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Barristers & Solicitors / Patent & Trade-mark Agents

Norton Rose Fulbright Canada LLP 1800 - 510 West Georgia Street Vancouver, BC V6B 0M3 CANADA

F: +1 604.641.4949 nortonrosefulbright.com

Matthew D. Keen +1 604.641.4913 matthew.keen@nortonrosefulbright.com

Assistant +1 604.641.4527 rosalind.endo@nortonrosefulbright.com

Project No. 1598984

Our reference 19-2668

July 11, 2019

Sent By E-mail

Dear Sir: Kinder Morgan 2019 Tariff Filing – Vancouver Airport Fuel Facilities Corporation (“VAFFC”) Information Request (IR) No. 1

We are legal counsel to VAFFC in this matter and write to enclose VAFFC’s IR No. 1 to KMJF. Please contact the writer if you have any questions.

Yours very truly,

for Matthew D. Keen

MDK/roe

Enclosure

British Columbia Utilities Commission 6th Floor – 900 Howe Street Vancouver, BC V6Z 2V3 Attention: Patrick Wruck, Commission Secretary

C2-3

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BRITISH COLUMBIA UTILITIES COMMISSION KINDER MORGAN CANADA (JET FUEL) INC. 2019 TARIFF FILING APPLICATION

Vancouver Airport Fuel Facilities Corporation (VAFFC) Information Request (IR) No. 1 to Kinder Morgan Canada (Jet Fuel) Inc. (KMJF)

July 11, 2018

1.0 Regulatory Principles

Reference: Exhibit B-8, KMJF Application, para. 2, p. 5

At para. 2 of the application, KMJF, in addressing the regulatory framework applicable to it and the BCUC’s jurisdiction, acknowledges that the BCUC may establish conditions “in relation to tolls that may be charged by KMJF as a common carrier”, and “in relation to extensions, improvements or abandonment of service by KMJF as a common carrier in respect of operating the Jet Fuel Line”.

1.1 Please confirm that for the 2009-2018 period:

(a) KMJF was a common carrier under the Utilities Commission Act;

(b) KMJF’s tolls were not based on a cost of service rate setting mechanism; and

(c) In setting KMJF’s tolls, the BCUC did not consider KMJF’s (i) rate of return on common equity or (ii) other rate components.

If any of the above are not confirmed, please fully explain why.

1.2 Please confirm that during the 2009-2018 period, KMJF tolls were not representative of those that would be found in a competitive market. If not confirmed, please fully explain your response.

1.3 Does the “regulatory compact” apply to KMJF? Please fully explain why or why not.

1.4 In KMJF’s view, are its obligations as a common carrier limited to accepting all volumes tendered in accordance with its tariff conditions? Please fully explain why or why not.

1.5 Beyond the capacity made available by KMJF’s existing pipeline, is it KMJF’s understanding that KMJF as a common carrier has an obligation to serve all parties who wish to ship Jet Fuel from the KMJF receiving point to the KMJF delivery point? i.e., is there an obligation on KMJF to expand the pipeline if requested shipper volumes exceed available capacity?

1.6 Please provide KMJF’s understanding of the definition of “common carrier” in British Columbia and how it compares to a “public utility”.

1.7 Does KMJF believe the circumstances of the Jet Fuel System support the pipeline as a “natural monopoly”, as that term is used in the standard economic literature on utilities? In your response, please confirm that there are no competing supply services that could currently replace the volumes KMJF supplies to VAFFC. If not confirmed, please fully explain why not.

1.8 Please confirm KMJF holds no franchise, nor government or regulator imposed exclusivity arrangement (with regard to either the Jet Fuel System’s collection or delivery areas).

1.9 Please confirm whether the form of regulations that have applied to KMJF since 2007 has required KMJF to adopt a specific set of depreciation parameters (e.g., assumptions on asset lives) and whether there were prohibitions on KMJF from changing these factors outside of BCUC approval. Please fully explain your answer. If KMJF confirms it was prohibited from changing depreciation

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factors, please provide specific pinpoint references to the legislative provisions, regulations, or lawful orders or decisions that gave rise to that prohibition.

2.0 Common Carrier Order History

Reference (i): Reasons for Decision and Order P-3-08 TMJF ~ Approval of Tolls and Accelerated Depreciation & Reasons for Decision, Appendix A, Jurisdiction, pdf. pp. 7-8

In the BCUC’s 2008 decision, the BCUC stated as follows with regard to the BCUC’s regulatory jurisdiction over KMJF:

4.1 Common Carrier

The Company is of the opinion that TMJ is not a common carrier for the purposes of the UCA. In addition, TMJ stated that it is not aware of any order declaring it to be a common carrier. Since the term “common carrier” is not defined in the Act, TMJ considers the applicability of this term to TMJ is subject to the interpretation of the common law definition. The Company submits that TMJ is a common carrier at common law (Exhibit B-5, Commission IR 36.1).

Although TMJ has not been declared a common carrier for the purposes of the UCA, the Application for the adjustment of tolls is pursuant to Section 44 of the Act which applies to common carriers (Exhibit B-1, Letter, p. 1). Since 1997, toll applications by TMJ and its predecessor companies have been decided pursuant to Section 44 of the Act (Order No. P-3-98). The Company’s July 23, 2007 submission also states that the Commission has jurisdiction in respect of suspensions of, or delays in resumption of, service (without abandonment) by virtue of Section 42 of the Act, which obligates common carriers to receive, transport and deliver all oil subject to exceptions or conditions approved by the Commission (Exhibit B-4, Order No. P-3-07 Submission, p. 2). In their submissions regarding the jurisdiction of the Commission to review a potential pipeline abandonment application by TMJ, both Chevron and VAFFC took the position that TMJ is a common carrier (Exhibit C1-2, p. 1; Exhibit C2-2, p. 1).

Given the Company’s position that TMJ is a common carrier at common law and the submission of the current Application and previous toll applications under Section 44 of the Act and TMJ’s acknowledgement of the Commission’s jurisdiction under Section 42 of the Act, the Commission concurs with the Chevron and VAFFC view that TMJ is common carrier. The functions that TMJ performs are consistent with those of common carriers and the Commission concludes that TMJ is a common carrier under the Act.

4.2 Abandonment

In accordance with Order No. P-3-07, the Parties made submissions on the jurisdiction of the Commission to review a potential pipeline abandonment application by TMJ pursuant to Section 41 of the UCA or under Part 7 of the Act. The Company’s July 23, 2007 submission stated that TMJ operates under Section 36 of the Act pursuant to leave obtained from the Oil and Gas Commission (“OGC”) and that Section 9 of the Act expressly confers jurisdiction over abandonment on the OGC (Exhibit B-4, Order No. P-3-07 Submission, pp. 1, 3). TMJ also takes the position that the Commission has no jurisdiction over the Company under Section 41 of the UCA, since Section 41 of the UCA only applies to “public utilities” and TMJ is not a “public utility” (Exhibit B-4, Order No. P-3-07 Submission, p. 1). TMJ is also of the view that the Commission’s jurisdiction under Section 42 of the Act is not brought into play because the Company is not seeking to suspend service temporarily (Exhibit B-4, Order No. P-3-07 Submission, p. 8).

Chevron considers the TMJ Pipeline a company pipeline within the meaning of the Act and a common carrier within the meaning of the UCA. As a result, Chevron is of the view that the TMJ Pipeline is subject to regulation by the OGC with respect to operation and safety, and regulation by the Commission with respect to tolls and tariffs. Chevron also submits that both the OGC and the Commission must acquiesce before a common carrier oil pipeline can cease to operate (Exhibit C1-2, Order No. P-3-07 Submission, p. 1). Given that the Company is a common carrier, Chevron is of the opinion that TMJ is in the same position as a public utility and subject to Section 41 of the UCA. In

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addition, Chevron states that the Commission’s jurisdiction is further confirmed by Sections 42 and 43 in Part 7 of the Act (Exhibit C1-2, Order No. P-3-07 Submission, p. 2).

VAFFC is of the view that, pursuant to Section 9 of the Act, the Company must obtain leave of the OGC before it may abandon operation of the Jet Fuel System. If the Company, pursuant to Section 9 of the Act, seeks approval from the OGC to abandon the TMJ Pipeline, VAFFC takes the position that the Company must also apply to the Commission for an exception pursuant to Section 42 of the Act to be relieved of its duty as a common carrier (Exhibit C2-2, Order No. P-3-07 Submission, p. 1). VAFFC states that the Act contains no explicit requirement to obtain Commission leave to abandon the operation of a pipeline, but the requirement arises by necessary implication from Part 7, Section 42 of the Act. Part 7, Sections 42 and 43 of the Act impose explicit positive duties on a common carrier and authorize the Commission to regulate the operation of a common carrier (Exhibit C2-2, Order No. P-3-07 Submission, p. 2). VAFFC also considers that Section 41 of the UCA does not apply to TMJ, since TMJ is not a public utility as that term is defined under the UCA (Exhibit C2-2, Order No. P-3-07 Submission, p. 3).

The Commission accepts that TMJ is not a “public utility” as defined by the UCA; therefore, TMJ is not subject to Commission jurisdiction regarding the review of a potential pipeline abandonment under Section 41 of the UCA. Given that the Company is a common carrier pursuant to the Act, TMJ is subject to Commission jurisdiction under Part 7 of the Act. Section 42 of the Act states that subject to exceptions the Commission approves, a common carrier must provide service for all oil offered for transportation by its company pipeline. The Commission considers that this requirement applies in the event the common carrier wishes to permanently terminate service, as well as temporarily suspend service. Furthermore, Section 43 of the Act provides that the Commission may require a common carrier to provide adequate and suitable facilities to provide service. The Commission concurs with VAFFC’s position that TMJ must obtain Commission approval to abandon the operation of the TMJ Pipeline due to the positive duties on a common carrier under Sections 42 and 43 of the Act.

Reference (ii): Utilities Commission Act, RSBC 1996, c 473, s. 65

Section 65 of the UCA provides in relevant part as follows:

65 (1) In this section, "common carrier" means a person declared to be a common carrier by the commission under subsection (2) (a).

(2) On application by an interested person and after a hearing, sufficient notice of which has been given to all persons the commission believes may be affected, the commission may

(a) issue an order, to be effective on a date determined by it, declaring a person who owns or operates a pipeline for the transportation of

(i) one or more of crude oil, natural gas and natural gas liquids, or

(ii) any other type of energy resource prescribed by the Lieutenant Governor in Council,

to be a common carrier with respect to the operation of the pipeline, and

(b) in the order establish the conditions under which the common carrier must accept and carry energy resources.

(3) On application by a person that uses or seeks to use facilities operated by a common carrier, the commission, by order and after a hearing, sufficient notice of which has been given to all persons the commission believes may be affected, may establish the conditions under which the common carrier must accept and carry crude oil, natural gas, natural gas liquids or prescribed energy resources referred to in subsection (2) (a).

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(3.1) Without limiting subsection (2) (b) or (3), the commission may establish conditions with respect to a common carrier in relation to any of the following matters:

(a) a toll that may be charged by the common carrier;

(b) extensions, improvements or abandonment of service.

(3.2) The commission may order that section 43 applies with respect to a common carrier as though the common carrier were a public utility referred to in that section.

Reference (iii): Oil and Gas Activities Act, SBC 2008, c 36, s. 117

Sections 117(1) and (6) of the Oil and Gas Activities Act provide as follows:

(1) In this section, "former Act" means the Pipeline Act, R.S.B.C. 1996, c. 364, as it read immediately before its repeal.

(6) Despite the repeal of Part 7 of the former Act, any decision made with respect to a common carrier by the British Columbia Utilities Commission under the authority of that Part continues to apply, subject to section 65 of the Utilities Commission Act as amended by this enactment.

VAFFC seeks additional information and confirmation regarding KMJF’s understanding of the regulatory framework applicable to KMJF’s operations, and whether and when certain orders have been made regarding KMJF’s operations pursuant to the above.

2.1 Please confirm whether, and provide details regarding, any of the following actions have been taken by regulators with respect to the Jet Fuel System:

(a) Declaration of KMJF as a common carrier under the Utilities Commission Act, section 65(2)(a). Please indicate the effective date of such declaration and indicate the practical implications for KMJF in terms of investment and operations before and after the noted date;

(b) Any decisions, orders or declarations under section 65(3) of the Utilities Commission Act;

(c) Any decisions, orders or declarations under section 65(3.1) of the Utilities Commission Act;

(d) Any decisions, orders or declarations under section 65(3.2) of the Utilities Commission Act. Whether such a decision, order or declaration has been made or not, please provide a detailed description of KMJF’s understanding of the implications of the status that exists for KMJF in respect of Section 65(3.2); and,

(e) Any decisions, orders, directions or declarations (including exceptions or conditions imposed) under those sections of the since repealed Part 7 of BC’s Pipeline Act relating to common carriers.

2.2 Please identify all regulatory approvals that KMJF expects will be required for cessation of service and abandonment of the Jet Fuel System (excluding strictly environmental focused requirements), including the section of the legislation triggered, and the responsible regulator.

3.0 Market Competition

Reference: Exhibit B-8, KMJF Application, para. 40, pp. 21-22

On pp. 21-22, KMJF states:

KMJF requests approval of an allowed return on rate base based on the cost of capital parameters for a “benchmark low-risk utility” as determined by the BCUC in its 2013 Generic Cost of Capital Decision. KMJF’s requested return on rate base is determined as follows:

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KMJF’s individual business risks and the underutilization risks likely justify a higher allowed return. However, KMJF considers that its proposed depreciation methodology more equitably addresses the underutilization risk, as the shippers who share in this risk appropriately share in the benefit of accelerated depreciation during the period before volumes are reduced by more than 50% when the VAFD project enters service.

VAFFC is seeking additional information on KMJF’s application of regulatory principles in its application.

3.1 Please confirm that, under KMJF’s proposal, KMJF’s revenue requirement during the test period does not vary with throughput. If not confirmed, please fully explain your response.

3.2 Please confirm that KMJF’s underutilization risk is limited to not fully depreciating its assets before the end of the economic life of the pipeline. If not confirmed, please fully explain KMJF’s underutilization risk, including specific quantification of the risk that underutilization poses.

3.3 Please identify and explain what an appropriate higher allowed return on equity would be if KMJF were to bear the referred to “underutilization risk” instead of its proposed approach of collection through an accelerated depreciation methodology.

3.4 Please confirm that the BCUC’s regulatory framework does not protect KMJF from competition with other jet fuel transporters. If not confirmed, please fully explain your response, with reference to the specific applicable statutory provisions or orders.

3.5 Who are “the shippers who share in this risk [and] appropriately share in the benefit of accelerated depreciation”?

3.6 Please confirm that the risk that these shippers “share in” is the risk that the economic life of the KMJF system ends with the in-service date of the VAFD project. If not confirmed, please fully explain your response.

3.7 Please explain what the “benefit of accelerated depreciation” is for these shippers, including how such a benefit relates to the potential addition of new shippers to the Jet Fuel System. In your response, please specifically describe and quantify the purported benefit referred to.

3.8 If KMJF bears the risks of any premature retirement due to market forces other than underutilization resulting from the VAFD project, please provide a revised response to the above Information Request 3.7 indicating which parties share in the risk and benefit, with quantification.

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3.9 Please fully explain why, with accelerated depreciation securing recovery of capital investment over a short period and a consequently reduced business risk, KMJF is not proposing a return on rate base that is lower than that provided for a benchmark low-risk utility as determined by the BCUC in its 2013 Generic Cost of Capital Decision.

3.10 Please explain the specific rationale for why KMJF believes it is entitled to a “higher allowed return” on rate base than that applied for. Please include detailed calculations of how KMJF would calculate this higher return.

4.0 Jet Fuel System

Reference (i): Exhibit B-8, KMJF Application, para. 11, p. 9

On p. 9, KMJF states:

… Since 1969, the Jet Fuel System has been used to transport aviation turbine (jet) fuel from the Westridge Marine Terminal in Burnaby to [YVR]. The pipeline is 41 km (25.5 miles) long and 152 mm (6-inches) in diameter. It currently has a maximum throughput capacity of 4,200 m3/d (26,400 bbl/d). There are five pump stations, four of which are located at the refinery sites and one at Burnaby.

4.1 Please provide a technical description of the Jet Fuel System, including any technical papers pertaining to its specifications and the technologies it utilizes and including the following:

a) Wall thickness; b) Grade of steel; c) Design pressure; d) Maximum operating pressure (if different maximum operating pressures apply on the pipeline,

please provide a diagram showing the pressure that applies for each section of the pipeline); e) A diagram showing the pressure and elevation profile along the pipeline that corresponds to

maximum capacity operation; and, f) Material changes to the construction, throughput potential or collection and delivery locations that

occurred throughout the pipeline’s life, including the approximate date of such changes.

4.2 Please provide the ownership history of the Jet Fuel System since it was first put into service, including full explanation of any relevant changes in the owning entities or owning entities’ shareholders’ corporate organizational structures.

Reference (ii): KMJF’s 2007 Application for Approval of Tolls and Accelerated Depreciation, Project No. 369846 (“2007 Application”), Exhibit B-1, p. 5, Section 2.1

On p. 5, KMJF’s 2007 Application identifies the Jet Fuel Systems capacity as 4,800 m/d (30,200 bbl/d).

VAFFC seeks clarification on why KMJF’s 2007 Application lists the Jet Fuel Systems capacity as 11.4% more than the 4,200 m/d referred to in the current application.

4.3 Please confirm that the capacity of the Jet Fuel System has decreased between 2007 and now.

4.4 Please confirm that the capacity of the Jet Fuel System has decreased because the maximum system pressure is lower than in 2007. If confirmed, please provide the reason for the lower system pressure. If not confirmed, please fully explain your response.

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Reference (iii): Exhibit B-8, KMJF Application, Appendix A, Schedule 4, pdf p. 42

On pdf p. 42, KMJF provides the following table and information:

VAFFC seeks additional information on plant additions and retirements, to better understand those costs and the current technological condition and reliability of the Jet Fuel System.

4.5 Please confirm that between 2010 and 2018, KMJF allocated approximately $3,254,000 to plant additions and $1,290,000 to plant retirements.

4.6 Please confirm that, other than regular and routine maintenance, the Jet Fuel System has not been significantly upgraded, technologically or otherwise, since it came into operation in 1969.

4.7 If unable to confirm Information Request 4.6, please provide a detailed description of any significant upgrades to the Jet Fuel System, including relevant integrated technologies, since it began operations.

4.8 Please confirm that none of the additions reflected in Reference (iii) were specifically reviewed and approved by the BCUC. If not confirmed, please fully explain.

4.9 Please explain the adjustment between forecast and actual balances for 2009 undertaken to “reflect actual balances” as referred to in footnote 2 in Reference (iii).

4.10 Please provide a detailed explanation of actual depreciation expense for each year during 2010-2018, including, for each year: (1) how that actual depreciation expense was calculated; and (2) stating in which years, if any, (a) the depreciation expense or (b) depreciation parameters were approved by the BCUC.

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4.11 Please outline the rationale and process for decision-making for all capital additions that have occurred since the 2008 proceeding, given KMJF’s assertion that the pipeline is to be abandoned imminently.

Reference (iv): 2007 Application, Exhibit B-1, Schedule 7, pdf pp. 64-65

In Schedule 7 of its application, KMJF sets out 2008 Forecast Plant in Service amounts, including as follows:

4.12 Please compare forecast additions, retirements and transfers for 2008, as provided in Schedule 7, to actuals and fully explain any variances.

4.13 Regarding References (iii) and (iv) above, as the last application for tolls was based on Plant in Service at year ending December 1, 2007, please extend the table referred to in Reference (iii) to reconcile it with the actual FA Opening Balance of $16,374,646.22, set out in the tables referred to in Reference (iv), by asset class. Please include in this amended table details by asset class for plant and reserve data (additions, adjustments, retirements, and plant balance at end of year) as well as reserve activity (retirements, depreciation expense, gross salvage, cost of removal, adjustments, transfers and reclassifications and reserve balance at end of year) for each year since 2007.

5.0 Depreciation Rates Reference (i): Ex. B-8, KMJF Application, Appendix A, Schedule 3, Table 5, pdf p. 40

Reference (ii): 2007 Application, Schedule 3, p. 4, pdf p. 56 Reference (iii): 2007 Application, Schedule 7, pp. 12-13, pdf pp. 64-65 The following table compares the depreciation rates from KMJF’s current application (column 1, taken from Reference (i) above) to the 2006 and 2008 depreciation rates from KMJF’s 2007 Application (columns 2 and 3, taken from References (ii) and (iii) above).

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VAFFC is seeking additional information to understand KMJF’s depreciation rate changes since its 2007 Application. 5.1 Please explain all depreciation rate changes by asset class. 5.2 Please confirm that the BCUC has not approved or directed any changes to KMJF’s depreciation

rates since its 2007 Application. If not confirmed, please fully explain your response. 5.3 Please provide a calculation of depreciation expense for forecast 2019 based on the last BCUC-

approved depreciation rates. 5.4 Please provide the depreciation study supporting the depreciation rates per December 31, 2018.

5.5 Please provide aged account balances, by vintage, for each class of asset listed above. In your

response, please include the original investment and plant since retired, by vintage and year.

6.0 Jet Fuel System Supply and Demand

Reference (i): Exhibit B-8, KMJF Application, para. 16, p. 10, Table 2

On p. 10, KMJF provides the following table:

Dep. Rate 12/31/2018

Dep. Rate 31/Dec/2006

Dep. Rate 31/Dec/2008

(5 yr. economic life)

152 Land Rights 1.77% 1.84% 5.20%153 Line Pipe 4.86% 1.96% 13.67%156 Buildings 4.00% 2.58% 11.96%158 Pumping Equipment 4.60% 3.43% 14.16%159 Station Lines 4.24% 2.94% 12.58%160 Other Station Equipment 5.73% 1.31% 16.21%

160C Central Pipeline Control 0.00% 10.00% 0.96%161 Storage Tanks 4.90% 1.13% 13.48%163 Communications 10.00% 10.00% 15.12%

185WE Work Equipment 20.00% 20.00% 4.97%186HW Computer Hardware 20.00% 20.00% 0.00%186SW Computer Software 20.00% 15.60% 0.00%

189D AFUDC (Interest) 3.23% 3.80% 10.36%189E AFUDC (Equity) 3.39% 3.80% 10.78%

190 Construction Overhead 4.01% 3.65% 12.45%Cost of Removal 7.69% - 20.00%

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Reference (ii): Exhibit B-8, KMJF Application, para. 21, p. 13

On p. 13, KMJF states:

KMJF expects that once the VAFD project enters service, the Jet Fuel System will no longer receive jet fuel from the Westridge Marine Terminal. No new sources of supply are expected to be available to replace volumes received from the Westridge Marine Terminal. As a result, KMJF expects a permanent decrease of about 60% of annual throughput volumes on the Jet Fuel System once the VAFD project commences operations.

VAFFC seeks additional information on KMJF’s assumptions about the demand for jet fuel and available supply from replacement sources.

6.1 Please provide forecast and historical volumes for the Parkland Refinery and the Shell Rail Facility for the last 10 years and the future 5 years.

6.2 Please provide copies of any communications with suppliers of jet fuel to the Jet Fuel System, including the Parkland Refinery and the Shell Rail Facility, regarding future supply of jet fuel for throughput on the Jet Fuel System.

6.3 Please confirm that KMJF’s list of shippers (i.e., Air Canada, Parkland, and Shell) means there are no possible new shippers. If confirmed, please explain why there are no possible new shippers. If not confirmed, please identify whether:

(a) KMJF has had discussions with other potential shippers in the past 24 months, and

(b) Whether potential shippers originate in any or all of BC, Alberta, Washington, or other US markets. If other US markets, please indicate which.

6.4 Does the Trans Mountain pipeline supply jet fuel to the KMJF system, directly or indirectly? Please fully explain your response.

6.5 Will an expanded Trans Mountain pipeline offer additional jet fuel supply sources to YVR jet fuel consumers? Why or why not? Please fully explain your response.

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6.6 Does KMJF expect the VAFD project to deliver 100% of jet fuel consumed at YVR after the VAFD project begins operations? If yes, why? If not, why not? Please fully explain your response.

6.7 Please provide any data or information KMJF has about the potential suppliers that will deliver jet fuel to the VAFD project.

6.8 Please describe all current sources of jet fuel supply for shippers at YVR that KMJF is aware of, including relative proportions that KMJF is aware of, whether specifically or generally.

6.9 Please provide all information KMJF has regarding past, present and forecast jet fuel demand at YVR airport (i.e., all jet fuel demand, not including just from the Jet Fuel System).

6.10 Please confirm that neither VAFFC nor its member shippers have communicated to KMJF that it would no longer receive jet fuel at the Westridge Marine Terminal, or cease use of the Jet Fuel System to ship said jet fuel, after completion of the VAFD project.

6.11 Discuss exactly why KMJF believes that as soon as the VAFFC project begins operations, the Jet Fuel System will immediately no longer receive jet fuel from the Westridge Marine Terminal.

7.0 KMJF’s Knowledge of the VAFD Project

Reference (i): Exhibit B-8, KMJF Application, paras. 20-24, pp. 13-14

At para. 20, KMJF states that “Construction of the VAFD project is underway, and VAFFC states that the full project is expected to commence operations by late 2021”. Footnote 14 refers to the VAFD Project Website as of June 6, 2019. At paras. 22-23, KMJF states:

Footnote 16 refers to the VAFD Project Website as of June 5, 2019.

VAFFC is seeking clarification on when KMJF acquired certain information about the VAFD project and the nature of the information itself, in order to better understand how that information was accounted for in its application.

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7.1 On what date did KMJF first learn of the VAFD project?

7.2 Please provide copies of any KMJF communications previously filed with the BCUC, studies, reports, or working papers during or after 2007 pertaining to abandonment cost collection, accelerated depreciation, and/or the assessment of when the VAFD project will commence operations and the implications of the VAFD project for KMJF.

7.3 Please confirm KMJF did not undertake any independent investigations into the completion date for the VAFD project beyond the VAFD project webpage screenshot relied on. If not confirmed, pleased fully explain your response.

7.4 On what date did KMJF become aware of the VAFD project webpage referred to in footnote 14 of para. 21?

Reference (ii): Exhibit B-8, KMJF Application, paras. 21, 24-26, pp. 13-15

At para. 25, KMJF refers to various statements from a 2017 Business in Vancouver article:

Adrian Pollard, VAFFC’s spokesman, was quoted as saying in an article in BIV, dated June 20, 2017, that the KMJF Jet Fuel System at that point will no longer be economical to maintain:

“The airlines are the end customer,” Pollard said. “They’re financing this project; naturally they’re going to use it. And the capacity on that existing [Jet Fuel System] will decline to such a point where it’s not really economical to maintain it.”

[Emphasis in Application]

7.5 Please confirm that KMJF became aware of this article on or about the date when it was published. If not, why not?

7.6 Please provide copies of any reports, studies or investigations conducted on the economic viability of the Jet Fuel System that were conducted in relation to the development of the VAFD project.

Reference (iii): Reasons for Decision and Order P-3-08 TMJF ~ Approval of Tolls and Accelerated Depreciation & Reasons for Decision, Appendix A, Accelerated Depreciation, Section 5.2; Actions of the VAFFC, pdf p. 12

On pdf p. 12, the BCUC stated:

The Commission accepts the VAFFC statement that when the Fraser River site became available for sale it took the opportunity to buy the property located at 15040 Williams Road, Richmond to keep its options open for future planning. Given that VAFFC states that it has not determined a final option, the Commission is not persuaded that the VAFFC has made a firm and final decision to proceed with the Barging option.

In the 2007 Application, the BCUC rejected KMJF’s request for accelerated depreciation on the basis that it was premature, because there was not yet evidence KMJF had made a “firm and final decision to proceed” with development of the VAFD project.

Reference (iv): Exhibit B-8, KMJF Application, Appendix B, pdf p. 61 In Appendix B, KMJF sets out the history of the VAFD project’s permitting process. KMJF states:

On April 3, 2017, the BCOGC issued VAFFC a permit, pursuant to section 25(1) of the Oil and Gas Activities Act, authorizing VAFFC to construct and operate the Project (the “Pipeline Permit”), subject to the conditions set out therein. A copy of the Pipeline Permit is attached hereto as Attachment A.

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On December 11, 2013, the Government of BC issued Environmental Assessment Certificate #E13-02 for the VAFD Project (the “2013 EA Certificate”), a copy of which is attached hereto as Attachment B. The accompanying reasons for decision are attached hereto as Attachment C. On January 18, 2017, the Government of BC issued an amendment to the 2013 EA Certificate authorizing an increase in the delivery pipeline diameter and to revise the location of the delivery pipeline, a copy of which is attached hereto as Attachment D.

Reference (v): Reasons for Decision and Order P-7-08, TMJF ~ Reconsideration of an Application for Approval of Tolls and Accelerated Depreciation ~ Reasons for Decision, p. 4

In its reasons for Decision for the reconsideration of the 2007 application, the BCUC stated as follows:

In the fullness of time, if [KMJF] is persuaded that the fuel supply options for the Vancouver airport have sufficiently matured and that shippers on the pipeline have made even tentative decisions to abandon service on the pipeline, then a further application to the Commission would be justified.

7.7 Please explain why KMJF did not apply for accelerated depreciation in 2013, or earlier.

8.0 2007 Evidence of Mr. Innis

Reference (i): 2007 Application, Exhibit C1-4, p. 2

This filing from the 2007 application set out the evidence of Robert C. Innis and Hugh W. Johnson. Mr. Innis was, at the time, the Manager of the Chevron refinery. Mr. Innis’ evidence included as follows, at p. 2 of Exhibit C1-4:

Q9. Please summarise [sic] the TMJ contentions that you dispute.

A. First, in its response to BCUC IR 1.11.2, TMJ contends that Chevron could shutdown production of jet fuel at the Burnaby refinery. TMJ also states in its response to Chevron IR 1.8.4. that it has assumed the Burnaby refinery could cease to produce jet fuel, though it has not evaluated whether Chevron could continue to operate without jet fuel or whether it would have to shut down. I do not agree that Chevron’s Burnaby refinery could cease to produce jet fuel and continue to operate as a refinery. Second, at section 3.3, page 11 of the Filing in Support of Application and in its responses to BCUC IR 1.11.1 and Chevron IRs 1.8.1 and 1.8.2, TMJ contends that Vancouver Airport Fuel Facilities Corporation (“VAFFC”) could continue to access jet fuel from the Burnaby refinery by barge (either via Chevron’s own dock or via the Westridge dock), thus preserving this existing supply source so long as the Burnaby refinery continues to produce jet fuel. I have no basis for believing that shipping jet fuel from the Burnaby refinery by either dock is a realistic option, given our current facilities.

8.1 Please confirm that the refinery referred to in Mr. Innis’ evidence is, today, the Parkland Refinery.

8.2 Please confirm that KMJF has no reason to believe that Mr. Innis’ evidence is no longer applicable, with respect to both the necessity of the Parkland Refinery’s production of jet fuel and the inability to ship jet fuel from the Parkland Refinery via barge given the dock facilities. If not confirmed, please fully explain why, including with reference to any changes to the dock or barge services available to Parkland that would allow for alternative jet fuel market access.

8.3 Is it KMJF’s understanding that cessation of service of the Jet Fuel System would require the Parkland Refinery to close? If no, please indicate why not. Please fully explain and support your response.

8.4 Please provide a description of all due diligence activities undertaken by KMJF in respect of the ability of the Parkland Refinery to reduce or eliminate production of jet fuel, or to secure viable alternative markets.

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8.5 Please confirm that KMJF does not have any reason to believe that the Parkland Refinery will cease operating in the foreseeable future. If not confirmed, please fully explain why not.

8.6 Please describe any discussions between KMJF and the Parkland Refinery owners regarding the critical nature of the KMJF pipeline to the refinery, including any alternative plans between the parties to address jet fuel that is produced at the refineries but remains “bottled up” without transportation options.

8.7 Please describe all due diligence and findings collected by KMJF on the impacts of any future shut down for the Parkland Refinery and related businesses and workers.

Reference (ii): 2007 Application, Exhibit C1-4, p. 4

At p. 4 of Exhibit C1-4, Mr. Innis is asked “If Chevron were the only shipper on the TMJ pipeline and tolls increased substantially in consequence, would you consider shipping jet fuel to YVR by barge across the Chevron dock?” His response was that “We would consider it but I would not expect it to be economical”.

8.8 How much dock export capacity has Chevron acquired, if any, since 2007? In your response, include any information KMJF has on whether Chevron has recently considered shipping jet fuel to YVR by barge across the Chevron dock.

9.0 Economic Life of the Jet Fuel System

Reference (i): Exhibit B-8, KMJF Application, paras. 24-27, p. 15

In para. 24, KMJF states that “Once the VAFD project is operational, the Jet Fuel System will become uneconomical to maintain and operate.” In para. 27, KMJF continues as follows:

Once the VAFD project enters service, the remaining shippers from the Parkland refinery and Shell rail facility, that currently represent about 40 percent of total volumes, would have to pay 100 percent of the Jet Fuel System revenue requirement. KMJF expects that, as a result, the Jet Fuel System will become economically unviable once the VAFD project commences operations and bypasses the Jet Fuel System.

Reference (ii): 2007 Application, Exhibit B-1, p. 3, pdf p. 11

On p. 3, KMJF states: “KMC has been unable to generate interest among potential buyers of the Jet Fuel System.”

Reference (iii): Rachel Adams-Heard, “Kinder Weighs Full Exit From Canada After Trans Mountain Debacle” (5 September 2018), online: Bloomberg LP (Attached as Appendix A)

On September 5, 2018, Bloomberg reported that Kinder Morgan was exploring the sale of its remaining Canadian assets, including the Jet Fuel pipeline system:

“Kinder Morgan Inc. hinted at a potential offloading of its remaining Canadian assets following the sale of the contentious Trans Mountain pipeline expansion to the federal government.

Speaking at an energy conference Wednesday, Kinder Morgan Chief Executive Officer Steve Kean said that while its Canadian affiliate has “attractive assets” and “no debt on the balance sheet,” the company’s primary objective was to use those projects to support the Trans Mountain expansion.

“It’s a set of midstream assets in what we think is an attractive seller’s market for those assets,” he said. “We are going to explore that over the coming months.”

In addition to the Canadian portion of the Cochin pipeline system and the Jet Fuel pipeline system, Kinder Morgan Canada Ltd. has a network of crude storage and rail terminals in Edmonton, Alberta, and the Vancouver Wharves Terminal in British Columbia.

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“We can always say no, because the assets themselves will stand on their own,” Kean said.”

VAFFC is seeking clarification of what KMJF means by the terms “economically unviable” and “uneconomical”, and how these terms relate to KMJF’s discussion regarding the economic life of the pipeline.

9.1 Please confirm that KMJF uses the terms “uneconomical” and “economically unviable” interchangeably in the application. If not confirmed, please fully explain your response.

9.2 Please provide KMJF’s definition of “uneconomical” and “economically unviable”, as it uses those terms in the application. If not confirmed, please fully explain your response.

9.3 On what basis will the Jet Fuel System become uneconomical as a result of the loss of the VAFFC volumes? Please fully explain your response and include a discussion of alternative markets and/or transportation options for the Parkland Refinery and Shell Rail jet fuel volumes.

9.4 Please confirm that the forecast loss of VAFFC volumes is the only reason why KMJF believes that the Jet Fuel System will become uneconomical at the end of 2021. If not, explain why not.

9.5 Please provide all economics-related studies or analysis undertaken by KMJF to conclude that the Jet Fuel System will become “economically unviable”.

9.6 Please describe all business-related activities and analysis KMJF has undertaken regarding future economic use of the Jet Fuel System, including any potential for the Jet Fuel System’s sale, repurpose or salvage. Please provide all financial analysis undertaken and potential impacts of the above opportunities.

9.7 Please describe all long-term planning conducted by KMJF (including dates) to meet YVR fuel requirements through 2030 as an alternative to any VAFFC delivery system (or other delivery services). Please indicate why such plans were not pursued.

9.8 Please provide a schedule that sets out annual revenue requirements if the current pipeline operations were extended to five years, as opposed to the three currently forecast in KMJF’s application. In this schedule, please identify or otherwise explain in detail how the proposed depreciation expense and abandonment cost collection, along with any other material changes to KMJF’s application that would result, would be affected by such an amendment.

9.9 Please confirm that, upon the VAFD project entering service, respectively:

(a) Residual volumes would still be shipped on the KMJF Jet Fuel System related to VAFFC member purchases;

(b) There may be potential Parkland Refinery margin reductions for its jet fuel to reflect that the product must be produced and may have no viable alternative market demand to VAFFC; and,

(c) There may be write-downs of KMJF capital, with KMJF continuing to operate the pipeline at reduced volumes.

Whether confirmed or not confirmed, please fully explain your response and provide all relevant details and supporting documents.

9.10 Has KMJF discussed the possibility of a take-or-pay contract with Chevron to use the Jet Fuel System? If not, why not? If yes, please provide the status of those discussions.

9.11 Is Kinder Morgan Canada Ltd.. or KMJF still actively seeking to sell the Jet Fuel System? If yes, what is the status of that process?

9.12 Has Kinder Morgan Canada Ltd. or KMJF considered selling the pipeline in parts? If not, why not? If yes, what is the status of that process?

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9.13 Please confirm that KMJF could offer service to shippers such as the Parkland Refinery at a lower tariff in the event KMJF elects or is directed to take a substantial write-down on the Jet Fuel System asset base.

Reference (ii): Exhibit B-8, KMJF Application, p. 19

KMJF states in its application that:

KMJF considers its proposed depreciation rates reasonable and fair as it ensures that Parkland, Shell, and Air Canada, together with VAFFC, equitably share the costs of the utilization of the pipeline prior to it becoming underutilized and economically unviable. This is particularly fair, given that VAFFC is the entity with sole control of whether the KMJF Jet Fuel Line becomes significantly underutilized as a result of the bypass VAFD project.

9.14 Please discuss in detail why KMJF believes that VAFFC is “the entity with sole control” of the Jet Fuel System’s utilization.

10.0 Historic Throughput

Reference: Exhibit B-8, KMJF Application, Schedule 20, pdf p. 59

At p. 59 of the application, KMJF sets out the following information:

10.1 Please provide actual annual throughput volumes for 2008 – 2014.

10.2 Please reconcile past throughput forecasts submitted to the BCUC with actual throughput volumes for those same years, starting with the 2008 year.

10.3 Please comment on variances between forecast and actual annual throughput levels, including the impact on actual revenues collected as compared to forecast.

11.0 Accelerated Depreciation

Reference: Exhibit B-8, KMJF Application, paras. 33-35, pp. 18-19

KMJF states as follows at paras. 33 through 35:

As discussed above, KMJF expects that once the VAFD project commences operations, the Jet Fuel System will become economically unviable. For this reason, the expected economic life of the pipeline is forecast to be three years from January 1, 2019, based on an expectation that the VAFD project will commence operations by late 2021.

Depreciation expense is forecast by multiplying the plant account balances by the appropriate depreciation rate. A separate depreciation rate is applied for each plant account or group of similar

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assets. The depreciation rates are based on an updated depreciation study that establishes deprecation rates effective January 1, 2019.

KMJF’s existing deprecation rates have been in effect since January 1, 2010. The 2019 Depreciation Study (Schedule 5 of the 2019 Cost of Service Study) presented below calculates revised depreciation rates as of January 1, 2019 based upon a three-year remaining depreciable life:

VAFFC is seeking clarification on why KMJF believes that a shorter economic life of the Jet Fuel System should justify accelerated depreciation starting now.

11.1 Please explain why the end of the pipeline’s economic life would justify accelerated depreciation and provide copies of any authorities relied upon, with pinpoint citation to relevant passages. For any authorities that are included, please indicate whether they relate to common carriers, public utilities, or unregulated markets.

11.2 Please confirm that KMJF shareholders bear the risk of system underutilization caused by market competition and/or bypass? If not confirmed, please fully explain your response.

11.3 Please provide specific pinpoint references for any previous regulatory decision in BC or elsewhere that applies a 3 year (or comparable) depreciation to all assets of a regulated service provider. For any decisions that are included, please indicate whether they relate to common carriers, public utilities, or unregulated markets.

12.0 Jet Fuel System — History of Depreciation and Studies

Reference (i): Exhibit B-8, KMJF Application, para. 35, p. 19

At p. 19, KMJF states as follows:

KMJF’s existing deprecation rates have been in effect since January 1, 2010. The 2019 Depreciation Study (Schedule 5 of the 2019 Cost of Service Study) presented below calculates revised depreciation rates as of January 1, 2019 based upon a three-year remaining depreciable life:

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VAFFC is seeking further information about how the depreciation of these assets has been considered, and any previous work products or information pertaining to the issue of accelerated depreciation.

12.1 Please confirm the accounting standard applied by KMJF and cite the specific provisions that address the estimates of each asset’s remaining economic life. Please include copies of all relevant underlying documents.

12.2 Please confirm that GAAP requires depreciating assets in a manner consistent with an estimate of an asset’s remaining economic life. If not confirmed, please fully explain why.

12.3 Please provide copies of all depreciation studies, and their supporting working papers, that have been conducted for the Jet Fuel System since 2006.

12.4 Please provide copies of any studies, reports or other material communications pertaining to the economic life of the Jet Fuel System, along with any working papers that may have been prepared with respect to that issue.

12.5 Please provide copies of all of KMJF’s internal accounting reports, audits, assessments or reports pertaining to assessment of the value of the Jet Fuel System assets and their depreciation, including any explanatory notes or working papers pertaining to that assessment.

12.6 Please identify and discuss any issues raised by KMJF auditors since 2009 in relation to KMJF gross plant or depreciation values and parameters in light of KMJF’s statements regarding possible abandonment. Specifically, please fully explain whether KMJF auditors have raised concerns regarding any of the following during that period:

(a) Potential need for write-downs;

(b) Accelerated depreciation; or

(c) Recognition of any Asset Retirement Obligation, including enhanced liabilities due to potential abandonment.

Please include copies of any relevant documents or correspondence in your response.

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12.7 Please provide supporting detail and explanation for the calculation of the 33.33% depreciation rate in Column I for the Cost of Removal line item.

12.8 Please provide supporting data for the calculation of Cost of Removal of $49,516.56 expense by asset class, and fully explain how Cost of Removal differs from the 3 year abandonment costs also included in revenue requirement.

12.9 Please provide aged surviving investments and aged retirements for each account.

12.10 Please provide the remaining life by asset class from the 2010 Depreciation Study filed as Appendix A with the BCUC as part of the filing for the 2010-2018 tariff, and compare this information to the forecast remaining life set out in the 2019 depreciation study. Please explain any variances where remaining life hasn’t decreased by the previously approximated sequential amount over the intervening years.

Reference (ii): Kinder Morgan Canada Limited Management’s Discussion and Analysis For the Three and Nine Months Ended September 30, 2017 and 2016 Security Filing, page 18; Accounting Policies, Judgments and Estimates (Attached as Appendix B)

In this securities filing, attached as Appendix B to these information requests, at page 18, KMJF’s parent entity Kinder Morgan Canada Limited stated that “In addition, DD&A [(depreciation, depletion and amortization)] expense is higher due to depreciation true-up adjustments applied to the Jet Fuel facility and Edmonton Rail Terminals”.

12.11 Please document and explain the depreciation true-up adjustments mentioned.

Reference (iii): TransCanada PipeLines Limited, 2004 Mainline Tolls and Tariff Application, RH-2-2004 Phase II, Reasons for Decision at p. 46 and TransCanada PipeLines Ltd., NOVA Gas Transmission Ltd. And Foothills Pipe Lines Ltd., 2012 and 2013 Final Tolls, RH-003-2011, Reasons for Decision at p. 44

The NEB has stated as follows in these two decisions (emphasis added):

RH-2-2004 Phase II Decision: The second aspect of depreciation-related risk is that the depreciation rates in use may not actually reflect the estimates of economic life that would be selected if assessed at that point in time. A company can mitigate the risk that the estimates in use are not current by bringing forward an application to reconsider its depreciation rates. The part of this risk that is mitigable should not be compensated through the cost of capital. Should it become apparent that depreciation rates do not adequately reflect current estimates of economic life, it is incumbent on the management of the company to seek to change depreciation rates, not to expect incremental compensation through the cost of capital.

RH-003-2011 Reasons for Decision: Further, we note that the concept of “expected return” indicates that the return is not a guaranteed return. It is a return to be earned if, among other things, depreciation rates correspond to the economic useful life of the regulated asset. TransCanada has been compensated for the risk that its best estimate of depreciation rates may end up being different than forecast – which is what a cost disallowance, upon a materialization of fundamental risk, could constitute. As a result, and as explained in the RH-2-2004 Phase II Decision, it is incumbent on TransCanada’s management to seek changes to depreciation rates if it becomes apparent that depreciation rates do not adequately reflect current estimates of economic life.

Reference (iv): Reasons for Decision and Order G-119-16 FortisBC Energy Inc. Proposal for Depreciation and Net Salvage Rate Changes ~ Project No. 3698871, pp. 6-7

The BCUC stated in the above decision (emphasis added):

The Panel acknowledges the following based on review of the information contained in the Application and in IR responses:

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there is an ongoing need to adjust depreciation rates to reflect adjustments to the estimated service lives of FEI’s assets which may range from less than one year to over 100 years;

…

With respect to BCOAPO’s statement that FEI’s proposed depreciation and net salvage rate changes should not be implemented until after the PBR term in 2019, the Panel disagrees. Changes to depreciation and net salvage rates are treated as flow-through items under the PBR and thus have no impact on FEI’s formula-driven expenditures or on the annual earnings sharing mechanism. Further, deferring the adjustment of rates until a later date would cause FEI to continue to use depreciation and net salvage rates which do not reflect its current circumstances. Accordingly, FEI’s proposed depreciation and net salvage rate changes, which result in a reduction to the composite deprecation rate from 3.19 percent to 3.06 percent and an increase to the composite net salvage rate from 0.44 percent to 0.64 percent, are approved, effective January 1, 2017.

Reference (v): 2007 Application, Exhibit B-1, Appendix F, p. III-2, pdf p. 110

As a qualification of its depreciation study in the 2007 application, KMJF stated as follows (emphasis added):

The calculation of the annual depreciation expense and depreciation rates is the principal results of the study. In the circumstances of the short remaining economic life it is imperative that annual surveillance and revisions are made in order to ensure that the service value of the pipeline is recovered over the economic life of the jet fuel pipeline. In future years, if it becomes known that the remaining economic life changes or the estimated costs of retirement become better known, the annual depreciation rate should be updated. Deferral of the update may cause large fluctuations in the annual depreciation expense and resultant toll. Additionally the depreciation rates have been developed assuming there will be no capital investment or retirement activity over the remaining economic life. The depreciation rates should also be adjusted in the circumstances where plant is added or retired over the remaining life of the pipeline.

Reference (vi): 2007 Application, Exhibit B-4, p. 2

As part of the summary of its submissions in this letter, KMJF stated as follows (emphasis added):

The Commission unquestionably has jurisdiction over establishing tolls, setting the depreciation rate underlying the tolls, and providing for the recovery of net negative salvage. [KMJF] is not asking the Commission to prejudge abandonment. Rather, the depreciation rate should be set based on the best available information regarding economic life of the assets, always recognizing that the economic life may change due to unforeseen circumstances and the depreciation rate is always subject to revision. It would not be sound policy to require [KMJF] to first commit to close the pipeline five years hence in order to obtain the relief sought in this Application.

12.12 Did KMJF consider seeking changes to depreciation rates when it became apparent that its depreciation rates did not adequately reflect current estimates of economic life? If not, why not?

12.13 Regarding References (v-vi) above, please confirm that KMJF still holds these views. If not, please fully explain your response.

Reference (vii): Exhibit B-8, KMJF Application, pdf pp. 39-41

At pdf pp. 39-41 of the KMJF application KMJF provides its schedule 3, “2018 Plant in Service”, as shown in the following images:

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12.14 Please confirm that Work In Progress (WIP) of $21,056.29 relates exclusively to the valve relocation and tie-in project explained on page 20 of the application. If not, please explain what project(s) the Work In Progress relates to.

12.15 Please provide the calculation for depreciation expense (total and regulated) where it is not equal to Total Plant Balance multiplied by the Depreciation Rate.

12.16 Please confirm that all disallowed plant is a result of the 1993 Commission decision to disallow costs of the jet fuel clay treatment system above $811,921.

(a) Please provide the Commission decision that is referenced in footnote 1 on pdf p. 41.

(b) If Information Request 12.16 is not confirmed, please provide a detailed history of the disallowed plant by asset class as shown in part D of Schedule 3 including reference to relevant BCUC orders and decisions and BCUC rationale for disallowing, as applicable.

12.17 Regarding References (i) and (vii) above, please explain and reconcile the differences in depreciation rates between the above mentioned schedules, including for Accounts 153 (Line Pipe), Account 160 (Other Station Equipment), Account 163 (Communications), and Account 185WE (Work Equipment).

Reference (viii): Exhibit B-8, KMJF Application, p. 17

KMJF provides the following Table 3 at page 17 of its application:

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12.18 Regarding References (vii) and (viii), please confirm that the Plant Depreciation and Amortization from Reference (viii) includes the Regulated Depreciation Expense from Reference (vii), as opposed to the Total Depreciation Expense plus the proposed three year abandonment recovery. If not confirmed, please explain why disallowed depreciation expense is included in applied-for revenue requirement.

13.0 Wetmore Cost of Service Study

Reference: Exhibit B-8, KMJF Application, para. 28

KMJF refers to the Wetmore Cost of Service Study at para. 28 of the application in the following way:

KMJF retained Erik Wetmore of Turner Wetmore Collins, LLC as an independent expert19 to conduct a cost of service study regarding KMJF’s annual costs, including a reasonable return on and of its investment, for providing fuel transportation services on the Jet Fuel System for the period from January 1, 2019 to December 31, 2019 (the “Wetmore 2019 Cost of Service Study” or “2019 Cost of Service Study”). The Wetmore 2019 Cost of Service Study is included as Appendix A to this application.

13.1 Please provide full copies of the following documents:

(a) Mr. Wetmore’s CV;

(b) Any written instructions or direction given to Mr. Wetmore (to the extent such directions or instruction was given or supplemented by verbal communications, please describe those verbal communications);

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(c) Materials Mr. Wetmore was provided with to review;

(d) Mr. Wetmore’s working papers; and,

(e) Full report outputs.

13.2 Please fully describe the basis for KMJF’s statement that it is entitled to a “reasonable return on and of its investment” with specific pinpoint references to the legislation, regulations and previous regulatory decisions in BC or elsewhere that KMJF relies on with respect to common carriers.

13.3 Did KMJF recover its investment during the 2008-2018 period? If not, why not? Please fully explain and support your response.

14.0 Capital Projects

Reference: Exhibit B-8, KMJF Application, para. 38, p. 20

KMFJ states the following about forecast capital additional additions for 2019:

The $0.7 million in 2019 forecast plant additions relates to a valve relocation and tie-in project. The relocation project is required to remove an existing above-ground valve to accommodate the construction of a new roadway adjacent to the new International Trade Center building. The project will include preparing the site for the construction of a new valve vault, completing pipeline fabrication at the tie-in points, hydrotesting, recoating and backfilling portions of the line, and rebuilding a separate upstream valve in-situ.

VAFFC is seeking additional information about capital projects.

14.1 Please provide the business case for this capital project, including all alternatives considered.

14.2 Please confirm this $0.7 million expenditure differs from the $680,000 listed in Table 9 of the application as a 2019 forecast cost for ILI Digs. If not confirmed, please explain why this expenditure is double-counted.

14.3 How much is the overall cost of the valve relocation?

(a) Is the requesting party contributing to this project? If yes, how much? If not, why not?

(b) Please elaborate on why the valve relocation is “required”, including by providing copies of any lawful orders, laws, rules, regulations, or communications with government on the issue.

15.0 Cost of Capital Debt

Reference (i): Exhibit B-8, KMJF Application, para. 39, p. 21 In support of its return on rate base, KMJF provides the following information:

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Reference (ii): FortisBC Energy Inc. – Annual Review for 2019 Delivery Rates – Project No. 1598966,

Exhibit B-2-1, Section 11, Schedule 26-27 at pdf p. 37 In its annual review for 2019 delivery rates, Fortis BC Energy Inc. provided the following information about its 2019 average embedded cost of long-term debt (5.18%) and short-term debt (3.10%):

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Reference (iii): Alberta Utilities Commission Decision 22570-D01-2018, 2018 Generic Cost of Capital, para. 822, p. 167 At para. 822, the Alberta Utilities Commission recognized AltaGas’ going-in-debt costs for the 2018-2022 PBR term reflected an average embedded rate of 4.46%:

Reference (iv): Alberta Utilities Commission Decision 23894-D01-2018, ATCO Gas and Pipelines Ltd. –

2019 Annual Performance-Based Regulation Rate Adjustment Filing, paras. 39 and 43-45 at pp. 8-9

On p. 8, the Alberta Utilities Commission identified ATCO Gas’ 2019 weighted average cost of debt of 5.115%:

On p. 9, the Alberta Utilities Commission approved ATCO Gas’s 2019 K-bar, including its 2019 weighted average cost of debt.

Reference (v): Trans-Northern Pipelines Application for 2019 Tolls, Schedule 8(e), pdf p. 16 and National Energy Board Order TO-002-2019 On p. 16, Trans-Northern Pipelines Inc. applied for approval of its final tolls for 2019, which included its cost of debt of 3.25%.

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In Order TO-002-2019, the National Energy Board approved Trans-Northern Pipelines Inc.’s applied-for tolls.

15.1 Please confirm that the entities listed above in References (ii) to (v), i.e., FEI, AltaGas, ATCO Gas, and Trans-Northern Pipelines, are appropriate comparators to KMJF. If not confirmed, please (1) fully explain why not; (2) identify the entities that KMJF believes to be its comparators; and (3) provide the cost of debt used by the comparators KMJF identifies in (2).

15.2 Please confirm that Trans-Northern Pipelines’ pipeline is the only other pipeline from the References (ii) to (v) above that is both small diameter and transports refined products.

15.3 Please fully explain the methodology KMJF used to calculate the cost of debt.

Reference (vi): ATCO Electric Limited v. Alberta (Energy and Utilities Board), 2004 ABCA 215 at paras. 171-172

At paras. 171-172 of this decision, the Alberta Court of Appeal discussed the “stand-alone principle” in the following way:

[171] The Board used the stand-alone principle as a critical element in its assessment of carrying costs on the deferral accounts of a number of utilities before it in Decision 2001-92, one of which was ATCO. The purpose of the stand-alone principle is to notionally isolate and categorize – for accounting and rate-making purposes – the costs incurred in the operation of a discrete business function of a utility. The Board distinguished between two recognized applications of the stand-alone principle. First, the principle could be used to allocate costs as between regulated and non-regulated activities of an integrated utility, the theory being that customers should pay only for the costs of the utility’s providing the regulated service, not the costs of other non-regulated activities. Hence the need to isolate the utility’s costs associated only with the regulated service. However, the Board concluded that this application of the stand-alone principle, frequently relied on in utility regulation, was not relevant to the task before the Board.

[172] What was relevant in the Board’s view though was the second accepted application of the stand-alone principle. This application involves allocating costs incurred by an integrated utility amongst its various business functions – for instance, the costs incurred in administering deferral accounts – so that just and reasonable rates might be set for each business function. In using this principle to determine a utility’s costs of financing the administration of deferral accounts, the Board essentially had three options open to it.

15.4 Please confirm KMJF’s understanding of the stand-alone principle, and confirm that the principle may be applied by a regulator in the regulation of a common carrier’s rates. If not confirmed, please fully explain your response.

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16.0 Abandonment and Decommissioning Costs

Reference (i): Exhibit B-8, KMJF Application, paras. 48-49, p. 27 On p. 27, KMJF states:

48. As discussed above, KMJF expects that once the VAFD project commences operations, the Jet Fuel Line will become economically unviable. For this reason, the expected economic life of the pipeline is forecast to be three years from January 1, 2019, based on an expectation that the bypass VAFD project will commence operations by late 2021. 49. For this reason, KMJF is proposing a toll surcharge collection mechanism to recover total estimate abandonment costs over the remaining three-year economic life of the Jet Fuel System.

Reference (ii): James C. Bonbright. Principles of Public Utility Rates. 1st ed. (New York: Columbia University Press, 1961) at p. 291

On p. 291, Bonbright identifies as criteria of a desirable rate structure: 6. Fairness of the specific rates in the apportionment of total costs of service among the different consumers 7. Avoidance of “undue discrimination” in rate relationships.

VAFFC requires more information to assess KMJF’s proposal to recover abandonment and decommissioning costs.

16.1 Please confirm that KMJF was aware of the risk of bypass by the VAFD project in 2007.

16.2 Please confirm that KMJF’s shareholder assumed the cost of abandoning and decommissioning in past years. If not confirmed, please fully explain your response.

16.3 Please provide all cost of abandonment and decommissioning estimates previously filed with the BCUC.

16.4 Did KMJF’s shareholder allocate any revenues during the past 10 years towards pipeline abandonment costs? If not, why not? If yes, please discuss the balance of those allocated funds to date and provide details, including when the allocation for abandonment costs was first established.

16.5 Please identify any pipe fill volume, ownership and potential revenue that may be generated towards reclamation costs.

16.6 Please explain how recovering all of the costs of abandonment and decommissioning over three

years is consistent with the Bonbright principles of fairness and avoiding undue discrimination (cited above in Reference (ii)) and the corollary principle of intergenerational equity.

17.0 Abandonment and Decommissioning Costs

Reference: Exhibit B-8, KMJF Application, Table 10, p. 28 In the footnotes below Table 10, KMJF states:

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VAFFC requires more information about KMJF’s proposal to recover abandonment and decommissioning costs. 17.1 Please provide the documents relied on for KMJF’s statement in footnote 1 regarding the 2.00%

escalation factor being “consistent with the Bank of Canada[‘s] continuing policy of actively adjusting its policy interest rate …”

17.2 Please provide the decisions and/or documents relied on for KMJF’s statement in footnote 2

regarding the return on funds collected being “consistent with prior National Energy Board discussion”, including the decisions and/or documents underlying the examples that KMJF provides. In your response, please include all decisions from the last 12 months in which the National Energy Board has used a 3.5% return on funds collected in abandonment cost calculations, with pinpoint references to relevant passages.

17.3 Please confirm that the 3.5% return on funds collected is to the benefit of ratepayers of 3.5% per year

(i.e., a reduction of the Annual Abandonment Cost Collection). 17.4 Please provide the decisions, with pinpoint references, and/or documents relied on for KMJF’s

proposal to include an adjustment of 40 basis points to estimate anticipated expenses associated with the investment of abandonment funds and management of the abandonment funds trust. In your response, please include:

(a) All NEB decisions that support the use of an anticipated expense adjustment within

abandonment calculations. (b) An explanation of KMJF’s rationale for why, as a common carrier, the risks associated with

variances between abandonment cost estimates and implementation should be at the expense of ratepayers and not the company.

(c) An explanation of how the 0.4% expense adjustment was forecast, including justification for

the inclusion of this adjustment and the amount proposed. 17.5 Please provide an updated version of Table 10 without a return on funds component (of 3.5%) and

without the expense adjustment (of 0.40%) and re-calculate the annual contribution as a result. 18.0 Abandonment Cost Principles Reference (i): Exhibit B-8, KMJF Application, paras. 43 and 51, pp. 25 and 29

Reference (ii): NEB-regulated Pipeline Companies, Applications for approval of set-aside and collection mechanisms for abandonment cost funding, Reasons for Decision, MH-001-2013, Appendix IV, Principles and Attributes – RH-2-2008 at pp. 114-115

29

On p. 25, KMJF states: “It is in the public interest that regulated pipelines be abandoned safely and efficiently.” On p. 29, KMJF refers to the National Energy Board’s Reasons for Decision in MH-001-2013 and in RH-2-2008 for the principles regarding abandonment cost mechanisms. 18.1 Please provide the pinpoint references that KMJF relies on from the two National Energy Board

decisions cited above (or any other National Energy Board decisions) that allow KMJF to collect abandonment costs through rates.

18.2 How does KMJF’s abandonment cost proposal for the Jet Fuel System meet the “principles and

attributes” listed in Reference (ii) above? Please fully explain your response. 18.3 Please provide details on the consultation carried out by KMJF with persons and groups potentially

affected by the proposed abandonment of the pipeline. In your response, please provide copies of all relevant correspondence sent or received by KMJF.

19.0 Return on Rate Base

Reference (i): Exhibit B-8, KMJF Application, para. 39, p. 21 On p. 21, KMFJ requests a return on rate base as follows:

39. KMJF requests approval of an allowed return on rate base based on the cost of capital

parameters for a “benchmark low-risk utility” as determined by the BCUC in its 2013 Generic Cost of Capital Decision. KMJF’s requested return on rate base is determined as follows:

Reference (ii): Reasons for Decision and Order G-47-14, Generic Cost of Capital Proceeding, Stage 2,

p. 115 At p. 115 of the above decision, the BCUC states:

While Stage 1 of the GCOC proceeding has been mainly concerned with determining an appropriate cost of capital for the benchmark utility, Stage 2 will be primarily concerned with business risk assessment relative to the benchmark. More specifically, public utilities will be called upon to provide

30

evidence as to how they differ from FEI with respect to business risk. The Commission Panel considers that it is feasible that a stand-alone public utility may face overall business risks that are either higher, lower or the same as the benchmark utility.

Reference (iii): Reasons for Decision and Order G-129-16, FortisBC Energy Inc. Application for its

Common Equity Component and Return on Equity for 2016, p. 15 At p. 15 of the above decision, FortisBC Energy Inc. (“FEI”) identified the following eight risk areas:

FEI has identified eight risk areas as follows: regulatory risk, market shift risk, political risk, energy price risk, business profile, economic conditions, operating risk and energy supply risk. FEI notes that other risk factors are possible or could be captured differently, but states that relying on the same categories as used in the 2012 GCOC proceeding facilitates comparison of FEI’s amalgamated risk profile since the categories are common to all three amalgamated entities.

VAFFC requires additional information to understand the KMJF’s business risks and assess the reasonableness of KMJF’s proposed return on rate base. 19.1 Please confirm KMJF has low to minimal risk in the following categories: regulatory risk, market shift

risk, political risk, business profile, and operating risk. If not confirmed, please fully explain your response.

19.2 Please provide financial schedules for the Kinder Morgan parent company, including background calculations for the actual 2018 capital structure and 2018 actual cost of debt.

20.0 Taxes Reference: Exhibit B-8, KMJF Application, Appendix A, Schedule 9, pdf p. 48 On pdf p. 48, KMJF lists its provincial and federal income tax rates. VAFFC is seeking additional information on tax issues in relation to KMJF’s application. 20.1 Please justify the forecast 2019 income rates selected by KMJF in its application.

20.2 Please provide the actual income taxes paid (and corresponding tax rates) by KMJF in each year of 2008 to 2018.

21.0 Fuel and Power Operating Expenses

Reference (i): Exhibit B-8, KMJF Application, Schedule 15, pdf p. 54 On pdf p. 54, in Schedule 15, KMJF provides a 2019 forecast for fuel & power of $304,000.

Reference (ii): 2007 Application, Exhibit B-1, Schedule 19, pdf p. 26 On pdf p. 26, KMJF provided a 2008 forecast for fuel & power of $147,000. KMJF provided the following information:

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VAFFC requires additional information on why 2019 forecast expenses are significantly higher than information previously filed by KMJF.

21.1 Please provide specific details of power and fuel costs for each year since 2007, including supporting documents.

22.0 Direct Field Expenses

Reference (i): Exhibit B-8, KMJF Application, Schedule 16, pdf p. 55

On pdf p. 55, in Schedule 16, KMJF provides a 2019 forecast for a range of Direct Field Expenses, as follows:

Reference (ii): 2007 Application, Exhibit B-1, Schedule 21, pdf p. 80 On pdf p. 80, KMJF provided a 2008 forecast for Direct Field Expenses of $502,000. KMJF provided the following information:

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VAFFC requires additional information on why 2019 forecast expenses are significantly higher than information previously filed by KMJF.

22.1 Please provide specific details, including supporting documents, on the following Direct Field Expenses for each year dating back to 2007, as well as the test period:

(a) Forecast number of employees with associated titles and financial compensation (including detailed information about salaries, benefits, bonuses, and other incentives).

(b) Actual number of employees with associated titles and financial compensation (including detailed information about salaries, benefits, bonuses, and other incentives).

(c) The costs of materials and supplies, and a justification for the 400% increase.

(d) A list of all outside services procured by KMJF in relation to the pipeline. For any outside services that exceed $10,000, please include a list of contracts and contract values.

(e) A list of all vehicle expenses, including: repair, fuel, and operating costs. Please provide details for any expenses that exceed $10,000.

(f) Details of rental agreements for each parcel of land/commercial building and item being rented for rentals that exceed $10,000.

(g) Details related to “other” expenses that exceed $10,000 and justification for those expenses that exceed $10,000.

(h) Details related to field major maintenance and supporting documents explaining what work was required and why it was required.

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(i) Details related to tank major maintenance and supporting documents explaining what work was required and why it was required.

22.2 Where itemized Direct Field Expenses have increased above 2% year over year during the period dating back to 2007, please provide an explanation for the increase.

23.0 A&G Costs

Reference (i): Exhibit B-8, KMJF Application, Schedule 17, pdf p. 56 On pdf p. 56, KMJF provides a 2019 forecast for a range of A&G costs, as follows:

Reference (ii): 2007 Application, Exhibit B-1, Schedule 21, pdf p. 80 On pdf p. 80, KMJF provided a 2008 forecast for Direct Field Expenses of $502,000. KMJF provided the following information:

34

VAFFC requires more information on why 2019 forecast expenses are significantly higher than information previously filed by KMJF.

23.1 Please provide specific details, including supporting documents, on the following A&G Costs for each year dating back to 2007:

(a) A list of Employee Benefits that exceed $10,000. Please explain which Employee Benefits are captured in Schedule 16 compared to Schedule 17.

(b) A breakdown of the Labor expenses associated with each subgroup: Operations, Product Logistics, EHS, Operator Qualification Training, Tax, Insurance, IT, Accounting, Payroll, Human Resources. Please provide a list of any expenses in each subgroup that exceed $10,000.

(c) A list of Outside Services that exceed $10,000. Please include a list of contracts and contract values for amounts in excess of $10,000. Please also explain which Outside Services are captured in Schedule 16 compared to Schedule 17.

(d) A list of Rent expenses that exceed $10,000. Please include a list of contracts and contract values for amounts in excess of $10,000. Please also explain which Rent expenses are captured in Schedule 16 compared to Schedule 17.

24.0 Actual Operating Expenses

Reference: Exhibit B-8, KMJF Application, Appendix A, Schedules 15, 16 and 17, pdf pp. 54-56 On pdf pp. 54-56, KMJF provides 2019 forecast operating expenses. VAFFC requests additional information to understand KMJF’s forecast methodology.

35

24.1 Please provide the actual Operating expenses listed in Schedules 15, 16 and 17 for the years 2008 to 2018 (since KMJF’s last toll application). Please explain whether (1) any changes were made to KMJF’s forecast methodology from 2008 to 2018, (2) any changes KMJF made to its forecast metholodogy for 2019 resulted from the 2018 actuals.

25.0 Employee Policies and Figures Reference: Exhibit B-8, KMJF Application, Schedules 16 and 17, pdf pp. 55-56 On pdf pp. 55-56, KMJF provides its employee-related costs. VAFFC requires more information on KMJF’s employee policies and numbers.

25.1 Please provide all policies for employee time and expense allocations for Direct Field Expenses as provided in the 2019 forecasts.

25.2 Are employees of KMJF exclusively under employment for KMJF or are employees split between

KMJF and other KMJF parent and/or subsidiary companies? In your response, please explain how labor and employee benefits are split between companies.

25.3 Please provide Full-Time Equivalent (FTE) employment numbers corresponding to KMJF’s actual

Operating costs for each year of 2008 to 2018 and forecast Operating costs for 2019. Please also provide an explanation for year-over-year changes to FTEs.

26.0 Integrity Costs Reference: Exhibit B-8, KMJF Application, Table 8 pdf p. 23

On pdf p. 24, KMJF proposes including a yearly normalized amount of integrity costs based on the three-year average, as follows:

VAFFC is seeking more information on KMJF’s integrity costs.

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26.1 For each cost category listed in Table 8, please provide the actual costs for each year for the years 2008 to 2018. Please compare the forecast costs for 2008 to the costs provided in KMJF’s 2007 Application.

26.2 For each cost category listed in Table 8, please provide a detailed explanation of the forecast

methodology used to determine annual costs for the three forecast years. 26.3 Please explain why certain line items are listed multiple times within Table 8. For example, the DOC

survey is listed three times in Table 8, with forecast costs of $62,000, $30,000 and $30,000 in 2020. 26.4 For each category listed in Table 8, please provide the associated KMJF internal policies, regulations,

or requirements. If no such documents exist, please explain the justification for incurring the costs in each of the forecast years.

26.5 For the ILI Assessment – Parkland to Airport and ILI Digs (2019 forecast costs of $345,000 and

$680,000 respectively), please provide:

(a) the business cases associated with these expenses; (b) the internal approvals for these expenses; (c) any other documents that address the justification of these expenditures for a pipeline that is

proposed to be abandoned imminently; and (d) a list of all alternatives considered, including supporting documents and an explanation of

why alternatives were not pursued. 27.0 Rate Case Costs Reference: Exhibit B-8, KMJF Application, Table 9, p. 24 On pdf p. 24, KMJF proposes normalizing its rate costs over three years as follows:

VAFFC is seeking additional information KMJF’s actual and forecast rate case costs. 27.1 Please provide the actual rate case costs for each year from 2007 to 2018. In your response, please

provide a detailed explanation of what is included in these costs and how they are tracked internally. Please also include a breakdown of KMJF costs and external stakeholder costs (e.g., BCUC, intervener, etc.)

27.2 Please explain how KMJF forecast its 2019 rate case costs.

28.0 Abandonment Fund Trust

Reference: Exhibit B-8, KMJF Application, Schedule 21, pdf p. 60, footnote 3

On pdf p. 60, KMJF proposes a 40 basis point adjustment in its abandonment cost collection mechanism:

37

[3/] KMJF proposes to include an adjustment of 40 basis points to estimate anticipated expenses associated with the investment of abandonment funds and management of the abandonment funds trust. For example, the independent, third-party management of the abandonment fund will give rise to investment management fees and the management of the trust will give rise to custody/trustee fees.

VAFFC requests additional information to assess the reasonableness of KMJF’s proposal.

28.1 Who are the beneficiaries of the environmental trust? Please fully explain your response.

28.2 Please provide examples of other pipelines and/or environmental trusts that receive an investment premium for administration purposes.

28.3 Provide examples of other pipelines and/or environmental trusts that are compensated for administration by means other than an investment premium.

28.4 Provide examples of other pipelines and/or environmental trusts that are not compensated for administration purposes.

28.5 Confirm that investment options will feature little to zero risk given the assumption that abandonment funds will be deployed in 2022. If not confirmed, why not? If confirmed, justify why administration compensation is required for conservative investment choices.

29.0 Abandonment Cost Estimate

Reference (i): Exhibit B-8, KMJF Application, Appendix E, pdf pp. 130-133 On pdf pp. 130-133, the ELM Abandonment Cost Study lists the following assumptions underlying its estimation of abandonment costs, which together total an estimated $5,745,750. Sub-reference (a): Engineering and Project Management heading, pdf p. 130 ELM identifies engineering and project management costs of $834,625. ELM states: “The NEB recommends a factor of 20% be applied to sections 2, 3a, 4, 5 and 6 for small diameter pipelines less than 50km in length. A factor of 25% has been applied in this case due to the urban setting and the current regulatory environment in British Columbia.”

Sub-reference (b): Abandonment Preparation heading, pdf p. 130 ELM identifies abandonment preparation costs of $246,000. ELM states: “The high end of the range prescribed by NEB was selected due to the urban setting and logistics involved with mobilization of services in and through the cities of Burnaby and Richmond.”

Sub-reference (c): Basic Pipeline Abandonment in Place, pdf p. 131 ELM identifies post-abandonment monitoring costs of $738,000.

Sub-reference (d): Special Treatment, pdf p. 131 ELM identifies special treatment costs of $90,000. ELM states: “The high end of the range prescribed by NEB was selected due to the urban setting and logistics involved with mobilization of services in and through the cities of Burnaby and Richmond.” Sub-reference (e): Pipeline Removal and Backfilling, pdf p. 131 ELM identifies pipe removal costs of $2,050,000 and pipe removal land restoration costs of $205,000. ELM states:

38

Due to the urban setting in which this pipeline is situated, it is reasonable to expect that the potential for future development is likely at some points along the pipeline route. A desktop aerial review of the pipeline route was completed to identify industrial and commercially zoned lands where the potential for future development is higher. This estimate includes costs to remove 20% of the total pipeline length, or 8.2 kilometres. Note: ELM is in the process of acquiring additional input from landowners, municipalities and regulators as to any specific removal requirements. ELM will reflect that additional input in its estimates once received. The high end of the cost range prescribed by NEB was selected due to the urban setting and logistics involved with mobilization of services in and through the cities of Burnaby and Richmond.

Sub-reference (f): Above-ground Facilities, pdf p. 132 ELM identifies above-ground facilities costs of $550,000 to decommission 10 block valve sites, $100,000 to decommission at two water crossings, and $97,500 for restoration at above-ground facilities. Regarding above-ground facilities, ELM states: “at least 12 sites along the pipeline route where the pipeline comes above-ground.” Sub-reference (g): Contingency, pdf p. 132 ELM identifies contingency costs of $834,625. ELM applies a 25% contingency factor. Sub-reference (h): ELM summary, pdf p. 132 ELM provides the following summary:

Reference (ii): National Energy Board, Reasons for Decision in RH-2-2008, Land Matters Consultation Initiative Stream 3, Financial Issues related to Pipeline Abandonment, p. 45

39

Reference (iii): 2007 Application, Exhibit B-1, pdf p. 93

At pdf p. 93, KMJF sets out the following assumptions made in preparing its abandonment cost estimate:

VAFFC is seeking additional information on KMJF’s abandonment cost estimates. 29.1 Please identify alternative methodologies that ELM/KMJF considered in preparing the abandonment

study. If no alternative methodologies were considered, please explain why not. 29.2 Please discuss any material differences between the ELM abandonment study and any previous

abandonment studies carried out or commissioned by KMJF, including changes in methodology and/or assumptions.

29.3 Regarding Sub-reference (a) above, please confirm the NEB does not recommend any escalation of

the cost factor for (i) urban environments or (ii) the BC regulatory environment.

29.4 Regarding Sub-reference (b) above, please provide documents identifying which portions of the pipeline terrain are “flat or downhill” and “mountainous or uphill” including any relevant maps.

29.5 Regarding Sub-reference (c) above, please provide an itemized breakdown of the $738,000 allocated to post-abandonment monitoring, including further details regarding:

40

(a) future depth cover issues;

(b) line locating requirements;

(c) continued participation in provincial one-call program;

(d) maintenance of signage at utility crossings and a long right-of-way;

(e) remediation of contamination;

(f) soil drainage problems;

(g) weed control; and,

(h) any other potential problems.

29.6 Regarding Sub-reference (d) above, please confirm that no cut, cap, and fill work will be conducted in environmentally sensitive areas. If not confirmed, please identify those environmentally sensitive areas and provide supporting documents confirming (i) they are environmentally sensitive; and (ii) the specific special treatment measures that must be taken with regard to cut, cap and fill work in these areas.

29.7 Regarding Sub-reference (e) above:

(a) Please provide the maps, reports, or supporting documents from the desktop aerial review.

(b) Please identify the basis for the assumption that 20% of the total pipeline length will be removed.

(c) Please provide copies of any correspondence between KMJF and landowners, municipalities, or regulators regarding specific removal requests.

(d) Please confirm that mobilization and demobilization costs are lower in urban areas than remote areas. If not confirmed, please explain why not.

(e) Please confirm that land restoration along the pipeline route does not include restoration of rough or mountainous terrain. If not confirmed, please provide maps, reports or supporting documents that identify which sections of the pipeline route include rough or mountainous terrain.

29.8 Regarding Sub-reference (f) above, please provide a list of the 12 or more sites where the pipeline comes above-ground and identify the type of facilities at each site.

29.9 Regarding Sub-reference (g) above, please confirm the following table summarizes how ELM’s estimation of abandonment costs implements the NEB recommendations:

41

Project Phase  Cost Description  Value  Unit  Implementing NEB 

Recommendation 

1. Project Management  

 

Planning & preparation. 

‐ Land use study, depth of cover survey, 

abandonment methodology, 

notifications & agreements 

 

$834,625  25% of 

project 

ELM identified a 25% factor, above 

the 20%  factor recommended by 

the NEB for projects <50 km. 

2. Abandonment 

Preparation 

Pipeline isolation, pigging, purging 

 

$246,000  $6,000/km  ELM calculated estimate based on 

the top of the NEB’s recommended 

range. 

3. Pipeline 

Abandonment 

a. Basic Pipeline Abandonment in Place 

 

b. Post‐abandonment Monitoring 

 

N/A for 6" 

Pipe 

$738,000 

$20,000/km  ELM calculated estimate based on 

the NEB’s recommended range for 

small diameter pipelines. 

4. Special Treatment  Cut & fill at road, rail utility and river 

crossings. 

$90,000  $45,000/site  ELM calculated estimate based on 

the top of the NEB’s recommended 

range. 

5. Pipeline Removal  a. Pipeline Removal (20% of total 

length = 8.2km) 

b. Pipeline Removal Restoration 

 

$2,050,000 

$205,000 

$250,000/km 

10% of above 

ELM calculated estimate based on 

the top of the NEB’s recommended 

range for small diameter pipelines 

and requested an additional 10% 

escalation. 

6. Above‐ground 

Facilities 

a. Decommission 10 Block Valve Sites 

b. Decommission at two Water 

Crossings 

c. Restoration at Above‐ground 

Facilities 

$550,000 

$100,000 

$97,500 

$55,000/site 

$50,000/site 

15% of above 

ELM calculated estimate based on 

the top of the NEB’s recommended 

range for block valve sites.  For 

restoration of above‐ground 

facilities, ELM requested an 

additional 15% escalation. 

7. Contingency  Unforeseen impairments 

 

$834,625  25% of 

project 

ELM requested the NEB’s maximum 

recommended contingency. 

  Total:  $5,745,750  $140,140/km   

29.10 Please identify what uncertainties exist for the cost estimates in the other sections, such that any contingency is required?

29.11 Regarding Reference (ii) above, please confirm that KMJF is aware that the NEB Base Case assumptions are based on a 40 year economic life.

29.12 Regarding Reference (iii) above, please discuss which assumptions were made in the 2007 Application’s abandonment study that were not made or were changed for the 2019 abandonment study. In your response, please address how and why each of those assumptions was changed for the 2019 abandonment study, including all support for each change.

30.0 Estimated Abandonment Costs

Reference: Kinder Morgan Canada Securities Filings: the April 24, 2017 Preliminary Prospectus at p.74 and the May 25, 2017 Long Form Prospectus at pp. 72-73 (Attached as Appendices C1 and C2)

Both of these documents, attached as Appendices C1 and C2 to these information requests, contain the following statement:

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… To the extent it becomes uneconomic to continue shipping jet fuel to the Vancouver International Airport, the Company estimates that the decommissioning and abandonment costs of the Jet Fuel pipeline would be in the range of $2.0 million to $3.0 million, subject to regulatory approval of the BCUC and the BC OGC.

VAFFC is seeking clarification on KMJF’s past estimates for abandonment costs.

30.1 Please explain why Kinder Morgan Canada reported the potential abandonment costs for the Jet Fuel System in 2017 as being in the range of $2-3 million in its securities filings and the same costs are now claimed in a total amount of over $5.7 million.

An oil tank stands near the Trans Mountain pipeline expansion site in Burnaby, British Columbia. Photographer: BenNelms/Bloomberg

Kinder Morgan Inc. hinted at a potential offloading of its remaining Canadian assets following thesale of the contentious Trans Mountain pipeline expansion to the federal government.

Speaking at an ener�y conference Wednesday, Kinder Morgan Chief Executive Officer Steve Keansaid that while its Canadian affiliate has “attractive assets” and “no debt on the balance sheet,”

CEO says Canadian assets sit in ‘attractive seller’s market’

Company recently sold contentious pipe project to government

Business

By Rachel Adams-HeardSeptember 5, 2018, 2:01 PM PDTUpdated on September 5, 2018, 9:00 PM PDT

Kinder Weighs Full Exit From Canada AfterTrans Mountain Debacle

Appendix A to VAFFC IR No. 1

Page 1 of 62

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In this article

KMLKINDER MORGAN CA11.62 CAD -0.04 -0.34%

the company’s primary objective was to use those projects to support the Trans Mountainexpansion.

“It’s a set of midstream assets in what we think is an attractive seller’s market for those assets,”he said. “We are going to explore that over the coming months.”

In addition to the Canadian portion of the Cochin pipeline system and the Jet Fuel pipelinesystem, Kinder Morgan Canada Ltd. has a network of crude storage and rail terminals inEdmonton, Alberta, and the Vancouver Wharves Terminal in British Columbia.

“We can always say no, because the assets themselves will stand on their own,” Kean said.

Kinder Morgan Canada shareholders voted last week to proceed with a C$4.5 billion sale of theTrans Mountain pipeline to the federal government. The decision came less than an hour after aCanadian court nullified its approval.

— With assistance by Kevin Orland

Appendix A to VAFFC IR No. 1

Page 2 of 62

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MANAGEMENT'S DISCUSSION AND ANALYSIS

For the Three and Nine Months Ended September 30, 2017 and 2016

Presentation of Information

Any references in this management's discussion and analysis (“MD&A”) to “KML,” the “Company,” “we,” “us” are to Kinder Morgan Canada Limited and, unless otherwise noted, includes Kinder Morgan Limited Partnership (the "Limited Partnership"), which holds certain businesses, assets and operations comprising the Company's Pipelines and Terminals (as defined herein) business segments (the “Operating Entities”) of Kinder Morgan, Inc. (“Kinder Morgan”). The Company holds indirectly an approximate 30% interest in the Limited Partnership, and Kinder Morgan holds indirectly an approximate 70% interest which is reflected as “Kinder Morgan Interest” in our financial statements, in each case after taking into account the preferred shareholders’ priority on distributions and upon liquidation. See “Recent Developments - The Reorganization and the Initial Public Offering (“IPO”).”

The following MD&A is as of October 24, 2017, and should be read in conjunction with the Company’s unaudited interim consolidated financial statements for the three and nine month periods ended September 30, 2017 and 2016 (the “Interim Consolidated Financial Statements”), the Company’s audited consolidated financial statements for the years ended December 31, 2016, 2015 and 2014, and associated MD&A, included in our long form prospectus dated May 25, 2017 (the “Final Prospectus”). No update is provided to the disclosure, including the MD&A, contained in the Final Prospectus, except for material information since the date thereof.

Management is responsible for preparing the MD&A. This MD&A has been reviewed and approved by the audit committee of our board of directors.

The Unaudited Interim Consolidated Financial Statements have been prepared in accordance with United States Generally Accepted Accounting Principles (“U.S. GAAP”). All financial information in this MD&A are presented in Canadian dollars, unless otherwise indicated.

In respect of forward-looking statements contained in this MD&A, see “Forward-Looking Statements.” Also, the non-U.S. GAAP financial measures “Adjusted EBITDA” and “DCF” contained in this MD&A are not prescribed by U.S. GAAP, see “Non-U.S. GAAP Financial Measures” below.

Recent Developments

Outlook

For 2017, we expect to generate Adjusted EBITDA of between $380.0 million and $390.0 million and DCF of approximately $315.0 million to $320.0 million. The reduction in DCF expected for 2017 relative to the guidance of $320.0 million delivered last quarter is primarily attributable to lower capitalized equity financing costs driven by lower spending on the project. Additionally, from a total expected project cost of $7.4 billion, which includes capitalized financing costs and capital spent to date, Trans Mountain Expansion Project (“TMEP”) has remaining estimated cash spend to completion, excluding interest, of approximately $6.0 billion as of the end of the third quarter.

The Reorganization and the Initial Public Offering (“IPO”)

The Company was incorporated on April 7, 2017. On May 30, 2017, we completed an IPO of 102,942,000 restricted voting shares (“Restricted Voting Shares”) on the Toronto Stock Exchange at a price to the public of $17.00 per Restricted Voting Share for total gross proceeds of approximately $1.75 billion. We used our IPO proceeds to indirectly acquire from Kinder Morgan an approximate 30% economic interest in the Limited Partnership, with Kinder Morgan retaining the remaining approximate 70% economic interest.

Appendix B to VAFFC IR No. 1

Page 3 of 62

2

Concurrent with closing of our IPO, Limited Partnership acquired an interest in the Operating Entities from Kinder Morgan Canada Company (“KMCC”) and KM Canada Terminals ULC (“KM Canada Terminals”) in exchange for the issuance to KMCC and KM Canada Terminals of Class B limited partnership units of the Limited Partnership. In addition, KMCC and KM Canada Terminals were issued Special Voting Shares in the Company for nominal consideration.

Immediately following closing of our IPO, the Company used the proceeds from our IPO to indirectly subscribe for Class A limited partnership units representing an approximate 30% interest in the Limited Partnership while the Class B limited partnership units held by KMCC and KM Canada Terminals represent, in the aggregate, an approximate 70% economic interest in the Limited Partnership’s total Class A units and Class B units. Following the issuance of the Series 1 Preferred Shares, the Company’s and Kinder Morgan’s respective interests in the Limited Partnership are subject to the preferred shareholders’ priority on distributions and upon liquidation.

The issued and outstanding Restricted Voting Shares comprise approximately 30% of the votes attached to all outstanding Company voting shares, and the Kinder Morgan interest, which represents its indirectly ownership of 100% of the Special Voting Shares, comprises approximately 70% of the votes attached to all outstanding Company voting shares.

Pursuant to current accounting principles in conformity with U.S. GAAP, we accounted for our acquisition of an approximate 30% economic interest in the Limited Partnership as a transfer of net assets among entities under common control. Therefore, the assets and liabilities in our unaudited interim consolidated financial statements have been reflected at historical carrying value of the immediate parent(s) within the Kinder Morgan organization structure including goodwill and purchase price assigned amounts, as applicable. Additionally, we prepared our interim consolidated financial statements to reflect the transfer of net assets of the Operating Entities from Kinder Morgan to us as if such transfer had taken place on January 1, 2016.

In addition, as of and for the reporting periods after May 30, 2017, Kinder Morgan’s interest in the Limited Partnership is reflected within “Kinder Morgan interest” in our consolidated statements of equity and consolidated balance sheets. The earnings attributable to Kinder Morgan’s ownership interest in the Limited Partnership are presented in “Net Income attributable to Kinder Morgan Interest” in our consolidated statements of income.

Series 1 Preferred Share Offering

On August 15, 2017, we completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of $25.00 per Series 1 Preferred Share for total gross proceeds of $300.0 million. The net proceeds of $293.0 million from the offering were used to indirectly subscribe for preferred units in the Limited Partnership, which in turn were used by the Limited Partnership to repay Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the TMEP and Base Line Terminal project, and for general corporate purposes. We have the option to redeem the Series 1 Preferred Shares on November 15, 2022 and on November 15 in every fifth year thereafter by payment of $25.00 per Series 1 Preferred Share plus all accrued and unpaid dividends. The holders of the Series 1 Preferred Shares will have the right to convert all or any of their Series 1 Preferred Shares into cumulative redeemable floating rate Preferred Shares, Series 2 (Series 2 Preferred Shares), subject to certain conditions, on November 15, 2022 and on November 15 in every fifth year thereafter. The Series 1 Preferred Shares and the Series 2 Preferred Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of security.

Financing

On June 16, 2017, Kinder Morgan Cochin ULC (“KMCU”) and Trans Mountain Pipeline ULC, our indirect subsidiaries, entered into a definitive credit agreement establishing (i) a $4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP; (ii) a $1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs, meeting the National Energy Board-mandated liquidity requirements); and (iii) a $500.0 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “Credit Facility”). The Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the Credit Facility will incur a standby fee of 0.30% to 0.625%, with the range dependent on our credit ratings. The Credit Facility is guaranteed by the Company and all of the non-borrower subsidiaries of the Company and is secured by a first lien security interest on all of the assets of the Company and the equity and assets of the other guarantors.

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Results of Operations

Overview

The reportable business segments of KML are based on the way management organizes the enterprise. Each of our reportable business segments represents a component of the enterprise that engages in a separate business activity and for which discrete financial information is available.

Our reportable business segments are:

• Pipelines - the ownership and operation of (i) the Trans Mountain pipeline system (“Trans Mountain”); (ii) the CanadianCochin pipeline system (“Cochin”); (iii) the Puget Sound pipeline system (“Puget Sound”); (iv) the Jet Fuel pipelinesystem (“Jet Fuel”); and (v) Kinder Morgan Canada, Inc. (“KMCI”).

• Terminals - the ownership and operation of liquid product merchant storage and rail terminals in the Edmonton, ABmarket as well as a predominantly dry cargo import/export facility in North Vancouver, B.C.

We evaluate the performance of our reportable business segments by evaluating the earnings before depreciation andamortization of each segment ("Segment EBDA”). We believe that Segment EBDA is a useful measure of the operating performance of KML because it measures segment operating results before depreciation, depletion and amortization (“DD&A”) and certain expenses that are generally not controllable by the operating managers of the respective business segments of KML, such as certain general and administrative expense, foreign exchange losses (or gains) on the KMI Loans, interest expense, and income tax expense. Our general and administrative expenses include such items as employee benefits, insurance, rentals, certain litigation, and shared corporate services including accounting, information technology, human resources and legal services. Certain general and administrative expenses attributable to Trans Mountain are billable as flow through items to shippers and result in incremental revenues. See Note 11 “Reportable Segments” to the Interim Consolidated Financial Statements for further discussion of KML’s reportable business segments.

Current Business Developments

Pipelines

We are undertaking a $7.4 billion TMEP which will increase throughput capacity of Trans Mountain from approximately 300,000 to 890,000 barrels per day (‘‘bpd’’). On May 19, 2016, the National Energy Board (“NEB”) recommended that the Governor in Council approve the TMEP, subject to 157 conditions. On November 29, 2016, the Governor in Council approved the TMEP, and directed the NEB to issue, Amending Orders AO-003-OC-2 and AO-002-OC-49, and Certificate of Public Convenience and Necessity OC-064, authorizing the construction of the TMEP. On January 11, 2017, the Government of British Columbia (“B.C.”) announced the issuance of an Environmental Assessment Certificate (“EAC”) from B.C.’s Environmental Assessment Office to the TMEP for the B.C. portion of the TMEP. The EAC includes 37 conditions that are in addition to and designed to supplement the 157 conditions required by the NEB. We have spent a cumulative total, net of contributions in aid of construction, of $778.8 million, which includes capitalized equity financing costs, on development of the TMEP as of September 30, 2017 (December 31, 2016— $480.0 million).

All available long-term firm service capacity remains contracted on the pipeline expansion with a diverse group of 13 customers.  This demonstrates strong market support for the TMEP and the much-needed access to new markets it will bring to Canadian producers, as well as providing a secure supply of Canadian crude to refineries throughout the Pacific basin including Washington state.  Collectively, the firm shippers have made 15- and 20-year commitments of 707,500 barrels per day, or approximately 80 percent of the capacity on the expanded pipeline, with the remaining 20 percent reserved for spot volumes consistent with NEB requirements.  Aboriginal support for the TMEP continues to grow, with 42 Aboriginal communities in support of the TMEP.

Provincial elections in B.C. occurred on May 9, 2017. Following a series of recounts, the final result was 43 Liberal seats, 41 seats for the New Democratic Party (“NDP”), and 3 seats for the Green Party. On May 29, 2017 the NDP and Green Party announced a Confidence and Supply Agreement. After a non-confidence vote on the Liberal Throne speech the Lieutenant Governor asked the NDP to form a government resulting in a 44 seat NDP/Green majority in the B.C. legislature. One component of the agreement  between the NDP and the Green Party was the statement of intent to utilize all means available to the B.C.  government to oppose the TMEP.  We also remain willing to discuss all concerns relating to the TMEP with the NDP.  Despite the NDP pledge to utilize all means to oppose the TMEP, recently we were granted access to approximately 140 kilometers of B.C. Crown land and are advancing the additional provincial permits that enable us to start pre-construction work in B.C.  In addition, we have

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received conditional permits from the NEB, B.C. Environmental Assessment Office, Vancouver Fraser Port Authority, and the federal Department of Fisheries and Oceans to proceed with water work at Westridge.

There are two judicial reviews underway in the British Columbia Supreme Court with respect to the EAC. Hearings are scheduled in October and November 2017. Separate judicial reviews pending in the Federal Court of Appeal challenging the process leading to the federal government’s approval of the TMEP were consolidated and heard by the court from October 2 to October 13, 2017. The new B.C. government sought and was granted limited intervenor status in the Federal Court of Appeal proceedings to argue against the process leading to the government's approval of the TMEP. On September 29, 2017, the B.C. government filed evidence in support of the EAC approval in one of the provincial proceedings. Decisions from the courts are expected in the coming months.

Despite the Company’s willingness to continue to work with the new B.C. government, the Company cannot predict the impact that this change in government may have on the ability of the Company to complete the TMEP on current expected timelines or budget.  See “Cautionary Statement Regarding Forward-Looking Information” in this MD&A and “Risk Factors” in the Final Prospectus, a copy of which is available under KML's profile on SEDAR at www.sedar.com.

TMEP Construction Progress

Construction preparation activity is off to a slower start than planned in the project schedule due primarily to the time required to file for, process and obtain all necessary permits and regulatory approvals. Since receiving Governor in Council approval in 2016, Trans Mountain has made steady positive progress on the regulatory, commercial and construction aspects of the TMEP. Limited construction activity began in September, 2017 at the Westridge Terminal facilities. Pre-construction work on key sections of the pipeline right of way is planned for the fourth quarter of 2017, subject to the receipt of all applicable permits.

We are assessing construction mitigation plans that maintain the current in-service schedule of December 31, 2019. That planning, with our contractors, will rely upon continued progress towards schedule-critical regulatory approvals and will assess the acceleration of construction activities that are behind schedule. Absent this mitigation, it is estimated that project completion could be delayed by up to nine months. All project planning and schedule mitigation efforts include cost management measures and spend control to maximize project returns, including a reduction in 2017 spend that has already been implemented.

Terminals

Construction continues at KML and Keyera Corp.’s Base Line Terminal, a 50-50 joint venture crude oil merchant storage terminal being developed in Sherwood Park, Alberta, Canada.  In the third quarter, on-site facility mechanical work was materially completed and significant progress was made on the off-site pipe rack and bridges required to connect the terminal with our other Edmonton-area facilities, including the North 40 Terminal, Edmonton South Terminal, and Edmonton Rail Terminal joint venture. The 12-tank, 4.8 million barrel new-build facility is fully contracted with long-term, firm take-or-pay agreements with strong, credit worthy customers.  Our investment in the joint venture will be approximately $396.0 million including costs associated with the construction of a new pipeline segment that will be funded solely by KML, with total spend to date of $250.0 million and remaining spend in 2017 of $33.0 million. Commissioning is expected to begin in the first quarter of 2018 with tanks phased into service throughout that year. The facility is forecast to be on schedule and on budget.

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Consolidated Earnings Results

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2017 2016 2017 2016(In millions of Canadian dollars)Segment EBDA (a)    

Pipelines 58.5 58.2 169.0 184.3Terminals 52.7 52.0 159.1 162.6

Total segment EBDA (a) 111.2 110.2 328.1 346.9DD&A (37.2) (34.3) (107.6) (102.5)Foreign exchange gain (loss) on the KMI Loans (b) 0.6 (15.7) (2.4) 54.2General and administrative expenses (16.2) (15.2) (50.5) (45.4)Interest, net (1.3) (7.0) (10.9) (22.9)Income before income taxes 57.1 38.0 156.7 230.3Income tax expense (14.7) (17.7) (42.4) (46.3)

Net income 42.4 20.3 114.3 184.0Preferred share dividends (2.0) — (2.0) —

Net income attributable to Kinder Morgan interest (28.7) (20.3) (96.4) (184.0)Net income available to restricted voting stockholders 11.7 — 15.9 —

______Notes:(a) Includes revenues and other (income) expense less operating expenses and other, net. Operating expenses primarily include operations and

maintenance expenses, and taxes, other than income taxes. Segment EBDA for the three months ended September 30, 2017 and 2016 includes (i) $(1.5) million and $(1.4) million, respectively, of unrealized foreign exchange losses due to changes in exchange rates between the Canadian dollar and the U.S. dollar on U.S. dollar denominated balances and (ii) $7.8 million and $4.6 million, respectively, of capitalized equity financing costs. Segment EBDA for the nine months ended September 30, 2017 and 2016 includes (i) $(3.3) million and $5.1 million, respectively, of unrealized foreign exchange (losses) gains due to changes in exchange rates between the Canadian dollar and the U.S. dollar on U.S. dollar denominated balances and (ii) $19.6 million and $12.8 million, respectively, of capitalized equity financing costs.

(b) The KMI Loans, which represented U.S. dollar denominated long-term notes payable with Kinder Morgan, were settled with proceeds from our IPO.

Three Months Ended September 30, 2017 vs Three Months Ended September 30, 2016

The increase of $22.1 million (109%) from the prior year third quarter in net income is primarily attributable to the change in foreign exchange gains (losses) on the KMI Loans. The remainder of the increase is largely attributable to lower interest expense primarily due to the settlement of the KMI Loans.

Nine Months Ended September 30, 2017 vs Nine Months Ended September 30, 2016

The decrease of $69.7 million (38%) from the prior year in net income is primarily attributable to the change in foreign exchange gains (losses) on the KMI Loans. The remainder of the decrease is largely attributable to decreased results on our Cochin and Puget Sound pipelines in our Pipelines business segment, increased general and administrative expense and DD&A expense, partially offset by lower interest expense primarily due to the settlement of the KMI Loans.

Non-U.S. GAAP Financial Measures

In addition to using financial measures prescribed by U.S. GAAP, references are made in this report to ‘‘distributable cash flow,’’ (“DCF”), and adjusted earnings before interest expense, taxes, depreciation and amortization (“Adjusted EBITDA’’) which are measures that do not have any standardized meaning as prescribed by U.S. GAAP. Neither Adjusted EBITDA nor DCF should be considered an alternative to U.S. GAAP net income or any other U.S. GAAP measures and such non-U.S. GAAP measures have important limitations as an analytical tool. The computation of Adjusted EBITDA and DCF may differ from similarly titled measures used by others. Accordingly, use of such terms may not be comparable to similarly defined measures presented by other entities. Investors should not consider these non-U.S. GAAP financial measures in isolation or as a substitute for an analysis of results as reported under U.S. GAAP. The limitations of these non-U.S. GAAP financial measures are compensated for by reviewing the comparable U.S. GAAP measures, understanding the differences between the measures and taking this information into account

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in our analysis and our decision making processes. Any use of Adjusted EBITDA, or DCF in the MD&A is expressly qualified by this cautionary statement.

DCF is net income before DD&A adjusted for (i) income tax expense and cash income taxes (paid) refunded; (ii) sustaining capital expenditures; and (iii) certain items that are items required by U.S. GAAP to be reflected in net income, but typically either (a) do not have a cash impact, or (b) by their nature are separately identifiable from the normal business operations and in our view are likely to occur only sporadically.

DCF is an important performance measure used by us and by external users of our financial statements to evaluate our performance and to measure and estimate our ability to generate cash earnings after servicing our debt and preferred share dividends, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as distributions or expansion capital expenditures. We use this performance measure and believe it provides users of our financial statements a useful performance measure reflective of our ability to generate cash earnings to supplement the comparable U.S. GAAP measure. DCF should not be used as an alternative to net cash provided by operating activities computed under U.S. GAAP. We believe the U.S. GAAP measure most directly comparable to DCF is net income. A reconciliation of net income available to Kinder Morgan Interest and Restricted Voting Shareholders to DCF is provided in the table below. DCF per Restricted Voting Share is DCF divided by average outstanding Restricted Voting Shares, including restricted stock awards that participate in dividends.

Reconciliation of Net Income to DCF

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2017 2016 2017 2016(In millions of Canadian dollars)

Net Income (a) 42.4 20.3 114.3 184.0Add/(Subtract):

DD&A 37.2 34.3 107.6 102.5Certain items (b) (0.4) 15.7 3.6 (54.2)Total book taxes (c) 14.6 17.7 43.8 46.3Cash income taxes refunded (paid) 0.3 0.2 — (1.0)Preferred share dividends (2.0) — (2.0) —Sustaining capital expenditures (14.9) (11.0) (27.3) (26.6)

DCF 77.2 77.2 240.0 251.0Weighted average Restricted Voting Shares

outstanding for dividends (d) 103.6 n/a 103.4 n/aDCF per Restricted Voting Share 0.214 n/a 0.297 n/aDeclared dividend per Restricted Voting Share 0.1625 n/a 0.2196 n/a

Adjusted EBITDA is used as a liquidity measure by the Company and external users of our financial statements, in conjunction with net debt, to evaluate certain leverage metrics. Adjusted EBITDA is earnings before interest expense, taxes, depreciation and amortization adjusted for certain items, as applicable. The Company believes the U.S. GAAP measure that must be directly comparable to Adjusted EBITDA is net income. A reconciliation of net income to Adjusted EBITDA is provided in the table below. We do not allocate Adjusted EBITDA amongst equity interest holders as we view total Adjusted EBITDA as a liquidity measure against our overall leverage.

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Reconciliation of Net Income to Adjusted EBITDA

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2017 2016 2017 2016(In millions of Canadian dollars)Net Income (a) 42.4 20.3 114.3 184.0Add/(Subtract):

Total certain items (b) (0.4) 15.7 3.6 (54.2)DD&A 37.2 34.3 107.6 102.5Total book taxes (c) 14.6 17.7 43.8 46.3Interest, net 1.3 7.0 10.9 22.9

Adjusted EBITDA 95.1 95.0 280.2 301.5______n/a - not applicable

Notes:(a) During the three and nine months ended September 30, 2017 and 2016, net income includes (a) capitalized equity financing costs of $7.8

million, $4.6 million, $19.6 million, and $12.8 million, respectively, and (b) interest expense on KMI Loans of none, $10.9 million, $19.6 million, and $32.9 million, respectively.

(b) Prior to our IPO, amounts primarily represented foreign currency losses and (gains) on the KMI Loans. The principal portion of the KMI Loans were repaid using proceeds from our IPO.

(c) Excludes book tax certain items.(d) Includes restricted stock awards that participate in dividends.

Segment Earnings Results

Pipelines Segment

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2017 2016 2017 2016(In millions of Canadian

dollars, except operating statistics)Revenues 95.9 98.6 281.8 287.0Operating expenses, except DD&A (42.4) (45.1) (124.9) (115.5)Other income and unrealized foreign exchange loss,

net 5.0 4.7 12.1 12.8Segment EBDA 58.5 58.2 169.0 184.3

Change from prior period Increase/(Decrease)Revenues (2.7) (3)% (5.2) (2)%Segment EBDA 0.3 1 % (15.3) (8)%

2017 2016 2017 2016Trans Mountain transport volumes (MMBbl)(a) 29.3 30.7 84.4 88.1Puget Sound transport volumes (MMBbl)(a) 16.1 18.7 45.5 55.3Cochin transport volumes (MMBbl)(a) 7.7 7.7 23.4 22.6________(a) Million barrels.

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Below are the changes in both Segment EBDA and revenues, in the comparable three and nine month periods ended September 30, 2017 and 2016:

Three months ended September 30, 2017 versus Three months ended September 30, 2016Segment EBDA increase/

(decrease) Revenues increase/(decrease)(In millions of Canadian

dollars, except percentages)Trans Mountain 4.6 10 % (1.0) (1)%Cochin (2.8) (64)% (0.1) (1)%Puget Sound (1.6) (22)% (1.7) (18)%All others (including eliminations) 0.1 13 % 0.1 6 %

Total Pipelines 0.3 1 % (2.7) (3)%

Nine months ended September 30, 2017 versus Nine months ended September 30, 2016Segment EBDA increase/

(decrease) Revenues increase/(decrease)(In millions of Canadian

dollars, except percentages)Trans Mountain 2.7 2 % (1.4) (1)%Cochin (11.6) (64)% 1.4 4 %Puget Sound (6.7) (29)% (5.4) (19)%All others (including eliminations) 0.3 12 % 0.2 4 %

Total Pipelines (15.3) (8)% (5.2) (2)%

The changes in Segment EBDA for our Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA in the comparable three and nine month periods ended September 30, 2017 and 2016:

• increases of $4.6 million (10%) and $2.7 million (2%), respectively, from Trans Mountain primarily due to an increase in capitalized equity financing costs related to the TMEP and an increase in unrealized foreign exchange gains between the comparable periods primarily related to U.S. dollar denominated affiliate balances partially offset by an increase in operating expense largely due to timing changes and lower Washington state revenues;

• decreases of $2.8 million (64%) and $11.6 million (64%), respectively, from Cochin primarily due to a decrease in earnings resulting from unrealized foreign exchange losses between the comparable periods primarily related to U.S. dollar denominated receivables with affiliates and cash balances. In addition, the quarter-to-date and year-to-date decreases were partially impacted by lower and higher pipeline integrity expenses, respectively; and

• decreases of $1.6 million (22%) and $6.7 million (29%), respectively, from Puget Sound primarily due to lower revenues driven by lower pipeline throughput volumes.

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Terminals Segment

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2017 2016 2017 2016(In millions of Canadian

dollars, except operating statistics)Revenues 71.1 70.9 218.4 214.9Operating expenses, except DD&A (20.1) (17.4) (62.1) (57.3)Other expense, net (0.5) (0.2) (2.7) (0.2)Other income and unrealized foreign exchange loss,

net 2.2 (1.3) 5.5 5.2Segment EBDA 52.7 52.0 159.1 162.6

Change from prior period Increase/(Decrease)Revenues 0.2 —% 3.5 2 %Segment EBDA 0.7 1% (3.5) (2)%

2017 2016 2017 2016Bulk transload tonnage (MMtonnes)(a) 1.2 1.2 3.2 3.1Liquids leaseable capacity (MMBbl)(b) 7.3 7.3 7.3 7.3Liquids utilization %(c) 100% 100% 100% 100 %

______Note:(a) Million metric tonnes.(b) Million barrels.(c) The ratio of our storage capacity under contract to our estimated storage capacity.

Below are the changes in both Segment EBDA and revenues, in the comparable three and nine month periods ended September 30, 2017 and 2016:

Three months ended September 30, 2017 versus Three months ended September 30, 2016Segment EBDA increase/

(decrease) Revenues increase/(decrease)(In millions of Canadian

dollars, except percentages)North 40 Terminal 1.8 26 % 0.8 10 %Edmonton Rail Terminal joint venture 1.2 9 % — — %Alberta Crude Terminal joint venture (1.7) (68)% (1.9) (49)%Vancouver Wharves Terminal (0.8) (9)% 0.1 — %Edmonton South Terminal — — % 1.2 6 %All others (including eliminations) 0.2 (200)% — — %

Total Terminals 0.7 1 % 0.2 — %

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Nine months ended September 30, 2017 versus Nine months ended September 30, 2016Segment EBDA increase/

(decrease) Revenues increase/(decrease)(In millions of Canadian

dollars, except percentages)North 40 Terminal (0.1) — % 1.7 7 %Edmonton Rail Terminal joint venture 2.1 5 % 0.1 — %Alberta Crude Terminal joint venture (5.2) (69)% (5.6) (48)%Vancouver Wharves Terminal (2.6) (10)% 4.7 7 %Edmonton South Terminal 2.4 4 % 2.6 4 %All others (including eliminations) (0.1) (100)% — — %

Total Terminals (3.5) (2)% 3.5 2 %

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA in the comparable three and nine month periods ended September 30, 2017 and 2016:

• increase of $1.8 million (26%) and decrease of $0.1 million (0%), respectively, from North 40 Terminal. The quarter-to-date increase was primarily due to higher throughput volumes and ancillary service fees and an increase in unrealized foreign exchange gains between the comparable periods primarily related to U.S. dollar denominated accounts payable to Kinder Morgan. The year-to-date decrease was impacted by a decrease in unrealized foreign exchange gains between the comparable periods primarily related to U.S. dollar denominated accounts payable to Kinder Morgan which was partially offset by an increase in revenues due to higher throughput volumes and ancillary service fees;

• increases of $1.2 million (9%) and $2.1 million (5%), respectively, from Edmonton Rail Terminal joint venture primarily due to an increase in unrealized foreign exchange gains between the comparable periods primarily related to U.S. dollar denominated accounts payable to Kinder Morgan;

• decreases of $1.7 million (68%) and $5.2 million (69%), respectively, from Alberta Crude Terminal joint venture which was primarily driven by a contracted throughput fee reduction;

• decreases of $0.8 million (9%) and $2.6 million (10%), respectively, from Vancouver Wharves Terminal primarily due to lower margins associated with bulk handling operations. The year-to-date decrease was partially offset by an increase in earnings related to a customer contract buy-out, net of associated project write-off costs; and

• flat and increase of $2.4 million (4%), respectively, from Edmonton South Terminal primarily due to higher throughput volumes and ancillary service fees. The quarter-to-date flat performance was also impacted by higher operating cost resulting from a timing adjustment in the prior year quarter.

Foreign Exchange Gain on the Long-term Debt-Affiliates (KMI Loans)

During June, 2017 we repaid the principal on the long-term debt-affiliates (KMI Loans) utilizing proceeds from our IPO and the associated notes payable were terminated. The exchange rate at the time of repayment of the notes was 1.3470. Prior to then we were exposed to foreign currency risk related to the U.S. dollar denominated KMI Loans. As of September 30, 2016, we had amounts outstanding under the KMI Loans of $1,281.4 million. The Bank of Canada quoted U.S. dollar to Canadian dollar closing exchange rates on September 30, 2016 was 1.3116. As of December 31, 2016, we had amounts outstanding under the KMI Loans of $1,362.1 million. The Bank of Canada quoted U.S. dollar to Canadian dollar closing exchange rates on December 31, 2016 was 1.3427.

The $16.3 million favorable change between the three months ended September 30, 2017 and 2016 was due to the pay off of the notes in June, 2017. The $56.6 million unfavorable change between the nine months ended September 30, 2017 and 2016 on foreign exchange rate gains associated with the KMI Loans was primarily due to less strengthening of the Canadian dollar against the U.S. dollar during the 2017 period prior to the KMI Loans pay off in June, 2017.

General and Administrative Expense

The $0.9 million increase in general and administrative expense before certain items of $0.1 million in 2017 for the comparable third quarters of 2017 and 2016 was primarily driven by increased benefits costs and audit fees.

The $2.5 million increase in general and administrative expense before certain items of $2.6 million in 2017 for the comparable nine months of 2017 and 2016 was primarily driven by increased benefits costs and audit fees.

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Interest, net

Interest expense is presented as net of interest income and capitalized interest. Interest, net decreased $5.7 million for the comparable quarters of 2017 and 2016, driven primarily by a $10.9 million decrease due to the repayment of our long-term debt-affiliates (KMI Loans) in June, 2017 as part of our IPO and a $4.2 million increase in capitalized debt financing costs; partially offset by an increase of $9.2 million in interest expense, including interest on revolver, commitment fees and amortization of debt issue costs, associated with our new Credit Facility, See -Liquidity and Capital Resources below. Interest,net decreased $12.0 million for the comparable nine months of 2017 and 2016, driven primarily by a $14.4 million decrease due to the repayment of our long-term debt-affiliates (KMI Loans) in June, 2017 as part of our IPO and a $9.5 million increase in capitalized debt financing costs partially offset by an increase of $10.5 million in interest expense, including interest on revolver, commitment fees and amortization of debt issue costs associated with our new June, 2017 Credit Facility.

Net Income Attributable to Kinder Morgan Interest

Net income attributable to Kinder Morgan interest, represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that is owned by Kinder Morgan. The increase in net income attributable to Kinder Morgan interest for the three months ended September 30, 2017 when compared with the respective prior period was $8.4 million which was due to inclusion of earnings attributable to Kinder Morgan. The decrease in net income attributable to Kinder Morgan interest for the nine months ended September 30, 2017 when compared with the respective prior period was $87.6 million which was primarily attributable to the May, 2017 IPO and associated reduction in Kinder Morgan’s interest in us.

Income Taxes Three Months Ended September 30, 2017 vs Three Months Ended September 30, 2016

Income tax expense for the three months ended September 30, 2017 was $14.7 million, as comparable with 2016 income tax expense of $17.7 million. The $3.0 million decrease in income tax expense is primarily due to a reduction in pretax income and the impact of pension adjustments.

Nine Months Ended September 30, 2017 vs Nine Months Ended September 30, 2016

Income tax expense for the nine months ended September 30, 2017 was $42.4 million, as compared with 2016 income tax expense of $46.3 million.  The $3.9 million decrease in income tax expense is due primarily to a reduction in pretax income and the impact of pension adjustments.

Liquidity and Capital Resources

 On June 16, 2017, we closed on a $4.0 billion Revolving Construction Facility, a $1.0 billion Revolving Contingent Facility and a $500.0 million Revolving Working Capital Facility (collectively, the “Credit Facility”).

Any drawn funds on the Credit Facility bear interest (i) in the case of drawdowns by way of bankers’ acceptances or London Interbank Offered Rate Loans, at an annual rate of approximately the Canadian Dollar Offered Rate (“CDOR”) or the London Interbank Offered Rate, as the case may be, plus a fixed spread ranging from 1.50% to 2.50%, and (ii) in the case of loans in Canadian dollars or U.S. dollars, at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from 0.50% to 1.50%, in each case, with the range dependent on the credit ratings of the Company. In addition, drawdowns on the Credit Facility by way of issuance of letters of credit will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from 1.50% to 2.50%, with the range dependent on the credit ratings of the Company. The foregoing rates and fees will increase by 0.25% on the fourth anniversary of the Credit Facility. Any undrawn commitments incur a standby fee of 0.30% to 0.625%, with the range dependent on the credit ratings of the Company. The Credit Facility is guaranteed by the Company and all of the non-borrower subsidiaries of the Company and are secured by a first lien security interest on all of the assets of the Company and the equity and assets of the other guarantors. The Credit Facility has a five year term. The Credit Facility provides for customary positive and negative covenants, including limitations on liens, dispositions, amalgamations, liquidations and dissolutions.

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As of September 30, 2017, we were in compliance with all required covenants. As of September 30, 2017, we had $165.0 million outstanding on our construction facility and no outstanding borrowings under our working capital facility. For the three and nine months ended September 30, 2017, we incurred $3.9 million and $4.6 million in standby fees. Our Credit Facility includes various financial and other covenants including:

• a maximum ratio of consolidated total funded debt to consolidated capitalization of 70%;• restrictions on ability to incur debt;• restrictions on ability to make dispositions, restricted payments and investments;• restrictions on granting liens and on sale-leaseback transactions;• restrictions on ability to engage in transactions with affiliates; and• restrictions on ability to amend organizational documents and engage in corporate reorganization transactions.

Drawdowns on each of the Credit Facilities are subject to satisfaction of certain conditions precedent set out in the credit agreement relating thereto, a copy of which is available under the Company’s profile on SEDAR at www.sedar.com. 

General

As of September 30, 2017, we had $330.3 million of cash and cash equivalents, an increase of $171.3 million (108%) from December 31, 2016. We believe that, our cash position, our cash flows from operating activities and our access to cash through the Credit Facility are considered adequate to manage our day-to-day cash requirements.

We generated cash flows from operating activities of $158.8 million and $261.6 million in the first nine months of 2017 and 2016, respectively, (the decrease of 39% for the first nine months of 2017 versus 2016 are discussed below in ‘‘- Cash Flows - Operating Activities’’). Prior to our May, 2017 IPO, we also received $70.2 million of borrowings and $10.8 million of contributions from Kinder Morgan subsidiaries that were used to partially fund our expansion capital expenditures.

Short-term Liquidity

As of September 30, 2017 and December 31, 2016, our principal source of short-term liquidity was cash from operating activities. We had working capital (defined as current assets less current liabilities) deficits of $44.2 million and $200.6 millionas of September 30, 2017 and December 31, 2016, respectively. Generally, our working capital balance varies due to factors such as timing differences in the collection and payment of receivables and payables, and changes in our cash and cash equivalent balances after payments for investing activities net of cash received from operating and financing activities. We expect to continue to operate with a working capital deficit during the construction of the TMEP. Such a deficit will be funded primarily through the use of the Construction Facility, which has been put in place to fund the cost of the TMEP, as well as dividend and distribution reinvestments, term debt and the issuance of preferred equity. In addition, we will be in a position to utilize the $500.0 millionWorking Capital Facility for general corporate purposes, including the funding of growth capital expenditures for non-TMEP expansion projects of KML. In addition, we received $293.0 million of net proceeds from the issuance of the Preferred Series 1 Shares in August, 2017.

Long-term Financing

We expect to fund the TMEP capital expenditures through (i) additional borrowings on our Credit Facility; (ii) the issuance of additional preferred shares; (iii) the issuance of long-term notes payable; (iv) retained cash flow from operations; and (v) the issuance of additional restricted voting stock or a combination of the above.

Credit Ratings

The following credit ratings information is provided as it relates to the Company’s financing costs and liquidity. Specifically, credit ratings affect the Company’s ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current ratings on the Company’s debt by its rating agencies, particularly a downgrade below investment-grade ratings, could adversely affect the Company’s cost of financing and its access to sources of liquidity and capital. In addition, changes in credit ratings may affect the Company’s ability, and the associated costs, to enter into normal course derivative or hedging transactions. Credit ratings are intended to provide investors with an independent measure of credit quality of any issues of securities.

DBRS Limited (“DBRS”) has assigned a debt rating of 'BBB (high)' to KMCU with a stable trend. KMCU is a wholly-owned subsidiary of the Limited Partnership and is the primary borrower under the Credit Facilities. DBRS also assigned a Pfd-3 (high), Stable rating to the Company’s preferred shares. Standard & Poor’s Rating Services (“S&P”) has assigned a rating of 'BBB'

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corporate credit rating to the Company and KMCU, an issue-level rating of 'BBB' to the borrower's Credit Facilities and a stable outlook. S&P also assigned a P-3 (High) rating to the Company’s preferred shares.

These securities ratings are not recommendations to purchase, hold or sell the securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

On October 17, 2017, Moody’s Investors Service (“Moody’s”) assigned a Baa3 senior secured rating to KMCU’s credit facility. The rating outlook is stable. Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C; a rating of Baa by Moody’s is within the fourth highest of nine categories and is assigned to obligations that are judged to be medium-grade and are subject to moderate credit risk. Moody’s appends numerical modifiers 1, 2 and 3 to each generic rating classification; the modifier 3 indicates a ranking in the lower end of that generic rating category. A Moody’s rating outlook is an opinion regarding the likely rating direction over the medium term. A stable outlook indicates a low likelihood of a rating change over the medium term.

Capital Expenditures

We account for our capital expenditures in accordance with U.S. GAAP. We also distinguish between capital expenditures that are sustaining capital expenditures (also referred to as ‘‘maintenance’’ capital expenditures) and those that are expansion capital expenditures (also referred to as ‘‘discretionary’’ capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF. Sustaining capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

Budgeting of sustaining capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those sustaining capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional sustaining capital expenditures that we expect will produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our segments from which it generally expects to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as sustaining or as expansion capital expenditures is made on a project level. The classification of capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification of capital expenditures has an impact on DCF because capital expenditures that are classified as discretionary capital expenditures are not deducted from DCF, while those classified as sustaining capital expenditures are.

Our capital expenditures for the nine months ended September 30, 2017, and the amount that is expected to be spent to sustain and grow KML for the remainder of 2017 are as follows:

Nine Months Ended September 30, 2017 Remaining 2017 Total

(In millions of Canadian dollars)Sustaining capital expenditures 27.3 20.1 47.4Expansion capital expenditures (a) 449.2 266.7 715.9______Note:(a) Nine-months 2017 excludes $68.7 million of net changes from accrued capital expenditures, contractor retainage, capitalized equity financing

costs and other.

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Cash Flows

The following table summarizes KML’s net cash flows from operating, investing and financing activities for each period presented:

Nine Months EndedSeptember 30,

2017 2016(In millions of Canadian dollars)Net cash provided by (used in):

Operating activities 158.8 261.6Investing activities (420.0) (190.1)Financing activities 433.8 12.4Effect of Exchange Rate Changes on Cash and Cash Equivalents (1.3) (1.6)

Net increase in cash and cash equivalents 171.3 82.3

Operating Activities

The net decrease of $102.8 million in cash provided by operating activities in nine months ended September 30, 2017compared to the same period in 2016 was primarily attributable to:

• a $97.1 million net decrease in cash associated with net changes in operating assets and liabilities, primarily due to interest payments made to Kinder Morgan subsidiaries when we paid off the KMI Loans in 2017, and due to the timing of the collection of trade and affiliate receivables and payables. These decreases were partially offset by an increase in cash due to favorable changes from the dock premiums and toll collections received from Westridge Marine Terminal dock customers; and

• a $5.7 million decrease in operating cash flow resulting from the combined effects of adjusting the $69.7 million decrease in net income for the period-to-period increase in non-cash items primarily consisting of the following: (i) change in foreign exchange due to foreign exchange rate on the KMI Loans; (ii) DD&A expenses; (iii) deferred income taxes; (iv) capitalized equity financing costs; and (v) other non-cash items.

Investing Activities

The $229.9 million net increase in cash used in investing activities in nine months ended September 30, 2017 compared to the same period in 2016 was primarily attributable to a $230.4 million increase in capital expenditures for expansion projects.

Financing Activities

The net increase of $421.4 million in cash provided by financing activities in the nine months ended September 30, 2017, compared to the same period in 2016 was primarily attributable to:

• $1,671.0 million of proceeds from our IPO, net of fees paid;• $293.5 million of proceeds from the preferred shares issuance in 2017, net of fees paid; and• $90.3 million of net proceeds from the net draw from our construction and working capital facilities, net of debt issue costs;

partially offset by,• a $1,618.8 million decrease in cash related to the long-term affiliate debt activity primarily due to a $1,606.3 million decrease

in cash in 2017 as we paid off the KMI Loans using proceeds from our IPO;• a $10.2 million decrease in cash due to the contribution received from Kinder Morgan in 2016 and none in 2017; and• a $4.3 million decrease in cash due to the dividend we paid to our share owners net of DRIP reinvestment in 2017.

Dividends and Distributions

Dividends on Restricted Voting Shares

We established a dividend policy pursuant to which we may pay a quarterly dividend on our restricted voting shares in an amount based on a portion of our DCF. We are currently targeting an initial dividend in the amount of approximately $0.65 per Restricted Voting Share on an annualized basis, assuming the payout of substantially all of our DCF excluding capitalized equity financing costs. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the

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discretion of our board of directors. The actual amount of cash dividends paid to shareholders, if any, will depend on numerous factors including: (i) our results of operations; (ii) our financial requirements, including the funding of current and future growth projects; (iii) the amount of distributions paid indirectly by the Limited Partnership to us through the general partner of the Limited Partnership, including any contributions from the completion of our growth projects; (iv) the satisfaction by us and the General Partner of certain liquidity and solvency tests; (v) any agreements relating to our indebtedness or the Limited Partnership; and (vi) the cost and timely completion of current and future growth projects. We intend to pay quarterly dividends if any, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of our restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter. We anticipate that any dividends paid on the Restricted Voting Shares will be designated as “eligible dividends” for Canadian income tax purposes, unless otherwise notified, and we will include disclosure on our website to this effect.

Following closing of our IPO, and subject to any required regulatory and stock exchange approvals, we implemented a dividend reinvestment plan (DRIP) pursuant to which holders (excluding holders not resident in Canada) of Restricted Voting Shares may elect to have all cash dividends of the Company payable to any such shareholder automatically reinvested in additional Restricted Voting Shares at a price per share calculated by reference to the volume weighted average of the closing price of the Restricted Voting Shares on the stock exchange on which the Restricted Voting Shares are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by the board of directors, in its sole discretion). The market discount has initially been set at 3%.

On August 15, 2017, we paid a dividend of $0.0571 per Restricted Voting Share to restricted voting shareholders of record as of the close of business on July 31, 2017 for the quarterly period ended June 30, 2017. This initial dividend was prorated from May 30, 2017, the day we closed on our IPO, to June 30, 2017 and amounted to approximately $5.9 million in total. We paid approximately $4.3 million of this dividend to restricted voting shareholders in cash and $1.6 million of the remaining dividend in the form of 94,003 Restricted Voting Shares issued in lieu of cash dividends under the restricted voting shareholders’ DRIP.

On October 17, 2017, our board of directors declared a dividend of $0.1625 per Restricted Voting Share ($0.65 annualized), payable on November 15, 2017, to restricted voting shareholders of record as of the close of business on October 31, 2017.

For 2017, we expect to pay a prorated dividend of $0.3821 per Restricted Voting Share (or $0.65 per annualized).

Dividends on Series 1 Preferred Shares

Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and $1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by our board of directors, for the initial fixed rate period to but excluding November 15, 2022.

On October 17, 2017, our board of directors declared a cash dividend of $0.3308 per share of our Series 1 Preferred Shares for the period from and including August 15, 2017 through and including November 14, 2017, which is payable on November 15, 2017 to Series 1 preferred shareholders of record as of the close of business on October 31, 2017.

Special Voting Shares (Kinder Morgan Interest)

On August 15, 2017, the Limited Partnership paid a pro rated distribution of $0.0571 per Class B limited partnership unit to Kinder Morgan for the quarterly period ended June 30, 2017 that amounted to approximately $13.8 million in total. Approximately $10.4 million of this distribution was paid to Kinder Morgan in cash, and $3.4 million of the remaining distribution in the form of 202,826 Class B limited partnership units issued under its distribution reinvestment plan. Kinder Morgan (as the sole holder of the Class B limited partnership units) subject to certain limitations, is entitled to reinvest its distributions into additional Class B limited partnership units on the same general terms as described above for the restricted voting shareholders’ distribution reinvestment plan.

Other

Off Balance Sheet Arrangements

There have been no material changes in our contractual obligations that would affect the disclosures presented in our audited consolidated financial statements for the years ended December 31, 2016, included in our Final Prospectus dated May 25, 2017, except as noted below.

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During June 2017, we repaid the KMI Loans utilizing proceeds from our IPO. As of December 31, 2016, the KMI Loans outstanding balance on our consolidated balances sheet was $1,362.1 million, which were comprised of U.S. dollar denominated five-year notes payable and other debt with Kinder Morgan subsidiaries.

Outstanding Share Data

As of October 23, 2017, we had 103,036,003 Restricted Voting Shares, 242,260,826 Special Voting Shares, 12,000,000 million Series 1 Preferred Shares and 793,825 restricted stock awards outstanding.

Controls and Procedures

We are responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings." The objective of this instrument is to improve the quality, reliability and transparency of information that is filed or submitted under securities legislation. Our ICFR is a process designed under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. GAAP. The internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of the Company, provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Our ICFR may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Company’s policies and procedures.

There were no changes in the Company's ICFR that occurred during the period beginning on July 1, 2017 and ended on September 30, 2017 that has materially affected, or is reasonably likely to materially affect, the Company's ICFR.

Risks and Risk Management

For a detailed discussion of the risks and trends that could affect our financial performance and the steps that we take to mitigate these risks, our MD&A and audited consolidated financial statements included in the Final Prospectus dated May 25, 2017. Refer to Note 9 and 10 “ Contingencies and Litigation” and “Risk Management and Financial Instruments” of the Interim Consolidated Financial Statements. Also, see “Cautionary Statement Regarding Forward-Looking Information” in this MD&A and “Risk Factors” in the Final Prospectus for the IPO dated May 25, 2017, a copy of which is available under KML's profile on SEDAR at www.sedar.com.

Transactions with Affiliates

We have transactions with Kinder Morgan and its subsidiaries. Refer to Note 5 “Transactions with Related Parties” of the Interim Consolidated Financial Statements for the amounts due to or from affiliates on the consolidated balance sheets and the classification of revenue and expenses in the consolidated statements of income.

Accounting Policies, Judgments and Estimates

Our significant accounting policies and critical judgments and estimates used in the preparation of our consolidated financial statements are summarized in our MD&A and audited consolidated financial statements included in the Final Prospectus dated May 25, 2017. There have been no material changes to our significant accounting policies and critical accounting estimates and judgments during the nine months ended September 30, 2017.

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Future Accounting Changes

Revenue from contracts with customers (Topic 606)

On May 28, 2014, the FASB issued ASU No. 2014 09, “Revenue from Contracts with Customers” followed by a series of related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensive guidance for transactions such as service revenue, contract modifications, and multiple element arrangements.

We are in the process of comparing our current revenue recognition policies to the requirements of Topic 606 for each of our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete, and we have not concluded on the overall impacts of adopting Topic 606. Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period, as applicable. We anticipate utilizing the modified retrospective method to adopt the provisions of this standard effective January 1, 2018, which requires us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be revised.

Accounting for Leases

On February 25, 2016, the FASB issued ASU No. 2016 02, “Leases (Topic 842).” This ASU requires that lessees will be required to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016 02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016 02.

Changes in Restricted Cash as presented in the Statement of Cash Flows

On November 17, 2016, the FASB issued ASU No. 2016 18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows. ASU No. 2016 18 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.

Goodwill Impairment Testing

On January 26, 2017, the FASB issued ASU No. 2017 04, “Simplifying the Test for Goodwill Impairment (Topic 350)” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017 04 will be effective for us as of January 1, 2020. We are currently reviewing the effect of this ASU to our financial statements.

Presentation of Retirement Benefit Costs

On March 10, 2017, the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715).” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allow only the service cost component of net benefit cost to be eligible for capitalization, and how to present the service cost component and the other components of net benefit cost in the income statement. ASU No. 2017-07 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.

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Selected Quarterly Financial Data

2017 2016 2015

Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4(In millions of Canadian dollars, except for per share amounts)Revenues 167.0 168.7 164.5 174.2 169.5 165.8 166.6 182.8Operating Income 50.6 50.7 51.1 56.4 57.4 63.4 60.2 72.4Foreign exchange (loss) gain (0.2) (16.0) 10.9 (26.7) (17.0) 5.8 70.5 (40.0)Net Income 42.4 25.1 46.8 17.7 20.3 51.7 112.0 11.2Net Income Available to Restricted Voting

Stockholders 11.7 4.2Basic and Diluted Earnings Per Restricted

Voting Share 0.11 0.11

During the last two years, the fluctuating Canadian dollar to U.S. dollar exchange rate resulted in overall period to period foreign currency exchange net loss of ($32.0) million and net gain of $19.3 million for the year ended September 30, 2017 and 2016, respectively, primarily associated with the KMI Loans denominated in U.S. dollars, the principal of which was paid off with proceeds from our IPO. This represents a combined $51.3 million decrease to earnings on a year to year basis.

Period to period decreases in operating income have been driven by lower earnings primarily from the Cochin and Puget Sound pipeline systems and higher general and administrative expense and DD&A. Earnings from the Cochin and Trans Mountain pipeline systems are lower over the trailing twelve month period as compared to the prior twelve month period primarily due to higher operations and maintenance costs. Earnings from Puget Sound have decreased period to period due to lower volumes to Washington State. In addition, DD&A expense  is higher due to depreciation true-up adjustments applied to the Jet Fuel facility and Edmonton Rail Terminals.  General and administrative costs are also higher due to an increase in pension expense as well as TMEP financing efforts incurred in the last year.  These period to period decreases in earnings were partially offset by lower interest expense from the KMI Loans that were repaid and terminated in the second quarter of 2017.

Public Securities Filings

Additional information about the Company is filed with the Canadian securities regulatory authorities under the Company’s profile on SEDAR at www.sedar.com.

Cautionary Statement Regarding Forward-Looking Information

This MD&A includes “forward-looking statements,” “financial outlook” and “forward-looking information” (collectively referred to as “forward-looking statements”) within the meaning of applicable Canadian securities legislation.

Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Forward-looking statements may be identified by words such as “anticipate,” “expect,” “will,” “believe,” “project,” “target,” “intend,” “should,” “may,” “future” or the negative of those terms or other variations of them or comparable terminology. In particular, but without limitation, this MD&A contains forward-looking statements pertaining to the following:

• the TMEP and Base Line Terminal project, including completion of such projects, anticipated costs and funding, scheduling, governmental impact, commissioning and in-service dates, future benefits and utilization, anticipated project returns and impacts of such projects;

• for 2017, we expect to generate Adjusted EBITDA of between $380.0 million and $390.0 million and DCF of approximately $315.0 million to $320.0 million, and declare a prorated dividend of $0.3821 per Restricted Voting Share (or $0.65 per Restricted Voting Share on an annualized basis);

• our expectation is to continue to operate with a working capital deficit during the construction of the TMEP and to the funding thereof;

• anticipated future sustaining and expansion capital expenditures;• the anticipated dividends and intended payment thereof; and• the anticipated adoption of new accounting standards.

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Forward-looking statements are not guarantees of future performance. They involve risks, uncertainties and assumptions. Any financial outlook or other forward-looking statements provided in this MD&A have been included for the purpose of providing information relating to management’s current expectations and plans for the future, are based on a number of significant assumptions and may not be appropriate, and should not be used, for any other purpose. Future actions, conditions or events and future results of operations may differ materially from those expressed in forward-looking statements. Many of the factors that will determine these results, including our ability to pay dividends, are beyond our ability to control or predict. As noted above, the forward-looking statements included in this MD&A are based on a number of material assumptions including, among others, those highlighted below. Specific factors that could cause actual results to differ from those in the forward-looking statements provided in this MD&A include, but are not limited to:

• issues, delays or stoppages associated with major expansion projects, including the TMEP;• changes in public opinion, public opposition, the resolution of issues relating to the concerns of individuals, special interest

or Aboriginal groups, governmental organizations, non-governmental organizations and other third parties that may expose us to higher project or operating costs, project delays or even project cancellations;

• significant unanticipated cost overruns or required capital expenditures;• the breakdown or failure of equipment, pipelines and facilities; releases or spills; operational disruptions or service

interruptions; and catastrophic events;• our ability to access sufficient external sources of financing, and the cost of such financing; and• changes to regulatory, environmental, political, legal operational and geological considerations.

The foregoing list should not be construed to be exhaustive. In addition to the foregoing, important additional information respecting the material assumptions, expectations and risks applicable to the financial outlook and other forward-looking statements included in this MD&A are set out in the Final Prospectus dated May 25, 2017, copies of which are available under our profile on SEDAR at www.sedar.com, under the headings “Notice to Investors - Forward-Looking Statements”, “Notice to Investors - Growth Estimates” and “Risk Factors”, and readers are urged to review and carefully consider such information prior to making any investment decision in respect of our Restricted Voting Shares. Our risk factors could cause actual results to vary materially from those contained in the forward-looking statements.

The forward-looking statements contained in this MD&A are made as of the date of this MD&A. Except as required by applicable securities laws, we assume no obligation to update publicly or otherwise any forward-looking statements or the foregoing risks and assumptions affecting such forward-looking statements, whether as a result of new information, future events or otherwise.

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13APR201709055563

No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. These securities have not been and willnot be registered under the United States Securities Act of 1933, as amended (the ‘‘U.S. Securities Act’’), or any state securities laws. Accordingly, thesesecurities may not be offered or sold within the United States unless registered under the U.S. Securities Act and applicable state securities laws or exceptpursuant to exemptions from the registration requirements of the U.S. Securities Act and applicable state securities laws in accordance with theUnderwriting Agreement (as defined herein). This prospectus constitutes a public offering of these securities only in those jurisdictions where they may belawfully offered for sale and only by persons permitted to sell these securities. See ‘‘Plan of Distribution’’.

PRELIMINARY PROSPECTUSInitial Public Offering April 24, 2017

KINDER MORGANCANADA LIMITED

$ �

� Restricted Voting Shares

Kinder Morgan Canada Limited (the ‘‘Company’’) is offering for sale � restricted voting shares (the ‘‘Restricted Voting Shares’’) at aprice of $ � per Restricted Voting Share (the ‘‘Offering’’).

The Company has been formed to acquire an approximate � % interest (an approximate � % interest if the Over-AllotmentOption (as defined below) is exercised in full) in Kinder Morgan Canada Limited Partnership (the ‘‘Limited Partnership’’). The LimitedPartnership, prior to the closing of the Offering, will own the Business (as defined herein) of Kinder Morgan (as defined herein), consistingof the Trans Mountain pipeline system, along with its associated terminals and storage facilities, the Puget Sound and Jet Fuel pipelinesystems, the Canadian Cochin pipeline system (as defined herein), the Vancouver Wharves Terminal in British Columbia and variousmerchant liquids storage and handling terminals and interests in crude oil loading facilities in the Edmonton, Alberta area. Upon closing ofthe Offering, Kinder Morgan will hold an approximate � % interest (an approximate � % interest if the Over-Allotment Option isexercised in full) in the Limited Partnership.

Upon closing of the Offering, Kinder Morgan will own approximately � % of the outstanding Company Voting Shares (as definedherein) (approximately � % if the Over-Allotment Option is exercised in full) through its indirect ownership of � Special VotingShares (as defined herein) of the Company. Kinder Morgan has advised the Company that it intends to remain the majority votingshareholder in the Company. Certain aspects of the business, operations and day-to-day administration of the Company, the GeneralPartner (as defined herein) and the Limited Partnership, and consequently the Business, will be managed and conducted by KinderMorgan Canada Inc. (‘‘KMCI’’), an Alberta corporation controlled by the Limited Partnership, through the Services Agreement(as defined herein) and under the supervision of the executive officers and the board of directors of the Company (the ‘‘Board ofDirectors’’). See ‘‘Relationship with Kinder Morgan’’, ‘‘The Company and the Limited Partnership — Services Agreement’’ and ‘‘Risk Factors —Risks Relating to the Company’s Relationship with Kinder Morgan’’.

Price: $ � per Restricted Voting Share

Price to Underwriters’ Net Proceeds tothe Public Fee(1) the Company(2)

Per Restricted Voting Share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ � $ � $ �Total Offering(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ � $ � $ �

Notes:

(1) Upon closing of the Offering, the Company will pay the Underwriters (as defined herein) a cash fee of � % of the gross proceeds of the Offering.See ‘‘Plan of Distribution’’.

(2) Before deducting the expenses of the Offering, estimated to be approximately $ � , and which, together with the Underwriters’ fee payable pursuantto the Offering, will be paid by the Company out of the proceeds of the Offering.

(3) The Company has granted to the Underwriters an option (the ‘‘Over-Allotment Option’’), exercisable at the Underwriters’ discretion at any time, inwhole or in part, until 30 days following closing of the Offering, to purchase, at the offering price, up to an additional � Restricted Voting Shares(representing 15% of the Restricted Voting Shares offered under this prospectus) to cover over-allotments, if any, and for market stabilizationpurposes. If the Over-Allotment Option is exercised in full, the total Price to the Public, Underwriters’ Fee and Net Proceeds to the Company inrespect of the Offering will be $ � , $ � and $ � , respectively. This prospectus qualifies the grant of the Over-Allotment Option and thedistribution of the Restricted Voting Shares pursuant to the exercise of the Over-Allotment Option. A purchaser who acquires Restricted Voting Sharesforming part of the Underwriters’ over-allocation position acquires such Restricted Voting Shares under this prospectus, regardless of whether theover-allocation position is ultimately filled through the exercise of the Over-Allotment Option or secondary market purchases. See ‘‘Plan ofDistribution’’.

(continued on next page)

A copy of this preliminary prospectus has been filed with the securities regulatory authorities in each of the provinces and territories in Canada but has notyet become final for the purpose of the sale of securities. Information contained in this preliminary prospectus may not be complete and may have to beamended. The securities may not be sold until a receipt for the prospectus is obtained from the securities regulatory authorities.

Appendix C1 to VAFFC IR No. 1

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(continued from cover)

The following table sets out the number of Restricted Voting Shares that may be sold by the Company pursuant to the Over-Allotment Option.

Maximum Size or Number ofUnderwriters’ Position Securities Available Exercise Period Exercise Price

Over-Allotment Option Option to acquire up to � At any time until 30 days following $ � per Restricted VotingRestricted Voting Shares closing of the Offering Share

The terms of the Offering will be determined by negotiation between Kinder Morgan and the Company, on the one hand, and TD Securities Inc.and RBC Dominion Securities Inc. (collectively, the ‘‘Underwriters’’) on the other hand. See ‘‘Plan of Distribution’’.

The Underwriters, as principals, conditionally offer the Restricted Voting Shares offered under this prospectus, subject to prior sale, if, as andwhen sold and delivered by the Company to, and accepted by, the Underwriters in accordance with the conditions contained in the UnderwritingAgreement referred to under ‘‘Plan of Distribution’’ and subject to the approval of certain legal matters on behalf of Kinder Morgan and theCompany by Blake, Cassels & Graydon LLP and on behalf of the Underwriters by Osler, Hoskin & Harcourt LLP.

In connection with the Offering, the Underwriters may over-allocate or effect transactions which stabilize, maintain or otherwise affect themarket price of the Restricted Voting Shares at levels other than those which otherwise might prevail on the open market. The Underwriters mayoffer the Restricted Voting Shares at a price lower than that stated above. Any such reduction in price will not affect the proceeds received by theCompany. See ‘‘Plan of Distribution’’.

Subscriptions in respect of the Offering will be received subject to rejection or allotment in whole or in part and the Underwriters reserve theright to close the subscription books at any time without notice. It is expected that closing of the Offering will occur on or about � , 2017 orsuch later date as Kinder Morgan, the Company and the Underwriters may agree, but in any event not later than � , 2017. The RestrictedVoting Shares offered under this prospectus are to be taken up by the Underwriters, if at all, on or before a date not later than 42 days after thedate of the receipt for the final prospectus.

Except in certain limited circumstances, no certificates representing Restricted Voting Shares will be issued to purchasers in the Offering. Instead,on the date of closing of the Offering, the purchasers of Restricted Voting Shares will have their securities registered in the name of CDS Clearingand Depository Services Inc. or its nominee (‘‘CDS’’) and electronically deposited with CDS. Purchasers of Restricted Voting Shares will receiveonly a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficialinterest in the Restricted Voting Shares is acquired.

There is currently no market through which the Restricted Voting Shares may be sold and purchasers may not be able to resell Restricted VotingShares purchased under this prospectus. This may affect the pricing of the Restricted Voting Shares in the secondary market, the transparency andavailability of trading prices, the liquidity of the Restricted Voting Shares and the extent of issuer regulation. See ‘‘Risk Factors — Risks Relating tothe Offering and the Restricted Voting Shares’’.

An investment in the Restricted Voting Shares is speculative and is subject to a number of risks that should be considered by a prospectivepurchaser. See ‘‘Risk Factors’’.

The Board of Directors is expected to establish a dividend policy pursuant to which the Company will pay a quarterly dividend, initially expectedto be in the amount of $ � per Restricted Voting Share on an annualized basis. Assuming closing of the Offering occurs on � , 2017, thefirst dividend for the period from closing of the Offering to � , 2017 is expected to be paid on or about � , 2017 to shareholders of recordon � , 2017 in the amount of $ � per Restricted Voting Share. The payment of dividends is not guaranteed and the amount and timing ofany dividends payable will be at the discretion of the Board of Directors and subject to a variety of factors. See ‘‘Dividend Policy’’ and ‘‘RiskFactors — Risks Relating to the Offering and the Restricted Voting Shares — Cash Dividend Payments are Not Guaranteed’’.

A return on an investment in the Restricted Voting Shares is not comparable to the return on an investment in a fixed-income security. Therecovery by shareholders of their initial investment is at risk, and the anticipated return on that investment is based on many performanceassumptions. Although the Company currently intends to pay quarterly dividends to shareholders, those cash dividends may be reduced orsuspended. The actual amount of cash dividends paid to shareholders, if any, will depend on numerous factors including: (i) the results ofoperations for the Business; (ii) financial requirements for the Business, including the funding of current and future growth projects; (iii) theamount of distributions paid indirectly by the Limited Partnership to the Company through the General Partner, including any contributions fromthe completion of the Company’s growth projects; (iv) the satisfaction by the Company and the General Partner of certain liquidity and solvencytests; and (v) any agreements relating to the indebtedness of the Company or the Limited Partnership. In addition, the market value of theRestricted Voting Shares may decline if the Company is unable to meet its target cash dividend in the future, which decline may be significant.See ‘‘Risk Factors’’.

It is important for purchasers of Restricted Voting Shares to consider each of the particular risk factors that may affect the Company (includingwith respect to the industry, business, operations and growth and development plans and projects of the Business) and, therefore, the marketvalue of the Restricted Voting Shares and the stability of the Company’s dividends, if any, that shareholders may receive. See ‘‘Risk Factors’’.

Each of TD Securities Inc. and RBC Dominion Securities Inc. is, directly or indirectly, an affiliate of a bank which is a lender to Kinder Morgan orits affiliates and which, following closing of the Offering, is expected to be a lender under the Credit Facility (as defined herein). Consequently,under applicable Canadian Securities Laws, the Company may be considered to be a connected issuer to such Underwriters. See ‘‘RelationshipsBetween the Company and Certain Underwriters’’.

Kinder Morgan, Inc. is incorporated under the laws of a foreign jurisdiction and each of Steven J. Kean, Kimberly A. Dang and Dax A. Sandersresides outside of Canada. Each of Kinder Morgan, Inc., Steven J. Kean, Kimberly A. Dang and Dax A. Sanders has appointed the Company(Kinder Morgan Canada Limited) at Suite 2700, 300 – 5th Avenue S.W., Calgary, Alberta T2P 5J2, as agent for service of process.

Purchasers are advised that it may not be possible for investors to enforce judgments obtained in Canada against any person or company that isincorporated, continued or otherwise organized under the laws of a foreign jurisdiction or resides outside of Canada, even if the party hasappointed an agent for service of process.

The financial statements of the Company and the Business included in this prospectus have been prepared in accordance with GAAP (as definedherein). See ‘‘Notice to Investors — Financial Statements and Exemptive Relief’’ and ‘‘Exemptions from Certain Disclosure Requirements’’.

The Company is incorporated under the ABCA (as defined herein). The head office of the Company is located at Suite 2700, 300 – 5th AvenueS.W., Calgary, Alberta T2P 5J2 and the registered office of the Company is located at Suite 3500, 855 – 2nd Street S.W., Calgary, Alberta T2P 4J8.

Appendix C1 to VAFFC IR No. 1

Page 23 of 62

TABLE OF CONTENTS

Page

GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

ABBREVIATIONS AND CONVERSIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

NOTICE TO INVESTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

About this Prospectus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Forward-Looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Non-GAAP Financial Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Allowance for Funds Used During Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Growth Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Marketing Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Financial Statements and Exemptive Relief . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Market, Independent Third Party and Industry Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

THE OFFERING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

PROSPECTUS SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

The Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Investment Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

The Trans Mountain Expansion Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Formation of the Company and the Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

The Reorganization and the Offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Relationship with Kinder Morgan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Summary of Selected Historical Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Risks Relating to the Development of the Trans Mountain Expansion Project and the Business andOperations of the Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Risks Relating to the Company’s Relationship with Kinder Morgan . . . . . . . . . . . . . . . . . . . . . . . . 44

Risks Relating to the Offering and the Restricted Voting Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

THE COMPANY AND THE LIMITED PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Formation of the Company and the Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

The Reorganization and the Offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Intercorporate Relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Services Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

THE BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Investment Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Trans Mountain Pipeline System, Terminals and Related Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . 60

Cochin Pipeline System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Terminals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Operations Management of the Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

Regulatory Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

i

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Page

RELATIONSHIP WITH KINDER MORGAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

The Reorganization and the Offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Kinder Morgan’s Ownership in the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Agreements Between the Company and Kinder Morgan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

DESCRIPTION OF SHARE CAPITAL AND PARTNERSHIP UNITS . . . . . . . . . . . . . . . . . . . . . . . 91

The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

The Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

The General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Dividend Reinvestment Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

DIVIDEND POLICY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

DISTRIBUTABLE CASH FLOW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

SELECTED HISTORICAL FINANCIAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

CONSOLIDATED CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

DESCRIPTION OF INDEBTEDNESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

KMI Loans and Other Indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

USE OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

MANAGEMENT’S DISCUSSION AND ANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Cautionary Statement Regarding Forward-Looking Information and Non-GAAP Financial Measures 102

Presentation of Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Activities of the Company Since its Incorporation through to Closing of the Offering . . . . . . . . . . . . 103

Results of Operations of the Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

Risks and Risk Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

Transactions with Affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

Critical Accounting Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

Accounting Policy Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

Selected Quarterly Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

Outstanding Share Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

DIRECTORS AND EXECUTIVE OFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

Directors and Executive Officers Biographical Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Security Ownership by Directors and Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

External Directorships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Cease Trade Orders, Bankruptcies, Penalties or Sanctions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Conflicts of Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Insurance Coverage and Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

CORPORATE GOVERNANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

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Page

Independence of the Board of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

Board of Directors’ Mandate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Position Descriptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Orientation and Continuing Education . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Code of Ethics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

Nomination and Election of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

Board Committees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

Assessment of Directors, the Board of Directors and Board Committees . . . . . . . . . . . . . . . . . . . . . 129

Diversity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Compensation of Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Compensation of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

PLAN OF DISTRIBUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

Over-Allotment Option . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

Price Stabilization, Short Positions and Passive Market Making . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

Lock-Up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

RELATIONSHIPS BETWEEN THE COMPANY AND CERTAIN UNDERWRITERS . . . . . . . . . . . 135

KINDER MORGAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

PRIOR SALES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON RESALE . . . . . . . . . . . . . . . . 137

PROMOTER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS . . . . . . . . . . . 137

ELIGIBILITY FOR INVESTMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138

CERTAIN CANADIAN FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . 138

Holders Resident in Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

Holders Not Resident in Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

LEGAL PROCEEDINGS AND REGULATORY ACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

EXEMPTIONS FROM CERTAIN DISCLOSURE REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . . . 141

AUDITORS, TRANSFER AGENT AND REGISTRAR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

EXPERTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

MATERIAL CONTRACTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

RIGHTS OF WITHDRAWAL AND RESCISSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

INDEX TO FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1

APPENDIX ‘‘A’’ — MANDATE OF THE BOARD OF DIRECTORS . . . . . . . . . . . . . . . . . . . . . . . . A-1

APPENDIX ‘‘B’’ — AUDIT COMMITTEE CHARTER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

CERTIFICATE OF THE COMPANY AND THE PROMOTER . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

CERTIFICATE OF THE UNDERWRITERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2

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The Trans Mountain pipeline regularly ships multiple products, including refined petroleum, syntheticcrude oil, light crude oil and heavy crude oil, and it is the only pipeline in North America that carries bothrefined products and crude oil together in the same line. This process, known as ‘‘batching’’, means that a seriesof products can follow one another through the pipeline in a ‘‘batch train’’. A typical batch train in the TMPLmainline is made up a variety of materials being transported for different shippers; however, any product movedin the pipeline must meet Trans Mountain’s tariff requirements, which include technical specifications for anyproducts accepted for transportation in the TMPL system. While products next to each other in the pipeline mix,product interface is kept to a minimum by moving the products in a specific sequence, as illustrated below.Products that do mix are re-refined for use.

HeavyCrude

LightCrude Distillates Gasoline Distillates

LightCrude

HeavyCrude

In order to optimize batches to achieve maximum throughput, Trans Mountain has built tanks, pumps andother ancillary equipment which enable connection and staging of batches to be delivered to the TMPL mainlinepipe. Tanks are used to accumulate enough of a particular type of product to make up an efficient batch. Whileshippers are permitted to deliver oil to the mainline at a rated throughput to avoid the use of tanks, the TMPLtanks can be used by shippers delivering at less than the 300,000 barrels per day capacity to accumulate theirproduct and have it pumped at the throughput capacity 300,000 barrels per day so as not to slow the line down.In addition to maximizing throughput, the tanks are also used to minimize the mixing or product interfaces. See‘‘— Trans Mountain Terminals’’ and ‘‘— Terminals’’ below.

As at the date hereof, the Trans Mountain pipeline remains the only pipeline that transports liquidpetroleum from the WCSB to the West Coast. It is also the only pipeline providing Canadian producers withaccess to world market pricing through a Canadian port.

Trans Mountain Terminals

Edmonton Terminal

The TMPL system begins in Sherwood Park, Alberta at the Edmonton terminal (the ‘‘EdmontonTerminal’’). This facility is made up of 35 tanks with total storage capacity of approximately 8.0 million barrels.All tanks at the Edmonton Terminal are in crude oil, condensate or refined product service and each tank hasthe flexibility to handle most products that are connected to the terminal, including in-tank mixing of multipleproducts. The Edmonton Terminal is connected to 20 incoming pipelines from oil and refinery production inAlberta and is adjacent, or in close proximity, to the starting point of the Enbridge Inc. cross-continent crude oilpipeline system, the North 40 Terminal, the Suncor Energy Inc. Edmonton refinery, the Keyera Edmontonterminal, the Keyera Alberta Envirofuels plant, the Gibson Energy Inc. Edmonton terminal, the PlainsMidstream Canada Edmonton Strathcona terminal and the Imperial Oil Strathcona refinery.

Twenty of the tanks at the Edmonton Terminal, ranging in size from 80,000 barrels to 220,000 barrels andcomprising 2.9 million barrels of total storage capacity, are currently used by Trans Mountain to serve the TMPLsystem’s regulated service. As noted above, these tanks are used by Trans Mountain to facilitate batching andmaximize throughput on the TMPL mainline. See ‘‘— Trans Mountain Overview’’ above. The remaining 15 tanksat the Edmonton Terminal (referred to as the ‘‘Edmonton South Terminal’’ and as illustrated in the imagebelow), ranging in size from 250,000 barrels to 400,000 barrels and constituting approximately 5.1 million barrelsof the total storage capacity, are leased to KM Canada North 40’s Edmonton South Terminal and are marketedon a merchant basis, subject to a 24 month right of recall, exercisable by Trans Mountain, in the event that theEdmonton Terminal is built out and Trans Mountain requires the tanks for its regulated service. This leasingarrangement is based on a Memorandum of Understanding with the Canadian Association of PetroleumProducers and has been sanctioned by the NEB. In connection with the completion of the Trans MountainExpansion Project, Trans Mountain expects that it will exercise recall rights under the leasing arrangement withKM Canada North 40 in respect of two of the tanks at the Edmonton South Terminal. As a result, following thisrecall, the Edmonton South Terminal will be comprised of 13 merchant tanks and 22 of the existing tanks will be

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used by Trans Mountain to service the regulated TMPL system. As the use of the recalled tanks will be includedin the overall tolls charged on the expanded TMPL, such tanks will no longer generate the incremental revenuerealized through leases to external customers. As such, the recall is expected to result in a decrease in the netcash earnings attributable to the Edmonton South Terminal. See ‘‘— Terminals — Overview of Terminals —Edmonton South Terminal’’ below.

In addition to its service as a storage and terminalling facility, the Edmonton Terminal houses the primarycontrol centre for the Trans Mountain pipeline, the Puget Sound pipeline, the Jet Fuel pipeline, the North40 Terminal and the line to the Edmonton Rail Terminal. It will also control the supply lines to the Base LineTerminal, once the terminal is in service. Transfer of centralized control for the Westridge Marine Terminal tothis control centre is anticipated to be completed during the latter part of 2017. The control centre located at theEdmonton Terminal does not operate the Cochin pipeline system, which is controlled from the United States.See ‘‘— Terminals’’ below.

Kamloops Terminal

In Kamloops, British Columbia, refined products from Edmonton, Alberta are delivered to a distributionterminal operated by a third party. The TMPL terminal in Kamloops contains two storage tanks with a totalstorage capacity of approximately 160,000 barrels and also serves as a primary pump station for theTMPL system.

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Sumas Pump Station and Sumas Terminal

The Sumas pump station and the Sumas terminal (the ‘‘Sumas Terminal’’) are approximately threekilometers apart and are both located in Abbotsford, British Columbia. The terminal is used to stage oil fordelivery and contains six storage tanks with total storage capacity of approximately 715,000 barrels. The pumpstation includes four pumps, two of which are used to route product from the TMPL mainline into WashingtonState via the Puget Sound pipeline system and two of which are used to route the product on the TMPLmainline to Burnaby, British Columbia.

Burnaby Terminal

The terminal located in Burnaby, British Columbia (the ‘‘Burnaby Terminal’’) is the terminus of the TMPLmainline. It receives both crude oil and refined products for temporary storage and distribution throughseparate pipelines to a local distribution terminal, a local refinery and the Westridge Marine Terminal. TheBurnaby Terminal has 13 storage tanks with total storage capacity of approximately 1.685 million barrels.

The pump station used to operate the Jet Fuel pipeline system is also located within the Burnaby Terminalalthough the Jet Fuel pipeline system and the Trans Mountain pipeline system are not connected and areoperated as separate systems.

Westridge Marine Terminal

The Westridge Marine terminal is located within the Burrard Inlet in Burnaby, British Columbia(‘‘Westridge’’ or the ‘‘Westridge Marine Terminal’’). Regulated by Transport Canada and the NEB, the dock atthe terminal can accommodate up to Aframax class vessels (approximately 120,000 dead weight tons) andbarges.

The Westridge Marine Terminal is used to deliver crude oil from the Trans Mountain pipeline system ontobarges and tankers and to receive jet fuel to the three tanks at the terminal used for delivery into the Jet Fuelpipeline system.

The Westridge Marine Terminal houses three storage tanks, that are currently being leased to a third party,with total storage capacity of approximately 395,000 barrels. Significant modifications are planned for theWestridge Marine Terminal as part of the Trans Mountain Expansion Project. See ‘‘— Trans MountainExpansion Project — Project Description’’ below.

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Puget Sound Pipeline System

In operation since 1954, the Puget Sound pipeline system ships crude oil products from the Sumas Terminalto Washington State refineries in Anacortes and Ferndale.

The Puget Sound pipeline system is approximately 111 kilometers long, with one pump station and adiameter of 16 to 20 inches (406 to 508 mm) and two storage tanks with total storage capacity of approximately200,000 barrels. The system has total throughput capacity of approximately 240,000 barrels per day (whentransporting primarily light oil), with approximately 191,000 barrels per day transported in 2016. The transit timeof products on the Puget Sound pipeline system is approximately one day. The pipeline is regulated by theFERC for tariffs and the USDOT for safety and integrity. Approximately 80% of the 2016 revenue from PugetSound originated from counterparties that have, or are subsidiaries of a parent entity that has, an investmentgrade credit rating (however such parent entity may not be a guarantor).

In addition to their access to the Westridge Marine Terminal, shippers on the TMPL system have, andfollowing completion of the Trans Mountain Expansion Project will continue to have, the option to deliver theirproduct to the Puget Sound pipeline system.

Jet Fuel Pipeline System

The Jet Fuel pipeline system transports jet fuel from a Burnaby refinery and the Westridge Marine Terminalto the Vancouver International Airport. The 41 kilometer pipeline system has been in operation since 1969. Itincludes five storage tanks at the Vancouver International Airport with aggregate storage capacity of

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45,000 barrels. The BC OGC regulates the integrity and safety of the pipeline and the BCUC regulates the JetFuel pipeline’s tolls.

The Trans Mountain Expansion Project

Background

Beginning in early 2011, through discussions with Trans Mountain and existing shippers and otherinterested parties, it became clear that there was significant interest in an expansion of the TMPL for thepurpose of improving access to the North American west coast and offshore markets. Between October 2011and November 2012, Trans Mountain conducted an open season process to obtain commitments for the TransMountain Expansion Project. Trans Mountain advanced a firm service offering designed to provide shippers withlong-term contractual certainty of shipping crude oil product volumes on the expanded system, while providingTrans Mountain with the financial certainty necessary to support the contemplated investment in the expansion.In total, at the conclusion of the open season process, Trans Mountain entered into firm transportation servicesagreements with 13 companies for a total of 707,500 barrels per day based on a capacity of 890,000 barrels perday (the maximum amount that Trans Mountain anticipated the NEB would authorize) following completion ofthe Trans Mountain Expansion Project.

In January 2013, Trans Mountain made an application to the NEB for approval of the proposedtransportation service to be provided and the proposed toll methodology to be used in the event the TransMountain Expansion Project was approved by the NEB. In May 2013, the NEB approved the commercial termsof the expansion proposal. See ‘‘— Customers and Contractual Relationships — Expansion Shipping Agreements’’below.

In December 2013, Trans Mountain submitted its formal facilities application to the NEB. The NEB reviewprocess included approximately 1,650 participants, including Commenters and approximately 400 Intervenors.Key steps in the process included several rounds of Information Requests by the NEB and Intervenors, IRresponses from Trans Mountain and opportunities for Intervenors to file written evidence. The process alsoincluded an oral hearing of Aboriginal groups’ traditional evidence in 2014 and oral argument respecting theTrans Mountain Expansion Project as a whole in 2015 and 2016.

On May 19, 2016, following a 29 month review, the NEB recommended that the Government of Canadaapprove the Trans Mountain Expansion Project, subject to the satisfaction of 157 required conditions. Theseconditions apply during various stages of the proposed project’s lifecycle, including before construction, duringconstruction and during the operation of the expanded TMPL system. The conditions are designed to reducepossible risks that were identified by the NEB during the application process. The conditions cover a wide rangeof areas including safety and integrity, emergency preparedness and response, environmental protection,ongoing consultation with stakeholders, socio-economic matters, financial responsibility and affirmation ofcommercial support.

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On November 29, 2016, the Government of Canada approved the Trans Mountain Expansion Project andon December 1, 2016, the NEB issued its Certificate of Public Convenience and Necessity. The approval of theTrans Mountain Expansion Project by the Government of Canada was provided in the context of a broaderpipeline plan developed by the federal government designed to grow the Canadian economy while protectingenvironmentally sensitive areas. As a result, along with the announcement of the Trans Mountain ExpansionProject approval, the Government of Canada also noted that, among other things: (i) a moratorium onpersistent oil tankers along British Columbia’s north coast has been implemented; (ii) more than $300 millionhad been committed to Indigenous groups by Kinder Morgan under mutual benefit agreements and theGovernment of Canada had agreed to provide funding for an Indigenous advisory and monitoring committee towork with federal regulators and Kinder Morgan to oversee environmental aspects of the Trans MountainExpansion Project and other projects throughout their applicable life cycles; (iii) before any shipping from theTrans Mountain Expansion Project begins, a recovery plan for the southern resident killer whale population anda $1.5 billion national ocean protection plan will be implemented to improve marine safety and responsibleshipping; (iv) Trans Mountain is required to develop a construction-related emissions offset plan to achieve zeronet emissions; and (v) through the climate leadership plan, the Government of Alberta had committed to cap oilsands emissions at 100 megatonnes of CO2 per year to limit future potential upstream greenhouse gas emissions.

On January 11, 2017, the Government of British Columbia announced the issuance of an environmentalassessment certificate from B.C.’s Environmental Assessment Office to Trans Mountain for the B.C. portion ofthe Trans Mountain Expansion Project. The environmental assessment certificate includes 37 conditions that arein addition to and designed to supplement the 157 conditions required by the NEB.

In addition, on January 11, 2017, the Government of British Columbia announced that the Trans MountainExpansion Project had met the B.C. Government’s five conditions relating to world-leading marine and land oilspill response, protection and recovery measures for B.C.’s coast and land areas, environmental reviews, FirstNations consultations and participation and economic agreements that reflect the level and nature of the risk theprovince bears with a heavy oil project. Trans Mountain has entered into an agreement to contribute aguaranteed amount of $25 million annually for 20 years to the B.C. Government, and up to a maximum of$50 million annually, depending on spot volume shipments. The B.C. Government has stated that all of theproceeds received from Trans Mountain pursuant to this agreement will be used and applied to a new B.C.Clean Communities Program, or similar program, which has a mandate to provide funding for projects andinitiatives that protect the environment and benefit communities, including local projects that protect, sustainand restore B.C.’s natural and coastal environments.

Trans Mountain incorporated the NEB’s 157 conditions and the 37 conditions of the Government of BritishColumbia into its cost estimates and project schedule and, in response to public feedback, has implementedcertain additional changes to the Trans Mountain Expansion Project including, among other things, increasingpipe wall thickness and adding additional drilled crossings in environmentally sensitive areas and the BurnabyMountain tunnel. These and other factors resulted in Trans Mountain increasing the final cost estimate and tollsto reflect an updated estimated Trans Mountain Expansion Project cost of approximately $7.4 billion (includingcapitalized financing costs). On March 9, 2017, the final cost estimate review with shippers was completedwherein shippers had the option to keep their volume commitments or turn back their commitments (or aportion thereof) and pay their pro rata share of development costs to date.

The NEB-approved commercial terms for the Trans Mountain Expansion Project contemplate a capital costrisk sharing investment structure whereby the capital costs associated with the Trans Mountain ExpansionProject will be classified into two segments: capped costs and uncapped costs. Uncapped costs, which account forapproximately 24% of the capital cost of the Trans Mountain Expansion Project, will include some of the higherrisk capital cost components of the Trans Mountain Expansion Project whereby any cost overruns will bereflected in increased tolls. These components include: (i) the price of steel for pipe; (ii) difficult pipelineconstruction spreads totaling approximately 10% of the Trans Mountain Expansion Project specifically, onemountain spread through the Coquihalla Summit near Hope, British Columbia and one urban spread betweenLangley and Burnaby, British Columbia (including the Burnaby tunnel); (iii) land acquisition costs betweenLangley and Burnaby, British Columbia; and (iv) all consultation and accommodation costs, including withrespect to Aboriginal and non-Aboriginal communities. Costs above or below the uncapped cost amount will bereflected in higher or lower tolls for shippers by approximately $0.07 per barrel per $100 million of capital cost

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change. Capped costs, which are expected to account for approximately 76% of the capital cost of the TransMountain Expansion Project, include all other costs associated with the construction of the Trans MountainExpansion Project not classified as uncapped costs. Any capped costs above the pre-determined amount are theresponsibility of Trans Mountain; however, capped costs below the pre-determined amount are reflected inlower tolls for shippers by approximately $0.07 per barrel per $100 million of capital cost change. KinderMorgan has spent years advancing engineering designs for the Trans Mountain Expansion Project and hasdeveloped a comprehensive construction plan in conjunction with several of the world’s leading engineering,procurement and construction and general contractor construction companies.

Trans Mountain delivered the final cost estimate and tolls to shippers in February 2017. At that time someexisting shippers gave up capacity, some increased capacity and some new shippers acquired capacity, the netresult of which was the turn back of 22,000 barrels per day (or 3% of the previously committed barrels). These22,000 barrels per day were subsequently recommitted during an additional supplemental open season process inMarch 2017. As a result of the Trans Mountain Expansion Project’s open season processes, 13 companies haveentered into one 15-year and 12 20-year transportation service agreements with Trans Mountain for a total of707,500 barrels per day, representing approximately 80% of the expanded system’s capacity (the maximumamount under the regulated limit imposed by the NEB). This maximum level of recommitment highlights thestrong market demand for the expanded system’s takeaway capacity and has better aligned the Trans MountainExpansion Project shipper composition with the changing Canadian crude producer landscape.

Project Description

Upon the completion of the proposed Trans Mountain Expansion Project, the TMPL system is anticipatedto have capacity of 890,000 barrels per day. The proposed expansion of the TMPL system is intended tocomprise, among other things, the following:

• approximately 980 kilometers of new, buried pipeline segments that twin (or ‘‘loop’’) the existing pipelinein Alberta and British Columbia, including two 3.6 kilometer segments (7.2 kilometers in total) of newburied delivery lines from the Burnaby Terminal to the Westridge Marine Terminal;

• new and modified facilities, including pump stations and tanks; and

• a new dock complex with three new berths at the Westridge Marine Terminal, each capable of handlingAframax class vessels.

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The following diagram illustrates the overall Trans Mountain Expansion Project configuration:

The major components of the pipeline portion of the Trans Mountain Expansion Project will include:

• using existing active 24 inch (610 mm) and 30 inch (762 mm) outside diameter buried pipeline segments;

• reactivating two 24 inch (610 mm) outside diameter buried pipeline segments that have been maintainedin a deactivated state;

• constructing three new 36 inch (914 mm) and one new 42 inch (1,220 mm) outside diameter buriedpipeline segments totaling approximately 860 kilometers and 120 kilometers, respectively; and

• constructing two parallel 3.6 kilometers long, 30 inch (762 mm) outside diameter buried delivery linesfrom the Burnaby Terminal to the Westridge Marine Terminal.

The Trans Mountain Expansion Project will result in two continuous pipelines between Edmontonand Burnaby:

• Line 1 is expected to have a capacity of 350,000 barrels per day of light crude oil; and

• Line 2 is expected to have a capacity of 540,000 barrels per day of heavy crude oil.

The existing TMPL has been operating safely for more than 60 years and its location is known to localTMPL operations crews, landowners, surface management agencies, and local emergency responders. Tominimize environmental and socio-economic effects and facilitate efficient pipeline operations, use of theexisting TMPL right of way has been maximized in the Trans Mountain Expansion Project design. Where it wasnot possible to align along the existing TMPL right of way, construction along other linear facilities wasevaluated including other pipelines, power lines, highways and roads, railways, communication lines and other

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utilities. The result is that approximately 73% of the new pipeline corridor follows the existing TMPL right ofway, approximately 17% follows other existing rights of way, and approximately 10% will be within a newcorridor. The completion of the Anchor Loop project in 2008 also avoids the need for additional construction inthe highly sensitive Jasper National Park region.

Electrically-powered pump stations located at regular intervals along the pipeline will be required for theexpansion. The major components of the pump stations portion of the Trans Mountain Expansion Project whichwill support mainline operation include:

• adding 12 new pump stations;

• reactivating the existing Niton pump station and adding one pumping unit at the Sumas pumpstation; and

• deactivating some elements of the existing Wolf, Alberta and Blue River, British Columbiapump stations.

The major components of the associated facilities of the Trans Mountain Expansion Project include:

• the addition of 20 new above-ground storage tanks, including the construction of four new tanks andinclusion of two existing tanks at the Edmonton Terminal, constructing one new tank at the SumasTerminal and the construction of 14 new tanks and the demolition of one existing tank at the BurnabyTerminal; and

• constructing a new dock complex, with a total of three Aframax-capable berths, as well as a utility dock(for tugs, boom deployment vessels, and emergency response vessels and equipment), at the WestridgeMarine Terminal, followed by the deactivation and demolition of the existing berth.

Seventy-two new buried remote mainline block valves will be installed and complement existing mainlineblock valves, which will be located at the pump stations. These remote mainline block valves and mainline blockvalves work to limit the volume and consequences associated with a pipeline leak or ruptures. A total of 25 newsending or receiving scraper traps for in-line inspection tools will also be installed at facility locations alongthe pipeline.

In addition, the Trans Mountain Expansion Project requires two power line connections to the BC Hydrosystem, an approximately 24 kilometer line to connect to a power station in Kingsvale, British Columbia and anapproximately 1.5 kilometer connection to a power station in Black Pines, British Columbia. BC Hydro requiresTrans Mountain to either build such lines and turn them over to BC Hydro for a minimal amount or continue toown, maintain and operate them. The Business is currently considering selling these power line assets to a thirdparty and entering into a services contract in relation thereto.

Currently, up to approximately five vessels per month are loaded with heavy crude oil at the WestridgeMarine Terminal. Upon completion of the Trans Mountain Expansion Project, it is anticipated that theWestridge Marine Terminal will be capable of serving up to 34 Aframax class vessels per month with actualdemand to be influenced by market conditions. The maximum vessel size (Aframax class) served at the terminalwill not change as a result of the Trans Mountain Expansion Project. Similarly, product moving over the dock atthe Westridge Marine Terminal is expected to continue to be primarily heavy crude oil. Of the 890,000 barrelsper day capacity of the expanded system, up to 630,000 barrels per day may be handled through the WestridgeMarine Terminal for shipment. Currently, monthly barge traffic typically consists of loading two crude oil bargesand receiving one jet fuel barge. This level of activity is not expected to be affected by the Trans MountainExpansion Project.

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The Business is currently in negotiations with construction contractors to construct the various pipelinespreads on the Trans Mountain Expansion Project, with the intention that general construction contracts will beentered into with respect to spreads one through six and engineering, procurement and construction contractswill be entered into with respect to spread seven, terminals and pump stations and with respect to any workrequired in the Lower Mainland. An illustration of the Trans Mountain Expansion Project pipeline spreads is setout below.

Upon completion, the newly constructed pipeline is expected to carry predominantly heavy crude volumesand the existing pipeline will carry predominantly light crude and refined products.

Project Schedule

Trans Mountain continues to work towards obtaining all necessary permits and, subject to receiving finalinvestment approval from the board of directors of Kinder Morgan, the Business expects to begin constructionon the Trans Mountain Expansion Project in September 2017, with an anticipated in-service date at the end of2019. A summary of the overall Trans Mountain Expansion Project timeline is set out in the graphic below and acomprehensive construction plan has been developed in order to help achieve this timeline. See ‘‘Risk Factors —Risks Relating to the Development of the Trans Mountain Expansion Project and the Business and Operations of theBusiness — Major Projects, Including the Trans Mountain Expansion Project, May be Inhibited, Delayedor Stopped’’.

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Customers and Contractual Relationships

Existing Shipping Agreements

The TMPL mainline is a common carrier pipeline, providing transportation services under a cost of servicemodel that is negotiated with shippers and regulated by the NEB. Although Trans Mountain takes custody of itsshippers’ products, it does not own any of the product it ships. The TMPL system has posted tariff rates that areavailable to all shippers based on a monthly contract which varies according to the type of product being shippedas well as receipt and delivery points. As such, it provides service to producers, marketers, refineries andterminals who sell or resell products to domestic markets, oil marketers and international shippers moving oil tosuch places as California, Washington and Asia.

Since late 2010, the TMPL system has been meaningfully over-subscribed, resulting in pipelineapportionment (nominating less volumes for shipment than shippers request). Shippers on the TMPL system aregenerally large and well-capitalized. As at the date hereof, a significant majority of the TMPL mainline shippershave, or are subsidiaries of a parent entity that has, an investment grade credit rating (however such parententity may not be a guarantor).

Throughout the past 20 years, Trans Mountain has entered into negotiated toll settlements with its shippersto establish final tolls on the TMPL system. The Company believes that negotiated settlements are advantageousfrom a cost perspective and may provide opportunities for additional returns.

In February 2016, the NEB approved Trans Mountain’s 2016 to 2018 (inclusive) negotiated toll settlement.The toll settlement provides for a three year term and includes a rollover provision and an Trans MountainExpansion Project transition provision. TMPL’s net regulated rate base is approximately $1 billion as atDecember 31, 2016 with sustaining capital automatically added in subsequent years. Under the NEB-approvednegotiated toll settlement, the tolls on the TMPL system are based on a 9.5% return on equity, a 5% cost of debtand a deemed 45% equity and 55% debt structure. The toll settlement provides for the flow-through to shippersof certain operating costs, including power costs, property tax, income tax, integrity costs, environmentalcompliance and remediation costs and the cost of insurance and security. Labour and service-related costs arefixed costs determined by the shared service model using a methodology approved by the NEB. These costs areallocated to the system based on usage and are escalated at a set index during the toll settlement period. Inaddition, the toll settlement agreement provides power and capacity incentives. Specifically, 50% of the BritishColumbia power costs savings are allocated to the shipper and 50% are allocated to the pipeline system and 75%of the transmission power costs savings are allocated to the shipper and 25% are allocated to pipeline sharing.The settlement agreement also provides for a capacity incentive which is allocated 50% to the shipper and 50%

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to the pipeline system. Revenue variances resulting from volume are recovered from shippers in the followingyear. Trans Mountain’s current negotiated toll settlement includes a provision for extension, if the extension ismutually acceptable to Trans Mountain and the shipper, up until the Trans Mountain Expansion Projectin-service date.

In 2011, Trans Mountain received approval from the NEB to implement firm service for 54,000 barrels perday of service to the Westridge Marine Terminal, and charge a premium on such barrels to fund expansionprojects on the TMPL system. This service and the premiums associated with it will be in effect until the earlierof the in-service date of the TMPL expansion and ten years from the date of implementation. The premiums areapproved to be used by Trans Mountain to offset the cost of projects designed to enhance existing and futureoperations including development costs relating to the Trans Mountain Expansion Project and equate to a totalof approximately $28.6 million per year. As at December 31, 2016, $34 million had been used to construct a250,000 barrel tank and associated infrastructure at the Edmonton Terminal and $104 million had been used tooffset the development costs of the Trans Mountain Expansion Project. As part of its firm serviceimplementation, 27,000 barrels per day of existing TMPL capacity was reallocated to the Westridge MarineTerminal, increasing the terminal’s allocation to a total of 79,000 barrels per day.

Rates charged on the Puget Sound pipeline system are regulated by the FERC and are based on a cost ofservice model that has been in place since prior to 1992 and, as such, have been grandfathered and escalatedfrom time to time as permitted by the FERC. As a result of this grandfathering, the Puget Sound cost of servicerates that were in place for the 365 day period prior to September 1992, plus escalation, may continue to becharged to its shippers unless and until the rates are successfully challenged on the basis that a substantialchange has occurred in the economic circumstances or nature of the services provided which were a basis forsuch rates. To date, no such complaints have been made. In 2016 approximately 80% of the revenue on thePuget Sound pipeline originated from customers that have, or are subsidiaries of a parent entity that has, aninvestment grade credit rating (however such parent entity may not be a guarantor).

The Jet Fuel pipeline system delivers jet fuel from the Westridge Marine Terminal and from a refinery inBurnaby to the Vancouver International Airport. With respect to the volume from the Westridge MarineTerminal, Trans Mountain has a contract with one of Canada’s largest airlines to unload jet fuel from barges atthe Westridge Marine Terminal and store such volumes at the Westridge Marine Terminal. The Jet Fuel pipelinesystem then transports such jet fuel to the Vancouver International Airport. Through this arrangement and thejet fuel shipped from the Burnaby refinery, the Jet Fuel pipeline system has a BCUC-approved negotiatedsettlement that ends in 2018.

Expansion Shipping Agreements

As noted above, as a result of the Trans Mountain Expansion Project’s open season processes, 13 companieshave entered into transportation service agreements with Trans Mountain, one having a 15 year term and12 having a 20-year term, for a total of 707,500 barrels per day, representing approximately 80% of the expandedsystem’s capacity (the maximum amount under the regulated limit imposed by the NEB). These shippersrepresent or are affiliates of some of the largest producing companies in the WCSB and a significant majority ofthese committed shippers have, or are subsidiaries of a parent entity that has, an investment grade credit rating(however such parent entity may not be a guarantor). These companies have direct access to large volumes ofsupply, either through their own production, or through their position in the market as a large marketer and/orrefiner of crude oil.

The Trans Mountain Expansion Project-related transportation service agreements provide for a sharing ofrisks between Trans Mountain and its shippers during the development stage, including the construction of theTrans Mountain Expansion Project, and the long-term operation of the pipeline system. Each shipper is entitledto a certain amount of capacity each month, and the shippers are required to pay for the fixed cost of suchcapacity whether they use it or not.

The transportation service agreements also provide flexibility to the shippers that are parties to them, assuch agreements enable the shippers to manage their capacity entitlements and associated financial obligations.Shippers can assign their shipping rights to third parties on a short-term or long-term basis, thereby reducing riskand ensuring that the firm capacity is fully utilized. There are also make-up provisions in the event that shippers

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cannot use their full capacity entitlements in any given month. Shippers also have the right to renew theircontracts at the end of the initial term for an additional five year period on rates to be determined at the time ofrenewal (if any).

The fixed toll to be paid by shippers under the Trans Mountain Expansion Project-related transportationservice agreements has been established according to a risk sharing formula that will be escalated during thelifetime of the contracts at a fixed rate. Under the agreements there is a variable toll component based on actualcosts incurred for power, unanticipated costs related to changes in legislation or regulation and other costs asmay be agreed to by Trans Mountain and shippers. As the vast majority of the toll will not be adjusted accordingto actual costs incurred, as would normally occur under a cost-of-service approach, this arrangement will providegreater toll certainty to shippers and reduce the risk of unanticipated increases in transportation costs over time.

Approximately 20% of the expanded TMPL system’s nominal capacity (182,500 barrels per day), will bereserved for spot month-to-month shipments. The toll for spot shipments will be tied to the toll for long-termservice and, as such, spot shippers will benefit from all of the contractual provisions that protect long-termshippers from cost escalation.

Competition

Trans Mountain is subject to competition resulting from the shipment of oil from the WCSB to marketsother than the Canadian and U.S. West Coast, including shipments to refineries in Ontario, the U.S. Midwestand the U.S. Gulf Coast. In addition, refineries in Washington State and California, which comprise animportant point of sale on the U.S. West Coast, have, in the past, been supplied primarily by crude oil from theAlaska North Slope. As such, there has historically been some competitive pressure on supply originating fromthe WCSB for sale in the Washington State and California refinery markets. A further source of competitionexists from the transportation of oil to the Canadian West Coast by rail. The Company expects that such supplyand demand conditions in the oil markets served from the west coast of British Columbia will continue to impactthe long-term value and economics of the TMPL system.

Despite this potential competitive pressure, the Company believes that the TMPL system, both pre- andpost-expansion, will maintain its strong competitive position as a result of a number of factors. For example,contracted tariff rates on Trans Mountain after the expansion will range from approximately $5.00 per barrel toapproximately $7.00 per barrel from Edmonton to Burnaby area. Uncontracted spot tariff rates will be 10%higher than the equivalent contracted tariff rates. Converted to U.S. dollars, these tariff rates would range fromapproximately U.S.$4.00 per barrel to approximately U.S.$6.00 per barrel. Environment and Climate ChangeCanada has estimated comparable rail transportation costs to California and the U.S. Gulf Coast to beapproximately U.S.$16.00 per barrel and approximately $18.00 per barrel, respectively. Keystone posted tariffrates for U.S. Gulf Coast delivery are approximately U.S.$7.80 per barrel to U.S.$12.60 per barrel for heavy oil.The Government of Alberta, as of January 2017, reported the differential between WTI (light oil at CushingOklahoma) and WCS (heavy crude at Hardisty, Alberta) was approximately U.S.$15.00 per barrel.

In addition, the TMPL offers significant optionality and flexibility to its customers. Its tolling methodologyand transportation contracts have been designed to promote high operating standards while remainingcost-competitive for the foreseeable future. Trans Mountain remains the only pipeline that transports oil andother liquid petroleum products from the WCSB to the West Coast of Canada and the United States and thisimportant outlet provides producers in the WCSB with improved market access and market diversification.Further, due to recent changes in U.S. legislation, oil from the Alaska North Slope may now be sold to marketsoutside of the United States. To the extent this additional access to alternative markets for Alaskan producersincreases overall demand from Washington State and California refineries, the TMPL system, through its PugetSound pipeline connection to four refineries in Washington State, will be in a position to facilitate supply to suchmarkets for WCSB producers. As evidence of these competitive advantages, capacity on the TMPL has beenover-subscribed since 2010 and approximately 80% of the capacity of the TMPL upon completion of the TransMountain Expansion Project is subject to long-term firm commitments. Similarly, throughput on the PugetSound pipeline system has steadily risen in recent years, with 2015 and 2016 experiencing increases fromprevious years of over 15% and 30%, respectively. In 2016, the Puget Sound pipeline transported average

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volumes of approximately 191,000 barrels per day, comprising approximately one-third of the collective capacityof all refineries in the Anacortes and Ferndale area.

Historically, the Jet Fuel pipeline has transported a significant proportion of the jet fuel used at theVancouver International Airport. However, the airport also receives jet fuel through other means includingtrucks and, recently, an affiliate of each of the airlines using the airport received approval to construct a jet fuelbarge-receiving terminal near the airport. In 2016, the entity owning the Burnaby refinery supplying products toJet Fuel for shipment announced its intention to sell the refinery and, due to this sale process, the Company isunable to predict whether, and to what extent, that refinery will continue to supply jet fuel to the Jet Fuelpipeline. These developments have made it unclear how much jet fuel will continue to be available for shipmentto the Vancouver International Airport by way of the Jet Fuel pipeline in the future. To the extent it becomesuneconomic to continue shipping jet fuel to the Vancouver International Airport, the Company estimates thatthe decommissioning and abandonment costs of the Jet Fuel pipeline would be in the range of $2.0 million to$3.0 million, subject to regulatory approval of the BCUC and the BC OGC. The Business continues to assess itsoptions relating to the Jet Fuel assets.

Potential Growth Opportunities

While the Business does not presently have any plans to expand the TMPL system outside of the currentscope of the Trans Mountain Expansion Project, the combined capacity of the expanded pipeline couldpotentially be further increased by over 300,000 barrels per day to approximately 1.2 million barrels per day, withadditional power and further capital enhancements.

The Puget Sound pipeline is capable of being expanded to increase its capacity to approximately500,000 barrels per day from its current capacity of 240,000 barrels per day. See ‘‘The Business — InvestmentHighlights — Sizeable growth project of strategic national importance to Canada’’.

The Business will continue to monitor market and industry developments to determine which, if any,further expansion projects on the TMPL system may be appropriate.

See ‘‘Risk Factors — Risks Relating to the Development of the Trans Mountain Expansion Project and theBusiness and Operations of the Business — Major Projects, Including the Trans Mountain Expansion Project, MayBe Inhibited, Delayed or Stopped’’.

Cochin Pipeline System

Overview

The Cochin pipeline system consists of a 12 inch (305 mm) diameter pipeline which spans from KankakeeCounty, Illinois to Fort Saskatchewan, Alberta, totalling approximately 2,452 kilometers. The Cochin pipelinesystem, which transports light hydrocarbon liquids (primarily to be used as diluent to facilitate bitumentransportation), traverses two provinces in Canada and four states in the United States. The Canadian Cochinpipeline system is comprised of 999 kilometers of pipeline and includes 38 block valves and ten pump stations.While the U.S. portion of Cochin is not part of the Business, the U.S. portion of Cochin and the CanadianCochin pipeline system are interdependent (including with respect to volumes shipped and financial andcontractual obligations) and, as the bulk of the tariffs on the Cochin pipeline system are governed by a jointinternational tariff, revenue is shared between the U.S. portion of Cochin and the Canadian Cochin pipelinesystem.

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13APR201709055563

No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. These securities have not been and willnot be registered under the United States Securities Act of 1933, as amended (the ‘‘U.S. Securities Act’’), or any state securities laws. Accordingly, thesesecurities may not be offered or sold within the United States unless registered under the U.S. Securities Act and applicable state securities laws or exceptpursuant to exemptions from the registration requirements of the U.S. Securities Act and applicable state securities laws in accordance with theUnderwriting Agreement (as defined herein). This prospectus constitutes a public offering of these securities only in those jurisdictions where they may belawfully offered for sale and only by persons permitted to sell these securities. See ‘‘Plan of Distribution’’.

PROSPECTUSInitial Public Offering May 25, 2017

KINDER MORGANCANADA LIMITED

$1,750,014,000102,942,000 Restricted Voting Shares

Kinder Morgan Canada Limited (the ‘‘Company’’) is offering for sale 102,942,000 restricted voting shares (the ‘‘Restricted Voting Shares’’)at a price of $17.00 per Restricted Voting Share (the ‘‘Offering’’).

The Company has been formed to acquire an approximate 30% interest (an approximate 34% interest if the Over-Allotment Option isexercised in full) in Kinder Morgan Canada Limited Partnership (the ‘‘Limited Partnership’’). The Limited Partnership, prior to theclosing of the Offering, will own the Business (as defined herein) of Kinder Morgan (as defined herein), consisting of the Trans Mountainpipeline system, along with its associated terminals and storage facilities, the Puget Sound and Jet Fuel pipeline systems, the CanadianCochin pipeline system (as defined herein), the Vancouver Wharves Terminal in British Columbia and various merchant liquids storageand handling terminals and interests in crude oil loading facilities in the Edmonton, Alberta area. Upon closing of the Offering, KinderMorgan will hold an approximate 70% interest (an approximate 66% interest if the Over-Allotment Option is exercised in full) in theLimited Partnership.

Upon closing of the Offering, Kinder Morgan will own approximately 70% of the outstanding Company Voting Shares (as defined herein)(approximately 66% if the Over-Allotment Option is exercised in full) through its indirect ownership of 242,058,000 Special Voting Shares(as defined herein) of the Company. Kinder Morgan has advised the Company that it intends to remain the majority voting shareholder inthe Company. Certain aspects of the business, operations and day-to-day administration of the Company, the General Partner (as definedherein) and the Limited Partnership, and consequently the Business, will be managed and conducted by Kinder Morgan Canada Inc.(‘‘KMCI’’), an Alberta corporation controlled by the Limited Partnership, through the Services Agreement (as defined herein) and underthe supervision of the executive officers and the board of directors of the Company (the ‘‘Board of Directors’’). See ‘‘Relationship withKinder Morgan’’, ‘‘The Company and the Limited Partnership — Services Agreement’’ and ‘‘Risk Factors — Risks Relating to the Company’sRelationship with Kinder Morgan’’. The Company’s articles contain ‘‘coattail’’ provisions restricting the transfer of Special Voting Shares incertain circumstances. See ‘‘Description of Share Capital and Partnership Units — Take-over Bid Protection — Coattail Arrangements’’.

Price: $17.00 per Restricted Voting Share

Price to Underwriters’ Net Proceeds tothe Public Fee(1) the Company(2)

Per Restricted Voting Share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $17.00 $0.765 $16.235Total Offering(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,750,014,000 $78,750,630 $1,671,263,370Notes:(1) Upon closing of the Offering, the Company will pay the Underwriters (as defined herein) a cash fee of 4.5% of the gross proceeds of the Offering. See

‘‘Plan of Distribution’’.

(2) Before deducting the expenses of the Offering, estimated to be approximately $6,700,000, and which, together with the Underwriters’ fee payablepursuant to the Offering, will be paid by the Company out of the proceeds of the Offering.

(3) The Company has granted to the Underwriters an option (the ‘‘Over-Allotment Option’’), exercisable at the Underwriters’ discretion at any time, inwhole or in part, until 30 days following closing of the Offering, to purchase, at the offering price, up to an additional 15,441,300 Restricted VotingShares (representing 15% of the Restricted Voting Shares offered under this prospectus) to cover over-allotments, if any, and for market stabilizationpurposes. If the Over-Allotment Option is exercised in full, the total Price to the Public, Underwriters’ Fee and Net Proceeds to the Company inrespect of the Offering will be $2,012,516,100, $90,563,224.50 and $1,921,952,875.50, respectively. This prospectus qualifies the grant of theOver-Allotment Option and the distribution of the Restricted Voting Shares pursuant to the exercise of the Over-Allotment Option. A purchaser whoacquires Restricted Voting Shares forming part of the Underwriters’ over-allocation position acquires such Restricted Voting Shares under thisprospectus, regardless of whether the over-allocation position is ultimately filled through the exercise of the Over-Allotment Option or secondarymarket purchases. See ‘‘Plan of Distribution’’.

The following table sets out the number of Restricted Voting Shares that may be sold by the Company pursuant to the Over-AllotmentOption.

Maximum Size or Number ofUnderwriters’ Position Securities Available Exercise Period Exercise Price

Over-Allotment Option Option to acquire up to At any time until 30 days $17.00 per Restricted Voting15,441,300 Restricted Voting following closing of the Offering Share

Shares

(continued on next page)

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(continued from cover)

The terms of the Offering were determined by negotiation between Kinder Morgan and the Company, on the one hand, and TD Securities Inc.and RBC Dominion Securities Inc. on behalf of the Underwriters, on the other hand. See ‘‘Plan of Distribution’’.The Underwriters, as principals, conditionally offer the Restricted Voting Shares offered under this prospectus, subject to prior sale, if, as andwhen sold and delivered by the Company to, and accepted by, the Underwriters in accordance with the conditions contained in the UnderwritingAgreement referred to under ‘‘Plan of Distribution’’ and subject to the approval of certain legal matters on behalf of Kinder Morgan and theCompany by Blake, Cassels & Graydon LLP and on behalf of the Underwriters by Osler, Hoskin & Harcourt LLP.Neither Deutsche Bank Securities Inc. nor Mizuho Securities USA LLC is registered as a dealer in any Canadian jurisdiction and, accordingly,will only sell Restricted Voting Shares into the United States or in other jurisdictions outside of Canada. Deutsche Bank Securities Inc. andMizuho Securities USA LLC are not permitted and have agreed not to, directly or indirectly, solicit offers to purchase or sell any of the RestrictedVoting Shares in Canada. See ‘‘Exemptions from Certain Disclosure Requirements’’.

In connection with the Offering, the Underwriters may over-allocate or effect transactions which stabilize, maintain or otherwise affect themarket price of the Restricted Voting Shares at levels other than those which otherwise might prevail on the open market. The Underwriters mayoffer the Restricted Voting Shares at a price lower than that stated above. Any such reduction in price will not affect the proceeds received by theCompany. See ‘‘Plan of Distribution’’.

Subscriptions in respect of the Offering will be received subject to rejection or allotment in whole or in part and the Underwriters reserve theright to close the subscription books at any time without notice. It is expected that closing of the Offering will occur on or about May 30, 2017 orsuch other date as the Company, Kinder Morgan and the Underwriters may agree; however, notwithstanding the foregoing, under certaincircumstances Kinder Morgan and the Company may, in their sole discretion, designate May 31, 2017 as the closing date of the Offering. TheRestricted Voting Shares offered under this prospectus are to be taken up by the Underwriters, if at all, on or before a date not later than 42 daysafter the date of the receipt for the final prospectus.Except in certain limited circumstances, no certificates representing Restricted Voting Shares will be issued to purchasers in the Offering. Instead,on the date of closing of the Offering, the purchasers of Restricted Voting Shares will have their securities registered in the name of CDS Clearingand Depository Services Inc. or its nominee (‘‘CDS’’) and electronically deposited with CDS. Purchasers of Restricted Voting Shares will receiveonly a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficialinterest in the Restricted Voting Shares is acquired.The Toronto Stock Exchange (the ‘‘TSX’’) has conditionally approved the listing of the Restricted Voting Shares under the symbol ‘‘KML’’.Listing is subject to the Company fulfilling all of the requirements of the TSX on or before August 22, 2017. See ‘‘Plan of Distribution’’.

There is currently no market through which the Restricted Voting Shares may be sold and purchasers may not be able to resell Restricted VotingShares purchased under this prospectus. This may affect the pricing of the Restricted Voting Shares in the secondary market, the transparency andavailability of trading prices, the liquidity of the Restricted Voting Shares and the extent of issuer regulation. See ‘‘Risk Factors — Risks Relating tothe Offering and the Restricted Voting Shares’’.

An investment in the Restricted Voting Shares is speculative and is subject to a number of risks that should be considered by a prospectivepurchaser. See ‘‘Risk Factors’’.

The Board of Directors is expected to establish a dividend policy pursuant to which the Company will pay a quarterly dividend, initially expectedto be in the amount of approximately $0.65 per Restricted Voting Share on an annualized basis. Assuming closing of the Offering occurs onMay 30, 2017, the first dividend for the period from closing of the Offering to June 30, 2017 is expected to be paid on or about August 15, 2017 toshareholders of record on July 31, 2017 in the amount of $0.0571 per Restricted Voting Share. The payment of dividends is not guaranteed andthe amount and timing of any dividends payable will be at the discretion of the Board of Directors and subject to a variety of factors. See‘‘Dividend Policy’’ and ‘‘Risk Factors — Risks Relating to the Offering and the Restricted Voting Shares — Cash Dividend Payments are NotGuaranteed’’.

A return on an investment in the Restricted Voting Shares is not comparable to the return on an investment in a fixed-income security. Therecovery by shareholders of their initial investment is at risk, and the anticipated return on that investment is based on many performanceassumptions. Although the Company currently intends to pay quarterly dividends to holders of the Restricted Voting Shares, those cash dividendsmay be reduced or suspended. The actual amount of cash dividends paid to holders of the Restricted Voting Shares, if any, will depend onnumerous factors including: (i) the results of operations for the Business; (ii) financial requirements for the Business, including the funding ofcurrent and future growth projects; (iii) the amount of distributions paid indirectly by the Limited Partnership to the Company through theGeneral Partner, including any contributions from the completion of the Business’ growth projects; (iv) the satisfaction by the Company and theGeneral Partner of certain liquidity and solvency tests; and (v) any agreements relating to the indebtedness of the Company or the LimitedPartnership. In addition, the market value of the Restricted Voting Shares may decline if the Company is unable to meet its target cash dividendin the future, which decline may be significant. See ‘‘Risk Factors’’.It is important for purchasers of Restricted Voting Shares to consider each of the particular risk factors that may affect the Company (includingwith respect to the industry, business, operations and growth and development plans and projects of the Business) and, therefore, the marketvalue of the Restricted Voting Shares and the stability of the Company’s dividends, if any, that shareholders may receive. See ‘‘Risk Factors’’.Each of the Underwriters (other than BMO Nesbitt Burns Inc. and National Bank Financial Inc.) is, directly or indirectly, an affiliate of a bankwhich is currently a lender to Kinder Morgan or its affiliates. In addition, following closing of the Offering each of the Underwriters will be, directlyor indirectly, an affiliate of a bank that is expected to be a lender under the Credit Facility (as defined herein). Consequently, under applicableCanadian Securities Laws, the Company may be considered to be a connected issuer to each of the Underwriters. See ‘‘Relationships Between theCompany and Certain Underwriters’’.

Kinder Morgan, Inc. is incorporated under the laws of a foreign jurisdiction and each of Steven J. Kean, Kimberly A. Dang and Dax A. Sandersresides outside of Canada. Each of Kinder Morgan, Inc., Steven J. Kean, Kimberly A. Dang and Dax A. Sanders has appointed the Company(Kinder Morgan Canada Limited) at Suite 2700, 300 – 5th Avenue S.W., Calgary, Alberta T2P 5J2, as agent for service of process.Purchasers are advised that it may not be possible for investors to enforce judgments obtained in Canada against any person or company that isincorporated, continued or otherwise organized under the laws of a foreign jurisdiction or resides outside of Canada, even if the party hasappointed an agent for service of process.

The financial statements of the Company and the Business included in this prospectus have been prepared in accordance with GAAP (as definedherein). See ‘‘Notice to Investors — Financial Statements and Exemptive Relief’’ and ‘‘Exemptions from Certain Disclosure Requirements’’.

The Company is incorporated under the ABCA (as defined herein). The head office of the Company is located at Suite 2700, 300 – 5th AvenueS.W., Calgary, Alberta T2P 5J2 and the registered office of the Company is located at Suite 3500, 855 – 2nd Street S.W., Calgary, Alberta T2P 4J8.

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TABLE OF CONTENTS

Page

GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

ABBREVIATIONS AND CONVERSIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

NOTICE TO INVESTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

About this Prospectus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Forward-Looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Non-GAAP Financial Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Allowance for Funds Used During Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Growth Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Marketing Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Financial Statements and Exemptive Relief . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Market, Independent Third Party and Industry Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

THE OFFERING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

PROSPECTUS SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

The Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Investment Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

The Trans Mountain Expansion Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Formation of the Company and the Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

The Reorganization and the Offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Relationship with Kinder Morgan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Summary of Selected Historical Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Risks Relating to the Development of the Trans Mountain Expansion Project and the Business andOperations of the Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Risks Relating to the Company’s Relationship with Kinder Morgan . . . . . . . . . . . . . . . . . . . . . . . . 40

Risks Relating to the Offering and the Restricted Voting Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

THE COMPANY AND THE LIMITED PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Formation of the Company and the Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

The Reorganization and the Offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Intercorporate Relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Services Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

THE BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Investment Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Trans Mountain Pipeline System, Terminals and Related Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . 57

Cochin Pipeline System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

Terminals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

Operations Management of the Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Regulatory Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

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Page

RELATIONSHIP WITH KINDER MORGAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

The Reorganization and the Offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Kinder Morgan’s Ownership in the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Agreements Between the Company and Kinder Morgan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

DESCRIPTION OF SHARE CAPITAL AND PARTNERSHIP UNITS . . . . . . . . . . . . . . . . . . . . . . . 91

The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

The Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

The General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Take-over Bid Protection — Coattail Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Dividend Reinvestment Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

DIVIDEND POLICY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

DISTRIBUTABLE CASH FLOW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

SELECTED HISTORICAL FINANCIAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

CONSOLIDATED CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

DESCRIPTION OF INDEBTEDNESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

KMI Loans and Other Indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

USE OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

MANAGEMENT’S DISCUSSION AND ANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Cautionary Statement Regarding Forward-Looking Information and Non-GAAP Financial Measures 102

Presentation of Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Activities of the Company Since its Incorporation through to Closing of the Offering . . . . . . . . . . . . 103

Results of Operations of the Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

Risks and Risk Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

Transactions with Affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

Critical Accounting Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Accounting Policy Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Selected Quarterly Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

Outstanding Share Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

DIRECTORS AND EXECUTIVE OFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

Directors and Executive Officers Biographical Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Security Ownership by Directors and Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

External Directorships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Cease Trade Orders, Bankruptcies, Penalties or Sanctions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Conflicts of Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

Indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

Insurance Coverage and Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

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Page

CORPORATE GOVERNANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

Independence of the Board of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

Board of Directors’ Mandate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Position Descriptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Orientation and Continuing Education . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Code of Ethics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Nomination and Election of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Board Committees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Assessment of Directors, the Board of Directors and Board Committees . . . . . . . . . . . . . . . . . . . . . 132

Diversity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

Compensation of Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

Compensation of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

PLAN OF DISTRIBUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

Over-Allotment Option . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

Price Stabilization, Short Positions and Passive Market Making . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

Lock-Up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

RELATIONSHIPS BETWEEN THE COMPANY AND CERTAIN UNDERWRITERS . . . . . . . . . . . 140

KINDER MORGAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

PRIOR SALES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON RESALE . . . . . . . . . . . . . . . . 142

PROMOTER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS . . . . . . . . . . . 142

ELIGIBILITY FOR INVESTMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143

CERTAIN CANADIAN FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . 143

Holders Resident in Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

Holders Not Resident in Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

LEGAL PROCEEDINGS AND REGULATORY ACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

EXEMPTIONS FROM CERTAIN DISCLOSURE REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . . . 146

AUDITORS, TRANSFER AGENT AND REGISTRAR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

EXPERTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

MATERIAL CONTRACTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

RIGHTS OF WITHDRAWAL AND RESCISSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

INDEX TO FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1

APPENDIX ‘‘A’’ — MANDATE OF THE BOARD OF DIRECTORS . . . . . . . . . . . . . . . . . . . . . . . . A-1

APPENDIX ‘‘B’’ — AUDIT COMMITTEE CHARTER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

CERTIFICATE OF THE COMPANY AND THE PROMOTER . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

CERTIFICATE OF THE UNDERWRITERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2

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Athabasca Oil Corporation, BP Canada Energy Trading Company, Brion Energy Corporation, CanadianNatural Resources Limited, Cenovus Energy Inc., Devon Canada Corporation, Husky Energy Marketing Inc.,Imperial Oil, MEG Energy Corp., Suncor Energy Marketing Inc., Teck Canadian Energy Sales Ltd., TesoroCanada Supply and Distribution Ltd. and Total E&P Canada Ltd. The TMPL is currently expected to beoperating at or near maximum capacity after the completion of the Trans Mountain Expansion Project and,based on the TMPL’s 65 year operating history, the Company believes that the long-term commercial viability ofthe system will extend well beyond the initial 20 year contract period.

Target capital structure consistent with an investment grade profile

The Business is not expected to have drawn corporate or asset level debt at the time of the closing of theOffering. A significant majority of the capital expenditure requirements related to the Trans MountainExpansion Project are expected to be funded through a combination of the Credit Facility and other loans,dividend and distribution reinvestments and the issuance of preferred equity. The Business’ targeted funding mixduring construction and following completion of the Trans Mountain Expansion Project is intended to beconsistent with an investment grade credit rating.

Trans Mountain Pipeline System, Terminals and Related Pipelines

Trans Mountain Overview

Trans Mountain Oil Pipe Line Company was established on March 21, 1951. Construction of the TMPLcommenced in 1952 and the first shipment of oil reached Trans Mountain’s Burnaby terminal on October 17,1953. The initial capacity of the pipeline system was 150,000 barrels per day. Since 1953, the capacity of theTMPL has been increased a number of times by twinning parts of the line and adding associated facilities.

In 2008, the Anchor Loop project was completed, which project involved the installation of a secondpipeline adjacent to the existing TMPL on a 158 kilometer section of the system between Hinton, Alberta andHargreaves, British Columbia, just west of Mount Robson Provincial Park. The Anchor Loop project increasedthe capacity of the pipeline system from 260,000 barrels per day to 300,000 barrels per day and involved theinstallation of two new pump stations.

The TMPL is approximately 1,150 kilometers long, beginning in Edmonton, Alberta and terminating on thewest coast of British Columbia in Burnaby. Twenty-three active pump stations located along the TMPL routemaintain the 300,000 barrels per day capacity of the line, flowing at a speed of approximately eight kilometersper hour. In addition to the pump stations, four terminals located in Edmonton, Kamloops, Sumas and Burnabyand the Westridge Marine Terminal, house storage tanks and serve as locations for incoming pipelines. The300,000 barrels per day nominal capacity of the pipeline has been determined based on a throughput mix of 20%heavy oil and 80% light oil. As shown in the table below respecting TMPL’s historical throughputapportionment, the actual delivery capacity on the TMPL mainline is based on the type of oil or refined productbeing transported. For example, when the pipeline is delivering only light oil, it can deliver an amount closer to

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approximately 350,000 barrels per day and if it is delivering only heavy oil, the system’s delivery capacity is closerto approximately 280,000 barrels per day.

70 77 44

61 58 56 35 25

210 220

230 230

219 237 281 291

280 297

274 291

277 293

316 316

-

50

100

150

200

250

300

350

2009 2010 2011 2012 2013 2014 2015 2016

d/lb

bm

Heavy Product Light Product

12% 34% 67% 69% 69% 69% 41% 15%

Annual Average Apportionment

APPORTIONMENT METHODOLOGY CHANGED IN 2015 (2)

Notes:

(1) Apportionment = 1 - (accepted nominations / total nominations)

(2) On May 1, 2015 the NEB changed the nomination methodology by limiting the amount of accepted nominations to the best 18 of thelast 24 months of historical nominations. This resulted in a decrease in nominations because there was less opportunity to achievemore accepted nominations

The Trans Mountain pipeline regularly ships multiple products, including refined petroleum, syntheticcrude oil, light crude oil and heavy crude oil, and it is the only pipeline in North America that carries bothrefined products and crude oil together in the same line. This process, known as ‘‘batching’’, means that a seriesof products can follow one another through the pipeline in a ‘‘batch train’’. A typical batch train in the TMPLmainline is made up a variety of materials being transported for different shippers; however, any product movedin the pipeline must meet Trans Mountain’s tariff requirements, which include technical specifications for anyproducts accepted for transportation in the TMPL system. While products next to each other in the pipeline mix,product interface is kept to a minimum by moving the products in a specific sequence, as illustrated below.Products that do mix are re-refined for use.

HeavyCrude

LightCrude Distillates Gasoline Distillates

LightCrude

HeavyCrude

In order to optimize batches to achieve maximum throughput, Trans Mountain has built tanks, pumps andother ancillary equipment which enable connection and staging of batches to be delivered to the TMPL mainlinepipe. Tanks are used to accumulate enough of a particular type of product to make up an efficient batch. Whileshippers are permitted to deliver oil to the mainline at a rated throughput to avoid the use of tanks, the TMPLtanks can be used by shippers delivering at less than the 300,000 barrels per day capacity to accumulate theirproduct and have it pumped at the throughput capacity 300,000 barrels per day so as not to slow the line down.In addition to maximizing throughput, the tanks are also used to minimize the mixing or product interfaces. See‘‘— Trans Mountain Terminals’’ and ‘‘— Terminals’’ below.

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As at the date hereof, the Trans Mountain pipeline remains the only pipeline that transports liquidpetroleum from the WCSB to the West Coast. It is also the only pipeline providing Canadian producers withaccess to world market pricing through a Canadian port.

Trans Mountain Terminals

Edmonton Terminal

The TMPL system begins in Sherwood Park, Alberta at the Edmonton terminal (the ‘‘EdmontonTerminal’’). This facility is made up of 35 tanks with total storage capacity of approximately 8.0 million barrels.All tanks at the Edmonton Terminal are in crude oil, condensate or refined product service and each tank hasthe flexibility to handle most products that are connected to the terminal, including in-tank mixing of multipleproducts. The Edmonton Terminal is connected to 20 incoming pipelines from oil and refinery production inAlberta and is adjacent, or in close proximity, to the starting point of the Enbridge Inc. cross-continent crude oilpipeline system, the North 40 Terminal, the Suncor Energy Inc. Edmonton refinery, the Keyera Edmontonterminal, the Keyera Alberta Envirofuels plant, the Gibson Energy Inc. Edmonton terminal, the PlainsMidstream Canada Edmonton Strathcona terminal and the Imperial Oil Strathcona refinery.

Twenty of the tanks at the Edmonton Terminal, ranging in size from 80,000 barrels to 220,000 barrels andcomprising 2.9 million barrels of total storage capacity, are currently used by Trans Mountain to serve the TMPLsystem’s regulated service. As noted above, these tanks are used by Trans Mountain to facilitate batching andmaximize throughput on the TMPL mainline. See ‘‘— Trans Mountain Overview’’ above. The remaining 15 tanksat the Edmonton Terminal (referred to as the ‘‘Edmonton South Terminal’’ and as illustrated in the imagebelow), ranging in size from 250,000 barrels to 400,000 barrels and constituting approximately 5.1 million barrelsof the total storage capacity, are leased to KM Canada North 40’s Edmonton South Terminal and are marketedon a merchant basis, subject to a 24 month right of recall, exercisable by Trans Mountain, in the event that theEdmonton Terminal is built out and Trans Mountain requires the tanks for its regulated service. This leasingarrangement is based on a Memorandum of Understanding with the Canadian Association of PetroleumProducers and has been sanctioned by the NEB. In connection with the completion of the Trans MountainExpansion Project, Trans Mountain expects that it will exercise recall rights under the leasing arrangement withKM Canada North 40 in respect of two of the tanks at the Edmonton South Terminal. As a result, following thisrecall, the Edmonton South Terminal will be comprised of 13 merchant tanks and 22 of the existing tanks will beused by Trans Mountain to service the regulated TMPL system. As the use of the recalled tanks will be includedin the overall tolls charged on the expanded TMPL, such tanks will no longer generate the incremental revenuerealized through leases to external customers. As such, the recall is expected to result in a decrease in the net

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cash earnings attributable to the Edmonton South Terminal. See ‘‘— Terminals — Overview of Terminals —Edmonton South Terminal’’ below.

In addition to its service as a storage and terminalling facility, the Edmonton Terminal houses the primarycontrol centre for the Trans Mountain pipeline, the Puget Sound pipeline, the Jet Fuel pipeline, the North40 Terminal and the line to the Edmonton Rail Terminal. It will also control the supply lines to the Base LineTerminal, once the terminal is in service. Transfer of centralized control for the Westridge Marine Terminal tothis control centre is anticipated to be completed during the latter part of 2017. The control centre located at theEdmonton Terminal does not operate the Cochin pipeline system, which is controlled from the United States.See ‘‘— Terminals’’ below.

Kamloops Terminal

In Kamloops, British Columbia, refined products from Edmonton, Alberta are delivered to a distributionterminal operated by a third party. The TMPL terminal in Kamloops contains two storage tanks with a totalstorage capacity of approximately 160,000 barrels and also serves as a primary pump station for theTMPL system.

Sumas Pump Station and Sumas Terminal

The Sumas pump station and the Sumas terminal (the ‘‘Sumas Terminal’’) are approximately threekilometers apart and are both located in Abbotsford, British Columbia. The terminal is used to stage oil for

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delivery and contains six storage tanks with total storage capacity of approximately 715,000 barrels. The pumpstation includes four pumps, two of which are used to route product from the TMPL mainline into WashingtonState via the Puget Sound pipeline system and two of which are used to route the product on the TMPLmainline to Burnaby, British Columbia.

Burnaby Terminal

The terminal located in Burnaby, British Columbia (the ‘‘Burnaby Terminal’’) is the terminus of the TMPLmainline. It receives both crude oil and refined products for temporary storage and distribution throughseparate pipelines to a local distribution terminal, a local refinery and the Westridge Marine Terminal. TheBurnaby Terminal has 13 storage tanks with total storage capacity of approximately 1.685 million barrels.

The pump station used to operate the Jet Fuel pipeline system is also located within the Burnaby Terminalalthough the Jet Fuel pipeline system and the Trans Mountain pipeline system are not connected and areoperated as separate systems.

Westridge Marine Terminal

The Westridge Marine terminal is located within the Burrard Inlet in Burnaby, British Columbia(‘‘Westridge’’ or the ‘‘Westridge Marine Terminal’’). Regulated by Transport Canada and the NEB, the dock atthe terminal can accommodate up to Aframax class vessels (approximately 120,000 dead weight tons) andbarges.

The Westridge Marine Terminal is used to deliver crude oil from the Trans Mountain pipeline system ontobarges and tankers and to receive jet fuel to the three tanks at the terminal used for delivery into the Jet Fuelpipeline system.

The Westridge Marine Terminal houses three storage tanks, that are currently being leased to a third party,with total storage capacity of approximately 395,000 barrels. Significant modifications are planned for theWestridge Marine Terminal as part of the Trans Mountain Expansion Project. See ‘‘— Trans MountainExpansion Project — Project Description’’ below.

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Puget Sound Pipeline System

In operation since 1954, the Puget Sound pipeline system ships crude oil products from the Sumas Terminalto Washington State refineries in Anacortes and Ferndale.

The Puget Sound pipeline system is approximately 111 kilometers long, with one pump station and adiameter of 16 to 20 inches (406 to 508 mm) and two storage tanks with total storage capacity of approximately200,000 barrels. The system has total throughput capacity of approximately 240,000 barrels per day (whentransporting primarily light oil), with approximately 191,000 barrels per day transported in 2016. The transit timeof products on the Puget Sound pipeline system is approximately one day. The pipeline is regulated by theFERC for tariffs and the USDOT for safety and integrity. Approximately 80% of the 2016 revenue from PugetSound originated from counterparties that have, or are subsidiaries of a parent entity that has, an investmentgrade credit rating (however such parent entity may not be a guarantor).

In addition to their access to the Westridge Marine Terminal, shippers on the TMPL system have, andfollowing completion of the Trans Mountain Expansion Project will continue to have, the option to deliver theirproduct to the Puget Sound pipeline system.

Jet Fuel Pipeline System

The Jet Fuel pipeline system transports jet fuel from a Burnaby refinery and the Westridge Marine Terminalto the Vancouver International Airport. The 41 kilometer pipeline system has been in operation since 1969. Itincludes five storage tanks at the Vancouver International Airport with aggregate storage capacity of

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45,000 barrels. The BC OGC regulates the integrity and safety of the pipeline and the BCUC regulates the JetFuel pipeline’s tolls.

The Trans Mountain Expansion Project

Background

Beginning in early 2011, through discussions with Trans Mountain and existing shippers and otherinterested parties, it became clear that there was significant interest in an expansion of the TMPL for thepurpose of improving access to the North American west coast and offshore markets. Between October 2011and November 2012, Trans Mountain conducted an open season process to obtain commitments for the TransMountain Expansion Project. Trans Mountain advanced a firm service offering designed to provide shippers withlong-term contractual certainty of shipping crude oil product volumes on the expanded system, while providingTrans Mountain with the financial certainty necessary to support the contemplated investment in the expansion.In total, at the conclusion of the open season process, Trans Mountain entered into firm transportation servicesagreements with 13 companies for a total of 707,500 barrels per day based on a capacity of 890,000 barrels perday (the maximum amount that Trans Mountain anticipated the NEB would authorize) following completion ofthe Trans Mountain Expansion Project.

In January 2013, Trans Mountain made an application to the NEB for approval of the proposedtransportation service to be provided and the proposed toll methodology to be used in the event the TransMountain Expansion Project was approved by the NEB (key issues included approval of negotiated rates forcontracted shippers, a 10% premium embedded in the toll methodology for spot shippers over 15-year contractshippers, the limitation of contract capacity to 80% of total capacity and the apportionment methodology forspot capacity). In May 2013, the NEB approved the commercial terms of the expansion proposal. See‘‘— Customers and Contractual Relationships — Expansion Shipping Agreements’’ below.

In December 2013, Trans Mountain submitted its formal facilities application to the NEB. The NEB reviewprocess included approximately 1,650 participants, including Commenters and approximately 400 Intervenors.Key steps in the process included several rounds of Information Requests by the NEB and Intervenors, IRresponses from Trans Mountain and opportunities for Intervenors to file written evidence. The process alsoincluded an oral hearing of Aboriginal groups’ traditional evidence in 2014 and oral argument respecting theTrans Mountain Expansion Project as a whole in 2015 and 2016.

On May 19, 2016, following a 29 month review, the NEB recommended that the Government of Canadaapprove the Trans Mountain Expansion Project, subject to the satisfaction of 157 required conditions. Theseconditions apply during various stages of the proposed project’s lifecycle, including before construction, duringconstruction and during the operation of the expanded TMPL system. The conditions are designed to reducepossible risks that were identified by the NEB during the application process. The conditions cover a wide range

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of areas including safety and integrity, emergency preparedness and response, environmental protection,ongoing consultation with stakeholders, socio-economic matters, financial responsibility and affirmation ofcommercial support. The conditions, which are acceptable to the Business on both a cost and schedule basis, arecomprised of five general conditions, 98 conditions that must be satisfied prior to commencing construction(54 of these conditions are filed as information), 35 conditions that must be satisfied prior to commencingoperations and 19 conditions that will require activities after operations have commenced.

On November 29, 2016, the Government of Canada approved the Trans Mountain Expansion Project andon December 1, 2016, the NEB issued its Certificate of Public Convenience and Necessity. The approval of theTrans Mountain Expansion Project by the Government of Canada was provided in the context of a broaderpipeline plan developed by the federal government designed to grow the Canadian economy while protectingenvironmentally sensitive areas. As a result, along with the announcement of the Trans Mountain ExpansionProject approval, the Government of Canada also noted that, among other things: (i) a moratorium onpersistent oil tankers along British Columbia’s north coast has been implemented; (ii) more than $300 millionhad been committed to Indigenous groups by Kinder Morgan under mutual benefit agreements and theGovernment of Canada had agreed to provide funding for an Indigenous advisory and monitoring committee towork with federal regulators and Kinder Morgan to oversee environmental aspects of the Trans MountainExpansion Project and other projects throughout their applicable life cycles; (iii) before any shipping from theTrans Mountain Expansion Project begins, a recovery plan for the southern resident killer whale population anda $1.5 billion national ocean protection plan will be implemented to improve marine safety and responsibleshipping; (iv) Trans Mountain is required to develop a construction-related emissions offset plan to achieve zeronet emissions; and (v) through the climate leadership plan, the Government of Alberta had committed to cap oilsands emissions at 100 megatonnes of CO2 per year to limit future potential upstream greenhouse gas emissions.

On January 11, 2017, the Government of British Columbia announced the issuance of an environmentalassessment certificate from B.C.’s Environmental Assessment Office to Trans Mountain for the B.C. portion ofthe Trans Mountain Expansion Project. The environmental assessment certificate includes 37 conditions that arein addition to and designed to supplement the 157 conditions required by the NEB.

In addition, on January 11, 2017, the Government of British Columbia announced that the Trans MountainExpansion Project had met the B.C. Government’s five conditions relating to world-leading marine and land oilspill response, protection and recovery measures for B.C.’s coast and land areas, environmental reviews, FirstNations consultations and participation and economic agreements that reflect the level and nature of the risk theprovince bears with a heavy oil project. The meeting of such conditions being an important precursor toreceiving approval of additional provincial permits. In connection with the B.C. conditions, Trans Mountain hasentered into an agreement to contribute a guaranteed amount of $25 million annually for 20 years to the B.C.Government, and up to a maximum of $50 million annually, depending on spot volume shipments. The B.C.Government has stated that all of the proceeds received from Trans Mountain pursuant to this agreement will beused and applied to a new B.C. Clean Communities Program, or similar program, which has a mandate toprovide funding for projects and initiatives that protect the environment and benefit communities, includinglocal projects that protect, sustain and restore B.C.’s natural and coastal environments.

Trans Mountain incorporated the NEB’s 157 conditions and the 37 conditions of the Government of BritishColumbia into its cost estimates and project schedule and, in response to public feedback, has implementedcertain additional changes to the Trans Mountain Expansion Project including, among other things, increasingpipe wall thickness and adding additional drilled crossings in environmentally sensitive areas and the BurnabyMountain tunnel. These and other factors resulted in Trans Mountain increasing the final cost estimate and tollsto reflect an updated estimated Trans Mountain Expansion Project cost of approximately $7.4 billion (includingcapitalized financing costs). On March 9, 2017, the final cost estimate review with shippers was completedwherein shippers had the option to keep their volume commitments or turn back their commitments (or aportion thereof) and pay their pro rata share of development costs to date.

The NEB-approved commercial terms for the Trans Mountain Expansion Project contemplate a capital costrisk sharing investment structure whereby the capital costs associated with the Trans Mountain ExpansionProject will be classified into two segments: capped costs and uncapped costs. Uncapped costs, which account for

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approximately 24% of the capital cost of the Trans Mountain Expansion Project, will include some of the higherrisk capital cost components of the Trans Mountain Expansion Project whereby any cost overruns will bereflected in increased tolls. These components include: (i) the price of steel for pipe; (ii) difficult pipelineconstruction spreads totaling approximately 10% of the Trans Mountain Expansion Project specifically, onemountain spread through the Coquihalla Summit near Hope, British Columbia and one urban spread betweenLangley and Burnaby, British Columbia (including the Burnaby tunnel); (iii) land acquisition costs betweenLangley and Burnaby, British Columbia; and (iv) all consultation and accommodation costs, including withrespect to Aboriginal and non-Aboriginal communities. Costs above or below the uncapped cost amount will bereflected in higher or lower tolls for shippers by approximately $0.07 per barrel per $100 million of capital costchange. This structure is anticipated to not only allow Trans Mountain to recover its costs with respect tooverruns on uncapped costs but to also earn returns following such cost recovery. Capped costs, which areexpected to account for approximately 76% of the capital cost of the Trans Mountain Expansion Project, includeall other costs associated with the construction of the Trans Mountain Expansion Project not classified asuncapped costs. Any capped costs above the pre-determined amount are the responsibility of Trans Mountain;however, capped costs below the pre-determined amount are reflected in lower tolls for shippers byapproximately $0.07 per barrel per $100 million of capital cost change. Kinder Morgan has spent yearsadvancing engineering designs for the Trans Mountain Expansion Project and has developed a comprehensiveconstruction plan in conjunction with several of the world’s leading engineering, procurement and constructionand general contractor construction companies. As of March 31, 2017, remaining cash construction costs on theTrans Mountain Expansion Project were estimated to be approximately $6.2 billion. The costs of the TransMountain Expansion Project are expected to remain attractive even in cases of significant cost increases andschedule delays; however, such increases or delays will affect the amount of capital raised and the timing of therealization of earnings and cash flows from the Trans Mountain Expansion Project.

Trans Mountain delivered the final cost estimate and tolls to shippers in February 2017. At that time someexisting shippers gave up capacity, some increased capacity and some new shippers acquired capacity, the netresult of which was the turn back of 22,000 barrels per day (or 3% of the previously committed barrels). These22,000 barrels per day were subsequently recommitted during an additional supplemental open season process inMarch 2017. As a result of the Trans Mountain Expansion Project’s open season processes, 13 companies haveentered into one 15-year and 12 20-year transportation service agreements with Trans Mountain for a total of707,500 barrels per day, representing approximately 80% of the expanded system’s capacity (the maximumamount under the regulated limit imposed by the NEB). This maximum level of recommitment highlights thestrong market demand for the expanded system’s takeaway capacity and has better aligned the Trans MountainExpansion Project shipper composition with the changing Canadian crude producer landscape.

The final investment approval with respect to the Trans Mountain Expansion Project was obtained May 25,2017, conditioned on the closing of the Offering. See ‘‘Plan of Distribution’’.

Project Description

Upon the completion of the proposed Trans Mountain Expansion Project, the TMPL system is anticipatedto have capacity of 890,000 barrels per day. The proposed expansion of the TMPL system is intended tocomprise, among other things, the following:

• approximately 980 kilometers of new, buried pipeline segments that twin (or ‘‘loop’’) the existing pipelinein Alberta and British Columbia, including two 3.6 kilometer segments (7.2 kilometers in total) of newburied delivery lines from the Burnaby Terminal to the Westridge Marine Terminal;

• new and modified facilities, including pump stations and tanks; and

• a new dock complex with three new berths at the Westridge Marine Terminal, each capable of handlingAframax class vessels.

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The following diagram illustrates the overall Trans Mountain Expansion Project configuration:

The major components of the pipeline portion of the Trans Mountain Expansion Project will include:

• using existing active 24 inch (610 mm) and 30 inch (762 mm) outside diameter buried pipeline segments;

• reactivating two 24 inch (610 mm) outside diameter buried pipeline segments that have been maintainedin a deactivated state;

• constructing three new 36 inch (914 mm) and one new 42 inch (1,220 mm) outside diameter buriedpipeline segments totaling approximately 860 kilometers and 120 kilometers, respectively; and

• constructing two parallel 3.6 kilometers long, 30 inch (762 mm) outside diameter buried delivery linesfrom the Burnaby Terminal to the Westridge Marine Terminal.

The Trans Mountain Expansion Project will result in two continuous pipelines between Edmontonand Burnaby:

• Line 1 is expected to have a capacity of 350,000 barrels per day of light crude oil; and

• Line 2 is expected to have a capacity of 540,000 barrels per day of heavy crude oil.

The existing TMPL has been operating safely for more than 60 years and its location is known to localTMPL operations crews, landowners, surface management agencies, and local emergency responders. Tominimize environmental and socio-economic effects and facilitate efficient pipeline operations, use of the

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existing TMPL right of way has been maximized in the Trans Mountain Expansion Project design. Where it wasnot possible to align along the existing TMPL right of way, construction along other linear facilities wasevaluated including other pipelines, power lines, highways and roads, railways, communication lines and otherutilities. The result is that approximately 73% of the new pipeline corridor follows the existing TMPL right ofway, approximately 17% follows other existing rights of way, and approximately 10% will be within a newcorridor. The completion of the Anchor Loop project in 2008 also avoids the need for additional construction inthe highly sensitive Jasper National Park region.

Electrically-powered pump stations located at regular intervals along the pipeline will be required for theexpansion. The major components of the pump stations portion of the Trans Mountain Expansion Project whichwill support mainline operation include:

• adding 12 new pump stations;

• reactivating the existing Niton pump station and adding one pumping unit at the Sumas pumpstation; and

• deactivating some elements of the existing Wolf, Alberta and Blue River, British Columbiapump stations.

The major components of the associated facilities of the Trans Mountain Expansion Project include:

• the addition of 20 new above-ground storage tanks, including the construction of four new tanks andinclusion of two existing tanks at the Edmonton Terminal, constructing one new tank at the SumasTerminal and the construction of 14 new tanks and the demolition of one existing tank at the BurnabyTerminal; and

• constructing a new dock complex, with a total of three Aframax-capable berths, as well as a utility dock(for tugs, boom deployment vessels, and emergency response vessels and equipment), at the WestridgeMarine Terminal, followed by the deactivation and demolition of the existing berth.

Seventy-two new buried remote mainline block valves will be installed and complement existing mainlineblock valves, which will be located at the pump stations. These remote mainline block valves and mainline blockvalves work to limit the volume and consequences associated with a pipeline leak or ruptures. A total of 25 newsending or receiving scraper traps for in-line inspection tools will also be installed at facility locations alongthe pipeline.

In addition, the Trans Mountain Expansion Project requires two power line connections to the BC Hydrosystem, an approximately 24 kilometer line to connect to a power station in Kingsvale, British Columbia and anapproximately 1.5 kilometer connection to a power station in Black Pines, British Columbia. BC Hydro requiresTrans Mountain to either build such lines and turn them over to BC Hydro for a minimal amount or continue toown, maintain and operate them. The Business is currently considering selling these power line assets to a thirdparty and entering into a services contract in relation thereto.

Currently, up to approximately five vessels per month are loaded with heavy crude oil at the WestridgeMarine Terminal. Upon completion of the Trans Mountain Expansion Project, it is anticipated that theWestridge Marine Terminal will be capable of serving up to 34 Aframax class vessels per month with actualdemand to be influenced by market conditions. The maximum vessel size (Aframax class) served at the terminalwill not change as a result of the Trans Mountain Expansion Project. Similarly, product moving over the dock atthe Westridge Marine Terminal is expected to continue to be primarily heavy crude oil. Of the 890,000 barrelsper day capacity of the expanded system, up to 630,000 barrels per day may be handled through the WestridgeMarine Terminal for shipment. Currently, monthly barge traffic typically consists of loading two crude oil bargesand receiving one jet fuel barge. This level of activity is not expected to be affected by the Trans MountainExpansion Project.

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The Business is currently in negotiations with construction contractors to construct the various pipelinespreads on the Trans Mountain Expansion Project, with the intention that general construction contracts will beentered into with respect to spreads one through six and engineering, procurement and construction contractswill be entered into with respect to spread seven, terminals and pump stations (including the EdmontonTerminal) and with respect to any work required in the Lower Mainland. An illustration of the Trans MountainExpansion Project pipeline spreads is set out below.

Upon completion, the newly constructed pipeline is expected to carry predominantly heavy crude volumesand the existing pipeline will carry predominantly light crude and refined products.

Project Schedule

Trans Mountain continues to work towards obtaining all necessary permits and the Business expects tobegin construction on the Trans Mountain Expansion Project in September 2017, with an anticipated in-servicedate at the end of 2019. A summary of the overall Trans Mountain Expansion Project timeline is set out in thegraphic below and a comprehensive construction plan has been developed in order to help achieve this timeline.See ‘‘Risk Factors — Risks Relating to the Development of the Trans Mountain Expansion Project and the Businessand Operations of the Business — Major Projects, Including the Trans Mountain Expansion Project, May beInhibited, Delayed or Stopped’’.

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Customers and Contractual Relationships

Existing Shipping Agreements

The TMPL mainline is a common carrier pipeline, providing transportation services under a cost of servicemodel that is negotiated with shippers and regulated by the NEB. Although Trans Mountain takes custody of itsshippers’ products, it does not own any of the product it ships. The TMPL system has posted tariff rates that areavailable to all shippers based on a monthly contract which varies according to the type of product being shippedas well as receipt and delivery points. As such, it provides service to producers, marketers, refineries andterminals who sell or resell products to domestic markets, oil marketers and international shippers moving oil tosuch places as California, Washington and Asia.

Since late 2010, the TMPL system has been meaningfully over-subscribed, resulting in pipelineapportionment (nominating less volumes for shipment than shippers request). Shippers on the TMPL system aregenerally large and well-capitalized. In 2016, the top ten shippers on the Trans Mountain pipeline accounted forapproximately 70% of the revenue generated from the system. Of these shippers, as a percentage of suchrevenue generated, 85% have, or are subsidiaries of a parent entity that has, an investment grade credit rating(however, such parent entity may not be a guarantor), with approximately 66% being rated A� to AA+ by S&Pand approximately 19% being rated BBB to BBB+ by S&P. Of the remaining 15%, 11% are non-investmentgrade and 4% of the shippers do not have a credit rating. In alphabetical order, current shippers on the TransMountain pipeline system include the following entities or affiliates thereof: BP Canada Energy TradingCompany, Cenovus Energy Inc., Chevron Canada Limited, Imperial Oil, Nexen Energy ULC, Phillips66 Canada Ltd, Shell Canada Products, Suncor Energy Inc., and Tesoro Canada Supply and Distribution Ltd.

Throughout the past 20 years, Trans Mountain has entered into negotiated toll settlements with its shippersto establish final tolls on the TMPL system. The Company believes that negotiated settlements are advantageousfrom a cost perspective and may provide opportunities for additional returns.

In February 2016, the NEB approved Trans Mountain’s 2016 to 2018 (inclusive) negotiated toll settlement.The toll settlement provides for a three year term and includes a rollover provision and an Trans MountainExpansion Project transition provision. TMPL’s net regulated rate base is approximately $1 billion as atDecember 31, 2016 with sustaining capital automatically added in subsequent years. Under the NEB-approvednegotiated toll settlement, the tolls on the TMPL system are based on a 9.5% return on equity, a 5% cost of debtand a deemed 45% equity and 55% debt structure. The toll settlement provides for the flow-through to shippersof certain operating costs, including power costs, property tax, income tax, integrity costs, environmentalcompliance and remediation costs and the cost of insurance and security. Labour and service-related costs are

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fixed costs determined by the shared service model using a methodology approved by the NEB. These costs areallocated to the system based on usage and are escalated at a set index during the toll settlement period. Inaddition, the toll settlement agreement provides power and capacity incentives. Specifically, 50% of the BritishColumbia power costs savings are allocated to the shipper and 50% are allocated to the pipeline system and 75%of the transmission power costs savings are allocated to the shipper and 25% are allocated to pipeline sharing.The settlement agreement also provides for a capacity incentive which is allocated 50% to the shipper and 50%to the pipeline system above a formulaic 96% capacity target. Revenue variances resulting from volume arerecovered from shippers in the following year. Trans Mountain’s current negotiated toll settlement includes aprovision for extension, if the extension is mutually acceptable to Trans Mountain and the shipper, up until theTrans Mountain Expansion Project in-service date.

In 2011, Trans Mountain received approval from the NEB to implement firm service for 54,000 barrels perday of service to the Westridge Marine Terminal, and charge a premium on such barrels to fund expansionprojects on the TMPL system. This service and the premiums associated with it will be in effect until the earlierof the in-service date of the TMPL expansion and ten years from the date of implementation. The premiums areapproved to be used by Trans Mountain to offset the cost of projects designed to enhance existing and futureoperations including development costs relating to the Trans Mountain Expansion Project and equate to a totalof approximately $28.6 million per year. As at December 31, 2016, $34 million had been used to construct a250,000 barrel tank and associated infrastructure at the Edmonton Terminal and $104 million had been used tooffset the development costs of the Trans Mountain Expansion Project. As part of its firm serviceimplementation, 27,000 barrels per day of existing TMPL capacity was reallocated to the Westridge MarineTerminal, increasing the terminal’s allocation to a total of 79,000 barrels per day.

Rates charged on the Puget Sound pipeline system are regulated by the FERC and are based on a cost ofservice model that has been in place since prior to 1992 and, as such, have been grandfathered and escalatedfrom time to time as permitted by the FERC. As a result of this grandfathering, the Puget Sound cost of servicerates that were in place for the 365 day period prior to September 1992, plus escalation, may continue to becharged to its shippers unless and until the rates are successfully challenged on the basis that a substantialchange has occurred in the economic circumstances or nature of the services provided which were a basis forsuch rates. To date, no such complaints have been made. In 2016 approximately 80% of the revenue on thePuget Sound pipeline originated from customers that have, or are subsidiaries of a parent entity that has, aninvestment grade credit rating (however such parent entity may not be a guarantor).

The Jet Fuel pipeline system delivers jet fuel from the Westridge Marine Terminal and from a refinery inBurnaby to the Vancouver International Airport. With respect to the volume from the Westridge MarineTerminal, Trans Mountain has a contract with one of Canada’s largest airlines to unload jet fuel from barges atthe Westridge Marine Terminal and store such volumes at the Westridge Marine Terminal. The Jet Fuel pipelinesystem then transports such jet fuel to the Vancouver International Airport. Through this arrangement and thejet fuel shipped from the Burnaby refinery, the Jet Fuel pipeline system has a BCUC-approved negotiatedsettlement that ends in 2018.

Expansion Shipping Agreements

The NEB approval for the Trans Mountain Expansion Project requires that no less than 60% of theexpanded system’s capacity remain contracted and that no shipper termination rights remain outstanding priorto the commencement of construction. As noted above, as a result of the Trans Mountain Expansion Project’sopen season processes, 13 companies have entered into transportation service agreements with Trans Mountain,one having a 15 year term and 12 having a 20-year term, for a total of 707,500 barrels per day, representingapproximately 80% of the expanded system’s capacity (the maximum amount under the regulated limit imposedby the NEB). As illustrated below, these shippers represent or are affiliates of some of the largest producingcompanies in the WCSB and a significant majority of these committed shippers have, or are subsidiaries of aparent entity that has, an investment grade credit rating (however such parent entity may not be a guarantor).These companies have direct access to large volumes of supply, either through their own production, or throughtheir position in the market as a large marketer and/or refiner of crude oil.

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AA+ / AA+

A+ / unrated

A- / A-

A- / unrated

BBB+ / BBB+

BBB+ / unrated

BBB+ / unrated

BBB / BBB

BB+ / unrated

BB / unratedBB- / BB-

B- / B-

BBB / BBB

0

100

200

300

400

500

600

700

800

Parent / Subsidiary Rating(1)

Volu

me

(mbb

l/d)

Note:

(1) On a barrels per day basis, approximately 82% of the post-expansion shippers have, or have a parent entity with, an investmentgrade credit rating (although such parent may not be a guarantor). Credit rating information sourced from Bloomberg.

Where a particular shipper is not investment grade or no support provider is available, Trans Mountain mayobtain, in respect of such shipper, letters of credit from acceptable banks for an amount having the same value asup to 12-months of the shipper’s contract exposure, or such other amount as may be determined reasonable andappropriate.

The Trans Mountain Expansion Project-related transportation service agreements provide for a sharing ofrisks between Trans Mountain and its shippers during the development stage, including the construction of theTrans Mountain Expansion Project, and the long-term operation of the pipeline system. Each shipper is entitledto a certain amount of capacity each month, and the shippers are required to pay for the fixed cost of suchcapacity whether they use it or not.

The transportation service agreements also provide flexibility to the shippers that are parties to them, assuch agreements enable the shippers to manage their capacity entitlements and associated financial obligations.Shippers can assign their shipping rights to third parties on a short-term or long-term basis, thereby reducing riskand ensuring that the firm capacity is fully utilized. There are also make-up provisions in the event that shipperscannot use their full capacity entitlements in any given month. Shippers also have the right to renew theircontracts at the end of the initial term for an additional five year period on rates to be determined at the time ofrenewal (if any).

The fixed toll to be paid by shippers under the Trans Mountain Expansion Project-related transportationservice agreements has been established according to a risk sharing formula that will be escalated during thelifetime of the contracts at a fixed rate. Under the agreements there is a variable toll component based on actualcosts incurred for power, unanticipated costs related to changes in legislation or regulation and other costs asmay be agreed to by Trans Mountain and shippers. As the vast majority of the toll will not be adjusted according

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to actual costs incurred, as would normally occur under a cost-of-service approach, this arrangement will providegreater toll certainty to shippers and reduce the risk of unanticipated increases in transportation costs over time.

Approximately 20% of the expanded TMPL system’s nominal capacity (182,500 barrels per day), will bereserved for spot month-to-month shipments. The toll for spot shipments will be tied to the toll for long-termservice and, as such, spot shippers will benefit from all of the contractual provisions that protect long-termshippers from cost escalation.

Competition

Trans Mountain is subject to competition resulting from the shipment of oil from the WCSB to marketsother than the Canadian and U.S. West Coast, including shipments to refineries in Ontario, the U.S. Midwestand the U.S. Gulf Coast. In addition, refineries in Washington State and California, which comprise animportant point of sale on the U.S. West Coast, have, in the past, been supplied primarily by crude oil from theAlaska North Slope. As such, there has historically been some competitive pressure on supply originating fromthe WCSB for sale in the Washington State and California refinery markets. A further source of competitionexists from the transportation of oil to the Canadian West Coast by rail. The Company expects that such supplyand demand conditions in the oil markets served from the west coast of British Columbia will continue to impactthe long-term value and economics of the TMPL system.

Despite this potential competitive pressure, the Company believes that the TMPL system, both pre- andpost-expansion, will maintain its strong competitive position as a result of a number of factors. For example,contracted tariff rates on Trans Mountain after the expansion will range from approximately $5.00 per barrel toapproximately $7.00 per barrel from Edmonton to Burnaby area. Uncontracted spot tariff rates will be 10%higher than the equivalent contracted tariff rates. Converted to U.S. dollars, these tariff rates would range fromapproximately U.S.$4.00 per barrel to approximately U.S.$6.00 per barrel. Environment and Climate ChangeCanada has estimated comparable rail transportation costs to California and the U.S. Gulf Coast to beapproximately U.S.$16.00 per barrel and approximately $18.00 per barrel, respectively. Keystone posted tariffrates for U.S. Gulf Coast delivery are approximately U.S.$7.80 per barrel to U.S.$12.60 per barrel for heavy oil.The Government of Alberta, as of January 2017, reported the differential between WTI (light oil at CushingOklahoma) and WCS (heavy crude at Hardisty, Alberta) was approximately U.S.$15.00 per barrel.

In addition, the TMPL offers significant optionality and flexibility to its customers. Its tolling methodologyand transportation contracts have been designed to promote high operating standards while remainingcost-competitive for the foreseeable future. Trans Mountain remains the only pipeline that transports oil andother liquid petroleum products from the WCSB to the West Coast of Canada and the United States and thisimportant outlet provides producers in the WCSB with improved market access and market diversification.Further, due to recent changes in U.S. legislation, oil from the Alaska North Slope may now be sold to marketsoutside of the United States. To the extent this additional access to alternative markets for Alaskan producersincreases overall demand from Washington State and California refineries, the TMPL system, including throughits Puget Sound pipeline connection to four refineries in Washington State, will be in a position to facilitatesupply to such markets for WCSB producers. As evidence of these competitive advantages, capacity on theTMPL has been over-subscribed since 2010 and approximately 80% of the capacity of the TMPL uponcompletion of the Trans Mountain Expansion Project is subject to long-term firm commitments. Similarly,throughput on the Puget Sound pipeline system has steadily risen in recent years, with 2015 and 2016experiencing increases from previous years of over 15% and 30%, respectively. In 2016, the Puget Soundpipeline transported average volumes of approximately 191,000 barrels per day, comprising approximatelyone-third of the collective capacity of all refineries in the Anacortes and Ferndale area.

Historically, the Jet Fuel pipeline has transported a significant proportion of the jet fuel used at theVancouver International Airport. However, the airport also receives jet fuel through other means includingtrucks and, recently, an affiliate of each of the airlines using the airport received approval to construct a jet fuelbarge-receiving terminal near the airport. In 2016, the entity owning the Burnaby refinery supplying products toJet Fuel for shipment announced its intention to sell the refinery and in April 2017 announced that it hadreached an agreement with a third party for such sale. As a result of this pending sale, the Company is unable topredict whether, and to what extent, that refinery will continue to supply jet fuel to the Jet Fuel pipeline. These

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developments have made it unclear how much jet fuel will continue to be available for shipment to theVancouver International Airport by way of the Jet Fuel pipeline in the future. To the extent it becomesuneconomic to continue shipping jet fuel to the Vancouver International Airport, the Company estimates thatthe decommissioning and abandonment costs of the Jet Fuel pipeline would be in the range of $2.0 million to$3.0 million, subject to regulatory approval of the BCUC and the BC OGC. The Business continues to assess itsoptions relating to the Jet Fuel assets.

Potential Growth Opportunities

While the Business does not presently have any plans to expand the TMPL system outside of the currentscope of the Trans Mountain Expansion Project, the combined capacity of the expanded pipeline couldpotentially be further increased by over 300,000 barrels per day to approximately 1.2 million barrels per day, withadditional power and further capital enhancements.

The Puget Sound pipeline is capable of being expanded to increase its capacity to approximately500,000 barrels per day from its current capacity of 240,000 barrels per day. See ‘‘The Business — InvestmentHighlights — Sizeable growth project of strategic national importance to Canada’’.

The Business will continue to monitor market and industry developments to determine which, if any,further expansion projects on the TMPL system may be appropriate.

See ‘‘Risk Factors — Risks Relating to the Development of the Trans Mountain Expansion Project and theBusiness and Operations of the Business — Major Projects, Including the Trans Mountain Expansion Project, MayBe Inhibited, Delayed or Stopped’’.

Cochin Pipeline System

Overview

The Cochin pipeline system consists of a 12 inch (305 mm) diameter pipeline which spans from KankakeeCounty, Illinois to Fort Saskatchewan, Alberta, totalling approximately 2,452 kilometers. The Cochin pipelinesystem, which transports light hydrocarbon liquids (primarily to be used as diluent to facilitate bitumentransportation), traverses two provinces in Canada and four states in the United States. The Canadian Cochinpipeline system is comprised of 999 kilometers of pipeline and includes 38 block valves and ten pump stations.While the U.S. portion of Cochin is not part of the Business, the U.S. portion of Cochin and the CanadianCochin pipeline system are interdependent (including with respect to volumes shipped and financial andcontractual obligations) and, as the bulk of the tariffs on the Cochin pipeline system are governed by a jointinternational tariff, revenue is shared between the U.S. portion of Cochin and the Canadian Cochin pipelinesystem.

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