Application but it does so
without making any determination as to whether the LRS Toll would be just and reasonable and
not unjustly discriminatory under Part IV of the Act.

P. Davies
Presiding Member

S. Kelly
Member

D. Côté
Member

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