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EX-32.2 - EXHIBIT 32.2 - Kinder Morgan Canada Ltdkml-2017x10kxexh322.htm
EX-32.1 - EXHIBIT 32.1 - Kinder Morgan Canada Ltdkml-2017x10kxexh321.htm
EX-31.2 - EXHIBIT 31.2 - Kinder Morgan Canada Ltdkml-2017x10kxexh312.htm
EX-31.1 - EXHIBIT 31.1 - Kinder Morgan Canada Ltdkml-2017x10kxexh311.htm
EX-21.1 - EXHIBIT 21.1 - Kinder Morgan Canada Ltdkml-2017x10kxexh211.htm
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________
Form 10-K
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 000-55864
kmllogo.jpg
Kinder Morgan Canada Limited
(Exact name of registrant as specified in its charter)
Alberta, Canada
 
N/A
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)

Suite 2700, 300 - 5th Avenue S.W. Calgary, Alberta T2P 5J2
(Address of principal executive offices) (zip code)
Registrant’s telephone number, including area code: 403-514-6780
____________
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Restricted Voting Shares
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.  Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.  Yes o  No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes o  No þ
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  o  No o 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” (in Rule 12b-2 of the Exchange Act).
Large accelerated filer o Accelerated filer o  Non-accelerated filer þ   Smaller reporting company o Emerging growth company þ
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o  No þ
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the Toronto Stock Exchange on June 30, 2017 was approximately CAD$1,631,630,700.  As of February 16, 2018, the registrant had 103,661,302 Restricted Voting Shares outstanding.
            
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018, are incorporated into PART III, as specifically set forth in PART III.




KINDER MORGAN CANADA LIMITED
TABLE OF CONTENTS

 
 
Page
Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 







EXPLANATORY NOTE

Capitalized terms used throughout this document are defined in "Glossary" below. References to "we," "us," "our" and the "Company" are to Kinder Morgan Canada Limited and, unless the context otherwise indicates, the Operating Entities. We state our financial statements in Canadian dollars. References in this document to "dollars," "$" or "CAD$" are to the currency of Canada, and references to "U.S.$" or “U.S. dollar” are to the currency of the United States. See "Conversions."


GLOSSARY

Company Abbreviations
 
Class A Units
=
the Class A limited partnership units of the Limited Partnership
 
Class B Units
=
the Class B limited partnership units of the Limited Partnership
 
Cochin
=
Canadian portion of the U.S. and Canadian Cochin pipeline system
 
Company Voting Shares
=
collectively, the Restricted Voting Shares and the Special Voting Shares
 
Cooperation Agreement

=
the cooperation agreement, between the Company, the General Partner, the Limited Partnership, KMCC, KMCT and Kinder Morgan (in respect to certain provisions only) entered into in connection with the IPO

 
General Partner

=
Kinder Morgan Canada GP Inc.

 
IPO
=
Initial Public Offering of KML’s Restricted Voting Shares in May 2017
 
Jet Fuel
=
Jet Fuel pipeline system
 
KMCC
=
Kinder Morgan Canada Company
 
KMCI
=
Kinder Morgan Canada Inc.
 
KMCT
=
Kinder Morgan Canada Terminal ULC
 
KMCU
=
Kinder Morgan Cochin ULC
 
KML
=
Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries
 
Kinder Morgan
=
Kinder Morgan, Inc.
 
Kinder Morgan Canada Group

=
collectively, the Company, the General Partner, the Limited Partnership, and each person that any of the Company, the General Partner or the Limited Partnership controls from time to time

 
Kinder Morgan Group
=
Kinder Morgan and each person that Kinder Morgan directly or indirectly controls from time to time, other than any member of the Kinder Morgan Canada Group

 
Limited Partnership
=
Kinder Morgan Canada Limited Partnership
 
LP Units
=
collectively, the Class A Units and the Class B Units
 
Operating Entities
=
the companies, partnerships and joint ventures that own and operate the assets comprising our business, which are direct or indirect wholly owned subsidiaries or jointly-controlled investments of the Limited Partnership, with the principal operating entities being KMCU, KM Canada Marine Terminal Limited Partnership, KM Canada North 40 Limited Partnership, Kinder Morgan Canada Rail Holdings GP Limited, KMCI, Trans Mountain Pipeline L.P., Trans Mountain (Jet Fuel) Inc., Trans Mountain Pipeline (Puget Sound) LLC and Trans Mountain
 
Preferred LP Units

=
the preferred limited partnership units in the Limited Partnership
 
Puget Sound
=
Puget Sound pipeline system
 
Restricted Voting Shares
=
the restricted voting shares in the capital of KML
 
Series 1 Preferred Shares
=
the 12,000,000 cumulative redeemable minimum rate reset Preferred Shares, Series 1 in the capital of KML
 
Series 2 Preferred Shares
=
the cumulative redeemable floating rate Preferred Shares, Series 2 in the capital of KML
 
Series 3 Preferred Shares
=
the 10,000,000 cumulative redeemable minimum rate reset Preferred Shares, Series 3 in the capital of KML
 
Series 4 Preferred Shares
=
the cumulative redeemable floating rate Preferred Shares, Series 4 in the capital of KML
 
Preferred Shares
=
Collectively all outstanding Series 1 Preferred Shares, Series 2 Preferred Shares (if and when issued), Series 3 Preferred Shares and Series 4 Preferred Shares (if and when issued)
 
Special Voting Shares
=
the special voting shares in the capital of KML
 
TMEP
=
Trans Mountain Expansion Project
 
TMPL
=
Trans Mountain pipeline system
 

1


GLOSSARY (continued)

Trans Mountain
=
Trans Mountain Pipeline ULC
 
Unless the context otherwise requires, references to “we,” “us,” “our,” “ours,” “the Company,” are intended to mean Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries.
 
 
 
Common Industry and Other Terms
 
/d
=
per day
 
Adjusted EBITDA
=
adjusted earnings before interest expense, taxes, depreciation and amortization
 
B.C.
=
British Columbia
 
BCUC
=
British Columbia Utilities Commission
 
bpd
=
barrels per day
 
DCF
=
distributable cash flow
 
DD&A
=
depreciation, depletion and amortization
 
EBDA
=
earnings before depreciation, depletion and amortization expenses
 
FASB
=
Financial Accounting Standards Board
 
FERC
=
Federal Energy Regulatory Commission
 
GAAP or U.S. GAAP
=
United States Generally Accepted Accounting Principles
 
LLC
=
limited liability company
 
MBbl
=
thousand barrels
 
MMBbl
=
million barrels
 
MMtonnes
=
million metric tonnes.
 
NEB
=
National Energy Board
 
SEC
=
United States Securities and Exchange Commission
 
TSX
=
Toronto Stock Exchange
 
U.S.
=
United States of America
 
WCSB
=
Western Canadian Sedimentary Basin
 
 


2


Information Regarding Forward-Looking Statements

This report includes forward-looking statements and forward-looking information, including forward-looking information and projections provided by third party sources (collectively “forward-looking statements”). These 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,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, but without limitation, this document contains forward-looking statements pertaining to the following:

the TMEP and Base Line Terminal project, including the possibility of mitigation to     address project delays, the impact of cost increases (and the extent to which Trans Mountain is able to pass such costs through to shippers) and delays on project returns, and the cost structure, anticipated funding, construction plans, completion scheduling, in-service dates, future utilization, future revenue and costs and future impacts on our Adjusted EBITDA and DCF;
expectations regarding our ability to generate certain targeted Adjusted EBITDA and DCF (including capitalized financing costs) and to declare dividends, including amounts thereof;
the future commercial viability of our business;
the realization of benefits deriving from future growth projects, including TMEP and Base Line Terminal;
the potential growth opportunities and anticipated competitive position of our business segments;
the anticipated results of our pipeline tolls and toll structure and our ability to recover certain cost overruns and earn returns as a result of such tolls;
expectations respecting our ability to generate predictable and growing cash available for distribution and to support growing dividends;
expectations and intentions respecting distributions from the Limited Partnership, the payout of DCF and our payment of quarterly dividends to our shareholders, as well as the amounts of those dividends;
the extent of Kinder Morgan’s indirect participation in the Limited Partnership’s distribution reinvestment plan;
the impact of commodity pricing;
anticipated future capital and operating expenditures;
expectations respecting the ongoing financing of our business and operations;
anticipated decommissioning and abandonment costs;
operational (including marine) safety levels and standards;
future pipeline capacity and tolls; and
future crude oil supply and demand and demand for the services we provide.

Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. 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 are beyond our ability to control or predict. Any “financial outlook” set out in this document has been included for the purpose of providing information relating to management’s current expectations and plans for the future, is based on a number of significant assumptions and may not be appropriate, and should not be used, for purposes other than those for which such forward-looking statements are disclosed herein.

Our business, financial condition and results of operations, including our ability to pay cash dividends, are substantially dependent on our financial condition and results of operations and our successful development of TMEP. As a result, factors or events that impact our business as well as the costs associated with and the time required to complete (if completed) TMEP are likely to have a commensurate impact on us, the market price and value of the Restricted Voting Shares and our ability to pay dividends. Similarly, given the nature of our relationship with Kinder Morgan, factors or events that impact Kinder Morgan may have consequences for us.

Specific factors that could cause actual results to differ from those in the forward-looking statements provided in this document include, but are not limited to:

issues, delays or stoppages associated with major expansion projects, including TMEP;
our receipt, and the timing of receipt, of governmental and/or regulatory approvals and permits;
changes in the level or nature of support or opposition from the federal government and various provincial governments (including the Alberta and B.C. provincial governments), municipal governments and/or applicable regulators (including the NEB);
public opposition and 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;
an increase in our indebtedness and/or significant unanticipated cost overruns or required capital expenditures;

3


changes in public opinion or damage to our reputation;
the resolution of issues relating to interested third party and/or Aboriginal rights, title and consultation;
the level of shipper demand for spot utilization on the Trans Mountain pipeline;
the breakdown or failure of equipment, pipelines and facilities; releases or spills; operational disruptions or service interruptions; and catastrophic events;
volatility in prices for and resulting changes in demand for refined petroleum products, oil, steel and other bulk materials and chemicals and certain agricultural products;
industry, market and economic conditions and demand for the services we provide;
the availability of alternative energy sources and conservation and technological advances;
changes in overall global demand for hydrocarbons;
natural disasters, extreme weather events or power shortages;
difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals, storage facilities or pipelines;
conditions in the capital and credit markets, inflation and fluctuations in interest rates;
our ability to access external sources of financing in sufficient amounts and on acceptable terms to the extent needed to fund expansions of our pipelines, terminals, storage and related facilities and the acquisition of operating businesses and assets;
compliance with legislative or regulatory requirements or changes in laws, regulations, third-party relations, approvals and decisions of courts, regulators (including the NEB) and other applicable governmental bodies;
changes to regulatory, environmental, political, legal, operational and geological considerations;
changes in tariff rates set by the NEB or another regulatory agency;
changes in our capital structure and credit ratings;
changes in tax law and/or tax reassessments;
national, international, regional and local economic, competitive and regulatory conditions and developments;
abandonment costs that may be substantial and exceed the amounts held in abandonment trusts;
risks related to Kinder Morgan holding the controlling voting interests in us and any changes in our relationship with Kinder Morgan;
the ability of our customers and other counterparties to perform under their contracts with us, financial distress experienced by our customers and other counterparties and our ability to secure development efforts, including renewing long-term customer contracts and the terms of such renewal;
our ability to recover indemnification from contractual counterparties;
our ability to adequately maintain a skilled workforce;
strikes, blockades, riots, terrorism (including cyber-attacks), war or other acts or accidents or catastrophic events;
increased industry competition;
volatility and wide fluctuations in the market price for the Restricted Voting Shares or our other outstanding securities;
foreign exchange fluctuations;
changes in accounting pronouncements and the timing of when such measurements are to be made and recorded; and
our ability to obtain and maintain sufficient insurance coverage.

The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this document are reasonable. However, there is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, investors should not put undue reliance on any forward-looking statements.

See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements in this document. When considering forward-looking statements, you should keep in mind the risk factors described in Item 1A “Risk Factors.” Such risk factors could cause actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.


4


PART I

Items 1 and 2. Business and Properties.

Overview

KML owns an interest in and operates an integrated network of pipeline systems and terminal facilities in Canada. Our interest in the Limited Partnership is described below and the Limited Partnership holds our business, which is comprised of a portfolio of strategic energy infrastructure assets across Western Canada.

For over 60 years, TMPL has been the only Canadian crude oil and refined products export pipeline with North American West Coast tidewater access. Current transportation capacity on TMPL is approximately 300,000 bpd (based on throughput of 80% light oil and refined products and 20% heavy oil), and it is connected to 20 incoming pipelines near Edmonton, Alberta, one of North America’s most significant energy hubs. In Alberta, we have one of the largest integrated networks of crude tank storage and rail terminals in Western Canada and the largest merchant terminal storage facility in the Edmonton market. We also operate the largest origination crude by rail loading facility in North America. In B.C., we control the largest mineral concentrate export/import facility on the west coast of North America through our Vancouver Wharves Terminal, transferring over four million tons of bulk cargo and 1.5 MMBbl of liquids annually. In the state of Washington, we ship crude oil from the Sumas Terminal for delivery to the BP plc, Phillips 66, Shell Oil Products U.S. and Tesoro Corporation refineries in Anacortes and Ferndale. We also own Cochin, which is the Canadian portion of the U.S. and Canadian Cochin pipeline system that transports light condensate to Fort Saskatchewan, Alberta, traversing two provinces in Canada and four states in the U.S. Given the challenges faced by the energy sector looking to construct major infrastructure projects, particularly in environmentally sensitive regions, our asset base has many unique attributes that offer significant, sustainable competitive advantages that we believe would be challenging for competitors to replicate over the near to mid-term.

Reorganization and IPO

The Company was incorporated on April 7, 2017. On May 30, 2017, the Company completed an IPO of 102,942,000 Restricted Voting Shares on the TSX 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, while Kinder Morgan indirectly retained the remaining approximate 70% economic interest.

Concurrent with the closing of our IPO, the Limited Partnership acquired an interest in the Operating Entities from KMCC and KMCT , each a wholly owned subsidiaries of Kinder Morgan, in exchange for the issuance to KMCC and KMCT of Class B Units of the Limited Partnership. In addition, KMCC and KMCT were issued Special Voting Shares in the Company for nominal consideration.

Immediately following the closing of our IPO, we used the proceeds from our IPO to indirectly subscribe for Class A Units representing an approximate 30% economic interest in the Limited Partnership while the Class B Units held by KMCC and KMCT represented, in the aggregate, an approximate 70% economic interest in the Limited Partnership. Following the issuance of the Series 1 Preferred Shares and Series 3 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.

Currently, the issued and outstanding Restricted Voting Shares comprise approximately 30% of all outstanding Company Voting Shares, and the Kinder Morgan interest, which represents its indirect ownership of 100% of the Special Voting Shares, comprises approximately 70% of all outstanding Company Voting Shares.

For the description of our share capital and the limited partnership units of the Limited Partnership, which holds our business, see Item 5 “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Ownership Interests.”
Subsequent to our IPO, Kinder Morgan retained control of us and the Limited Partnership, and as a result 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, our consolidated financial statements presented herein were derived from the consolidated financial statements and accounting records of Kinder Morgan. The assets and liabilities in these consolidated financial statements have been reflected at historical carrying value of the immediate parents within the Kinder Morgan organizational structure including goodwill and purchase price assigned amounts, as applicable. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

5


The intercorporate relationships of the Company, the Limited Partnership, and our Operating Entities as of December 31, 2017 are as follows:
kmlstructure3.jpg
_______________
(a)
Approximate percentages based on ownership of total outstanding Company Voting Shares as of December 31, 2017.
(b)
Approximate percentages based on ownership of total outstanding Class A Units and Class B Units as of December 31, 2017. Distributions on the Preferred LP Units will be made prior to any distributions on the Class A Units and Class B Units.
(c)
Other operating entities include the Operating Entities other than KMCU.
(d)
Kinder Morgan owns (indirectly through KMCC and KMCT) 100% of our outstanding Special Voting Shares and 100% of the Class B Units.


6


Business and Segments

We focus on providing fee-based services to customers from an asset portfolio consisting of energy-related pipelines and liquid and bulk terminaling facilities. Our two business segments are: (i) Pipelines, which is comprised of TMPL including the Westridge Marine Terminal and other related terminaling assets, TMEP, Puget Sound, Jet Fuel, and Canadian portion of Cochin and (ii) Terminals, which is comprised of the Vancouver Wharves Terminal and the terminals located in the Edmonton, Alberta area, including the Base Line Terminal joint venture project.

Our key strategies are to:

focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of Western Canada;
increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;
leverage economies of scale from expansions of existing assets and potential incremental acquisitions that fit within our strategy and are accretive to cash flow; and
maintain a strong balance sheet and maximize value for our investors.

Overview of Assets
Asset
 
Design [Storage] Capacity
 
Description
Pipelines
TMPL
 
~300 MBbl/d
 
Only pipeline in Canada transporting crude oil and refined products to the West Coast.
TMEP
 
~890 MBbl/d
(~590 incr.)
 
Total capital cost estimated to be ~$7.4 billion, further described below under “ Pipelines BusinessTMEP”(a)
Puget Sound
 
~240 MBbl/d
 
Ships from Sumas Terminal to the state of Washington refineries via TMPL.
Edmonton Terminal
 
[~8,000 MBbl]

 
35 tanks in total, majority serving TMPL regulated service with 15 of 35 tanks leased to Terminal business (unregulated entity).(b)
Westridge Marine Terminal
 
[395 MBbl]
 
Liquid export / import terminals in Burnaby, which can accommodate Aframax sized tankers.
Kamloops/Sumas/Burnaby Terminals
 
[2,560 MBbl]

 
Kamloops: 2 tanks serving TMPL (160 MBbl),
Sumas: 6 tanks all serving TMPL (715 MBbl), and
Burnaby: 13 tanks serving TMPL (1,685 MBbl).
Jet Fuel(c)
 
[45 MBbl]

 
Transport jet fuel from refinery in Burnaby and the Westridge Marine Terminal to Vancouver International Airport.
Cochin(d)
 
~110 MBbl/d
 
Transport condensate from the Canada/U.S. border near Maxbass, North Dakota to Fort Saskatchewan, Alberta.
Terminals
Vancouver Wharves Terminal
 
4.0 MMtonnes bulk +
[250 MBbl]
 
Bulk commodity marine terminal provides handling, storage, loading and unloading services.
Edmonton South Terminal
 
[5,100 MBbl]
 
15 tanks currently leased from Trans Mountain(b); tanks sub-leased to third parties in unregulated service (merchant tanks).
North 40 Terminal
 
[2,150 MBbl]
 
Merchant crude oil storage and blending services.
Edmonton Rail Terminal
 
210 MBbl/d
 
Operated 50/50 joint venture with Imperial Oil (largest origination crude-by-rail terminal in North America).
Alberta Crude Terminal
 
40 MBbl/d
 
Non-operated 50/50 joint venture with Keyera Corporation (Keyera) that is fully contracted.
Base Line Terminal
 
[4,800 MBbl]
 
Operated 50/50 joint venture with Keyera (12 tanks planned to be placed in service throughout 2018), further described below.
_________
(a)
Includes capitalized financing costs.
(b)
We currently expect that TMPL will recall two of the 15 merchant tanks comprising the Edmonton South Terminal upon the completion of TMEP for use in its regulated service.

7


(c)
Jet Fuel has a BCUC-approved negotiated settlement that ends in 2018.
(d)
Cochin is part of the Cochin pipeline system, which transports condensate from Kankakee County, Illinois to Fort Saskatchewan, Alberta. Capacity on the U.S. portion of the Cochin pipeline system, which is not owned by us, is approximately 95 MBbl/d

Overview Map of Our Business
kmlmapa01.jpg
For financial information on our two reportable business segments, see Note 18 “Reportable Segments” to our consolidated financial statements.


8


Pipelines Business

TMPL

Trans Mountain Oil Pipe Line Company was established on March 21, 1951. Construction of TMPL commenced in 1952 and the first shipment of oil reached TMPL’s Burnaby Terminal on October 17, 1953. The initial capacity of the pipeline system was 150,000 bpd. Since 1953, the capacity of TMPL 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 involved the installation of a second pipeline adjacent to the existing TMPL on a 158 kilometer section of the system between Hinton, Alberta and Hargreaves, B.C., just west of Mount Robson Provincial Park. The Anchor Loop project increased the capacity of the pipeline system from 260,000 bpd to 300,000 bpd and involved the installation of two new pump stations.

TMPL is approximately 1,150 kilometers long, beginning in Edmonton, Alberta and terminating on the west coast of B.C. in Burnaby. Twenty-three active pump stations located along TMPL route maintain the 300,000 bpd capacity of the line, flowing at a speed of approximately eight kilometers per hour. In addition to the pump stations, four terminals located in Edmonton, Kamloops, Sumas and Burnaby and the Westridge Marine Terminal, house storage tanks and serve as locations for incoming pipelines. The 300,000 bpd nominal capacity of the pipeline has been determined based on a throughput mix of 20% heavy oil and 80% light oil. The actual delivery capacity on the TMPL mainline is based on the type of oil or refined product being transported. For example, when the pipeline is delivering only light oil, it can deliver an amount closer to approximately 350,000 bpd and if it is delivering only heavy oil, the system’s delivery capacity is closer to approximately 280,000 bpd.

TMPL regularly ships multiple products, including refined petroleum, synthetic crude oil, light crude oil and heavy crude oil, and it is the only pipeline in North America that carries both refined products and crude oil together in the same line. This process, known as “batching,” means that a series of products can follow one another through the pipeline in a “batch train.” A typical batch train in the TMPL mainline is made up of a variety of materials being transported for different shippers; however, any product moved in the pipeline must meet TMPL’s tariff requirements, which include technical specifications for any products accepted for transportation on TMPL. While products move next to each other in the pipeline mix, product interface is kept to a minimum by moving the products in a specific sequence. Products that mix are refined for use.

In order to optimize batches to achieve maximum throughput, TMPL has built tanks, pumps and other ancillary equipment which enable connection and staging of batches to be delivered to the TMPL mainline pipe. Tanks are used to accumulate enough of a particular type of product to make up an efficient batch. While shippers are permitted to deliver oil to the mainline at a rated throughput to avoid the use of tanks, the TMPL tanks can be used by shippers delivering at less than the 300,000 bpd capacity to accumulate their product and have it pumped at the throughput capacity 300,000 bpd 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.

As at the date hereof, TMPL remains the only pipeline that transports liquid petroleum from the WCSB to the West Coast. It is also the only pipeline providing Canadian producers with direct access to world market pricing through a Canadian port.

Trans Mountain’s Terminals

Edmonton Terminal

TMPL begins in Sherwood Park, Alberta at the Edmonton Terminal. This facility is made up of 35 tanks with total storage capacity of approximately 8.0 MMBbl. All tanks at the Edmonton Terminal are in crude oil, condensate or refined product service and each tank has the flexibility to handle most products that are connected to the terminal, including in-tank mixing of multiple products. The Edmonton Terminal is connected to 20 incoming pipelines from oil and refinery production in Alberta and is adjacent, or in close proximity, to the starting point of the Enbridge Inc. cross-continent crude oil pipeline system, the North 40 Terminal, the Suncor Energy Inc. Edmonton refinery, the Keyera Edmonton terminal, the Keyera Alberta EnviroFuels plant, the Gibson Energy Inc. Edmonton terminal, the Plains Midstream 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 and comprising 2.9 MMBbl of total storage capacity, are currently used by Trans Mountain to serve TMPL’s regulated service. As noted above, these tanks are used by Trans Mountain to facilitate batching and maximize throughput on the TMPL mainline. The remaining 15 tanks at the Edmonton Terminal (referred to as the “Edmonton South Terminal”)), ranging in size from 250,000 barrels to 400,000 barrels and constituting approximately 5.1 MMBbl of the total storage capacity, are leased to KM Canada North 40’s Edmonton

9


South Terminal and are marketed on a merchant basis, subject to a 24 month right of recall, exercisable by Trans Mountain, in the event that the Edmonton Terminal is further expanded and Trans Mountain requires the tanks for its regulated service. This leasing arrangement is based on a Memorandum of Understanding with the Canadian Association of Petroleum Producers and has been sanctioned by the NEB. In connection with the completion of TMEP, Trans Mountain expects that it will exercise recall rights under the leasing arrangement with KM Canada North 40 in respect of two of the tanks at the Edmonton South Terminal. As a result, following this recall, the Edmonton South Terminal will be comprised of 13 merchant tanks and 22 of the existing tanks will be used by Trans Mountain to service the regulated TMPL. As the use of the recalled tanks will be included in the overall tolls charged on the expanded TMPL, such tanks will no longer generate the incremental revenue realized through leases to external customers. As such, the recall is expected to result in a decrease in the net cash earnings attributable to the Edmonton South Terminal. See “—Terminals BusinessEdmonton South Terminal” below.

In addition to its service as a storage and terminaling facility, the Edmonton Terminal houses the primary control center for TMPL, Puget Sound, Jet Fuel, the North 40 Terminal, the Westridge Marine Terminal, the Base Line Terminal, and the line to the Edmonton Rail Terminal. The control center located at the Edmonton Terminal does not operate Cochin, which is controlled from the U.S. See “—Terminals Business” below.

Kamloops Terminal

In Kamloops, B.C., refined products from Edmonton, Alberta are delivered to a distribution terminal near Kamloops airport that we operate. The TMPL terminal in Kamloops contains two inactive crude oil storage tanks with a total storage capacity of approximately 160,000 barrels and also serves as a primary pump station for TMPL.

Sumas Pump Station and Sumas Terminal

The Sumas pump station and the Sumas Terminal are approximately three kilometers apart and are both located in Abbotsford, B.C. The terminal is used to stage oil for delivery further down TMPL and contains six storage tanks with total storage capacity of approximately 715,000 barrels. The pump station includes four pumps, two of which are used to route product from the TMPL mainline into the state of Washington via Puget Sound and two of which are used to route the product on the TMPL mainline to Burnaby, B.C.

Burnaby Terminal

The Burnaby Terminal, located in Burnaby, B.C., is the terminus of the TMPL mainline. It receives both crude oil and refined products for temporary storage and transportation through separate pipelines to a local distribution terminal, a local refinery and the Westridge Marine Terminal. The Burnaby Terminal has 13 storage tanks with total storage capacity of approximately 1.685 MMBbl.

The pump station used to operate Jet Fuel is also located within the Burnaby Terminal although Jet Fuel and TMPL are not connected and are operated as separate systems.

Westridge Marine Terminal

The Westridge Marine Terminal is located within the Burrard Inlet in Burnaby, B.C. Regulated by Transport Canada and the NEB, the dock at the terminal can accommodate up to Aframax class vessels (approximately 120,000 dead weight tons) and barges. The Westridge Marine Terminal is used to deliver crude oil from TMPL onto barges and tankers and to receive jet fuel into the three tanks at the terminal for delivery into Jet Fuel.

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. The terminal is used to receive jet fuel for delivery into Jet Fuel. Significant modifications are planned for the Westridge Marine Terminal as part of TMEP. Limited construction activity on such modifications began in September 2017.

TMEP
 
Our estimated total capital cost for TMEP is approximately $7.4 billion,which includes capitalized financing costs ($6.7 billion excluding capitalized equity and debt financing costs). Construction related delays could result in increases to the estimated total costs. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of OperationsRecent Business Developments TMEP Permitting and Construction Progress.”
 

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Upon completion, TMEP would provide western Canadian crude oil producers with an additional 590,000 bpd of crude oil transportation capacity and tidewater access to the western United States (most notably states of Washington, California and Hawaii) and global markets (most notably Asia). Over 70% of Canadian crude products are currently exported to U.S. markets, with the majority of the remaining products being consumed domestically (Source: CAPP 2016 Forecast, Markets and Transportation 2016-0007). This dependence on a single market, combined with the cost and limited availability of transportation options, has resulted in Canadian crude products producers receiving a material discount to global benchmark prices on the sale of similar quality products (Source: CAPP 2016 Crude Oil Forecast, Markets and Transportation 2016-0007).

Beginning in early 2011, through discussions with Trans Mountain and existing shippers and other interested parties, it became clear that there was significant interest in an expansion of TMPL for the purpose of improving access to the North American west coast and offshore markets. Between October 2011 and November 2012, Trans Mountain conducted an open season process to obtain commitments for TMEP. Trans Mountain advanced a firm service offering designed to provide shippers with long-term contractual certainty of shipping crude oil product volumes on the expanded system, while providing Trans 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 services agreements with 13 companies for a total of 707,500 bpd based on a capacity of 890,000 bpd (the maximum amount that Trans Mountain anticipated the NEB would authorize) following completion of TMEP.

Upon the completion of the proposed TMEP, throughput capacity of TMPL will increase from approximately 300,000 bpd to 890,000 bpd. The proposed expansion of TMPL is intended to comprise, among other things, the following:

approximately 980 kilometers of new, buried pipeline segments that twin (or “loop”) the existing pipeline in Alberta and B.C., including two 3.6 kilometer segments (7.2 kilometers in total) of new buried 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 handling Aframax class vessels.

The major components of the pipeline portion of TMEP 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 maintained in a deactivated state;
constructing three new 36-inch (914 mm) and one new 42-inch (1,220 mm) outside diameter buried pipeline 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 lines from the Burnaby Terminal to the Westridge Marine Terminal.

TMEP will result in two continuous pipelines between Edmonton and Burnaby:

Line 1 is expected to have a capacity of 350,000 bpd of light crude oil and refined products; and
Line 2 is expected to have a capacity of 540,000 bpd of heavy crude oil.

The existing TMPL has been operating safely for more than 60 years and its location is known to local TMPL operations crews, landowners, surface management agencies, and local emergency responders. To minimize environmental and socio-economic effects and facilitate efficient pipeline operations, use of the existing TMPL right of way has been maximized in the TMEP design. Where it was not possible to align along the existing TMPL right of way, construction along other linear facilities was evaluated including other pipelines, power lines, highways and roads, railways, communication lines and other utilities. The result is that approximately 73% of the new pipeline corridor follows the existing TMPL right of way, approximately 17% follows other existing rights of way, and approximately 10% will be within a new corridor. The completion of the Anchor Loop project in 2008 also minimizes the need for additional construction in the highly sensitive Jasper National Park region.

Electrically powered pump stations located at regular intervals along the pipeline will be required for the expansion. The major components of the pump stations portion of TMEP that will support mainline operation include:

adding 12 new pump stations; and
deactivating some elements of the existing Blue River, B.C. pump station.


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The major components of the associated facilities of TMEP include:

the addition of 20 new above-ground storage tanks, including the construction of four new tanks and inclusion of two existing tanks at the Edmonton Terminal, constructing one new tank at the Sumas Terminal and the construction of 14 new tanks and the demolition of one existing tank at the Burnaby Terminal; 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 Westridge Marine 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 mainline block valves, which will be located at the pump stations. These remote mainline block valves and existing mainline block valves work to limit the volume of and consequences associated with pipeline leaks or ruptures. A total of 25 new sending or receiving scraper traps for in-line inspection tools will also be installed at facility locations along the pipeline.

B.C. Hydro requires TMEP to build two connections, an approximately 24 kilometer line to connect to a power station in Kingsvale, B.C. and an approximately 1.5 kilometer connection to a power station in Black Pines, B.C., that will either be (i) turned over to B.C. Hydro for a minimal amount, (ii) owned, maintained and operated by us, or (iii) sold to a third party to maintain and operate.

Currently, up to approximately five vessels per month are loaded with heavy crude oil at the Westridge Marine Terminal. Upon completion of TMEP, it is anticipated that the Westridge Marine Terminal will be capable of serving up to 34 Aframax class vessels per month with actual demand to be influenced by market conditions. The maximum vessel size (Aframax class) served at the terminal will not change as a result of TMEP. Similarly, product moving over the dock at the Westridge Marine Terminal is expected to continue to be primarily heavy crude oil. Of the 890,000 bpd capacity of the expanded system, up to 630,000 bpd may be handled through the Westridge Marine Terminal for shipment. Currently, monthly barge traffic typically consists of loading two crude oil barges and receiving one jet fuel barge. This level of activity is not expected to be affected by TMEP.

We have signed a number of agreements with general construction contractors and are currently in negotiations with other construction contractors to construct the various pipeline spreads on TMEP, with the intention that general construction contracts will be entered into with respect to spreads one through six and engineering, procurement and construction contracts will be entered into with respect to spread seven, terminals and pump stations (including the Edmonton Terminal) and with respect to any work required in the Lower Mainland of B.C.

Upon completion, the newly constructed pipeline is expected to carry predominantly heavy crude volumes and the existing pipeline will carry predominantly light crude and refined products.

TMEP Expansion Shipping Agreements

Trans Mountain delivered the final cost estimate and tolls to shippers in February 2017. At that time some existing shippers gave up capacity, some increased capacity and some new shippers acquired capacity, the net result of which was the turn back of 22,000 bpd (or 3% of the previously committed barrels). These 22,000 bpd were subsequently recommitted during an additional supplemental open season process in March 2017. As a result of TMEP’s open season processes, 13 companies have entered into one 15-year and twelve 20-year transportation service agreements with Trans Mountain for a total of 707,500 bpd, representing approximately 80% of the expanded system’s capacity (the maximum amount under the regulated limit imposed by the NEB). These shippers represent or are affiliates of some of the largest producing companies in the WCSB and a significant majority of these 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 of supply, either through their own production, or through their position in the market as a large marketer and/or refiner of crude oil. This maximum level of recommitment highlights the strong market demand for the expanded system’s takeaway capacity and has better aligned TMEP shipper composition with the changing Canadian crude producer landscape.

Where a particular shipper is not investment grade or no support provider is available, Trans Mountain may obtain, in respect of such shipper, letters of credit from acceptable banks for an amount having the same value as up to 12 months of the shipper’s contract exposure, or such other amount as may be determined reasonable and appropriate.

The TMEP-related transportation service agreements provide for a sharing of risks between Trans Mountain and its shippers during the development stage, including the construction of TMEP and the long-term operation of the pipeline system. Each shipper is entitled to a certain amount of capacity each month, and the shippers are required to pay for the fixed cost of such capacity whether they use it or not.

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The transportation service agreements also provide flexibility to the shippers that are parties to them, as such 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 risk and ensuring that the firm capacity is fully utilized. There are also make-up provisions in the event that shippers cannot use their full capacity entitlements in any given month. Shippers also have the right to renew their contracts at the end of the initial term for an additional five-year period on rates to be determined at the time of renewal (if any).

The fixed toll to be paid by shippers under the TMEP-related transportation service agreements has been established according to a risk sharing formula that will be escalated during the lifetime of the contracts at a fixed rate. Under the agreements there is a variable toll component based on actual costs incurred for power, unanticipated costs related to changes in legislation or regulation and other costs as may be agreed to by Trans Mountain and shippers. As the vast majority of the toll will not be adjusted according to actual costs incurred, as would normally occur under a cost-of-service approach, this arrangement will provide greater toll certainty to shippers and reduce the risk of unanticipated increases in transportation costs over time.

Approximately 20% of the expanded TMPL’s nominal capacity (182,500 bpd), will be reserved for spot month-to-month shipments. The toll for spot shipments will be tied to the toll for long-term service and, as such, spot shippers will benefit from all of the contractual provisions that protect long-term shippers from cost escalation.

Puget Sound

In operation since 1954, Puget Sound ships crude oil products from the Sumas Terminal to state of Washington refineries in Anacortes and Ferndale.

Puget Sound is approximately 111 kilometers long, with one pump station and a diameter of 16 to 20 inches (406 to 508 mm) and two storage tanks with total storage capacity of approximately 200,000 barrels. The system has total throughput capacity of approximately 240,000 bpd (when transporting primarily light oil), with approximately 191,000 bpd transported in 2016. The transit time of products on Puget Sound is approximately one day. The pipeline is regulated by the FERC for tariffs and the U.S. Department of Transportation for safety and integrity. Approximately 80% of the 2016 revenue from Puget Sound originated from counterparties that have, or are subsidiaries of a parent entity that has, an investment grade credit rating (however such parent entity may not be a guarantor).

In addition to their access to the Westridge Marine Terminal, shippers on TMPL have, and following completion of TMEP will continue to have, the option to deliver their product to Puget Sound.

Jet Fuel

Jet Fuel transports jet fuel from a Burnaby refinery and the Westridge Marine Terminal to the Vancouver International Airport. The 41 kilometer pipeline system has been in operation since 1969. It includes five storage tanks at the Vancouver International Airport with aggregate storage capacity of 45,000 barrels. British Columbia Oil and Gas Commission (“BC OGC”) regulates the integrity and safety of the pipeline and BCUC regulates Jet Fuel’s tolls.

Cochin

The U.S. and Canadian Cochin pipeline system consists of a 12 inch (305 mm) diameter pipeline that spans from Kankakee County, Illinois to Fort Saskatchewan, Alberta, totaling approximately 2,452 kilometers. The U.S. and Canadian Cochin pipeline system, which transports light hydrocarbon liquids (primarily to be used as diluent to facilitate bitumen transportation), traverses two provinces in Canada and four states in the United States. The U.S. and Canadian Cochin pipeline system is comprised of approximately 1000 kilometers of pipeline and includes 38 block valves and ten pump stations. While we do not own or operate the U.S. portion of the U.S. and Canadian Cochin pipeline system, the U.S. and Canadian portions are interdependent (including with respect to volumes shipped and financial and contractual obligations) and, as the bulk of the tariffs on this pipeline system are governed by a joint international tariff, revenue is shared between the U.S. and Canadian portions. The U.S,. portion of this pipeline system is wholly owned by an indirect subsidiary of Kinder Morgan.

In 2014, Kinder Morgan reversed the western leg of the U.S. and Canadian Cochin pipeline system (which was previously used primarily to ship propane into the U.S) to begin moving light condensate westbound from the Kinder Morgan Cochin terminal in Kankakee County, Illinois, to terminal facilities near Fort Saskatchewan, Alberta (the “Cochin Reversal Project”). Cochin is currently capable of transporting approximately 95,000 bpd of light condensate (constrained by the U.S. portion of the Cochin pipeline system). If additional receipt points in Canada are established, and future demand supports it, throughput on the Cochin

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pipeline has the potential to reach approximately 110,000 bpd. This additional volume would most likely come from the Bakken oil play in North Dakota.

KMCU is the operator of Cochin, which is operated and maintained by Canadian staff located at the KMCU regional and local offices in Wainwright, Alberta and Regina, Saskatchewan. KMCU is also the holder of the NEB certificates for Cochin.

Pipeline Segment - Potential Growth Opportunities

While we do not presently have any plans to expand TMPL outside of the current scope of TMEP, the combined capacity of the expanded pipeline could potentially be further increased by over 300,000 bpd to approximately 1.2 million bpd, with additional power and further capital enhancements.

The Puget Sound pipeline is capable of being expanded to increase its capacity to approximately 500,000 bpd from its current capacity of 240,000 bpd.

We will continue to monitor market and industry developments to determine which, if any, further expansion projects on TMPL may be appropriate.

With the projected continuing growth of Canadian bitumen production, U.S. diluent imports are expected to remain an integral part of bringing Canadian bitumen to market (Source: CAPP 2017 Crude Oil Forecast, Markets and Transportation 2017-0009). Cochin has an additional 15,000 bpd of capacity on its Canadian section of the pipeline system due to a higher pressure rating in Canada. While Cochin would need to loop its line to be in position to expand its capacity to greater than 110,000 bpd, we are currently evaluating a number of other opportunities to utilize the existing 15,000 bpd capacity through the addition of new connections to Cochin. In 2017, Cochin completed a new delivery point to the Plains Midstream Canada storage facility in Fort Saskatchewan, Alberta, as well as a new receipt point near Kankakee County, Illinois from Marathon Pipe Line LLC’s Wabash pipeline. Kinder Morgan is also currently constructing a new truck facility in Maxbass, North Dakota to allow for delivery of additional volumes onto the U.S. portion of the Cochin pipeline system from the Bakken region. Future projects that we may undertake, should conditions warrant, include, among others, the addition of a new delivery point to the Pembina Condensate Diluent Hub facility, as well as a connection to the Conway natural gas liquids market via Oneok’s North system. Other than as disclosed in this document, no definitive decisions have been made with respect to any material growth projects within the Pipelines segment.

See Item 1A “Risk FactorsRisks Relating to Our BusinessMajor projects, including TMEP, may be inhibited, delayed or stopped.”

Terminals Business

In addition to our pipeline assets, we are supported by a network of strategically located terminal facilities in Western Canada, including the largest merchant terminal position in the Edmonton, Alberta market. This merchant terminal position is underpinned predominantly by fee-based services without direct commodity price exposure, and is secured by superior market positions and contracts. See “—Major Customers and Contractual Relationships” and “—Competition” below.

Vancouver Wharves Terminal

Located in North Vancouver, B.C., the Vancouver Wharves Terminal is a 125-acre bulk marine terminal facility that annually transfers over 4.0 million tons of bulk cargo and 1.5 MMBbl of liquids predominantly to offshore export markets. The Vancouver Wharves Terminal, which has been in operation since 1959, was acquired by Kinder Morgan in 2007. This acquisition included securing a 40-year operating lease and asset ownership agreement with the B.C. Railway Company for the terminal uplands. Vancouver Wharves also holds a corresponding water lot lease agreement with Port Metro Vancouver to support the terminal vessel loading and unloading operations with the same 40-year term.

Since the acquisition of Vancouver Wharves, Kinder Morgan has undertaken a number of projects designed to improve and expand the terminal: in June 2013, it sanctioned the construction of a zinc concentrate truck load out facility; in April 2014, approval was received to expand the terminal’s lead concentrate interior shed walls; in March 2015, upgrading work commenced on the sulphur load out facility; and in June 2015, project approval was received to upgrade the terminal’s grain handling facility. The Vancouver Wharves Terminal currently has 1.0 million tons of bulk storage capacity, 250,000 barrels of petroleum storage and facilities that can house up to 325 rail cars. The terminal assets include four berths capable of handling Panamax-size vessels. The main export products at Vancouver Wharves are sulphur, copper concentrates, diesel, jet fuel, bio-diesel, wheat and canola seed, while the most significant import products at Vancouver Wharves are zinc and lead concentrate. With good connectivity

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through the recently expanded Vancouver North Shore rail gateway corridor and connections with three Class 1 rail companies serving the area (the Canadian National Railway (“CN”), the Canadian Pacific Railway (“CP”) and the BNSF Railway) as well as all major highway routes in western Canada, Vancouver Wharves continues to provide a safe and efficient link for customers’ supply chain connectivity for water borne trade to global markets.

Edmonton South Terminal

The Edmonton South Terminal is a merchant tank terminal located in Sherwood Park, Alberta. As noted above, the assets currently making up the Edmonton South Terminal are embedded within the Edmonton Terminal, are owned by Trans Mountain and are operated by KMCI, for and on behalf of KM Canada North 40. A long-term leasing arrangement with Trans Mountain governs the merchant use of the tanks by KM Canada North 40. The first phase of the Edmonton South Terminal, comprised of nine merchant tanks, was put into service throughout 2013 and 2014. As part of a phase two expansion, an additional four tanks and associated infrastructure were constructed and placed in service in 2014. In connection with the Edmonton Rail Terminal project, a final two tanks were brought into service at the Edmonton South Terminal at the end of 2014. In total, the assets comprising this facility consist of 15 tanks with a total storage capacity of approximately 5.1 MMBbl along with associated outbound pumps, meters and pipe connections to other facilities. Trans Mountain currently expects to recall two of the tanks in merchant service at the Edmonton South Terminal upon the completion of TMEP for use in TMPL regulated service, comprising between approximately 700,000 and 800,000 barrels of total storage capacity. The NEB approved agreement specifies that if additional tanks are identified as needed for TMPL for regulated purposes, more tanks can be recalled upon 24-months’ notice. As the use of the recalled tanks will be included in the overall tolls charged on the expanded TMPL, such tanks will no longer generate the incremental revenue realized through leases to external customers. As such, the recall is expected to result in a decrease in the net cash earnings attributable to the Edmonton South Terminal.

The Edmonton South Terminal provides significant optionality for customers through its diverse suite of inbound and outbound pipeline connections, including access to the vast majority of crude types in Alberta. All tanks at the terminal are in crude oil service and each tank has the flexibility to handle all products that are connected to the terminal, including in-tank mixing and outbound blending of multiple products. In addition to its connection to the Edmonton Rail Terminal and the North 40 Terminal, the Edmonton South Terminal has significant pipeline connectivity. The Edmonton South Terminal has 14 major inbound pipeline connections from throughout Alberta and two major outbound pipeline connections, which allow customers to ship their products west, east or south. In addition to its position within the larger Trans Mountain Edmonton Terminal, the Edmonton South Terminal is, similarly, adjacent, or in close proximity, to the starting point of the Enbridge Inc. cross-continent crude oil pipeline system, the North 40 Terminal, the Suncor Energy Inc. Edmonton refinery, the Keyera Edmonton terminal, the Keyera Alberta EnviroFuels plant, the Gibson Energy Inc. Edmonton terminal, the Plains Midstream Canada Edmonton Strathcona terminal and the Imperial Oil Strathcona refinery. Customers utilizing the Edmonton South Terminal tanks have the option of direct injection into the TMPL mainline or utilizing any of the other outbound connections available at the terminal.

North 40 Terminal

Located in Sherwood Park, Alberta, immediately adjacent to the Edmonton South Terminal, the nine tank North 40 Terminal facility, in service since March 2008, provides merchant storage for crude oil products. This approximately 2.15 million barrel facility is comprised of eight 250,000 barrel tanks and one 150,000 barrel tank. The North 40 Terminal has a highly diverse suite of eight inbound pipeline connections (anticipated to increase to ten inbound pipeline connections by 2018), including access to the vast majority of crude types in Alberta, and five outbound connections. In addition to its pipeline connections which allow customers to ship their products west, east or south, the North 40 Terminal is connected to the Alberta Crude Terminal (as described below), the Base Line Terminal (as described below), TMPL, a local refinery and a third-party midstream facility. All tanks at the terminal are in crude oil service and have the flexibility to handle all products that are connected to the terminal, including in-tank mixing of multiple products. The North 40 Terminal is operated by KMCI, for and on behalf of KM Canada North 40.

Edmonton Rail Terminal

In December 2013, Kinder Morgan and Imperial Oil announced the formation of a 50-50 unincorporated joint venture to build the Edmonton Rail Terminal with an initial capacity of 100,000 bpd. By August 2014, the joint venture had entered into firm, take-or-pay agreements with strong, creditworthy major oil companies. These contracted commitments allowed for an expansion of the Edmonton Rail Terminal to add incremental capacity of 110,000 bpd, for a total of 210,000 bpd. The terminal was constructed by Kinder Morgan, placed in service in April 2015 and is currently operated by an affiliate of KM Canada North 40.

The Edmonton Rail Terminal capacity at start-up in 2015 was approximately 210,000 bpd, making the terminal the largest origination crude by rail loading facility in North America. The terminal is connected via pipeline to the Edmonton South Terminal

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and is capable of sourcing all crude streams that are handled there for delivery by rail to North American markets and refineries. The terminal connects to both the CN and CP railway networks and can hold up to four unit trains on-site (two loading and two staged), load unit trains of up to 150 rail cars per train and load two trains with the same or differing products simultaneously. Trains are loaded at the Edmonton Rail Terminal through a 38-spot dual-sided rack (76 loading spots in total). Upon the completion of the construction of the Base Line Terminal, the Edmonton Rail Terminal, through its connections with the Edmonton South Terminal and the Base Line Terminal, will have access to the approximately 9.9 MMBbl of crude oil capable of being stored at such terminals.

Alberta Crude Terminal

An unincorporated 50-50 joint venture between an affiliate of KM Canada North 40 and Keyera, the Alberta Crude Terminal is a crude oil rail loading facility located in Sherwood Park, Alberta and operated by Keyera. The Alberta Crude Terminal construction project was sanctioned in July 2013 and placed in service in November 2014. The terminal is fully contracted and is served by the CN and CP railway networks. This terminal has approximately 40,000 bpd of manifest crude oil rail loading capacity as well as capacity for 250 rail car storage spots, which assist in the efficient manifest movement of the railcars loaded at the facility. Upon the completion of the construction of the Base Line Terminal, the Alberta Crude Terminal, through its connections with the North 40 Terminal and the Base Line Terminal, will have access to the approximately 7.0 MMBbl of crude oil capable of being stored at such terminals.

Base Line Terminal

Announced in March 2015, the Base Line Terminal is a second 50-50 unincorporated joint venture between an affiliate of KM Canada North 40 and Keyera. The Base Line Terminal is a merchant crude oil storage terminal located on land at the Keyera Alberta EnviroFuels facility in Sherwood Park, Alberta. Construction commenced on this project in the second half of 2015. The initial build will have 12 tanks with a total capacity of 4.8 MMBbl. This project is supported by multiple long-term customer contracts that will draw revenue streams and associated risks that are similar in nature to those for the existing terminals near Edmonton. See “—Major Customers and Contractual Relationships and “—Competition below.

Upon completion, the Base Line Terminal is expected to have some of the best tank terminal connectivity in Canada, with a diverse suite of ten inbound pipeline connections, including access to the vast majority of crude types in Alberta and six outbound connections, including both pipeline and rail. This terminal will leverage off of the existing North 40 Terminal by using transfer lines to facilitate product transfer between terminals via a pipeline bridge over a highway in Strathcona County. In addition to its pipeline access, the Base Line Terminal will also be connected to the Alberta Crude and Edmonton Rail Terminals. All tanks at the terminal will be in crude oil service and have the flexibility to handle all products that are connected to the terminal, including in-tank mixing and outbound blending of multiple products. We expect to have more than 14.9 MMBbl of total storage (including regulated tankage) capacity in the Edmonton area upon completion of the Base Line Terminal.

See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of OperationsRecent Business DevelopmentsBase Line Terminals Construction Progress: andOutlook.”

Potential Growth Opportunities

The Terminals segment routinely explores opportunities for growth in its Terminals business. In addition to its growth projects currently underway, there is potential for the Base Line Terminal to expand its operations in the future to include up to six additional tanks and add additional inbound and outbound connections. Vancouver Wharves has one of the last remaining parcels of land available for development in Port Metro Vancouver and the Terminals segment is currently exploring potential opportunities for this available land. To date, we have identified approximately $250 million worth of potential capital projects predominantly at our Vancouver Wharves terminal (excluding projects that have been discussed elsewhere in this document), and those projects are in various stages of evaluation and/or development. Other than as disclosed in this document, no definitive decisions have been made with respect to any material growth projects within the Terminals segment. See Item 1A “Risk FactorsRisks Relating to Our BusinessMajor projects, including TMEP, may be inhibited, delayed or stopped.”


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Major Customers and Contractual Relationships

Major Customers

For the year ended December 31, 2017, we had two customers that represented 20% and 11% of total revenue, respectively. For the year ended December 31, 2016, we had two customers that each represented 14% and 10% of total revenue, respectively. For the year ended December 31, 2015, we had two customers that each represented 12% of total revenue.

Contractual Relationships

TMPL is a common carrier pipeline, providing transportation services under a cost of service model that is negotiated with shippers and regulated by the NEB. Although TMPL takes custody of its shippers’ products, it does not own any of the product it ships. TMPL has posted tariff rates that are available to all shippers based on a monthly contract which varies according to the type of product being shipped as well as receipt and delivery points. As such, it provides service to producers, marketers, refineries and terminals who sell or resell products to domestic markets, oil marketers and international shippers moving oil to such places as Asia, and the states of California and Washington.

Since late 2010, TMPL has been meaningfully over-subscribed, resulting in pipeline apportionment (nominating less volumes for shipment than shippers request). Shippers on TMPL are generally large and well-capitalized. In 2017, the top ten shippers on TMPL accounted for approximately 85% of the revenue generated from the system, including its terminal assets. Of these shippers, as a percentage of such revenue generated, 96% 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&P and approximately 19% being rated BBB to BBB+ by S&P. Of the remaining 15%, 11% are non-investment grade and 4% of the shippers do not have a credit rating. In 2017, some of the shippers on TMPL , in alphabetical order, were the following entities or affiliates thereof: BP Canada Energy Trading Company, Cenovus Energy Inc., Chevron Canada Limited, Imperial Oil Limited, Nexen Energy ULC, Phillips 66 Canada Ltd, Shell Canada Products, Suncor Energy Inc., and Tesoro Canada Supply and Distribution Ltd.

Throughout the past 20 years, TMPL has entered into negotiated toll settlements with its shippers to establish final tolls on TMPL. We believe that negotiated settlements are advantageous from a cost perspective and may provide opportunities for additional returns.

In February 2016, the NEB approved TMPL’s 2016 to 2018 (inclusive) negotiated toll settlement. The toll settlement provides for a three-year term and includes a rollover provision and the TMEP transition provision. TMPL’s net regulated rate base is approximately $1 billion as of December 31, 2016 with sustaining capital automatically added in subsequent years. Under the NEB-approved negotiated toll settlement, the tolls on TMPL are based on a 9.5% return on equity, a 5% cost of debt and a deemed 45% equity and 55% debt structure. The toll settlement provides for the flow-through to shippers of certain operating costs, including power costs, property tax, income tax, integrity costs, environmental compliance and remediation costs and the cost of insurance and security. Labor and service-related costs are fixed costs in the toll settlement, and are escalated annually at a set index. These costs are allocated to TMPL by KMCI based on usage and are determined by the shared service model using a methodology approved by the NEB. In addition, the toll settlement agreement provides power and capacity incentives. Specifically, 50% of the B.C. 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. Variances between toll proceeds and annual revenue requirement are adjusted through tolls in the following year. TMPL’s current negotiated toll settlement includes a provision for extension, if the extension is mutually acceptable to TMPL and the shipper, up until the TMEP in-service date.

In 2011, TMPL received approval from the NEB to implement firm service for 54,000 bpd of service to the Westridge Marine Terminal, and charge a premium on such barrels to fund expansion projects on TMPL. This service and the premiums associated with it will be in effect until the earlier of the in-service date of TMPL expansion and ten years from the date of implementation. The premiums are approved to be used by TMPL to offset the cost of projects designed to enhance existing and future operations including development costs relating to the TMEP and equate to a total of approximately $28.6 million per year. As of December 31, 2017, $34 million had been used to construct a 250,000 barrel tank and associated infrastructure at the Edmonton Terminal and $132.6 million had been used to offset the development costs of TMEP.

Rates charged on Puget Sound are regulated by the FERC and are based on a cost of service model that has been in place since prior to 1992 and, as such, have been grandfathered and escalated from time to time as permitted by the FERC. As a result of this grandfathering, the Puget Sound cost of service rates that were in place for the 365-day period prior to September 1992,

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plus escalation, may continue to be charged to its shippers unless and until the rates are successfully challenged on the basis that a substantial change has occurred in the economic circumstances or nature of the services provided that were a basis for such rates. To date, no such complaints have been made. In 2017 approximately 100% of the revenue on the Puget Sound pipeline originated from customers that have, or from subsidiaries of a parent entity that has, an investment grade credit rating (however such parent entity may not be a guarantor).

Jet Fuel delivers jet fuel from the Westridge Marine Terminal and from a refinery in Burnaby to the Vancouver International Airport. With respect to the volume from the Westridge Marine Terminal, it has a contract with one of Canada’s largest airlines to unload jet fuel from barges at the Westridge Marine Terminal and store such volumes at the Westridge Marine Terminal. Jet Fuel then transports such jet fuel to the Vancouver International Airport. Through this arrangement and the jet fuel shipped from the Burnaby refinery, Jet Fuel has a BCUC-approved negotiated settlement that ends in 2018.

Cochin has three primary customers who, among them, have total contractual take-or-pay commitments of 85,000 bpd. These customers have investment grade credit ratings and financial capacity that support their long-term contractual commitments, which expire in 2024. The take-or-pay commitments obligate the committed shippers to make payments based on their contractual volume commitments, regardless of actual throughput. The joint international tariff rate is adjusted annually in accordance with the standard FERC methodology for escalating indexed rates for petroleum products pipelines. Cochin also offers transportation under: (i) a volumes incentive rate (available to certain committed shippers who ship above their contractual commitments in a calendar year), (ii) an uncommitted joint rate, as well as (iii) local uncommitted U.S. and Canadian rates.

The Terminals business services as many as 20 liquids customers, made up of a diverse mix of production, refining, marketing and integrated companies, and 9 bulk customers at any given point in time. Approximately 60% (by revenue dollar amount) of these customers have, or their parent entity has, an investment grade credit rating (however parent entities may not be guarantors). Our top three Terminal segment customers account for approximately 45% of total Terminal segment’s total revenue and the top ten Terminal segment customers account for approximately 75% of total Terminals segment revenue.

The majority of the Vancouver Wharves Terminal capacity is contracted under long-term, take-or-pay terminal service agreements. For the most part, the terminal service agreements contain annual minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize the terminal for all or a specified percentage of their production for exports. While our contractual arrangements at Vancouver Wharves are typically shorter in duration than those for our Alberta Terminals assets (with Vancouver Wharves’ average remaining term being approximately four years), customers have, historically, opted to renew their contractual arrangements with Vancouver Wharves. The majority of the Vancouver Wharves revenue originates from customers that have been using our terminal services for over five years, and including term extension options, a number of major long-term contracts at the Vancouver Wharves Terminal could be extended out through 2039 and 2045.

Each of the Edmonton South, North 40, Edmonton Rail, Alberta Crude and Base Line Terminals are contracted under long-term, take-or-pay agreements with terms between two and 20 years and an average term of ten years. As at December 31, 2017, the remaining life of the contracts at our terminals in Edmonton, Alberta ranged between approximately one and 17 years, with an average remaining contract life of six years. The rates charged for the Terminals segment terminals’ services are market-based and the majority of the fees charged at the Alberta-based terminals are fixed, regardless of the volumes actually handled. Over 90% of the total revenue of the Edmonton South, North 40, Edmonton Rail, Alberta Crude and Base Line Terminals is, or will be, derived from guaranteed take-or-pay contracts while the remaining is, or will be, derived from throughput in excess of contracted minimums as well as ancillary terminaling and connection services delivered, which are driven by the demand for the crude oil that is being handled and stored. One of the current contractual arrangements, which accounts for a significant source of revenue at the Edmonton Rail Terminal, expires in 2020.

Competition

TMPL is subject to competition resulting from the shipment of oil from the WCSB to markets other than the Canadian and U.S. West Coast, including shipments to refineries in Ontario, the U.S. Midwest and the U.S. Gulf Coast. In addition, refineries in the states of Washington and California, which comprise an important point of sale on the U.S. West Coast, have, in the past, been supplied primarily by crude oil from the Alaska North Slope. As such, there has historically been some competitive pressure on supply originating from the WCSB for sale in the states of Washington and California refinery markets. A further source of competition exists from the transportation of oil to the Canadian West Coast by rail. We expect that such supply and demand conditions in the oil markets served from the west coast of B.C. will continue to impact the long-term value and economics of TMPL.

Despite this potential competitive pressure, we believe that TMPL, both pre- and post-expansion, will maintain a competitive position as a result of a number of factors. For example, we estimate contracted tariff rates on TMPL after the expansion

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will range from approximately $5.00 per barrel to approximately $7.00 per barrel from Edmonton to Burnaby area. Uncontracted spot tariff rates will be 10% higher than the equivalent contracted tariff rates. Converted to U.S.$, these tariff rates would range from approximately U.S.$4.00 per barrel to approximately U.S.$6.00 per barrel. Environment and Climate Change Canada has estimated comparable rail transportation costs to California and the U.S. Gulf Coast to be approximately U.S.$16.00 per barrel and approximately U.S.$18.00 per barrel, respectively. Keystone posted tariff rates for U.S. Gulf Coast delivery are approximately U.S.$7.80 per barrel to U.S.$12.60 per barrel for heavy oil. For 2017, the average differential between West Texas Intermediate (light oil at Cushing Oklahoma) and Western Canada Select (heavy crude at Hardisty, Alberta) was nearly U.S.$15.00 per barrel.

Historically, Jet Fuel has transported a significant proportion of the jet fuel used at the Vancouver International Airport. However, the airport also receives jet fuel through other means including trucks and an approved, and yet to be constructed, jet fuel barge-receiving terminal near the airport. Jet Fuel’s supplying refinery was sold in 2017. As a result of that sale, we are unable to predict whether, and to what extent, that refinery will continue to supply jet fuel to Jet Fuel. These developments have made it unclear how much jet fuel will continue to be available for shipment to the Vancouver International Airport by way of Jet Fuel in the future. We continue to assess our options relating to Jet Fuel assets.

While Cochin is exposed to competition from other pipeline systems that are capable of transporting significant volumes of diluent, its volumes are supported by minimum volume commitments from its shippers. In addition, Cochin’s delivery point in Fort Saskatchewan has a low gravity diluent pool and a high level of connectivity, thereby making Cochin an attractive mode of shipping diluent. For 2017, Cochin has had an approximate 90% utilization rate.

In regards to our Terminals segment, there are competing liquids terminal facilities in the Western Canada area that are smaller than our Vancouver Wharves facility. There are currently a number of potential competitive grain terminal projects contemplated or underway that may increase the competitive pressures on the Vancouver Wharves grain business. In addition, our Alberta-based terminals are subject to competition from other truck and rail terminals and storage facilities that are either in the general vicinity of our facilities or have gathering systems that are, or could potentially extend into, areas served by our Alberta-based terminals, including the Enbridge Mainline System. As with the rest of our business, as our long-term terminals contracts expire, while fees for tankage are generally expected to increase on renewal, the storage and handling services of our terminals will have additional exposure to the longer-term trends in supply and demand for oil and gas products.

Operations Management

Safety, compliance and protection are the key components of our Operations Management System (“OMS”), a management system capturing important operational expectations in areas such as physical operations, engineering, environmental compliance, asset integrity, efficiency, quality, and project management.

Across our operations, we strive to provide for the safety of the public, our employees and contractors; protect the environment; comply with applicable laws, rules, regulations, and permit requirements; and operate and expand efficiently and safely to serve our customers. The OMS plays a critical role in setting the objectives and expectations for all these activities and individual business unit operations, maintenance procedures, and site-specific procedures are designed to meet these objectives and expectations.

We are committed to our operational goals, which include risk reduction, efficiency and productivity, effective expansion and integration, quality assurance, and a culture of excellence. These goals are embedded into our operations. The operations of each business unit are as unique as the regulatory and commercial environments in which they operate.

As federally regulated businesses, Cochin, TMPL and the Edmonton South Terminal are regularly audited by the NEB. Concerns identified in NEB audits are addressed through a comprehensive Corrective Action Plan approved by the NEB that remains in place until all items are completed. We are committed to continually improving pipeline and facility integrity to protect the safety of the public, the environment, and company employees. We are dedicated to being a good corporate citizen by incorporating responsible business practices and conducting our business in an ethical manner.

Additionally, we have implemented an Integrated Safety and Loss Management System (“ISLMS”) which is designed for establishing, implementing and continually improving our processes and controls to conduct business in a safe, secure, environmentally responsible and sustainable manner. The ISLMS applies to activities involving the design, construction, operations and abandonment of certain pipelines and terminals systems, including TMPL, Jet Fuel, and Puget Sound and certain Terminals assets in Alberta. Through our procedures, this system helps provide for appropriate satisfaction of NEB regulations and efficient, safe operations in an integrated, systematic and comprehensive manner.


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Safety and Emergency Management

Our operators maintain programs designed to safeguard the health and safety of employees, contractors and the general public, including through comprehensive health and safety programs that address risk assessment and monitoring, capability, development, emergency response plans, systems for incident investigation and tracking, and employee evaluation. We believe these safety programs meet or exceed the standards set by the Canadian energy infrastructure industry and applicable government regulations. We have a strong operating and safety track record, with no reportable right of way releases since 2013.

The integrity of each of TMPL and Cochin are regularly monitored using in-line inspection tools. These devices inspect the pipeline from the inside and can identify potential anomalies or changes to the condition of the pipe. The collected data is analyzed to find locations where further investigation is required. If necessary, a section of the pipe is exposed and assessed by qualified technicians so that it can be repaired or replaced.

Each of the TMPL (including Puget Sound and Jet Fuel) and Cochin has its own control center wherein Control Center Operators (“CCOs”) monitor pipeline operations and operating conditions 24 hours a day, seven days a week using a sophisticated Supervisory Control and Data Acquisition (“SCADA”) computer system. This electronic surveillance system gathers and displays such data as pipeline pressures, volume and flow rates and the status of pumping equipment and valves. Alarms notify CCOs if parameters deviate from prescribed operating limits. Both automated and manual valves are strategically located along the pipeline system to enable the pipeline to be shut down immediately and sections to be isolated quickly, if necessary. In the event of a precautionary shutdown of the pipeline there is a formal protocol related to restarting the pipeline. This protocol includes analysis of SCADA and leak detection system data, aerial or foot patrols of the pipeline as appropriate, completion of any inspections or repairs, notifications to regulators, and development of a restart plan. All restarts must be approved by the appropriate Operations Director.

Similarly, our terminals have been built with sophisticated technology and incorporate safety and environmental protection features. In Alberta, the Strathcona District Mutual Assistance Program, assists with emergency planning and tests of the emergency preparedness of our terminals in the Edmonton area. Each of the terminals facilities, as described under “—Terminals Business” above, are staffed with trained personnel 24 hours a day, seven days a week.

Pipeline rights-of-way are regularly patrolled by both land and air. Any observed unauthorized activity or encroachment is reported and investigated. We have a public awareness program for each of our pipelines that is designed to create awareness about pipelines, provide important safety information, increase knowledge of the regulations for working around pipelines, and educate first responders and the public on emergency preparedness response activities.

Operations staff are trained to maintain our pipelines and to respond in the event of a spill or other safety related incident along each pipeline route.

We maintain comprehensive emergency management plans and actively maintain emergency response capabilities across our operations. We take an all-hazards approach to preparedness and use the Incident Command System (“ICS”) to manage incident response. ICS is widely used by the public safety agencies with whom we may need to coordinate a response. It provides a standardized management structure that allows ready integration of public safety agencies and regulators into a unified response organization.

As part of its integrated safety and loss management program, TMPL maintains an emergency management program (“EMP”). The EMP is a comprehensive set of policies, procedures and processes designed to support its commitment to the safety and security of the public, employees, workers, company property and the environment. The EMP is an all-hazards emergency management program of mitigation, preparedness and response designed to provide a continuous cycle of improvement as mandated by the NEB Onshore Pipeline Regulations. Emergency response plans are constantly being updated to keep them current. The plans are location specific, identify locations of emergency response materials and equipment and are regularly practiced through field deployment exercises.

Caches of mobile equipment are located along TMPL to minimize response time. These caches typically include river boats and response trailers equipped with booms, pumps and liquid storage. TMPL also provides training sessions to first responders along TMPL. These sessions, along with regular exercises, provide TMPL with the opportunity to maintain working relationships with first responders and to facilitate mutual awareness of response programs.

TMPL is a member and shareholder of both Western Canadian Spill Services (“WCSS”) and the Western Canada Marine Response Corporation (“WCMRC”). WCSS maintains caches of oil spill response equipment in western Canada to augment the resources of member companies. WCMRC is the Transport Canada-certified spill response organization for the West Coast of

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Canada. KM Canada Marine Terminal (“Vancouver Wharves”) is also a member of WCMRC for the liquid bulk distillates exports and imports. TMPL also participates in mutual assistance agreements with Canadian Energy Pipeline Association member companies, the Strathcona District Mutual Assistance Program, the Kamloops Fire Department and the Burnaby Industrial Mutual Aid Group, which consists of the petroleum terminals operating in Burnaby, B.C.

TMPL, along with Suncor Energy Inc., Imperial Oil Limited, Parkland Fuel Corp. and Shell Canada Products, are shareholders of the WCMRC, Canada’s West Coast-certified response organization responsible for emergency response preparedness which is on call 24 hours a day, seven days per week, to manage oil spill response on the B.C. coast. To address changes in maritime shipping that will result from TMEP completion, the WCMRC has agreed to implement an enhancement program to increase its response capacity in the Salish Sea. These enhancements, including the five new bases along the transit route, will satisfy certain of the NEB conditions for TMEP and will double capacity and halve response times relating to the existing planning standards under which the WCMRC operates. In addition, the vessel acceptance process will require tankers to engage in an extended tug escort with new larger tugs being required for the Juan de Fuca Strait. The improvements to be implemented in connection with the commitments made by Trans Mountain, including spill response capacity enhancements, are expected to build upon the existing systems to result in an overall level of marine safety that exceeds globally accepted standards.

While we do not own, operate or control the vessels that call at the Vancouver Wharves Terminal or the Westridge Marine Terminal, we are an active member of the maritime community and work with maritime agencies to promote business practices and facilitate improvements to provide for the safety and efficiency of tanker traffic in the Salish Sea.

In addition to our own rigorous screening process and terminal procedures, vessels calling at Westridge and Vancouver Wharves must operate according to rules established by the International Maritime Organization, the Government of Canada through Transport Canada, the Pacific Pilotage Authority, and Port Metro Vancouver. Under this regime there is a well-established system to provide for maritime safety in the Salish Sea, including established shipping lanes and aids to navigation, various inspection methodologies, coordinated vessel traffic monitoring, mandatory tug escort for laden tankers and mandatory pilotage with two pilots on the bridge of laden tankers. In addition, such vessels must maintain their membership in a mandatory spill response regime.

Our Employees and Communities

Employees

At the head office located in Calgary, Alberta, we have a total of 169 staff as of December 31, 2017. Non-union Canadian employees are employed by KMCI and provide services to each of the Canadian operating assets. TMPL employs 100 staff in Alberta in Edmonton, Stony Plain, Edson, and Jasper. Through central B.C. in the towns of Blue River, Clearwater, and Kamloops, an additional 33 operations personnel maintain the pipeline, while in southern B.C., 60 staff are located in Hope, Sumas and Burnaby.Seven staff located in Laurel, Washington are dedicated to the operations of Puget Sound. Seventeen staff are dedicated exclusively to work on Cochin and are primarily located in the two most critical strategic locations along the pipeline. With respect to the Terminals business, we currently employ 21 staff at the Edmonton Rail Terminal, 12 staff at the Base Line Terminal and 61 staff at Vancouver Wharves.

With respect to the operation of Vancouver Wharves, KM Canada Marine Terminals is a member of the B.C. Maritime Employers Association which is party to collective agreements with the International Longshore and Warehouse Union - Canada (the “Longshore CBA”) and the International Longshore and Warehouse Union Ship and Dock Foreman Local 514 (the “Foremen CBA”). Each of these collective bargaining agreements expire in March 2018. Under the Longshore CBA, up to 250 longshoremen supplement the non-unionized workforce employed by KMCI at the Vancouver Wharves Terminal. Under the Foremen CBA, up to 30 foremen are similarly provided at that location.

In addition to its permanent staff, KMCI is party to a general service contract with Roevin Technical People, a division of Adecco Employment Services Limited (“Roevin”), whereby Roevin provides services relating to the administration of term employees and independent contractors for KMCI. Currently, Roevin manages 222 personnel for KMCI, 105 of whom are temporary employees. These contracted employees augment the KMCI workforce and are utilized throughout our business, but they are primarily utilized on TMEP.

Engaging Communities

We believe that our neighbors as well as governments and Aboriginal communities play an important role in how we conduct our business and that our success depends on earning the trust, respect and cooperation of such groups.


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In addition to cooperating with various government initiatives including abandonment trusts and the federal government’s $1.5 billion ocean protection plan, Trans Mountain participates in Canadian Energy Pipeline Association work groups, Integrity First and is a party to the Canadian Energy Pipeline Association mutual aid agreement. In addition, the Pipelines segment has established relationships with landowners, neighbors, and communities along its pipeline corridors. Our pipelines cross private properties as well as public lands. Agreements are in place with landowners that have allowed us to build and operate our existing pipelines. We value our ongoing and positive relationships with landowners and neighbors in communities along pipeline routes and are committed to respectful, transparent and collaborative interactions with them to develop long-term effective relationships.

The Terminals segment has developed working relationships with key governmental authorities, regulatory bodies and local stakeholders, including the AER, Alberta Transport, Strathcona County, the City of Edmonton, the District of North Vancouver, Transport Canada, Port Metro Vancouver and the Longshore CBA. We have had the opportunity to engage with the public on new terminals and terminal expansion projects and have welcomed the opportunity to discuss our growing terminals business with the communities in which we have facilities. The Terminals segment’s open engagement with the communities in which it operates, along with its productive relationships with applicable regulators, has historically helped to facilitate receipt of the permits required to successfully grow and operate the Terminals segment, including, most recently, its successful agreement with both Alberta Transport and Strathcona County to build Strathcona County’s first highway overhead pipeline bridge.

In connection with our commitment to developing strong relationships with the communities in which we operate, we routinely host facility open houses, provide newsletters and project updates, make safety and public awareness presentations and participate in community events.

As TMPL operates in certain Aboriginal territories and reserve lands, we recognize and appreciate the many unique and diverse interests of Aboriginal groups. As such, we are committed to open, transparent dialogue and to creating mutually beneficial working relationships with these groups. With respect to TMEP process, we view the Crown’s obligation for Aboriginal consultation as an opportunity to demonstrate recognition and respect for the constitutionally protected rights held by Aboriginal groups. Accordingly, numerous Aboriginal communities have entered into mutual benefit agreements agreeing to support TMEP, and over the last five years, Trans Mountain has had more than 40,000 engagements with 133 separate Aboriginal communities with respect to TMEP and remains committed to continuing this engagement through the entire life of the project. See Item 1A “Risk FactorsRisks Relating to Our Business” and “—Risk FactorsRisks Relating to Regulation.”

Environmental Stewardship

As a long-time industry and community member, we are committed to working with residents, regulatory authorities, and other stakeholders on environmental initiatives. Recent examples of our commitment to preserving and protecting the environment include Trans Mountain’s Raft River erosion protection and stabilization project; the Stoney Creek salmon habitat restoration; and a commitment by Trans Mountain to contribute to the planting of 13,000 trees for the purpose of offsetting carbon dioxide (“CO2”) emissions. In addition, KMCI was awarded an Emerald Award in 2010 for the excellent environmental initiatives associated with the Anchor Loop expansion.

Regulation

Canadian Regulation

NEB

Both TMPL and Cochin are regulated by the NEB. The NEB, pursuant to the terms of the NEB Act, regulates the tolls and tariffs governing these pipeline systems, as well as the physical construction, operation and abandonment of the associated pipelines and facilities.

Tolls are either determined on a contested application to the NEB or through a negotiated toll settlement between the operator and interested parties, which settlement must subsequently be approved by the NEB. With respect to its approvals of these tolls, the NEB generally allows companies to recover costs of transporting shipper’s products and earn a reasonable return on invested capital. However, all tolls must comply with the governing regime under the NEB Act which requires that tolls: (i) be just and reasonable; (ii) always, under substantially similar circumstances and conditions with respect to all traffic of the same description carried over the same route, be charged equally to all persons at the same rate; and (iii) not result in unjust discrimination. Generally, the NEB approves each pipeline’s cost of service and tolls on a yearly basis, and will allow for the recovery or refund of the variance between actual and expected revenues and costs in future years. As described above, TMPL currently operates under a negotiated toll settlement for its transportation services.


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In addition to rate regulation, the NEB regulates all phases of a pipeline’s operational life-cycle, from the planning and application phase of a project through to the deactivation, decommissioning or abandonment of a project. Where necessary, the NEB can issue mandatory compliance or remediation orders or use other appropriate tools to enforce its requirements, including, among other things, issuing fines and monetary penalties. The NEB is also responsible for conducting environmental assessments for certain projects that it regulates in accordance with the requirements of the Canadian Environmental Assessment Act, 2012.

In the planning and application assessment phase of a project, the NEB is responsible for assessing whether the project is in the national public interest and can be built and operated safely and in a manner that protects the public and the environment. The NEB assessment includes a review of the design, construction and proposed operations of the pipeline as well as an evaluation of the potential risks posed to people or effects on the environment by the project plans and whether these risks will be prevented, managed and mitigated through appropriate planning. Where a Certificate of Public Convenience and Necessity is required, the NEB will undertake its assessment and, if it finds that the project is in the public interest, make a recommendation to the Governor in Council that the project be approved subject to any conditions that might be appropriate to mitigate any potential project-related risks and effects. If the Governor in Council accepts the NEB’s recommendation and approves the project, the NEB is then required to issue a Certificate of Public Convenience and Necessity to authorize construction and operation. After the NEB issues its approval, it will review compliance with all conditions that must be satisfied prior to construction. In addition, for projects that require a Certificate of Public Convenience and Necessity, the NEB must review and approve the detailed route for the pipeline (called the Plan, Profile and Book of Reference). Parties affected by the detailed route are entitled to a detailed route hearing if they object to the detailed location, methods or timing of construction activities. The pipeline company may also apply to the NEB for a right-of-entry approval to acquire land rights if it is unable to acquire the rights through direct negotiation with the landowner.

During the construction phase of a project, the NEB monitors and verifies compliance with its construction-related requirements and the terms and conditions of its project approval. Once construction is completed, the pipeline company must apply for leave to open the pipeline, which the NEB must approve before the pipeline can be placed in service.

With respect to assets that are in operation, the NEB monitors and verifies compliance with its operation-related requirements. The NEB will hold compliance meetings with regulated companies, conduct audits of management and protection programs and systems, inspect facilities to assess compliance with requirements, review and approve key documents and evaluate regulated company emergency response exercises for the ability to respond to an emergency. The NEB requires pipeline companies to have integrity management programs in place to ensure the physical condition of the asset is monitored and maintained so that releases do not occur. In addition, pipeline companies must have an EMP that anticipates, prevents, manages and mitigates conditions during an emergency that could adversely affect property, the environment, or the safety of workers or the public, as well as incident first-responders. In the case of a pipeline emergency, the NEB will monitor and assess a company’s emergency response, investigate the incident, initiate enforcement actions as necessary and oversee remediation actions.

In the deactivation, decommissioning or abandonment of a project, the NEB will assess whether the applied-for plan can be conducted safely and whether risks to people or the environment can be reduced or avoided. The NEB currently requires holders of an authorization to operate a pipeline under the NEB Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline and associated facilities. While a pipeline company bears the ultimate responsibility for the full cost of the abandonment attributable to its assets, upon receipt of approval from the NEB, companies are able to recover certain of these abandonment costs from users of the applicable pipelines. As at the date hereof, Kinder Morgan has received approval to recover its estimated future abandonment costs from shippers on all of its NEB-regulated pipeline assets.

In June 2016, the Pipeline Safety Act, which enshrines in law the “polluter pays” principle, came into force in Canada. Under the Pipeline Safety Act, in the event that an environmental incident occurs with respect to one of our pipeline assets, we will have unlimited liability if we are determined to be at fault or negligent. Further, in the event of any environmental incident, regardless of whether there is proof of fault or negligence by us, we will be liable for up to $1 billion in costs and damages. In connection with this “absolute liability” of up to $1 billion, we are required to demonstrate that we have the financial resources to meet these responsibilities (and a portion of our resources need to be readily accessible to help ensure rapid incident response). In this respect, the NEB has determined that Trans Mountain must have $500 million of short term cash available for this purpose and the remainder may be met with insurance and/or other instruments and has indicated that they intend to require similar financial capacity for Cochin. Further, in connection with the Pipeline Safety Act requirements, among other things: (i) the government has the ability to pursue pipeline operators for the costs of environmental damages; (ii) the NEB is authorized to order reimbursement of costs and expenses incurred by others in taking actions related to an incident; and (iii) the NEB is permitted to take control of incident response in exceptional circumstances, if a company operating a pipeline is unwilling or unable to shoulder its responsibilities. The Pipeline Safety Act also provides that a pipeline company remains liable indefinitely for any pipelines that are abandoned in place.


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Recent NEB Developments

On February 6 and 8, 2018, the Canadian government introduced Bills C-68 and Bill C-69 (the “Bills”), respectively, which introduce several major changes to Canada’s federal regime for the assessment of federally regulated projects and regulation of waterways. The Bills repeal and replace the Canadian Environmental Assessment Act, 2012 and the National Energy Board Act, while making several significant changes to the Fisheries Act and the Navigation Protection Act.  These bills are not likely to be passed into legislation until the middle of 2019, and resulting changes in regulations are not likely to be implemented until 2020. When passed, these acts would not impact the TMEP federal certificates because TMEP has been approved under prior legislation.

Some of the potential significant changes that would result from passage of C-69 would be environmental reviews for new projects would be conducted by a new agency (the “Impact Assessment Agency of Canada”) under the direction of the Minister of Environment and Climate Change Canada, and the scope of the review would be expanded to include a preliminary planning phase; consideration of a proposed project’s impact on the government of Canada’s climate change commitments and on sustainability; potential alternatives to the project; a requirement to hold hearings in a manner that offers the general public an opportunity to participate; considerations related to indigenous cultures; and consideration of the intersection of sex and gender with other identity factors. The role of regulating construction, operations, toll setting, and abandonment would be changed to a new regulator (“Canadian Energy Regulator”) with a similar mandate to the existing NEB (except for environmental reviews), with changes such as organization governance structure, requirements for Indigenous representation on panels, and establishment of committees to include Indigenous people to enhance involvement. Although some opponents have raised concerns that these changes will adversely affect timing and certainty for proposed projects, the government of Canada has indicated that one of the purposes of the changes is to ensure that the impact assessment is completed in a timely manner and contributes to a positive investment climate in Canada.

B.C. Regulations

While the NEB is the primary regulator for pipelines and associated infrastructure that are interprovincial or international, such projects are also subject to elements of provincial jurisdiction. For example, in addition to the federal legislative regime that is administered by the NEB, aspects of TMPL are regulated by BC OGC, which maintains certain incremental requirements with respect to, among other things, environmental management, pipeline crossings, integrity management and damage prevention.

As Jet Fuel is located within B.C., its operations are regulated by BC OGC and its tolls are regulated by BCUC. The financial regulation of Jet Fuel tolls is undertaken by BCUC on a complaints basis, meaning that pipeline-related matters are generally dealt with between Jet Fuel pipeline operator and the party using its services, subject to the ability to make complaint to BCUC where a dispute cannot be resolved. Jet Fuel is currently being operated pursuant to a contract that has been approved by BCUC through 2018.

Climate Change and GHG Regulations

We generate greenhouse gas (“GHG”) emissions through our operations, which are below regulatory reporting thresholds. These GHG emissions are subject to various climate change policies and regulations across North America.

Canada has committed to reduce its GHG emissions by 30% below 2005 levels by 2030. In December of 2015, Canada, along with 194 other countries reached an historic agreement to maintain global temperature increases to below two degrees Celsius above pre-industrial levels (the “Paris Agreement”). In late 2016, Canada, along with all of its provincial and territorial governments, with the exception of Saskatchewan and Manitoba, entered into the Pan-Canadian Framework on Clean Growth and Climate Change (the “Framework”). Under the Framework, the federal government requires all provinces and territories to implement a carbon price, starting at $10 per metric ton in 2018 and rising by $10 per year to $50 per metric ton in 2022. The provinces and territories have the flexibility to implement either price-based systems such as a carbon tax or cap-and-trade systems. Within these programs the provinces and territories also have the discretion to manage the competitiveness of their trade-exposed industries.

In Alberta, facilities that emit less than 100,000 metric tons of carbon dioxide equivalent (CO2e) per annum as well as all residents were subject to a carbon tax of $20 per metric ton of carbon used. This tax increased to $30/metric ton on January 1, 2018. Facilities that emit greater than 100,000 metric tons of CO2e per annum are subject to the Specified Gas Emitters Regulation (the “SGER”). As of January 1, 2017, existing facilities that exceed this threshold must decrease their emissions intensity by 20% relative to their baseline emissions. If a facility is unable to decrease its emissions intensity through increases in operational efficiency, it is still able to comply with the Alberta requirements by purchasing qualifying emission offsets from other sources in

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Alberta or by contributing to the Climate Change and Emissions Management Fund (the “Fund”). The contribution cost to the Fund is currently $30 per metric ton of CO2e. To address the competiveness of trade-exposed sectors, the SGER is expected to be replaced with a Carbon Competiveness Regulation in 2018.

Alberta has also enacted the Oil Sands Emissions Limit Act (the “OSEL Act”) which limits GHG emissions in the oil sands sector to a maximum of 100 metric megatons per annum. The OSEL Act includes provisions for cogeneration and new upgrading facilities allowing for continued growth and optimization while accelerating emissions reduction technology.

In B.C., the government introduced a broad-based, revenue-neutral carbon tax in 2008 on the purchase and use of fuels. Since 2012 the carbon tax has been set at $30 per metric ton of CO2e. In 2016, it introduced the Greenhouse Gas Industrial Reporting and Control Act which creates intensity-based emissions performance standards for prescribed industrial facilities and sectors.

B.C. recently adopted a Climate Leadership Plan, which outlines more than 20 climate change action areas that will be developed by the Province. Highlights include action items to reduce GHG emissions under the following six categories: natural gas; transportation; forestry and agriculture; industry and utilities; communities and the built environment; and the public sector. On September 11, 2017, the B.C. government announced proposed changes to the provincial tax laws, which are still subject to the approval of the legislature, including an increase to carbon tax rates which will be increased by $5 per metric ton of CO2e annually beginning April 1, 2018 until rates are equal to $50 per metric ton of CO2e on April 1, 2021.

The imposition of carbon pricing is not expected to have a material direct effect on TMPL or TMEP. Existing and pending carbon taxes were considered in Trans Mountain’s $7.4 billion cost estimate for TMEP and future power costs and cost impacts relating to changes in legislation included as flow-through items to shippers under the existing shipper contracts for the expanded TMPL. In addition and as noted above, Trans Mountain has take-or-pay contracts for approximately 80% of the expanded throughput following the completion of TMEP. See Item 1A “Risk FactorsRisks Relating to Our Business.

United States Regulation

Puget Sound is a common carrier interstate pipeline subject to the regulatory authority of the FERC under the provisions of the Interstate Commerce Act; it has tariffs on file at the FERC and files quarterly and annual reports at FERC, among other regulatory requirements. Puget Sound transports petroleum that crosses the international border and is delivered to refineries and/or terminals near the state of Washington coast — i.e., the shipments are exclusively interstate in nature. Puget Sound is also subject to pipeline safety oversight and authority of the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”). Under PHMSA procedures, the Washington Utilities and Transportation Commission has been acting as an Interstate Agent in oversight of Puget Sound under PHMSA standards. In addition, because of its status as a liquids pipeline that crosses (or, perhaps, abuts and transports across) an international border, Puget Sound may be subject to the Executive Orders requiring a Presidential Permit for certain physical changes, which are issued by the U.S. Department of State. Certain changes in facilities may require submission of an application for a Presidential Permit as to the new facilities, particularly if the facilities affect the border crossing or increase capacity.

Environmental Matters

Our business operations are subject to federal, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment (including with respect to climate change), natural resources and human health and safety. Such laws, regulations and obligations affect many aspects of our business’ present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals, including with respect to its expansion and new build projects. Liability under such laws and regulations may be incurred without regard to fault for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage.

Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in operations that could influence our business, financial position, or results of operations. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay government penalties, address natural resource damage, compensate for human exposure, property damage or economic loss, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect earnings and cash flows. In addition, emission controls required under provincial laws could require significant capital expenditures at our facilities.

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We own and/or operate numerous properties and assets that have been used for many years in connection with our business activities. While we believe we have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties and assets have been owned and/or operated by third parties whose management, operation, handling and disposal of hydrocarbons or other hazardous substances were not under our or our predecessors’ control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws which impose joint and several liability, without regard to fault or the legality of the original conduct. In addition, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

We cannot ensure that existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to our business. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial position, results of operations and prospects. In addition to revised or additional regulations affecting our customers and/or shippers, including those related to the protection or preservation of the environment (including with respect to climate change), natural resources and human health or safety may have significant negative impacts on the business and operations of such customers and/or shippers that result in such customers and/or shippers defaulting on their contractual obligations to us (including with respect to take-or-pay obligations). We are exposed to the risk of loss in the event of non-performance by such customers and/or shippers, which could have a material adverse effect on our business, and consequently, the Company.

An environmental incident could have lasting reputational impacts to the Company, our business or Kinder Morgan and could impact their ability to work with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance), environmental incidents may lead to an increased cost of operating and insuring our assets, thereby negatively impacting earnings and DCF (see Regulation above”).

Although we have OMS and EMP programs in place, there remains a chance that an environmental incident could occur. Kinder Morgan also seeks to mitigate the severity of a potential environmental incident through continued process improvements and enhancements in leak detection processes and alarm analysis procedures. We have also invested significant resources to enhance our emergency response plans, operator training and landowner education programs to address potential environmental incidents. However, the mitigation efforts are incapable of guarding against all environmental risks, including in the event that there is significant damage to our assets as a result of catastrophic events (including natural disasters, other significant weather-related events or adverse sea conditions) or the actions of third parties acting outside of our control.

We maintain an insurance program which is renewed annually and has $1 billion worth of financial capacity for spill events in accordance with the Pipeline Safety Act (seeRegulation” above). The insurance program includes coverage for commercial liability that is considered customary for the industry in which we operate and includes coverage for operational and environmental incidents. However, the insurance program may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us. The total insurance coverage will be allocated on an equitable basis among the members of the Kinder Morgan Canada Group in the event multiple insurable incidents exceeding our coverage limits within the same insurance period are experienced.

Financial Information about Geographic Areas

Our assets are located in the Canadian provinces of B.C., Alberta and Saskatchewan, and the U.S. state of Washington. See Note 18 “Reportable Segments” to our consolidated financial statements for further discussion of the financial information about geographic areas.

Available Information

For this annual report on Form 10-K and future reporting periods, we will make available free of charge on or through our internet website, at www.kindermorgancanadaltd.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on or connected to our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

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Item 1A. Risk Factors.

Our business, financial condition and results of operations, including our ability to pay cash dividends, are substantially dependent on our financial condition and results of operations and our successful development of TMEP. As a result, factors or events that impact the successful operation or our business as well as the costs associated with and the time required to complete (if completed) TMEP, are likely to have a commensurate impact on us, the market price and value of the Restricted Voting Shares, our preferred shares, and our ability to pay dividends. Similarly, given the nature of our relationship with Kinder Morgan, factors or events that impact Kinder Morgan may have consequences for us.

Risks Relating to Our Business

Major projects, including TMEP, may be inhibited, delayed or stopped.

Our ability to continue and complete construction on TMEP, as well as other expansion and new build projects, may be inhibited, delayed or stopped by a variety of factors (some of which may be outside of our control), including without limitation, inabilities to overcome challenges posed by or related to regulatory or governmental approvals by federal, provincial or municipal governments, difficulty in obtaining, or inability to obtain, permits (including those that are required prior to construction such as the permits required under the Species at Risk Act), land agreements, governmental or public opposition, blockades, legal and regulatory proceedings (including judicial reviews, injunctions, detailed route hearings, variance applications and land acquisition processes), delays to ancillary projects that are required for TMEP (including, with respect to power lines and power supply), increased costs and/or cost overruns, inclement weather or significant weather-related events (including storms and rising sea levels (potentially resulting from climate change) impacting our marine terminals) and other issues. Detailed route hearings will be required where valid route objections arise. The NEB must approve the detailed route for TMEP before full construction can commence. Such approval will be by segment. Detailed route hearings could result in delays and increased cost to the project and could require modifications to the detailed location, construction methods and construction schedule. To the extent we are not able to acquire land rights through negotiated agreements for the sections of TMEP that require new land rights, we will need to seek right of entry orders from the NEB, which could result in delays and increased cost to TMEP. In addition, we have applied for certain variances to the Certificate of Public Convenience and Necessity from the NEB and may apply for additional variances in the future. These variances may require, among other things, additional consultation and further regulatory processes and approvals before construction of the affected portions of TMEP can commence. These additional, and possible other, processes and approvals could result in delays, increased costs and/or cost overruns or other issues with respect to the project.

Although we have signed a number of agreements with general construction contractors, we are currently in negotiations with other construction contractors to construct the various pipeline spreads on TMEP. As some of the contractors themselves and the terms of such applicable contracts have not been finalized, there can be no assurance that the construction contracts entered into in respect of TMEP will be finalized on terms that are advantageous to us or consistent with our cost estimates. Further, there is no guarantee that, once such contracts are entered into, such contracts will be performed in a manner satisfactory to us. In the event that we must enter into construction contracts on terms that are less favorable to us or contractual counterparties fail to perform their duties in accordance with the terms of the applicable contract, TMEP may be delayed or we may incur significant additional costs.

In addition to TMEP, we are currently undertaking certain other growth projects and may, in the future, further expand existing assets and construct new assets. Such projects, and any potential growth opportunities that are undertaken, will be subject to the same or similar risks as those identified above and elsewhere in these Risk Factors, for TMEP.

Any new growth projects will be subject to, among other things, the receipt of regulatory approvals, feasibility and cost analyses, funding availability and industry, market and demand conditions. There can be no guarantee that any potential opportunities identified will be undertaken or completed or, if any such growth projects are undertaken there can be no certainty as to the timing, nature, extent or completion of such projects. Additionally, events such as inclement weather or significant weather-related events (including storms and rising sea levels (potentially resulting from climate change) impacting our marine terminals), natural disasters, unforeseen geological conditions and delays in performance by third-party contractors may result in increased costs and/or cost overruns or delays in construction. Significant cost increases and/or cost overruns or delays could have a material adverse effect on our return on investment, results of operations and cash flows and could result in reduced or eliminated dividends, project cancellations or constraints on our ability to pursue other growth opportunities.


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Judicial reviews of the processes pursuant to which we have been granted certain governmental, administrative and contractual rights to construct and operate our pipelines for TMEP, including on other owners’ land, are on-going. If we were to lose these rights or TMEP were to become subject to additional significant regulatory reviews, changes, further obligations or restrictions, TMEP may be significantly delayed or stopped altogether, and we may incur additional costs.

While a number of key governmental approvals have been received with respect to TMEP, the completion, timing and costs of TMEP are still subject to significant risks. Numerous legal challenges have been filed with the Federal Court of Appeal by various governmental and non-governmental organizations, Aboriginal groups or other parties that seek judicial review of the recommendation of the NEB and subsequent decision by the Federal Governor in Council to conditionally approve TMEP. Such requests for judicial review claim, among other things, that additional Aboriginal consultation, engagement or accommodation is required and that various non-economic impacts of TMEP were not adequately considered. The remedies sought include requests that the NEB recommendation report be quashed, that additional consultations be undertaken and that the order of the Governor in Council approving TMEP be quashed. As leave has been granted in a number of circumstances, the Federal Court of Appeal will review, in the case of the NEB, its recommendation that TMEP proceed and, in the case of the Government of Canada, the Governor in Council’s approval of TMEP. In the event that an applicant is successful at the Federal Court of Appeal, among other things, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be imposed or TMEP may be stopped altogether.

If an applicant is unsuccessful at the Federal Court of Appeal, the applicant may further appeal such decision to the Supreme Court of Canada. If the applicant is successful at the Supreme Court of Canada, among other things, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be imposed or TMEP may be stopped altogether.

In addition to the judicial reviews of the NEB recommendation report and Governor in Council’s order, parties have also commenced judicial review proceedings have been commenced at the Supreme Court of B.C. (Squamish Nation and the City of Vancouver) and seek to quash the Environmental Assessment Certificate, or EAC, that was issued by the B.C. Environmental Assessment Office. The petitions allege a duty and failure to consult or accommodate First Nations, and generally, among other claims, that the Province ought not to have approved the Project. If one of these applicants for judicial review is successful, among other things, the EAC may be quashed, provincial permits may be revoked, TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be imposed or TMEP may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of B.C., they may further seek to appeal the decision to the B.C. Court of Appeal. Any decision of the B.C. Court of Appeal may be appealed to the Supreme Court of Canada. A successful appeal at either of these levels could result in the same types of consequences described above.

To the extent we seek to continue construction of TMEP prior to the determination of such judicial review applications by the applicable court, the applicants may seek injunctions from the court to prevent us from proceeding with construction until the litigation has been resolved. If such injunctive relief is granted, TMEP may be significantly delayed or stopped altogether, and we may incur additional costs.

Additional efforts to block or revise TMEP (including through new litigation, changes in government or government policy or legislation, protests, blockades or otherwise) may arise in the future and the success of any such future efforts may have the same or similar results. Events such as a change in government, legislative or regulatory changes, loss of government or community support or ongoing governmental or community opposition to projects, including TMEP (for example, the strong and likely unyielding opposition of the City of Burnaby), may cause such projects, including TMEP, to be significantly disrupted, delayed or stopped, or cause significant increased costs to be incurred. (see also “—We are subject to reputational risks and risks relating to public opinion,” “—Aboriginal relations have the potential to delay or halt regulatory approval processes and construction and increase project costs, which may negatively affect the economics of projects,” “—Non-governmental organizations could impact projects and operations” and “—Risks Relating to Regulation” below). The total stoppage of TMEP would have a material adverse effect on us. Further, in addition to potentially resulting in significant increased costs and/or cost overruns and delays, the quashing of the NEB recommendation or the Governor in Council’s approval, the revocation of permits, additional significant regulatory reviews, significant changes to the TMEP plans or the imposition of further obligations or restrictions, could materially impact the overall feasibility or economic benefits of TMEP, which, in turn, would have a material adverse effect on TMEP (including the anticipated increases to Adjusted EBITDA referenced in this document) and, consequently, our business.


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We could be adversely affected by future substantial levels of debt.

We must incur substantial indebtedness to fund capital expenditure requirements related to TMEP. See Note 9 “Debt” to our consolidated financial statements for a description of our indebtedness. As of December 31, 2017, we had no debt outstanding. A significant increase in our debt levels could have significant negative consequences, including in connection with TMEP, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, including with respect to TMEP, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends or distributions because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service debt will depend upon, among other things, our future financial and operating performance, which will be affected by the relative success (or lack thereof) of TMEP, prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If cash flow is not sufficient to service our debt, we will be forced to take actions such as reducing or eliminating dividends or distributions, reducing or delaying business activities (including our expansion projects), acquisitions, investments and/or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all. See also “—We will require access to external capital” and “—Risks Relating to Ownership of Restricted Voting Shares—Additional sales of Restricted Voting Shares will dilute a holder’s ownership in us, and issuances of our senior securities or senior securities of the Limited Partnership may impact the rights of the Restricted Voting Shares and their trading price” below.

The terms of the Credit Facility, and any debt we may incur in the future, may prevent us or the Limited Partnership from engaging in certain transactions, including paying dividends or distributions, as applicable, that might have otherwise been beneficial to us and the holders of Restricted Voting Shares.

We will require access to external capital.

Our growth plans, including TMEP, require access to significant amounts of external capital. Limitations on our ability to access external financing sources could impair our ability to complete these significant projects, including TMEP. We will have limited amounts of internally generated cash flows to fund growth capital expenditures and acquisitions. Kinder Morgan has stated that TMEP will be funded by us without further capital infusion from Kinder Morgan. In order to execute on our business plans, including with respect to the completion of TMEP, we expect that we will have to rely on external financing sources, including additional commercial borrowings and issuances of debt and equity securities (including preferred securities) and potential joint venture arrangements, to fund such growth capital expenditures. Adverse changes to the availability, terms and cost of capital or interest rates affecting our ability to meet the requirements to borrow under the Credit Facility could cause the cost of doing business to increase by limiting our access to capital, limiting our ability to pursue expansion opportunities or additional acquisitions and reducing our cash flows. Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on satisfactory terms.

Limitations on access to external financing sources, whether due to tightened capital markets, more expensive capital or otherwise, or any significant reduction in the availability of credit would significantly impair our ability to execute our growth strategy, including without limitation the completion of TMEP, which would have a significant material and adverse effect on our business, financial condition and results of operations. To the extent that we are required to issue additional equity, including preferred shares, or the Limited Partnership issues additional securities, including preferred units, to raise funds that are required to continue operating our business or complete TMEP or other expansion projects, the dilutive impact on existing shareholders would be increased and the price of the Restricted Voting Shares could decline. Further delays or cost overruns of key projects could result in depressed market prices or values of the Restricted Voting Shares and the issuance of additional equity or voting shares, including preferred shares, at such depressed prices may be required.

We are subject to reputational risks and risks relating to public opinion.

TMEP, our other expansion and new build projects and our business, operations or financial condition generally may be negatively impacted as a result of any negative public opinion toward TMEP or our other expansion and new build projects or as a result of any negative sentiment toward or in respect of Kinder Morgan’s or our enterprise-wide reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups’ negative portrayal of the industry in which we operate as well as their opposition to development projects, including TMEP. In addition, market events specific to us or Kinder Morgan could result in the deterioration of our reputation with key stakeholders. Potential impacts of negative public opinion or reputational issues may include delays or stoppages in project execution, legal or regulatory actions or challenges, blockades, increased regulatory oversight, reduced support of the

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federal, provincial or municipal governments for, delays in, challenges to, or the revocation of regulatory approvals, permits and/or Land Agreements and increased costs and/or cost overruns in respect of TMEP and/or the loss or degradation of our business generally.

Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and legal risks, among others, must all be managed effectively to safeguard our reputation. Our reputation and public opinion could also be impacted by the actions and activities of other companies operating in the energy industry, particularly other energy infrastructure providers, over which we have no control. In particular, our reputation could be impacted by negative publicity related to pipeline incidents, unpopular expansion plans or new projects and due to opposition from organizations opposed to energy, oil sands and pipeline development and particularly with shipment of production from oil sands regions that are considered to increase GHG emissions and contribute to climate change. Negative impacts from a compromised reputation or changes in public opinion (including with respect to the production, transportation and use of hydrocarbons generally) could include revenue loss, reduction in customer base, delays in obtaining, or challenges to, regulatory approvals with respect to growth projects and decreased value of our securities, including the Restricted Voting Shares, and our business.

Aboriginal relations have the potential to delay or halt regulatory approval processes and construction and increase project costs, which may negatively affect the economics of projects.

The Canadian courts have confirmed that the Crown has a duty to consult with Aboriginal people, and to accommodate if necessary, when its decisions or actions may adversely affect Aboriginal rights and interests or treaty rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may affect the economics of projects, including TMEP. In some cases, respecting Aboriginal rights may mean regulatory approval is denied or the conditions in the approval make a project economically challenging or not feasible. Certain of the TMEP-related claims for which leave to seek judicial review at the Federal Court of Appeal has been granted, involve, among other things, Aboriginal rights and title and the Crown’s duty to consult. The petitions seeking judicial review of the recommendation of the NEB, the subsequent decision by the Governor in Council to approve TMEP and the issuance of the B.C. Environmental Assessment Certificate allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of TMEP were not adequately considered. In addition to the potential impacts of such claims noted above under “—Major projects, including TMEP, may be inhibited, delayed or stopped,” a successful claim respecting Aboriginal title along any portion of the TMEP route could result in, among other things, a significant increase in costs and/or cost overruns, TMEP delays, reduced support of the federal, provincial or municipal governments for TMEP, delays in, further challenges to, or the revocation of regulatory approvals, permits and/or Land Agreements, the need for additional regulatory processes, significant changes to TMEP plans or additional obligations and/or restrictions placed on Trans Mountain in respect of TMEP, any of which could materially impact the overall feasibility or economic benefits of TMEP which, in turn, could have a material adverse effect on TMEP and, consequently, our business. In certain circumstances, these claims, if successful, could result in the total stoppage of TMEP, which stoppage would have a material adverse effect on our business.

We have instituted policies to promote the achievement of participative and mutually beneficial relationships with the Aboriginal groups affected by our projects and operations, including TMEP, and are committed to working with such groups so they may realize benefits from our projects and operations. Notwithstanding the efforts to this end, the issues are complex and the impact of Aboriginal relations on operations and development initiatives is uncertain. There is no guarantee that we will be able to satisfy the concerns of the Aboriginal groups and attempting to address such concerns may require us to incur significant and unanticipated capital and operating expenditures. In addition, to the extent that we have entered into agreements with Aboriginal groups respecting our operations, including TMEP, future disagreements with Aboriginal groups could result in legal challenges by Aboriginal groups alleging breach of contract. If successful, such claims could require us to pay significant and/or unanticipated compensation or damages to one or more Aboriginal groups.

Non-governmental organizations could impact projects and operations.

The development of TMEP, as well as other expansion projects, and our operations generally will at times be subject to public opposition which could expose us to the risk of higher costs, delays or even project cancellations (including TMEP) due to increasing pressure on governments and regulators by special interest groups including Aboriginal groups, landowners, environmental interest groups (including those opposed to oil sands and other oil and gas production operations) and other non-governmental organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support of the federal, provincial or municipal governments, and delays in, challenges to, or the revocation of regulatory approvals, permits and/or Land Agreements. There is no guarantee that we will be able to satisfy the concerns of the special interest groups and non-governmental organizations and attempting to address such concerns may require us to incur significant and unanticipated capital and operating expenditures.


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Commodity transportation and storage activities involve numerous operational risks that may result in accidents or otherwise adversely affect our operations.

Commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations. There are a variety of hazards and operating risks inherent in the transportation and storage of crude oil, refined petroleum products and other products, such as: leaks; releases; the breakdown or failure of equipment, pipelines and facilities (including as a result of internal or external corrosion, cracking, third party damage, material defects, operator error or outside forces), information systems or processes; the compromise of information and control systems; the performance of equipment at levels below those originally intended (whether due to misuse, ordinary course “wear and tear,” unexpected degradation or design, construction or manufacturing defects); spills at terminals and hubs; spills associated with the loading and unloading of harmful substances onto rail cars; adverse sea conditions (including storms and rising sea levels) and releases or spills from vessels loaded at our marine terminals; failure to maintain adequate supplies of spare parts; operator error; labor disputes/work stoppages; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries which may prevent the full utilization of assets; and catastrophic events including but not limited to natural disasters, fires, floods, explosions, earthquakes, acts of terrorists and saboteurs, cyber security breaches, and other similar events, many of which are beyond our control. Some climatic models indicate that global warming may result in rising sea levels, increased intensity of weather, and increased frequency of extreme precipitation and flooding. To the extent these phenomena occur, they could damage physical assets, especially operations located near rivers, and facilities situated in rain susceptible regions. In addition, we may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. Further, given the natural hazards inherent in our operations, workers and contractors are subject to personal safety risks. We will also be exposed, from time to time, to other operational risks in addition to those set out above.

The occurrence or continuance of any of the risks set out above could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution, significant reputational damage, impairment or suspension of operations, fines or other regulatory penalties, and revocation of regulatory approvals or imposition of new requirements, any of which also could result in substantial financial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. In addition, the consequences of any operational incident (including as a result of adverse sea conditions) at our marine terminals or involving a vessel receiving products from one of our marine terminals, may be even more significant as a result of the complexities involved in addressing leaks and releases occurring in the ocean or along coastlines and/or the repair of our marine terminals. We do not own or operate vessels calling at the Westridge Marine Terminal or the Vancouver Wharves Terminal. Any leaks, releases or other incidents involving such vessels, or other similar operators along the West Coast, could result in significant harm to the environment, curtailment of, or disruptions and/or delays in, offshore shipping activity in the affected areas, including our ability to effectively carry on operations at our marine terminals. Our inability to facilitate the movement of our shippers’ products to offshore markets, or a significant delay in such services, could have a material adverse effect on our business.

Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and cash flows while the affected asset is temporarily out of service.

A service interruption due to a major power disruption or curtailment of commodity supply could have a significant impact on our ability to operate, and could negatively impact future earnings, relationships with stakeholders and our enterprise-wide reputation. Service interruptions that impact our transportation services can negatively impact shippers’ operations and earnings as they are dependent on our services to move their product to market or fulfill their own contractual arrangements.

Our insurance program includes coverage for commercial liability that is considered customary for the industry in which we operate and includes coverage for operational and environmental incidents. However, our insurance program may not cover all operational risks and costs and/or may not provide sufficient coverage in the event a claim is made against us. Losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations. The total insurance coverage will be allocated among the Kinder Morgan Canada Group on an equitable basis in the event multiple insurable incidents exceeding our coverage limits within the same insurance period are experienced.

We are dependent on the supply of and demand for the commodities we handle.

Our pipelines, terminals and other assets and facilities depend in large part on continued production of crude oil and other products in the geographic areas to which our pipelines, terminals and other facilities provide service, and the ability and willingness of shippers and other customers to supply such demand. Without additions to oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may shut down production at lower product prices or

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higher production costs, especially where the existing cost of production exceeds other extraction methodologies. Producers in the areas we serve may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput. Commodity prices and tax allowance may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Changes in the business environment, an increase in production costs, supply disruptions, or higher development costs, could result in a slowing of supply to our pipelines, terminals and other assets. In addition, changes in the overall demand for hydrocarbons, the regulatory environment or applicable governmental policies (including in relation to climate change or other environmental concerns) may have a negative impact on the supply of crude oil and other products. In recent years, a number of initiatives and regulatory changes relating to reducing GHG emissions have been undertaken by federal, provincial, state and municipal governments and oil and gas industry participants (including, for example, the decarbonization targets set forth in the Paris Agreement). In addition, emerging technologies and public opinion have resulted in an increased demand for energy provided from renewable energy sources rather than fossil fuels. These factors could not only result in increased costs for producers of hydrocarbons but also an overall decrease in the global demand for hydrocarbons. Each of the foregoing could negatively impact our business directly as well as the customers that are shipping through our pipelines or using our terminals, which in turn could negatively impact the prospects of new contracts for transportation or terminaling, renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us” below.

Our pipelines and transmission infrastructure assets are largely dependent on supply and demand for the crude oil and other products originating in the WCSB. We will continue to monitor any changes in our customers’ crude oil production plans and how these changes may impact our existing assets and project schedules. There is significant competition for WCSB supply from several pipelines and rail terminals within the WCSB and significant competition from other pipelines and modes of transportation for the delivery of the diluent required by producers in the WCSB. An overall decrease in production and/or competing demand for supply could impact throughput on WCSB connected pipelines that, in turn, could negatively impact overall revenues generated. The WCSB has considerable reserves, but the amount actually produced depends on many variables, including commodity prices, basin-on-basin competition, pipeline tolls, demand for these products and the overall value of the reserves.

We cannot predict the impact of any of the risks set out above, all of which could reduce the production of and/or demand for crude oil, refined petroleum products and other hydrocarbons which in turn would reduce the demand for the pipeline and terminaling services we provide.

Our operating results may be adversely affected by unfavorable economic and market conditions including, in particular, the volatility of commodity prices and overall demand for fossil fuels.

Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the energy infrastructure industry, and in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. Prices for crude oil are subject to large fluctuations in response to relatively minor changes in the supply and demand for crude oil, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions or significant weather-related events (including storms and rising sea levels on the West Coast of B.C. or other environmental events potentially related to climate change); (ii) North American economic conditions; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political changes in North American or political instability in the Middle East and elsewhere; (vi) the foreign supply of and demand for crude oil; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources. If global economic and market conditions (including volatility in commodity markets), or economic conditions in the WCSB or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.

The industry in which we operate is highly competitive.

We face significant competition from other pipelines and other forms of transportation in the areas we serve and with respect to the supply for our pipeline systems. Any current or future pipeline system or other form of transportation that delivers crude oil, refined petroleum products or other hydrocarbons into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those currently provided by us because of price, location, facilities or other factors. To the extent that an excess of supply into these areas is created and persists, our ability to re-contract for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired. We also could experience competition for

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the supply of crude oil, refined petroleum products or other hydrocarbons from both existing and proposed pipeline systems. Several other pipelines access the same areas of supply as our pipeline systems and transport to destinations not served by us. See Items 1 and 2 “Business and Properties.

Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.

We are party to numerous contracts of varying durations. Certain of the contracts associated with our services are comprised of a mixture of firm and non-firm commitments, varying tenures and varying renewal terms, among other differences. There can be no guarantee that, upon the expiry of our contracts, we will be able to renew such contracts on terms as favorable to us, or at all. In particular, one of the current contractual arrangements, which accounts for a significant source of revenue at the Edmonton Rail Terminal, will expire in 2020. This contract is subject to a right of renewal on very favorable terms for the customer and, as a result, revenue from the Edmonton Rail Terminal is expected to decline following such renewal. Such a revenue decline could have a significant negative impact on our financial position.

Financial distress experienced by our customers or other counterparties could have an adverse impact in the event they are unable to pay us for the services we provide or otherwise fulfill their contractual obligations. We are exposed to the risk of loss in the event of non-performance by such customers or other counterparties. Some of these counterparties may be highly leveraged and subject to their own operating, market and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Further, while certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, there can be no assurance as to the impact of the parent credit ratings on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us.

We cannot provide any assurance that such customers and key counterparties will not become financially distressed or that such financially distressed customers or counterparties will not default on their obligations to us or file for bankruptcy or creditor protection. If one of such customers or counterparties files for bankruptcy or creditor protection, we likely would be unable to collect all, or even a significant portion, of amounts owed to us. Significant customer and other counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash flows. Furthermore, in the case of financially distressed customers, such events might force such customers to reduce or curtail their future use of our services, which could have a material adverse effect on our results of operations, financial condition, and cash flows.

We require a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plan.

The operation and management of our business requires the recruitment and retention of a skilled workforce, including engineers, technical personnel and other professionals, and the loss of key members of such workforce, or a substantial portion of the workforce as a whole, could result in the failure to implement our business plans. We compete with other companies in the energy infrastructure industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (i) retain current employees; (ii) successfully complete effective knowledge transfers; and/or (iii) recruit new employees with comparable knowledge and experience, we could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.

Terrorist attacks and “cyber security” events may adversely affect our business or reputation.

Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business. Our pipeline systems, terminals or operating systems may be targets for terrorist organizations or experience “cyber security” events. Our infrastructure, applications and data are becoming more integrated, creating an increased risk that failure in one system could lead to a failure of another system. There is also increasing industry-wide cyber-attacking activity targeting industrial control systems and intellectual property. A successful cyber-attack could lead to unavailability, disruption or loss of key functionalities within our control systems which could impact pipeline operations and potentially result in an environmental or public safety incident. A successful cyber-attack could also lead to a large scale data breach resulting in unauthorized disclosure, corruption or loss of sensitive information which could have lasting reputational impacts on us, and could negatively impact our ability to work with various stakeholders.

The occurrence of one of these events could cause a substantial decrease in revenues and cash flows, increased costs to respond or other financial loss, damage to our reputation, increased regulation or litigation or inaccurate information reported

33


from their operations. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates that we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.

We may be subject to abandonment costs.

We are responsible for compliance with all applicable laws and regulations regarding the abandonment of our pipeline systems and other assets at the end of their economic life, and these abandonment costs may be substantial. The proceeds of the disposition of certain assets, including in respect of certain pipeline systems and line fill, may be available to offset abandonment costs. While we estimate future abandonment costs and receive (through tolls) future abandonment costs based on such estimates, actual abandonment costs may be higher than the amounts received through tolls. We may, in the future, determine it to be prudent or required by applicable laws or regulations to establish and fund additional reclamation trusts to provide for payment of our future abandonment costs. Such reserves could decrease cash flow available for dividends to shareholders and to service our obligations under any applicable debt obligations.

To date, we have complied with the NEB requirements on our NEB-regulated pipelines (TMPL and Cochin) for the creation of abandonment trusts and has completed the compliance-based filings that are required under the applicable NEB rules and regulations regarding the abandonment of our NEB-regulated pipeline systems and assets. While we collect abandonment surcharges from our shippers and deposit such amounts in our abandonment trust for our NEB-regulated pipelines, there is a risk that abandonment costs and post-abandonment liabilities could exceed the amounts held in trust. Further, and unlike TMPL and Cochin, we do not maintain dedicated abandonment trusts for our Puget Sound, Jet Fuel or Terminals. Additional or unexpected expenditures incurred in respect of abandonment costs could decrease DCF available for dividends to shareholders and to service obligations under any applicable debt obligations.

Risks Relating to Regulation

New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.

New regulations, rulemaking and oversight, as well as changes in existing regulations, by regulatory agencies having jurisdiction over our operations could adversely impact our earnings, cash flows and operations. Our assets and operations are subject to regulation and oversight by federal, state, provincial and municipal regulatory authorities. Regulatory actions taken by these agencies have the potential to adversely affect our profitability and/or the profitability of our business. Regulation affects almost every part of our business and extends to such matters as (i) the certification and construction of expansion projects and new facilities; (ii) tariff rates, operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with customers; (v) the integrity, safety and security of facilities and operations; (vi) the acquisition of other businesses; (vii) the acquisition, extension, disposition or abandonment of services or facilities; (viii) reporting and information posting requirements; (ix) the maintenance of accounts and records; and (x) relationships with affiliated companies involved in various aspects of the oil and gas industry.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential revocation of permits, including with respect of TMEP. Furthermore, new laws or regulations sometimes arise from unexpected sources. New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to us or TMEP could have a material adverse impact on our business, financial condition and results of operations.

Environmental, health and safety laws and regulations could expose us to significant costs and liabilities.

Our business operations are subject to federal, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment (including with respect to climate change), natural resources and human health and safety. Such laws, regulations and obligations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals, including with respect to our expansion and new build projects. Liability under such laws and regulations may be incurred without regard to fault for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage.


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Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in operations that could influence our business, financial position, results of operations or prospects. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay government penalties, address natural resource damage, compensate for human exposure, property damage or economic loss, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our earnings and cash flows. In addition, emission controls required under provincial laws could require significant capital expenditures at our facilities.

We own and/or operate numerous properties and assets that have been used for many years in connection with our business activities. While we believe we have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties and assets have been owned and/or operated by third parties whose management, operation, handling and disposal of hydrocarbons or other hazardous substances were not under our or our predecessors’ control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws which impose joint and several liability, without regard to fault or the legality of the original conduct. In addition, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

We cannot ensure that existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to our business. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial position, results of operations and prospects. In addition to revised or additional regulations affecting our customers and/or shippers, including those related to the protection or preservation of the environment (including with respect to climate change), natural resources and human health or safety may have significant negative impacts on the business and operations of such customers and/or shippers that result in such customers and/or shippers defaulting on their contractual obligations (including with respect to take-or-pay obligations). We are exposed to the risk of loss in the event of non-performance by such customers and/or shippers, which could have a material adverse effect on us. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us” above.

An environmental incident could have lasting reputational impacts on us and could impact our ability to work with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance), environmental incidents may lead to an increased cost of operating and insuring our assets, thereby negatively impacting earnings and DCF. See Items 1 and 2 “Business and PropertiesRegulationCanadian RegulationClimate Change and GHG Regulations.”

Although we have OMS and EMP programs in place, there remains a chance that an environmental incident could occur. We have also invested significant resources to enhance our emergency response plans, operator training and landowner education programs to address potential environmental incidents. However, our mitigation efforts are incapable of guarding against all environmental risks, including in the event that there is significant damage to our assets as a result of catastrophic events (including natural disasters, other significant weather-related events or adverse sea conditions) or the actions of third parties acting outside of our control.

We maintain an insurance program which is renewed annually and has $1 billion worth of financial capacity for spill events in accordance with the Pipeline Safety Act (see Items 1 and 2 “Business and PropertiesRegulationCanadian Regulation”). The insurance program includes coverage for commercial liability that is considered customary for the industry in which we operate and includes coverage for operational and environmental incidents. However, our insurance program may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us. The total insurance coverage will be allocated on an equitable basis among the members of the Kinder Morgan Canada Group in the event multiple insurable incidents exceeding our coverage limits within the same insurance period are experienced.

Pipeline integrity laws and regulations may have a negative impact on us.

Increased regulatory requirements relating to the integrity of our pipelines may require it to incur significant capital and operating expenditures to comply. We are subject to extensive laws and regulations related to pipeline integrity. The ultimate costs

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of compliance with the integrity management rules are difficult to predict. The majority of compliance costs relate to pipeline integrity testing and repairs. Technological advances in in-line inspection tools and identification of additional threats to a pipeline’s integrity can have a significant impact on integrity testing and repair costs. We plan to continue our integrity testing programs in respect of our assets to assess and maintain the integrity of our existing and future pipelines as required by applicable laws, rules and regulations. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to provide for the continued safe and reliable operation of these pipelines.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts currently anticipated. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators or negotiated customer agreements to be fully recoverable from customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

Changes in tax laws and reassessments could adversely impact future DCF.

Income tax returns filed by entities forming part of our business remain subject to reassessment by applicable taxation authorities and it is possible that the taxation authorities could successfully challenge prior transactions and tax filings of such entities. In the event of a successful reassessment, we could be subject to higher than expected past or future income tax liability as well as, potentially, interest and/or penalties, which could result in a material reduction in DCF or cash available for dividends.

Income tax laws, including income tax laws applicable to the energy infrastructure industry, may in the future be changed or interpreted in a manner that adversely affects us. Furthermore, tax authorities having jurisdiction over us may disagree with how those entities calculate income for tax purposes or could change administrative practices to the detriment of those entities. A change in applicable tax laws, or the administrative interpretation thereof, in a manner adverse to us could result in a material reduction in DCF or cash available for dividends.

Changes in pipeline tariff rates may have a negative impact on our operating results.

Regulatory bodies having jurisdiction over us may establish pipeline tariff rates or requirements that could have a negative impact on our business. In addition, such regulatory bodies, or our customers could file complaints challenging the tariff rates charged by us, and a successful complaint could have an adverse impact on us. The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that those costs increase in an amount greater than what we are permitted by the regulators to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact upon our operating results.

Certain existing rates may also be challenged by complaint. Regulators and shippers on our pipelines have rights to challenge the rates that are charged under certain circumstances prescribed by applicable regulations. We may face challenges to the rates charged on our pipelines. Any successful challenge to our rates could materially adversely affect our future earnings, DCF and financial condition.

Risks Relating to Our Relationship with Kinder Morgan

Kinder Morgan’s shareholdings in the Company may give rise to conflicts of interest.

Kinder Morgan, indirectly through its wholly owned subsidiaries KMCC and KMCT, holds the controlling voting interest in us, including with respect to the right to vote for the election of directors to the board of directors. In addition, we are the sole shareholder of the General Partner and, as such, Kinder Morgan indirectly, through controlling the Company Voting Shares, has the ability to influence elections of the directors to the board of directors of the General Partner. In its capacity as general partner of the Limited Partnership, the General Partner is authorized to manage, administer and operate the business and affairs of the Limited Partnership, to make all decisions regarding the business of the Limited Partnership and to bind the Limited Partnership in respect of any such decisions, subject to certain limitations contained in the Limited Partnership Agreement. As a result of the foregoing, Kinder Morgan, indirectly through its controlling voting interest in us and corresponding ability to influence the elections of directors, has the ability to influence the management of our business. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” and “—Risks Relating to Ownership of Restricted Voting SharesThere are limitations on voting power of the holders of Restricted Voting Shares” below.


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Our relationship with Kinder Morgan, as our majority shareholder, does not impose any duty on Kinder Morgan or its affiliates to act in our best interest and, other than as set out in the Cooperation Agreement, Kinder Morgan is not prohibited from engaging in other business activities that may compete with us. Our ownership structure involves a number of relationships that may give rise to conflicts of interest between us and the holders of Restricted Voting Shares and our preferred shares, on the one hand, and Kinder Morgan, on the other hand. In certain instances, the interests of Kinder Morgan may differ from our interests and the interests of our shareholders, including with respect to future acquisitions or strategic decisions. It is possible that conflicts of interest may arise between us and Kinder Morgan, and that such conflicts may not be resolved in a manner that is in our best interests or in the best interests of our shareholders. Additionally, Kinder Morgan and its affiliates have access to material confidential information about us. Although some of these entities are subject to confidentiality obligations pursuant to confidentiality agreements or pursuant to duties of confidence or applicable codes of conduct, neither the Services Agreement nor the Cooperation Agreement contain general confidentiality provisions. See Item 13 “Certain Relationships and Related Transactions and Director Independence.

Future changes in our relationship with Kinder Morgan may negatively impact our business.

Our arrangements with Kinder Morgan do not require Kinder Morgan, either directly or indirectly, to maintain any ownership level in us or the Limited Partnership. Accordingly, Kinder Morgan may transfer all or a substantial portion of its interest in the Limited Partnership (together with the Special Voting Shares) to a third party, including in a merger or consolidation or sale of its Class B Units and Special Voting Shares, without our consent or the consent of our shareholders, but subject to compliance with applicable “coattail” provisions of the Limited Partnership Agreement and our articles, market conditions, Kinder Morgan’s requirements for capital or other circumstances that may arise in the future. The interests of a transferee of the Class B Units and Special Voting Shares may be different from Kinder Morgan’s and may not align with those of other shareholders. We cannot predict with any certainty the effect that any such transfer would have on the trading price of the Restricted Voting Shares or our ability to raise capital in the future. As a result, our future would be uncertain and our business and financial condition may suffer.

Risks Relating to Ownership of Restricted Voting Shares and Preferred Shares

There are limitations on voting power of the holders of Restricted Voting Shares.

Each Restricted Voting Share and each Special Voting Share entitles the holder thereof to one vote per share held at all meetings of our shareholders, except meetings at which or in respect of matters on which only the holders of another class of shares are entitled to vote separately as a class pursuant to applicable laws. Unless otherwise required by law, the holders of Restricted Voting Shares and Special Voting Shares vote together as a single class. Holders of Restricted Voting Shares are entitled to approximately 30% of the votes held by all our shareholders and Kinder Morgan, the indirect holder of the Special Voting Shares, is entitled to approximately 70% of the votes held by all our shareholders.

As a result, Kinder Morgan has a controlling interest in the combined voting power of the Company Voting Shares, including with respect to the election of the board of directors. This level of ownership of Special Voting Shares indirectly by Kinder Morgan will limit the ability of holders of the Restricted Voting Shares to influence corporate and partnership matters for the foreseeable future, including the election of directors (both with respect to the Company and the General Partner) as well as with respect to decisions regarding the amendment of our share capital or the Limited Partnership Agreement, creating and issuing additional Company Voting Shares or classes of shares or limited partnership units, making significant acquisitions, selling significant assets or parts of our business, merging with other companies, significant joint ventures, the payment or non-payment of dividends or limited partnership distributions and undertaking other significant transactions. The market price of the Restricted Voting Shares could be adversely affected due to the significant voting power of Kinder Morgan. Additionally, the significant voting interest of Kinder Morgan may discourage transactions involving a change of control, including transactions in which a holder of the Restricted Voting Shares might otherwise receive a premium for their Restricted Voting Shares over the then-current market price, or discourage competing proposals if a going private transaction is proposed or undertaken by Kinder Morgan. See Item 13 “Certain Relationships and Related Transactions and Director Independence.

Additional sales of Restricted Voting Shares will dilute a holder’s ownership in us, and issuances of our senior securities or senior securities of the Limited Partnership may impact the rights of the Restricted Voting Shares and their trading price.

Subject to the provisions of the Limited Partnership Agreement, Kinder Morgan may sell its Special Voting Shares (together with the accompanying Class B Units in the Limited Partnership) from time to time and is not required to consider the potential negative impact of such sales on the trading price of the Restricted Voting Shares or on us in general.

The board of directors may issue an unlimited number of Restricted Voting Shares (or Special Voting Shares to the extent the General Partner issues additional Class B Units of the Limited Partnership) without any vote or action by the shareholders,

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subject to the rules of any stock exchange on which our securities may be listed from time to time. We may make future acquisitions or enter into financings or other transactions involving the issuance of our securities.

Our Series 1 Preferred Shares and Series 3 Preferred Shares are and,if issued, the Series 2 Preferred Shares and Series 4 Preferred Shares will be, senior to the Restricted Voting Shares with respect to priority in payment of dividends and the distribution of assets in the event of liquidation. Additionally, we are authorized to issue an unlimited number of preferred shares and may issue additional preferred shares in the future. Any such additional preferred shares will be entitled to preference over the Restricted Voting Shares with respect to priority in payment of dividends and the distribution of assets in the event of the liquidation, dissolution or winding up of the Company. The rights of the holders of Restricted Voting Shares will be subject to, and may be adversely affected by, the rights of the holders of any preferred shares that may be issued in the future. The issuance of preferred shares could delay, deter or prevent certain transactions and could adversely affect the voting power or economic value of the Restricted Voting Shares. Further, if we issue any additional equity or voting shares, the percentage ownership or voting power, as applicable, of existing shareholders will be reduced and diluted, which reduction and dilution may be significant, and the price of the Restricted Voting Shares could decline.

Similarly, the Limited Partnership Agreement authorizes the General Partner to cause the Limited Partnership to issue additional LP Units as well as any other type of security, including Preferred LP Units, that it determines to be necessary or advisable. Like us, the Limited Partnership may make future acquisitions or enter into financings or other transactions involving the issuance of its securities, including LP Units or preferred units. In the event that the Limited Partnership were to issue additional Preferred LP Units, the rights associated with the Class A Units held indirectly by us will be subject to, and may be adversely affected by, the rights associated with such Preferred LP Units. Additionally, an issuance of additional securities by the Limited Partnership, including Preferred LP Units, may dilute our interest in the Limited Partnership and/or reduce the amounts available for distribution by the Limited Partnership to us as an indirect holder of Class A Units. See “—Cash dividend payments are not guaranteed” below.

We are currently undertaking significant projects, including TMEP, which will require considerable amounts of capital. The Credit Facility requires that we maintain an overall balance of debt and equity capital of 70% and 30%, and with respect to capital expenditures on TMEP, a balance of debt and equity capital of 60% and 40%. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources and Note 9 “Debt” to our consolidated financial statements. We expect to issue additional equity over the course of TMEP in order to comply with these requirements under the Credit Facility.

In the event that we are unable to access debt or other external financing sources to fund the completion of such projects or such projects experience significant cost increases and/or cost overruns or delays, we may be required to issue additional equity or voting shares, or the Limited Partnership may be required to issue additional units, to raise funds that are required for us to continue operating or complete our projects. Additionally, if TMEP is over budget and/or delayed and the value of our business becomes depressed, issuances of our securities, including preferred shares, or issuances of securities of the Limited Partnership, including preferred units, to fund TMEP, could be pursued at prices reflecting such depressed value, increasing the dilutive impact on the existing Restricted Voting Shares and/or our indirect interest in the Limited Partnership. See also “—Risks Relating to Our BusinessWe will require access to external capital” above.

Cash dividend payments are not guaranteed.

The payment of dividends is not guaranteed under our dividend policy or under the terms of our Preferred Shares, and amounts of such dividends could fluctuate with the performance of our business. Additionally, the Series 1 Preferred Shares and Series 3 Preferred Shares are and, if and when issued, the Series 2 Preferred Shares and Series 4 Preferred Shares, and any preferred shares issued by us in the future may be, senior to the Restricted Voting Shares with respect to priority in payment of dividends and the distribution of assets in the event of liquidation. The terms of the Series 1 Preferred Shares, Series 2 Preferred Shares, Series 3 Preferred Shares and Series 4 Preferred Shares prohibit us from declaring or paying dividends on the Restricted Voting Shares unless all dividends on then outstanding preferred shares of the Company have been paid.

The board of directors has the discretion to determine the amount of dividends, if any, to be declared and paid to shareholders. The board of directors may alter our dividend policy at any time, and the payment of dividends may be affected by, among other things, changes in: commodity prices; the financial condition of our business; current and expected future levels of earnings; capital and liquidity requirements; market opportunities; income taxes; debt repayments; legal and regulatory requirements, including the solvency requirements of the Business Corporations Act (Alberta) and the regulations thereunder, as amended from time to time (“ABCA”); contractual constraints; tax laws; and other relevant factors (including TMEP being over budget, delayed or stopped). There can be no guarantee as to the amount of distributions from the Limited Partnership and any

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number of factors could cause the General Partner to revise its policies and/or strategies respecting distributions. Certain terms of the Credit Facility also restrict our ability to pay dividends or the ability of the Limited Partnership to pay distributions.

Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether we pay dividends and the amount of dividends, if any, we may pay in the future. If we experience a significant downturn, the currently anticipated level of distributions by the Limited Partnership (and funding for Company dividends) could leave us with insufficient cash to finance growth opportunities, meet any large unanticipated liquidity requirements or fund our activities. The board of directors may amend, revoke or suspend our dividend policy or elect not to declare Preferred Share dividends, or both, in response to such circumstances or for other reasons. A decline in the market price or liquidity, or both, of the Restricted Voting Shares or our Preferred Shares could result if we reduce or eliminate the payment of dividends, which could result in losses to shareholders.

There can be volatility in the market price of Restricted Voting Shares.

The market price for Restricted Voting Shares may be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond our control, including the following: (i) delays or difficulties experienced during construction or the completion of TMEP or the total stoppage of TMEP; (ii) anticipated fluctuations in our financial results; (iii) recommendations by securities research analysts; (iv) changes in the economic performance or market valuations of other companies that investors deem comparable to us or Kinder Morgan; (v) the loss or resignation of directors, officers and other key personnel of the Company; (vi) sales or anticipated sales of additional Restricted Voting Shares; (vii) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by or involving us or our competitors where we do not realize the anticipated benefits from such transaction; (viii) trends, concerns, technological or competitive developments, regulatory changes and other related issues in the energy infrastructure industry; and (ix) actual or anticipated fluctuations in interest rates.

Financial markets have experienced significant price and volume fluctuations in recent years that have particularly affected the market prices of equity securities of companies and that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of the Restricted Voting Shares may decline even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values which may result in impairment losses. Certain institutional investors may base their investment decisions on consideration of our environmental, governance and social practices and performance against such institutions’ respective investment guidelines and criteria, and failure to meet such criteria may result in a limited or no investment in the Restricted Voting Shares by those institutions, which could adversely affect the trading price of the Restricted Voting Shares.

Non-Canadian holders of Restricted Voting Shares face foreign exchange risk on dividends.

Our cash dividends will be declared in Canadian dollars. As a consequence, non-resident shareholders, and shareholders who calculate their return in currencies other than the Canadian dollar, will be subject to foreign exchange risk. To the extent that the Canadian dollar strengthens with respect to their currency, the amount of the dividend will be reduced when converted to their home currency.

Item 1B.  Unresolved Staff Comments.
 
None.

Item 3.  Legal Proceedings.
 
See Note 19 “Litigation, Commitments and Contingencies” to our consolidated financial statements.

Item 4.  Mine Safety Disclosures.

Not applicable.


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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Restricted Voting Shares

Our Restricted Voting Shares are listed on the TSX under the symbol “KML.” The following table sets forth, for the periods indicated, the high and low closing prices of our Restricted Voting Shares on the TSX since our IPO as reported by the TSX:
Period
Price Range
 
Declared Cash Dividend(a)
(In Canadian dollars)
Low
 
High
 
May 25, 2017 (initial listing) - June 30, 2017 (b)
15.41
 
 
16.72
 
 
0.0571
July 1, 2017 - September 30, 2017
15.44
 
 
18.35
 
 
0.1625
October 1, 2017 - December 31, 2017
15.74
 
 
17.62
 
 
0.1625
________
(a)
Dividend information is for dividends declared with respect to that quarter.  Generally, our declared dividends on our Restricted Voting Shares are paid on or about the 15th day of each February, May, August and November. 
(b)
Dividend was for the period May 30, 2017 to June 30, 2017.

Preferred Share Issuances

During 2017, we issued an aggregate of 22 million preferred shares for gross proceeds of $550 million that are listed on the TSX with the following characteristics:
Description
Gross Proceeds
Annual Dividend Per Share
Initial Yield
Per Share Base Redemption Value
Redemption and Conversion
Right to Convert into
(In millions of Canadian dollars, except per share amounts)

Series 1 Preferred Shares
300

1.3125

5.25
%
25.00

November 15, 2022
Series 2
Series 3 Preferred Shares
250

1.30

5.20
%
25.00

February 15, 2023
Series 4

As of February 16, 2018, there were 12,000,000 and 10,000,000 Series 1 Preferred Shares and Series 3 Preferred Shares outstanding, respectively. See —Ownership InterestsPreferred Shares” below.

Dividends

The terms of the Preferred Shares prohibit us from declaring or paying dividends on the Restricted Voting Shares unless all dividends on the Preferred Shares have been paid. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of OperationsDividends and Distributions.”

The Credit Facility restricts us from paying dividends until the completion of TMEP unless the following three conditions have been satisfied: (i) the dividend payment would not result in aggregate distributions in any period of four consecutive fiscal quarters exceeding Distributable Cash (as defined in the Credit Facility) for such period; (ii) the delivery of a certification by an authorized officer that the Company is in compliance with certain enumerated financial metrics, including maximum debt and minimum equity requirements, equity financing to sufficiently cover project costs for a six month period and the forecasted distributions included in the calculation of net forecasted retained cash flow; and (iii) no default has occurred under the Credit Facility. Following the completion of TMEP, we may pay quarterly dividends provided that no default has occurred under the Credit Facility. See Note 9 “Debt” to the consolidated financial statements and Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesCredit Facility

The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of the board of directors.


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Related Stockholder Matters

As of February 16, 2018, there were 103,661,302 Restricted Voting Shares, 243,455,654 Special Voting Shares, 12,000,000 Series 1 Preferred Shares and 10,000,000 Series 3 Preferred Shares outstanding, and there was one holder of record of our Restricted Voting Shares, two holders of record of our Special Voting Shares, one holder of record of our Series 1 Preferred Shares and one holder of record of our Series 3 Preferred Shares. These holders of record do not include beneficial owners whose shares are held by a nominee, such as a broker or bank.
 
Also, see Preferred Share, Restricted Voting Share, and Special Voting Share dividends and distributions for and during 2017 in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of OperationsDividends and Distributions.”

Tax Matters Applicable to Ownership of Restricted Voting Shares
 
Holders Resident in the U.S.
 
The following discussion is applicable to a holder of Restricted Voting Shares who, for the purposes of the Canadian Income Tax Act (the “Tax Act”) and the Canada-United States Tax Convention (1980), as amended (the “Treaty”), at all relevant times, is not resident or deemed to be resident in Canada, is a resident of the United States for the purposes of the Treaty and qualifies for the full benefits thereunder, and who does not use or hold (and is not deemed to use or hold) the Restricted Voting Shares in connection with a business carried on in Canada (a “U.S. Resident Holder”). This discussion is not applicable to a U.S. Resident Holder that is an insurer that carries on an insurance business in Canada.
 
This discussion is not applicable to a U.S. Resident Holder whose Restricted Voting Shares are or are deemed to be “taxable Canadian property” for purposes of the Tax Act. Provided that the Restricted Voting Shares are listed on a designated stock exchange (which includes the TSX) at a particular time, the Restricted Voting Shares generally will not constitute taxable Canadian property to a U.S. Resident Holder at that time unless, at any time during the five year period immediately preceding that time: (i) 25% or more of the issued shares of any class or series of the Company’s capital stock were owned by any combination of (a) the U.S. Resident Holder, (b) persons with whom the U.S. Resident Holder did not deal at arm’s length, and (c) partnerships in which the U.S. Resident Holder or a person described in (b) holds a membership interest directly or indirectly through one or more partnerships; and (ii) more than 50% of the value of the Restricted Voting Shares was derived, directly or indirectly, from one or any combination of (a) real or immoveable property situated in Canada, (b) Canadian resource properties, (c) timber resource properties, and (d) options in respect of, or an interest in, any such property (whether or not the property exists), all for purposes of the Tax Act. A U.S. Resident Holder’s Restricted Voting Shares can also be deemed to be taxable Canadian property in certain circumstances set out in the Tax Act.
 
Taxation of Dividends
 
Dividends paid or credited or deemed to be paid or credited by the Company to a non-resident of Canada will generally be subject to Canadian withholding tax at the rate of 25%, subject to any applicable reduction in the rate of such withholding under an income tax treaty between Canada and the country where the holder is resident. Under the Treaty, the withholding tax rate in respect of a dividend paid to a U.S. Resident Holder that beneficially owns such dividends is generally reduced to 15%, unless the U.S. Resident Holder is a company which owns at least 10% of the voting shares of the Company at that time, in which case the withholding tax rate is reduced to 5%.
 
Disposition of Restricted Voting Shares
 
A U.S. Resident Holder will not be subject to tax under the Tax Act in respect of any capital gain realized on the disposition of Restricted Voting Shares.

Recent Sales of Unregistered Securities

Since our incorporation on April 7, 2017, we have issued the following securities in offerings registered under the Securities Act:
 
On May 25, 2017, we consummated our IPO and sold 102,942,000 Restricted Voting Shares to the public in Canada for gross proceeds of $1,750,014,000 through TD Securities Inc. and RBC Dominion Securities Inc., as principal underwriters. The Restricted Voting Shares were sold in Canada in accordance with applicable Canadian securities laws and in the United States to qualified institutional buyers in reliance on Rule 144A under the Securities Act. The proceeds of our IPO were used to purchase

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our indirect ownership interest in the Operating Entities. In connection with our IPO, 226,616,700 Special Voting Shares were issued to KMCC and KMCT. See Items 1 and 2 “Business and PropertiesOur Reorganization and IPO.

On August 15, 2017, we completed an offering of 12,000,000 Series 1 Preferred Shares to the public on the TSX in Canada at a price of $25.00 per Series 1 Preferred Share for total gross proceeds of $300 million.  On December 15, 2017, we completed an offering of 10,000,000 Series 3 Preferred Shares to the public on the TSX at a price of $25.00 per Series 3 Preferred Share for total gross proceeds of $250 million. SeeOwnership Interests—Preferred Shares” and “—Ownership InterestsLimited Partnership Units” below.

Ownership Interests

The following description of our capital stock is a summary only and is qualified in its entirety by reference to our Articles and By-laws, each as amended, and to the Limited Partnership Agreement, which are included as Exhibits 3.2, 3.4, 3.6 and 3.8 hereof, respectively.

We are authorized to issue an unlimited number of Restricted Voting Shares, an unlimited number of Special Voting Shares and an unlimited number of preferred shares issuable in series. As of February 16, 2018, we had outstanding 103,661,302 Restricted Voting Shares, 243,455,654 Special Voting Shares, 12,000,000 Series 1 Preferred Shares and 10,000,000 Series 3 Preferred Shares.

Restricted Voting Shares

Holders of Restricted Voting Shares are entitled to one vote for each Restricted Voting Share held at all meetings of our shareholders, except meetings at which or in respect of matters on which only holders of another class of shares are entitled to vote separately as a class. Except as otherwise provided by our Articles or required by law, the holders of Restricted Voting Shares will vote together with the holders of Special Voting Shares as a single class.

The holders of Restricted Voting Shares are entitled to receive, subject to the rights of the holders of another class of shares, any dividend we declare, and the remaining property of the Company upon the liquidation, dissolution or winding-up of the Company, whether voluntary or involuntary. Notwithstanding the foregoing, we may not issue or distribute to all or to substantially all of the holders of the Restricted Voting Shares either (i) Restricted Voting Shares, or (ii) rights or securities of the Company exchangeable for or convertible into or exercisable to acquire Restricted Voting Shares, unless contemporaneously therewith, we issue or distribute Special Voting Shares or rights or securities of the Company exchangeable for or convertible into or exercisable to acquire Special Voting Shares on substantially similar terms (having regard to the specific attributes of the Special Voting Shares) and in the same proportion.

None of the Restricted Voting Shares will be subdivided, consolidated, reclassified or otherwise changed unless contemporaneously therewith the Special Voting Shares are subdivided, consolidated, reclassified or otherwise changed in the same proportion or same manner (having regard to the specific attributes of the classes of securities comprising the Company Voting Shares). In addition, under the Cooperation Agreement, we will make equivalent changes to the Restricted Voting Shares in the event any adjustments are made to the LP Units, in order to preserve the general alignment of the LP Units and the Company Voting Shares. See “—Special Voting Shares” below and Item 13 “Certain Relationships and Related Transactions and Director IndependenceAgreements between the Company and Kinder MorganCooperation Agreement.

We may not modify or remove any of the rights, privileges, conditions or restrictions of the Restricted Voting Shares without the approval by special resolution of the holders of Restricted Voting Shares.

Special Voting Shares

All of the outstanding Special Voting Shares were issued to, and are held by Kinder Morgan, indirectly through KMCC and KMCT, for the purpose of providing voting rights with respect to the Company. Under our Articles, we are prohibited from issuing any Special Voting Shares unless a corresponding number of associated Class B Units are concurrently issued by the Limited Partnership. In addition, holders of Special Voting Shares are prohibited from transferring their Special Voting Shares separately from the related Class B Units except for certain permitted transfers among affiliates.

Holders of Special Voting Shares are entitled to one vote for each Special Voting Share held at all meetings of shareholders of the Company, except meetings at which or in respect of matters on which only holders of another class of shares are entitled to vote separately as a class. Except as otherwise provided by our Articles or required by law, the holders of Special Voting Shares will vote together with the holders of Restricted Voting Shares as a single class.

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The holders of Special Voting Shares are entitled to receive, subject to the rights of the holders of preferred shares and in priority to the holders of Restricted Voting Shares, an amount per Special Voting Share equal to $0.000001 on the liquidation, dissolution or winding up of the Company, whether voluntary or involuntary.

The holders of Special Voting Shares, as such, are not entitled to receive any dividends or other distributions except for such dividends payable in Special Voting Shares, as may be declared by the board of directors from time to time. Notwithstanding the foregoing, we may not issue or distribute to all or to substantially all of the holders of the Special Voting Shares either (i) Special Voting Shares, or (ii) rights or securities of the Company exchangeable for or convertible into or exercisable to acquire Special Voting Shares, unless contemporaneously therewith, we issue or distribute Restricted Voting Shares, or rights or securities of the Company exchangeable for or convertible into or exercisable to acquire Restricted Voting Shares on substantially similar terms (having regard to the specific attributes of the Restricted Voting Shares) and in the same proportion.

The Special Voting Shares are subject to anti-dilution provisions, which provide that adjustments will be made to the Special Voting Shares in the event of a change to the Restricted Voting Shares in order to preserve the voting equivalency of such shares. In addition, pursuant to the Cooperation Agreement, we will make equivalent changes to the Special Voting Shares in the event of any adjustments made to the LP Units, in order to preserve the general alignment of the LP Units and the Company Voting Shares. See “Certain Relationships and Related Transactions and Director IndependenceAgreements between the Company and Kinder Morgan—Cooperation Agreement.” The Special Voting Shares are also subject to “coattail” provisions which restrict the transfer of Special Voting Shares in certain circumstances. See “—Takeover Bid Protection - Coattail Arrangements” below.

We may not modify or remove any of the rights, privileges, conditions or restrictions of the Special Voting Shares without the approval by special resolution of the holders of Special Voting Shares.

Preferred Shares

We are authorized to issue an unlimited number of preferred shares and we may issue preferred shares in one or more series with such terms as the board of directors may fix, subject to the ABCA. Any such additional preferred shares shall, rank on a parity with the preferred shares of every other series and shall be entitled to preference over the Restricted Voting Shares and the Special Voting Shares, in each case with respect to priority in payment of dividends and the distribution of assets in the event of the liquidation, dissolution or winding up of the Company.

Series 1 Preferred Shares

On August 15, 2017, we issued 12,000,000 Series 1 Preferred Shares at a price of $25.00 per share. The holders of Series 1 Preferred Shares are entitled to receive dividends at an annual rate of $1.3125 per share, payable quarterly, up to but excluding November 15, 2022. as and when declared by our board of directors. For each five-year period following November 15, 2022, the holders of Series 1 Preferred Shares shall be entitled to receive dividends, as and when declared, in the amount per share determined by multiplying one-quarter of the “Annual Fixed Dividend Rate” by $25.00. The Annual Fixed Dividend Rate for the applicable period will be equal to the sum of the Government of Canada Yield (as defined herein) on such date plus 3.65%, provided that, in any event, such rate shall not be less than 5.25%. This spread will remain unchanged over the life of the Series 1 Preferred Shares.

The Series 1 Preferred Shares are not entitled to vote or attend meetings of the holders of Voting Shares (except as otherwise provided by law and except for meetings of the holders of Preferred Shares as a class and meetings of the holders of Series 1 Preferred Shares as a series) unless dividends on the Series 1 Preferred Shares have not been paid for eight quarters, whether or not consecutive, whether or not such dividends have been declared and whether or not we have sufficient cash properly applicable to the payment of such dividends. Until all such arrears of dividends have been paid, holders of Series 1 Preferred Shares will be entitled to one vote per Series 1 Preferred Share with respect to resolutions to elect directors.

The Series 1 Preferred Shares are not redeemable prior to November 15, 2022. Subject to certain conditions, on November 15, 2022, and on November 15 in every fifth year thereafter, we may, at our option, upon not less than 30 days and not more than 60 days prior written notice, redeem for cash all or any part of the outstanding Series 1 Preferred Shares by the payment of $25.00 per Series 1 Preferred Share plus all accrued and unpaid dividends.

Prior to November 15, 2022, the Series 1 Preferred Shares are not convertible. The holders of the Series 1 Preferred Shares will have the right to convert all or any of their Series 1 Preferred Shares into Series 2 Preferred Shares, subject to certain conditions, on November 15, 2022 and on November 15 in every fifth year thereafter. Other than redemption rights and dividends, the Series 2 Preferred Shares are identical to the Series 1 Preferred Shares.

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The holders of the Series 2 Preferred Shares will be entitled to receive, as and when declared by the board of directors of the Company, quarterly cash dividends calculated using a floating rate of interest. Holders of Series 2 Preferred Shares have the right to convert their Series 2 Preferred Shares back into Series 1 Preferred Shares under certain circumstances.

In the event of the liquidation, dissolution or winding-up of the Company, the holders of the Series 1 Preferred Shares and Series 2 Preferred Shares are entitled to receive $25.00 per share plus all accrued and unpaid dividends thereon before any amount is paid or any property or assets of the Company are distributed to the holders of the Restricted Voting Shares, Special Voting Shares or to the holders of any other shares ranking junior to the Series 1 Preferred Shares or Series 2 Preferred Shares in any respect.

The terms of the Series 1 Preferred Shares and the Series 2 Preferred Shares prohibit the Company from declaring or paying dividends on the Restricted Voting Shares unless all dividends on the Series 1 Preferred Shares and the Series 2 Preferred Shares have been paid.

Series 3 Preferred Shares

On December 15, 2017, we issued 10,000,000 Series 3 Preferred Shares at a price of $25.00 per share. The holders of Series 3 Preferred Shares are entitled to receive dividends at an annual rate of $1.3000 per share, payable quarterly, up to but excluding February 15, 2023 as and when declared by our board of directors. For each five-year period following February 15, 2023, the holders of Series 3 Preferred Shares shall be entitled to receive dividends, as and when declared, in the amount per share determined by multiplying one-quarter of the “Annual Fixed Dividend Rate” by $25.00. The Annual Fixed Dividend Rate for the applicable period will be equal to the sum of the Government of Canada Yield (as defined herein) on such date plus 3.51%, provided that, in any event, such rate shall not be less than 5.20%. This spread will remain unchanged over the life of the Series 3 Preferred Shares.

The Series 3 Preferred Shares are not entitled to vote or attend meetings of the holders of Voting Shares (except as otherwise provided by law and except for meetings of the holders of Preferred Shares as a class and meetings of the holders of Series 3 Preferred Shares as a series) unless dividends on the Series 3 Preferred Shares have not been paid for eight quarters, whether or not consecutive, whether or not such dividends have been declared and whether or not we have sufficient cash properly applicable to the payment of such dividends. Until all such arrears of dividends have been paid, holders of Series 3 Preferred Shares will be entitled to one vote per Series 3 Preferred Share with respect to resolutions to elect directors.

The Series 3 Preferred Shares are not redeemable prior to February 15, 2023. Subject to certain conditions, on February 15, 2023, and on February 15 in every fifth year thereafter, we may, at our option, upon not less than 30 days and not more than 60 days prior written notice, redeem for cash all or any part of the outstanding Series 3 Preferred Shares by the payment of $25.00 per Series 3 Preferred Share plus all accrued and unpaid dividends.

Prior to February 15, 2023, the Series 3 Preferred Shares are not convertible. The holders of the Series 3 Preferred Shares will have the right to convert all or any of their Series 3 Preferred Shares into Series 4 Preferred Shares, subject to certain conditions, on February 15, 2023 and on February 15 in every fifth year thereafter. Other than redemption rights and dividends, the Series 4 Preferred Shares are identical to the Series 3 Preferred Shares.

The holders of the Series 4 Preferred Shares will be entitled to receive, as and when declared by the board of directors of the Company, quarterly cash dividends calculated using a floating rate of interest. Holders of Series 4 Preferred Shares have the right to convert their Series 4 Preferred Shares back into Series 3 Preferred Shares under certain circumstances.

In the event of the liquidation, dissolution or winding-up of the Company, the holders of the Series 3 Preferred Shares and Series 4 Preferred Shares are entitled to receive $25.00 per share plus all accrued and unpaid dividends thereon before any amount is paid or any property or assets of the Company are distributed to the holders of the Restricted Voting Shares, Special Voting Shares or to the holders of any other shares ranking junior to the Series 3 Preferred Shares or Series 4 Preferred Shares in any respect.

The terms of the Series 3 Preferred Shares and the Series 4 Preferred Shares prohibit the Company from declaring or paying dividends on the Restricted Voting Shares unless all dividends on the Series 3 Preferred Shares and the Series 4 Preferred Shares have been paid.


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Limited Partnership Units
The Limited Partnership is a limited partnership existing under the laws of the Province of Alberta and holds our business and engages in such activities from time to time as the General Partner may, in its discretion, determine.

As of February 16, 2018, the Limited Partnership had issued and outstanding two GP Units held by the General Partner, 103,661,302 Class A Units held by the Company (indirectly through the General Partner) representing an approximate 30% interest in the Limited Partnership, 243,455,654 Class B Units held by Kinder Morgan (indirectly through KMCC and KMCT) representing an approximate 70% interest in the Limited Partnership and 22,000,000 Preferred LP Units held by the General Partner.

The GP Units, Class A Units, Class B Units and Preferred LP Units are entitled to participate in distributions of the Limited Partnership on the terms set out in the Limited Partnership Agreement. See" — Distributions" below. In certain circumstances, the General Partner may be required to make changes to the attributes of the LP Units to maintain the equivalency among the Related Securities in the manner contemplated by the Limited Partnership Agreement and the Cooperation Agreement. See Item 13 “Certain Relationships and Related Transactions and Director Independence—Agreements Between the Company and Kinder Morgan—Cooperation Agreement.

Each of the Class B Units is accompanied by a Special Voting Share, which entitles the holder of such Special Voting Share to receive notice of, to attend and to vote at meetings of our shareholders. Under our Articles and the Limited Partnership Agreement, as applicable, the transfer of the Special Voting Shares separately from the Class B Units to which they relate, as well as the transfer of Class B Units separately from the related Special Voting Shares, is prohibited except for certain permitted transfers among affiliates. See “—Special Voting Shares” above.

Distributions

Under the Limited Partnership Agreement, the Limited Partnership may make distributions to (i) the Company, indirectly through the General Partner, and (ii) Kinder Morgan, indirectly through KMCC and KMCT, on a quarterly basis, and on or before any scheduled date for payment by the Company of any declared dividends. The Company will be entirely dependent on indirectly receiving distributions from the Limited Partnership in order to pay any dividends on the Restricted Voting Shares and any then outstanding preferred shares of the Company, which dividends shall in any event be declared only at the discretion of the board of directors.

Distributions by the Limited Partnership are not guaranteed and will be at the discretion of the General Partner. The General Partner will, in its sole discretion, determine the amount of the distribution from the Limited Partnership. See Item 1A “Risk FactorsRisks Relating to Ownership of Restricted Voting SharesCash dividend payments are not guaranteed.

The Limited Partnership will make its distributions in the following order and priority: (i) the reimbursement of costs and expenses to the General Partner pursuant to the Limited Partnership Agreement; (ii) an amount to the holders of GP Units (being the General Partner) sufficient to allow the Company to pay its expenses (including, without limitation, any fees or commissions payable to agents or underwriters in connection with the sale of securities by the Company, listing fees of applicable stock exchanges and fees of the Company’s counsel and auditors) on a timely basis (the “Priority Distribution”); (iii) an amount to the holders of Preferred LP Units in accordance with the terms of the Preferred LP Units; (iv) an amount to the General Partner equal to 0.001% of the balance of the distributable cash of the Limited Partnership; and (v) an amount equal to the remaining distribution to the holders of Class A Units and the holders of Class B Units in accordance with their respective holdings of Class A Units and Class B Units. The General Partner may, in addition to the distributions described above, make a distribution in cash or other property to holders of GP Units or LP Units, provided that such distribution is paid or distributed to the holders of LP Units in accordance with their pro rata entitlements as holders of LP Units.

A holder of Class B Units has the right to elect to reinvest all distributions payable on its Class B Units in Class B Units on the same economic terms as a holder of Restricted Voting Shares that participates in the DRIP. See “—Dividend Reinvestment Plan” below. If a holder of Class B Units elects to reinvest its distributions, such distributions will be used to purchase additional Class B Units at the same price per unit as Restricted Voting Shares are issued by the Company under the DRIP (generally being the weighted average trading price of the Restricted Voting Shares on the TSX for the five trading days preceding the dividend payment date) at a discount of between 0% and 5%, as determined from time to time by the board of directors of the General Partner, in its sole discretion. The market discount is currently set at 3%. Pursuant to the terms of the DRIP and pursuant to the Limited Partnership Agreement, the Company and the Limited Partnership may concurrently suspend the DRIP and the distribution reinvestment plan, respectively, at their discretion. Kinder Morgan currently participates in the distribution reinvestment plan at a rate of 25%.


45


Allocation of Net Income and Losses

The net income of the Limited Partnership, determined in accordance with the provisions of the Income Tax Act (Canada) and the regulations thereunder, as amended from time to time, is generally allocated in respect of each fiscal year in the following manner: (i) first, to the General Partner in an amount equal to (a) the Priority Distribution, and (b) the aggregate of reimbursement of costs and expenses to the General Partner pursuant to the Limited Partnership Agreement and the distributions paid on the GP Units; (ii) second, to holders of Preferred LP Units based on their proportionate share of distributions on the Preferred LP Units received or receivable for such fiscal year; and (iii) the balance, among the holders of Class A Units and Class B Units based on their proportionate share of distributions received or receivable for such fiscal year. The amount of income for tax purposes allocated to a partner may be more or less than the amount of cash distributed by the Limited Partnership to that partner. Income and loss of the Limited Partnership for accounting purposes is allocated to each partner in the same proportion as income or loss is allocated for tax purposes.

If, with respect to a given fiscal year, no distribution is paid or payable or allocated to the partners, or the Limited Partnership has a loss for tax purposes, the taxable income or loss, as the case may be, for tax purposes of the Limited Partnership for that fiscal year will be allocated to the holders of LP Units in that fiscal year in the proportion to the percentage of LP Units held by each holder of LP Units at each of those dates. The fiscal year end of the Limited Partnership will initially be December 31.

Functions and Powers of the General Partner

In its capacity as general partner of the Limited Partnership, the General Partner is authorized to manage, administer and operate the business and affairs of the Limited Partnership, to make all decisions regarding the business and affairs of the Limited Partnership and to bind the Limited Partnership in respect of any such decisions, subject to certain limitations contained in the Limited Partnership Agreement. The General Partner is required to exercise its powers and discharge its duties honestly, in good faith with a view to the best interests of the Limited Partnership and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. The board of directors of the General Partner is the same as the board of directors of the Company. Similarly, the executive officers of the General Partner are the same as the executive officers of the Company.

The authority and power vested in the General Partner to manage the business and affairs of the Limited Partnership includes all authority to do any act, take any proceeding, make any decision and execute and deliver any instrument, deed, agreement or document necessary or incidental to carrying out the objects, purposes and business of the Limited Partnership, including, without limitation, the ability to engage other persons to assist the General Partner to carry out its management obligations and administrative functions in respect of the Limited Partnership and its business. Pursuant to the terms of the Services Agreement, the General Partner has contracted with KMCI for certain services relating to the operation of the Operating Entities. See Item 13 “Certain Relationships and Related Transactions, and Director Independence—Agreements between the Company and Kinder Morgan—Services Agreement.”

Restrictions on the Authority of the General Partner

The authority of the General Partner, as general partner, is limited in certain respects under the Limited Partnership Agreement. Certain matters must be approved by special resolution of the holders of Class A Units (all of which is held indirectly by the Company and voted in accordance with the instructions of the Company), including (i) the removal of the general partner, (ii) the dissolution, termination, wind up or other discontinuance of the Limited Partnership, (iii) the sale, exchange or other disposition of all or substantially all of the business or assets of the Limited Partnership, (iv) amendments to the Limited Partnership Agreement, and (v) a merger or consolidation involving the Limited Partnership. Certain other matters must be approved by special resolution of the holders of the Class A Units and Class B Units voting together as a class, including (i) a consolidation, subdivision or reclassification of LP Units (except for the purposes of preserving the alignment of the LP Units and the Company Voting Shares pursuant to the Limited Partnership Agreement and the Cooperation Agreement), and (ii) a waiver of a default by the general partner or release of the general partner from any claims in respect thereof.

Transfer of Partnership Units

No limited partner may transfer any of the LP Units owned by it except to persons and in the manner expressly permitted in the Limited Partnership Agreement. LP Units may not be transferred to a person who is not an Eligible Person (as defined in the Limited Partnership Agreement). In addition, the Class B Units are subject to “coattail” provisions which restrict the transfer of Class B Units in certain circumstances. See “—Takeover Bid Protection - Coattail Arrangements” below.


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The General Partner

The authorized capital of the General Partner consists of an unlimited number of common shares and an unlimited number of preferred shares issuable in series. The Company holds all of the issued and outstanding common shares of the General Partner. Pursuant to the Cooperation Agreement, the board of directors of the General Partner is the same as the board of directors. Similarly, the executive officers of the General Partner is the same as the executive officers of the Company.
Preferred Units

Concurrently with the issuance of the Series 1 Preferred Shares and the Series 3 Preferred Shares by the Company, 12,000,000 and 10,000,000 Preferred LP Units, respectively, were issued by the Limited Partnership to the General Partner. The terms of the Preferred LP Units are substantially similar to the terms of the Preferred Shares. Pursuant to the terms of the Limited Partnership Agreement, the General Partner, as the holder of the Preferred LP Units, will have priority over the holders of LP Units (being, indirectly, the Company and Kinder Morgan) on any distributions, and in the event of dissolution, of the Limited Partnership. In addition, no amendments to the provisions of the Preferred LP Units or the priority of distributions or in the event of dissolution may be made unless such amendments receive approval of two-thirds of then outstanding Preferred Shares and, if required, the approval of the TSX.

Takeover Bid Protection - Coattail Arrangements

Under applicable securities laws in Canada, an offer to purchase Special Voting Shares or Class B Units would not necessarily require that an offer be made to purchase Restricted Voting Shares. In accordance with the rules of the TSX designed to ensure that, in the event of a takeover, the holders of Restricted Voting Shares will be entitled to participate on an equal footing with holders of Special Voting Shares or Class B Units, each of the Company’s Articles and the Limited Partnership Agreement contain customary coattail provisions.

Pursuant to the Articles of the Company, no holder of Special Voting Shares is permitted to transfer such Special Voting Shares unless either: (i) such transfer would not require that the transferee make an offer to holders of Restricted Voting Shares to acquire Restricted Voting Shares on the same terms and conditions under applicable securities laws, if such Special Voting Shares were outstanding as Restricted Voting Shares; or (ii) if such transfer would require that the transferee make such an offer to holders of Restricted Voting Shares to acquire Restricted Voting Shares on the same terms and conditions under applicable securities laws, the transferee acquiring such Special Voting Shares makes a contemporaneous identical offer for Restricted Voting Shares (in terms of price, timing, proportion of securities sought to be acquired and conditions) and does not acquire such Special Voting Shares unless the transferee also acquires a proportionate number of Restricted Voting Shares actually tendered to such identical offer.

In addition, pursuant to the terms of the Limited Partnership Agreement, no holder of Class B Units is permitted to transfer such Class B Units, unless: (i) such transfer would not require the transferee to make an offer to holders of Restricted Voting Shares to acquire Restricted Voting Shares on the same terms and conditions under applicable securities laws if such Class B Units, and all other outstanding Class B Units, were instead outstanding as Restricted Voting Shares; or (ii) the offeror acquiring such Class B Units makes a contemporaneous identical offer for the Restricted Voting Shares (in terms of price, timing, proportion of securities sought to be acquired and conditions) and acquires such Class B Units along with a proportionate number of Restricted Voting Shares actually tendered to such identical offer.

Dividend Reinvestment Plan

The Company has implemented a 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 weighted average trading price of the Restricted Voting Shares on the stock exchange on which the Restricted Voting Shares are then listed for the five trading days 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 is currently set at 3%.

No brokerage commission will be payable in connection with the purchase of Restricted Voting Shares under the DRIP and all administrative costs will be borne by the Company. Cash undistributed by the Company upon the issuance of additional Restricted Voting Shares under the DRIP will be invested in the Company and/or the Limited Partnership to be used for general corporate purposes and working capital.

Holders of Restricted Voting Shares who are non-residents of Canada are not entitled to participate in the DRIP as a result of foreign securities law restrictions.

47



The Limited Partnership Agreement provides for a similar distribution reinvestment plan for the holders of Class B Units such that they may elect to have all of the cash distributions on the Class B Units payable to any such person automatically reinvested in additional Class B Units on the same basis and at the same price per Class B Unit as a holder of Restricted Voting Shares purchases Restricted Voting Shares pursuant to the DRIP. Kinder Morgan may participate in the Limited Partnership’s distribution reinvestment plan at levels that vary from the levels of participation by shareholders in the DRIP. The proceeds received by the Company pursuant to the DRIP will be used to indirectly acquire additional Class A Units of the Limited Partnership. Similarly, the reinvestment of distributions received by Kinder Morgan from the Limited Partnership pursuant to the corresponding distribution reinvestment mechanism applicable to the Class B Units will result in the issuance of additional Class B Units to Kinder Morgan, at the same price per unit at which additional Restricted Voting Shares are issued by the Company pursuant to the DRIP. See “—Limited Partnership Units—Distributions” above.

As a result of differing participation levels, the overall ownership interests in the Company, as between Kinder Morgan (through its ownership interest in Special Voting Shares) and the holders of Restricted Voting Shares, may vary and such variances may be significant. Pursuant to the terms of the DRIP and the Limited Partnership Agreement, the Company and the Limited Partnership may concurrently suspend the DRIP and the distribution reinvestment plan, respectively, at their discretion.

Item 6. Selected Historical Financial Information.

The following table sets forth, for the periods and at the dates indicated, our summary historical financial data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited consolidated financial statements. See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information.

As at and for the Year Ended December 31,
2017

 
2016

 
2015

(In millions of Canadian dollars)
 
 
 
 
 
GAAP Income Statement Information
 
 
 
 
 
Revenues
683.8

 
676.1

 
645.9

Operating income
215.9

 
237.4

 
242.3

Foreign exchange (loss) gain
(5.2
)
 
32.6

 
(185.4
)
Net income (loss)
160.7

 
201.8

 
(22.9
)
Non-GAAP Financial Measures(a)
 
 
 
 
 
DCF
322.7

 
318.2

 
272.7

Adjusted EBITDA
388.3

 
395.4

 
368.7

Allocation of Earnings to Ownership Interests
 
 
 
 
 
Preferred share dividends
(6.6
)
 

 

Net (income) loss attributable to Kinder Morgan interest(b)
(126.2
)
 
(201.8
)
 
22.9

Net income available to Restricted Voting Stockholders
27.9

 

 

DCF available to Kinder Morgan interest(a)(b)
266.4

 
318.2

 
272.7

DCF available to Restricted Voting Stockholders(a)(c)
54.9

 

 

GAAP Balance Sheet Information (at end of period)
 
 
 
 
 
Property, plant and equipment, net
3,708.0

 
3,181.1

 
3,008.3

Total assets
4,452.7

 
3,739.4

 
3,485.2

Outstanding debt(d)

 
1,362.1

 
1,320.4

Total equity
3,637.6

 
1,436.0

 
1,251.0

_________
(a)
See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of OperationsResults of OperationsNon-GAAP Financial Measures.
(b)
Prior to our May 2017 IPO, net income (loss) and DCF were attributable only to Kinder Morgan interest.
(c)
Year ended December 31, 2017 amount is net of approximately $1.4 million of U.S. cash taxes attributable to Restricted Voting Stockholders.
(d)
Prior to May 2017 IPO outstanding debt represented the Long-term debt-affiliates (“KMI Loans”).




48


Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto.  We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report that should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—Business and Segments;” (ii) a description of developments during 2017, found in Items 1 and 2 “Business and Properties—Pipelines Business” and in “—Terminals Business;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”

Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements.  These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties.  Our actual results could differ materially from those discussed in the forward-looking statements.  Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and at the beginning of this report in “Information Regarding Forward-Looking Statements.”

Subsequent to our IPO, Kinder Morgan retained control of us and the Limited Partnership. As a result 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, our consolidated financial statements presented herein were derived from the consolidated financial statements and accounting records of Kinder Morgan. The assets and liabilities in these consolidated financial statements have been reflected at historical carrying value of the immediate parents within the Kinder Morgan organization structure including goodwill and purchase price assigned amounts, as applicable. Prior to May 30, 2017, our historical financial statements were presented as combined consolidated financial statements derived from information included within the consolidated financial statements and accounting records of Kinder Morgan. All significant intercompany balances between the companies included in our accompanying consolidated financial statements have been eliminated.

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

Kinder Morgan retained control of us, therefore, the amounts recorded to “Share capital,” “Retained deficit,” “Accumulated other comprehensive loss” and “Kinder Morgan interest” presented in the consolidated statements of equity for the year ended December 31, 2017 include (i) the “Reallocation of Kinder Morgan pre-IPO carrying basis” which represents Kinder Morgan’s pre-IPO 100% ownership interest in us including net income for the period January 1 through May 29, 2017 and (ii) the “Reallocation of equity on common control transaction” which represents the difference between our book value prior to our IPO and the proportionate ownership percentages in the book value in our net assets after our IPO.

General

Our reportable business segments are based on the way our management organizes our 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) TMPL and TMEP; (ii) Cochin; (iii) Puget Sound; (iv) Jet Fuel; and (v) KMCI.

Terminals - the ownership and operation of liquid product merchant storage and rail terminals in the Edmonton, Alberta market 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 EBDA of each segment (“Segment EBDA”). We believe that Segment EBDA is a useful measure of our operating performance because it measures segment operating results before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as certain general and administrative expense, foreign exchange losses (or gains) on the Long-term debt-affiliates (“KMI Loans”) prior to their payoff with proceeds from our IPO, interest expense, net, and income tax expense. Our general and administrative

49


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 18 “Reportable Segments” to the accompanying consolidated financial statements for further information on our reportable business segments.

Recent Business Developments

Base Line Terminal Construction Progress

In January 2018, we commenced operation of the 4.8 million barrel Base Line Terminal, a 50-50 crude oil merchant terminal joint venture between us and Keyera Corp., in Sherwood Park, Alberta (near Edmonton). The first four of twelve crude oil storage tanks were placed in service on January 15, 2018 with the balance of the tanks to be phased into service throughout the year. The facility, which is expected to be completed on-time and on-budget, is fully contracted with long-term, firm take-or-pay agreements with credit-worthy customers. Our total investment in the project is approximately $398 million, including costs associated with the construction of a pipeline segment solely funded by us. Up to an additional 1.8 million barrels may be added in a phase-two expansion of the terminal, depending on future demand.

TMEP Permitting and Construction Progress

The TMEP was approved by Order in Council on December 1, 2016, with 157 conditions. The Province of B.C. stated its approval of TMEP on January 11, 2017, with 37 conditions. Trans Mountain has made filings with the NEB and B.C. Environment with respect to all of the federal and provincial conditions required prior to general construction. The B.C. Environmental Assessment Office (“EAO”) has now released all condition filings required prior to general construction. The NEB has released sufficient approvals for proceeding with the Westridge Terminal and Temporary Infrastructure work phase. Trans Mountain is now in receipt of a number of priority permits from regulatory authorities in Alberta and B.C., including access to B.C. northern interior Crown lands.  Trans Mountain continues to make progress on approvals from the NEB, government of B.C. and government of Alberta. However, as of the end of 2017, even with this progress, Trans Mountain has yet to obtain numerous provincial and municipal permits and federal condition approvals necessary for construction.

On December 4, 2017, we announced that, while TMEP had made incremental progress during 2017 on permitting, regulatory condition satisfaction and land access, the scope and pace of the permits and approvals received to date did not allow for significant additional construction to begin at that time. We also stated that we must have a clear line of sight on the timely conclusion of the permitting and approvals processes before we would commit to full construction spending. Consistent with our primarily permitting strategy and to mitigate risk, we set our 2018 budget assuming TMEP spend in the first part of 2018 would be focused primarily on advancing the permitting process, rather than spending at full construction levels, until we have greater clarity on key permits, approvals and judicial reviews. In our January 17, 2018 earnings press release, we announced a potential unmitigated delay to project completion of one year (to December 2020) primarily due to the time required to file for, process and obtain necessary permits and regulatory approvals. As stated in Trans Mountain's November 14, 2017 motion to the NEB discussed below, "it is critical for Trans Mountain to have certainty that once started, the TMEP can confidently be completed on schedule." The TMEP projected in service date remains subject to change due to risks and uncertainties described in “Information Regarding Forward-Looking Statements,” Item 1A “Risk Factors,” elsewhere in this Item 7, and in Note 19 “Litigation, Commitments and Contingencies” to our consolidated financial statements under the heading “TMEP Litigation.” Further, as stated in our January 17, 2018 earnings press release, if TMEP continues to be "faced with unreasonable regulatory risks due to a lack of clear processes to secure necessary permits . . . it may become untenable for Trans Mountain's shareholders . . . to proceed." TMPL continues to proceed with in water work at the Westridge Terminal.

On October 26 and November 14, 2017, we filed motions with the NEB to resolve delays as they relate to the City of Burnaby and to establish a fair, transparent and expedited backstop process for resolving any similar delays in other provincial and municipal permitting processes. On December 7, 2017, the NEB granted our motion in respect to the City of Burnaby and indicated that Trans Mountain is not required to comply with two sections of the city’s bylaws, thereby allowing Trans Mountain to start work at its pipeline terminals subject to other permits or authorizations that may be required. The NEB indicated that it would release its reasons for the decision at a later date. On January 18, 2018, the NEB issued its reasons for decision on the Burnaby motion and granted in part Trans Mountain’s motion for a backstop process, establishing a generic process to hear any future motions as they relate to provincial and municipal permitting issues.

Hearings were held in October and November 2017 related to two judicial reviews underway in the B.C. Supreme Court with respect to the environmental certificate granted to TMEP by the province of B.C. Separate judicial reviews pending in the Federal Court of Appeal (“FCA”) challenging the process leading to the federal government’s approval of TMEP were heard by the court from October 2 to October 13, 2017. Decisions from the courts are expected in the coming months. We are confident

50


that the NEB, the Federal Government and the B.C. Government properly assessed and weighed the various scientific and technical evidence through a comprehensive review process, while taking into consideration varying interests on the TMEP. The approvals granted followed many years of engagement and consultation with communities, Aboriginal groups and individuals.

As of December 31, 2017, we had spent approximately $930 million on the TMEP, of which approximately $385 million was incurred by us after our IPO. Our estimated total cost for the TMEP is $7.4 billion ($6.7 billion excluding capitalized equity and debt financing costs). Construction related delays could result in increases to the estimated total costs; however, because the extent of the delay remains uncertain we have not updated its cost estimate at this time.

Outlook

Also on December 4, 2017, and again in our January 17, 2018 earnings press release, we announced certain expectations and preliminary financial projections for 2018, in which we expect our business to:

generate $474 million of Adjusted EBITDA and $349 million of DCF, respectively, with growth due primarily to the phased in-service of tanks at the new Base Line Terminal during the year and higher capitalized equity financing costs associated with spending on TMEP (recognized in other income). Excluding capitalized equity financing costs, Adjusted EBITDA and DCF are budgeted to be $403 million and $278 million, respectively. Actual capitalized equity financing costs will vary depending on the amount and timing of TMEP expenditures;
generate DCF to holders of Restricted Voting Shares of $0.96 per Restricted Voting Share, with an expected declared dividend of $0.65 per Restricted Voting Share;
invest $1.9 billion on expansion projects and other discretionary spending, of which $1.8 billion is associated with TMEP and the balance is associated with the Base Line Terminal; and
end 2018 with a net debt-to-Adjusted EBITDA ratio of approximately 2.7 times.

Our current projection for 2018 Adjusted EBITDA is lower than our projection disclosed at the time of our IPO of $523 million (including $106 million of capitalized equity financing costs) due to lower capitalized equity financing costs resulting from reduced spending on TMEP in 2017 and expected spend for 2018 as compared to our forecast at the time of the IPO. Excluding capitalized equity financing costs, our current projection for 2018 Adjusted EBITDA is slightly higher than our projection disclosed at the time of our IPO. See “—TMEP Permitting and Construction Progress”.

Our projected Adjusted EBITDA and DCF assumptions include:

Our base business, while expected to be relatively stable, is subject to re-contracting and other risks;
Our 2018 projected Adjusted EBITDA includes $71 million of TMEP capitalized equity financing costs based on capital spent to date and our 2018 projected $1.8 billion capital expenditures. Our 2018 projected Adjusted EBITDA includes the capitalized equity financing costs derived under our current methodology, which is approved by the NEB and is agreed upon with representatives of current TMPL shippers and applies a 45% equity capital structure and a 9.5% return on equity to the monthly average cumulative spend on TMEP. After TMEP is complete, capitalized equity financing costs associated with the project will no longer be recognized in Adjusted EBITDA. See Note 2 “Summary of Significant Accounting PoliciesProperty, Plant and Equipment” in our accompanying consolidated financial statements for further information regarding capitalized equity financing costs which is one of two components of our allowance for funds used during construction;
Our 2018 projected Adjusted EBITDA also includes $22 million of Adjusted EBITDA contribution related to our 50% share of a partial year of in-service of the Base Line Terminal project based on contracted volumes, rates and expected operating costs (with the full $44 million of Adjusted EBTIDA expected on an annualized basis after the project is fully placed into service).
Projected Adjusted EBITDA contribution from the Base Line Terminal includes firm, take-or-pay revenue plus a relatively small amount of variable, volume-sensitive revenue less operating expenses. The forecasted annual take-or-pay revenue is equal to contracted storage capacity on an annual basis multiplied by the corresponding contracted tariff rates. The forecasted annual variable revenue is based on forecasted utilization of the terminal after it is placed in service. If these uncontracted revenues were higher than forecasted by 10%, the resulting impact on Adjusted EBITDA from the Base Line Terminal would be an increase of less than 1% on a full year basis. The estimates of operating expenses are based on our historical experience with other operating assets. The forecasted operating costs are comprised of labor, power, property taxes and other operating costs. The forecast for operating costs is based on our relevant experience operating similar assets, and if these operating costs were to increase or decrease by 10%, the resulting impact on Adjusted EBITDA from the Base Line Terminal would be an increase or decrease of less than 1.5% on a full year basis. and
A CAD$/U.S.$ dollar exchange rate of $0.79.


51


We currently expect TMEP to generate $900 million of incremental Adjusted EBITDA in its first 12 months of service (or approximately $75 million of Adjusted EBITDA per month). This is based on our average current expected toll rate of $5.17 per barrel for our contracted minimum volume commitments of 707.5 MBbl/d less projected operating costs and less the existing Trans Mountain System’s Adjusted EBITDA contribution. For simplicity, this $900 million of Adjusted EBITDA is incremental to Adjusted EBITDA in previous periods after removing the contribution of capitalized equity financing costs to Adjusted EBITDA during periods prior to TMEP completion. Once TMEP is in service, Adjusted EBITDA will not include capitalized equity financing costs for TMEP, which are included in Adjusted EBITDA for pre-completion periods.
    
If TMEP construction costs increase by 10%, the impact on Adjusted EBITDA from TMEP would be an increase of approximately 3%, assuming those costs were allocated approximately 24% to uncapped and approximately 76% to capped TMEP costs. The forecasted operating costs are comprised of fixed costs, variable costs, and a fixed payment to the province of B.C. The variable costs, which include power and certain Aboriginal accommodation and consultation costs, flow through to the shippers via a tariff adjustment. Fixed costs, which include operating and maintenance, labor, property tax, insurance and other expenses, are not protected by a tariff rate adjustment. These costs are forecasted based on our experience operating similar assets, and if these costs were to increase or decrease by 10%, the resulting impact on Adjusted EBITDA from TMEP would be an increase or decrease of less than 1.5% on a full year basis.
    
Estimated incremental Adjusted EBITDA attributable to TMEP as described above excludes any utilization of spot volumes, which, as discussed below, could add more than $200 million of Adjusted EBITDA annually.
    
At the time of our IPO, we estimated (based on our then-anticipated in-service date of December 31, 2019) that our 2020 incremental Adjusted EBITDA attributable to TMEP would be $900 million (or $776 million including the impact of our original estimate of $124 million for 2018 capitalized equity financing costs), based on an anticipated full year of service in 2020. Assuming our currently estimated in-service date of December 2020, we would not receive any incremental Adjusted EBITDA attributable to TMEP in 2020, excluding the impact of capitalized equity financing costs. As described above, we would expect to receive the full $900 million of incremental Adjusted EBITDA over the twelve months after TMEP is placed into service, as our estimate of total Adjusted EBITDA from the project has not changed. See “—TMEP Construction and Permitting Progress”.

We do not provide forecasted net income (the GAAP financial measure most directly comparable to the non-GAAP financial measures DCF and Adjusted EBITDA) due to the impracticality of quantifying certain amounts required by GAAP, such as realized and unrealized foreign currency gains and losses and potential changes in estimates for certain contingent liabilities. See “—Results of OperationsNon-GAAP Financial Measures” below as well as the other information set forth herein.
    
Upon completion of TMEP, 100% spot utilization on the expanded TMPL could add more than $200 million to our Adjusted EBITDA annually on such terms. Notably, the three pipeline connected refineries with historic and expected continued demand in excess of 100,000 bpd on TMPL are not contracted shippers on the expanded TMPL and, accordingly, could become spot shippers or receive allocated capacity for any additional volumes following completion of TMEP. We believe that there will be significant demand for spot volume capacity upon start-up of the new system due to increasing demand in the United States and abroad. PADD V, and state of Washington in particular (as demand is expected to stay flat), is expected to require increasing access to Canadian crude oil if Alaskan production continues to decline. In addition, transit time to California from Burnaby is shorter than from Alaska by approximately three days (thereby reducing tanker costs) and the reversal of the U.S. oil export ban in late 2015 has put further supply pressure on the PADD V market. While markets in Asia are collectively larger than the U.S. Gulf Coast market and are forecasted to grow significantly, representing the majority of global crude demand growth (estimated to be approximately 70% from 2014 to 2040), Canadian crude exported from the West Coast can, where pricing is favorable, also access the U.S. Gulf Coast market through the Panama Canal (Source: CAPP 2016 Crude Oil Forecast, Markets and Transportation, 2016-0007).

For additional information about the risks and uncertainties regarding TMEP and Base Line Terminal projects, see Item 1A “Risk FactorsRisks Relating to Our Business,” including the risk factors captioned “Major projects, including TMEP, may be inhibited, delayed or stopped.” and “Judicial reviews of the processes pursuant to which we have been granted certain governmental, administrative and contractual rights to construct and operate our pipelines for TMEP, including on other owners’ land, are ongoing. If we were to lose these rights or TMEP were to be subject to additional significant regulatory reviews, changes, further obligations or restrictions, TMEP may be significantly delayed or stopped altogether, and we may incur additional costs.” As a result of the significance of the assumptions and the substantial risks to which TMEP and the Base Line Terminal project are subject, the actual impact of each of the TMEP and Base Line Terminal project on incremental projected Adjusted EBITDA, and our business generally, will vary and may vary materially. Therefore, investors are cautioned not to attribute undue certainty to this projected financial information. We plan to provide updates to this projected financial information when we believe such projections no longer have a reasonable basis.


52


Critical Accounting Policies and Estimates

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time such financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant estimates and judgments made by management in the preparation of our consolidated financial statements are outlined below.

Regulatory Assets and Liabilities

The TMPL and Cochin pipeline operations are regulated by the NEB. The Puget Sound pipeline operations are regulated by the FERC. The NEB and the FERC exercise statutory authority over matters such as construction and operation of facilities, rates and ratemaking, and accounting practices. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under GAAP for non-regulated businesses. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates, or paid to cover future abandonment costs. Long-term regulatory assets are recorded in “Regulatory assets” and current regulatory assets are recorded in “Other current assets” on the accompanying consolidated balance sheets. Long-term regulatory liabilities are included in Long-term liabilities and deferred credits — regulatory liabilities and current regulatory liabilities are recorded in Current liabilities — regulatory liabilities on the accompanying consolidated balance sheets. Regulatory assets are assessed for impairment if an event is indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned.

For rate-regulated assets, allowance for funds used during construction (“AFUDC”) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component (“capitalized debt financing costs”) and, if approved by the regulator, a cost of equity component (“capitalized equity financing costs”), which are both capitalized based on rates set out in a regulatory agreement. We capitalize only interest incurred during the construction of non rate-regulated assets. Capitalized debt financing costs result in a reduction in interest expense and capitalized equity financing costs results in the recognition of other income.

Impairment of Long-lived Assets

We evaluate long-lived assets for impairment whenever events or changes in circumstances that indicate that our carrying amount of an asset may not be recoverable. Impairment losses may be recognized on long-lived assets when estimated future cash flows expected to result from use of the asset and its eventual disposition is less than its carrying amount. We had no long-lived asset impairments during the years ended December 31, 2017, 2016 and 2015.

Goodwill

Goodwill is the cost of an acquisition in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires goodwill to be assigned to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount. Goodwill is also evaluated for impairment to the extent events or conditions indicate a risk of possible impairment during the interim periods subsequent to our annual impairment test.

Goodwill, which is attributable to the Trans Mountain reporting unit, is evaluated for impairment on May 31 of each year. The fair value of the Trans Mountain reporting unit was based on a market approach utilizing enterprise value to estimated EBITDA multiples of comparable companies. The value of the reporting unit is determined from the perspective of a market participant representing the price estimated to be received in a sale of the reporting unit in an orderly transaction between market

53


participants at the measurement date. The results of our Step 1 analysis did not indicate an impairment of goodwill and we did not identify any triggers for further impairment analysis during the remainder of the year.

The fair value estimate of our reporting unit fair value was based on Level 3 inputs of the fair value hierarchy.

Depreciation

Depreciation of regulated assets, except Cochin, is recorded on a straight-line basis over their estimated useful lives.  Depreciation rates for regulated assets are approved by the regulator.  For Cochin assets, we apply a composite depreciation rate to the total cost of the composite group until the net book value equals the salvage value. Non-regulated assets require the use of management estimates of the useful lives of assets. When it is determined that the estimated service life of a non-regulated asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life.

Income Taxes

The calculation of income tax assets or liabilities is based on assumptions about the timing of many taxable events and the enacted or substantively enacted rates anticipated to be applicable to income in the years in which temporary differences are expected to be realized or reversed. Prior to our May 30, 2017 reorganization and IPO, and for the years ended and as of December 31, 2016 and 2015, there was no U.S. income tax recognized on earnings from Trans Mountain Pipeline (Puget Sound) LLC as it was a subsidiary of a limited partnership until it became a subsidiary of our Limited Partnership.

Contingent Liabilities

Provisions recognized are based on management’s judgment about assessing contingent liabilities and timing, scope and amount of liabilities including liabilities relating to legal and environmental matters. Management uses judgment in determining the likelihood of realization of contingent liabilities to determine the outcome of contingencies.

Employee Benefit Plans

We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2017, our pension plans were underfunded by $56.7 million and our other postretirement benefits plans were underfunded by $19.9 million. Our pension and other postretirement benefit obligations and net benefit costs are estimated based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plans and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. The selection of these assumptions is further discussed in Note 10 ‘‘Share-based Compensation and Benefit Plans’’ in the accompanying consolidated financial statements.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2017, we had deferred net losses of approximately $50.4 million in pre-tax accumulated other comprehensive loss related to our pension and other postretirement benefits.


54


The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits:
 
Pension Benefits
 
Other Postretirement Benefits
Year Ended December 31, 2017
Net benefit cost (income)
 
Change in funded status(a)
 
Net benefit cost (income)
 
Change in funded status(a)
(In millions of Canadian dollars)
 
 
 
 
 
 
 
One percent increase in:
 
 
 
 
 
 
 
Discount rates
(4.5
)
 
35.2

 
(0.2
)
 
2.6

Expected return on plan assets
(1.8
)
 

 

 

Rate of compensation increase
1.9

 
(8.0
)
 

 

Health care cost trends

 

 
0.2

 
(1.5
)
One percent decrease in:
 
 
 
 
 
 
 
Discount rates
6.2

 
(43.4
)
 
0.3

 
(3.3
)
Expected return on plan assets
1.8

 

 

 

Rate of compensation increase
(1.9
)
 
7.8

 

 

Health care cost trends

 

 
(0.2
)
 
1.2

_________
(a)
Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.

Transactions with Affiliates

We have transactions with Kinder Morgan and its subsidiaries. Refer to accompanying consolidated balance sheets for the amounts due to or from affiliates and Note 13 “Transactions with Related Parties” to the our consolidated financial statements for the identification of revenue and expenses with affiliated parties included in the accompanying consolidated statements of operations. Accounts receivable-affiliate and accounts payable-affiliate are non-interest bearing and are settled on demand, and subsequent to our IPO, settled monthly.

Other Risk Management Activities

For a further discussion of the risks and trends that could affect our financial performance and the steps that we take to mitigate these risks, see Note 16 “Risk Management and Financial Instruments” to our consolidated financial statements.

Results of Operations

Overview

We evaluate the performance of our reportable business segments by evaluating the EBDA of each segment (“Segment EBDA”). We believe that Segment EBDA is a useful measure of our operating performance because it measures segment operating results before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as certain general and administrative expense, interest expense, net, and income tax expense, and prior to their pay off in the second quarter of 2017, the foreign exchange losses (or gains) on the KMI Loans. 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 18 “Reportable Segments” to our consolidated financial statements for further discussion of our reportable business segments.

55


Consolidated Earnings Results
Year Ended December 31,
2017

 
2016

 
2015

(In millions of Canadian dollars)
 
 
 
 
 
Segment EBDA(a)
 
 
 
 
 
Pipelines
235.4

 
241.9

 
249.5

Terminals
218.3

 
211.2

 
180.5

Total segment EBDA(a)
453.7

 
453.1

 
430.0

DD&A
(142.4
)
 
(137.2
)
 
(123.5
)
Foreign exchange (loss) gain on the KMI Loans(b)
(2.4
)
 
29.7

 
(175.9
)
General and administrative expenses
(68.2
)
 
(57.6
)
 
(61.3
)
Interest, net
(15.8
)
 
(29.9
)
 
(30.1
)
Income before income taxes
224.9

 
258.1

 
39.2

Income tax expense
(64.2
)
 
(56.3
)
 
(62.1
)
Net income (loss)
160.7

 
201.8

 
(22.9
)
Preferred share dividends
(6.6
)
 

 

Net (income) loss attributable to Kinder Morgan interest
(126.2
)
 
(201.8
)
 
22.9

Net income available to Restricted Voting Stockholders
27.9

 

 

_________
(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 year ended December 31, 2017, 2016 and 2015 includes (i) $29.1 million, $17.9 million and $12.9 million, respectively, of capitalized equity financing costs and (ii) $(2.8) million, $2.9 million and $(9.5) million, respectively, of 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.
(b)
The KMI Loans, which represented U.S. dollar denominated long-term notes payable with Kinder Morgan, were settled with proceeds from our IPO.

Year Ended December 31, 2017 vs 2016

The decrease of $41.1 million (20%) from the prior year in net income is primarily attributable to the $32.1 million change in foreign exchange gains (losses) on the KMI Loans. The $9.0 million remainder of the decrease is largely attributable to increased general and administrative expense driven by legal and audit fees related to TMEP financing activities and increased DD&A expense from recent assets being placed in service, partially offset by lower interest expense primarily due to the 2017 settlement of the KMI Loans.

Year Ended December 31, 2016 vs. 2015

The increase in net income of $224.7 million (981%) from the prior year in net income is primarily attributable to changes in the unrealized foreign exchange gains (losses) on the U.S. dollar denominated KMI Loans. Due to changes in the exchange rates between Canadian and U.S. dollars, we recorded unrealized foreign exchange gains of $29.7 million in 2016, and unrealized foreign exchange losses of $175.9 million in 2015 associated with the KMI Loans. The remainder of the increase is largely attributable to increased Terminals Segment EBDA driven by increased contributions from the Edmonton Rail Terminal joint venture and other terminal projects being placed in service, and reduced general and administrative expense from 2015 environmental costs that did not recur in 2016.

Non-GAAP Financial Measures

In addition to using financial measures prescribed by GAAP, references are made in this report to DCF, both in the aggregate and per share, and Adjusted EBITDA, which are measures that do not have any standardized meaning as prescribed by GAAP. Neither DCF nor Adjusted EBITDA should be considered an alternative to GAAP net income or any other GAAP measures and such non-GAAP measures have important limitations as an analytical tool. The computation of DCF and Adjusted EBITDA 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-GAAP performance measures in isolation or as a substitute for an analysis of results as reported under GAAP. The limitations of these non-GAAP performance measures are compensated for by reviewing the comparable GAAP measures, understanding the differences between the measures and taking this information into account in our analysis and our decision making processes. Any use of DCF or Adjusted EBITDA in this MD&A is expressly qualified by this cautionary statement.

56



DCF is net income before DD&A adjusted for (i) income tax expense and cash income taxes (paid) refunded; (ii) sustaining capital expenditures (also referred to as ‘‘maintenance’’ capital expenditures); and (iii) certain items that are items required by 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 (for example certain legal settlements and casualty losses).

DCF is an important performance measure used by us and by external users of our financial statements to evaluate our performance and in measuring and estimating 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 (also referred to as ‘‘discretionary’’ 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 GAAP measure. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is net income. A reconciliation of net income 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
Year Ended December 31,
2017

 
2016

 
2015

(In millions of Canadian dollars, except per share amounts)
 
 
 
 
 
Net income (loss)(a)
160.7

 
201.8

 
(22.9
)
Add/(Subtract):
 
 
 
 
 
Certain items(b)
3.8

 
(29.7
)
 
175.9

DD&A
142.4

 
137.2

 
123.5

Total book taxes(c)
65.6

 
56.3

 
62.1

Cash income taxes (paid) refunded
(0.2
)
 
(1.2
)
 
0.4

Preferred share dividends
(6.6
)
 

 

Sustaining capital expenditures
(43.0
)
 
(46.2
)
 
(66.3
)
DCF
322.7

 
318.2

 
272.7

DCF to KMI interest
(266.4
)
 
n/a

 
n/a

Cash taxes attributable to Restricted Voting Stockholders
(1.4
)
 
n/a

 
n/a

DCF to Restricted Voting Stockholders
54.9

 
n/a

 
n/a

Weighted average Restricted Voting Shares outstanding for dividends (in millions)(d)
103.7

 
n/a

 
n/a

DCF per Restricted Voting Share(e)
0.530

 
n/a

 
n/a

Declared dividend per Restricted Voting Share
0.3821

 
n/a

 
n/a


Adjusted EBITDA is used by us and by 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. We believe the GAAP measure most 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 measure against our overall leverage.

57


Reconciliation of Net Income to Adjusted EBITDA
Year Ended December 31,
2017

 
2016

 
2015

(In millions of Canadian dollars)
 
 
 
 
 
Net income (loss)(a)
160.7

 
201.8

 
(22.9
)
Add/(Subtract):
 
 
 
 
 
Total certain items(b)
3.8

 
(29.7
)
 
175.9

DD&A
142.4

 
137.2

 
123.5

Total book taxes(c)
65.6

 
56.3

 
62.1

Interest, net
15.8

 
29.9

 
30.1

Adjusted EBITDA
388.3

 
395.5

 
368.7

_________
n/a - not applicable

(a)
During the years ended December 31, 2017, 2016 and 2015, net income (loss) includes (i) capitalized equity financing costs of $29.1 million, $17.9 million and $12.9 million, respectively, and (ii) interest expense on the KMI Loans of $19.6 million, $44.5 million and $42.5 million, respectively.
(b)
Prior to our IPO, amounts represented foreign currency losses and (gains) on the KMI Loans. The principal amounts on the KMI Loans were repaid using proceeds from our IPO. 2017 amount also includes General and administrative and book tax certain items of $2.8 million and $(1.4) million, respectively.
(c)
2017 amount excludes book tax certain item of $(1.4) million.
(d)
The weighted average Restricted Voting Shares outstanding for dividends calculation is based on the actual days in which the shares were outstanding for the period from May 30, 2017 to December 31, 2017, and also includes stock awards of Restricted Voting Shares that participate in dividends. Therefore, the amounts differ from the GAAP weighted average Restricted Voting Shares outstanding from the date of our formation.
(e)
Represents DCF per restricted voting share, including capitalized equity financing costs of $5.9 million, for the period from the May 30, 2017 IPO through December 31, 2017. If we had been a public company for the entire year ended December 31, 2017, DCF per restricted voting share would have been $0.92.

Segment Earnings Results

Pipelines Segment
Year Ended December 31,
2017

 
2016

 
2015

(In millions of Canadian dollars, except operating statistics)
 
 
 
 
 
Revenues
385.2

 
388.6

 
383.7

Operating expenses, except DD&A
(171.2
)
 
(164.5
)
 
(152.7
)
Other (expense) income
(0.2
)
 

 
1.7

Other income and unrealized foreign exchange loss, net
21.6

 
17.8

 
16.8

Segment EBDA
235.4

 
241.9

 
249.5

 
 
 
 
 
 
Change from prior period
Increase/(Decrease)
 
 
Revenues
(3.4
)
 
4.9

 
 
Segment EBDA
(6.5
)
 
(7.6
)
 
 
 
 
 
 
 
 
Operating statistics
2017

 
2016

 
2015

TMPL transport volumes (MBbl/d)
308

 
316

 
316

Puget Sound transport volumes (MBbl/d)
166

 
191

 
177

Cochin transport volumes (MBbl/d)
86

 
84

 
80



58


Below are the changes in both Segment EBDA and revenues in 2017 and 2016, when compared with the respective prior year:

Year ended December 31, 2017 versus Year ended December 31, 2016
 
Segment EBDA
increase/(decrease)
 
Revenues
 increase/(decrease)
(In millions of Canadian dollars, except percentages)
 
TMPL
10.3

 
6
 %
 
1.9

 
1
 %
Cochin
(10.3
)
 
(40
)%
 
(0.1
)
 
 %
Puget Sound
(6.1
)
 
(22
)%
 
(5.4
)
 
(15
)%
All others (including eliminations)
(0.4
)
 
(10
)%
 
0.2

 
3
 %
Total Pipelines
(6.5
)
 
(3
)%
 
(3.4
)
 
(1
)%
 
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 years of 2017 and 2016:

increase of $10.3 million (6%) from TMPL primarily due to an increase in capitalized equity financing costs due to spending on TMEP, higher incentive revenues and unrealized foreign exchange gains primarily related to U.S. dollar denominated payable and cash balances partially offset by an increase in operating expense largely due to timing of when such expenses were incurred;
decrease of $10.3 million (40%) from Cochin primarily resulting from unrealized foreign exchange losses on U.S. dollar denominated receivables with affiliates, cash, and payable balances, and higher fuel and power costs as a result of higher volumes; and
decrease of $6.1 million (22%) from Puget Sound primarily due to lower revenues driven by lower throughput.

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 years of 2016 and 2015:

The Pipelines segment had a decrease in Segment EBDA of $7.6 million (3%) which was driven primarily by (i) an $8.6 million decrease in Segment EBDA from Cochin, consisting of a $2.6 million increase in revenues offset by an $11.2 million increase in operating expenses, which included a $9.0 million increase in pipeline integrity costs in 2016 and (ii) $4.2 million of lower unrealized foreign exchange gains related to U.S. dollar denominated cash, accounts payable and accounts receivable. The decreases in Segment EBDA were partially offset by (i) a $2.0 million increase in Segment EBDA from Puget Sound, consisting of a $4.6 million increase in revenues and a $2.6 million increase in operating expenses from increased pipeline volumes, net of foreign exchange effects and (ii) a $5.0 million increase in capitalized equity financing costs related to TMEP.


59


Terminals Segment
Year Ended December 31,
2017

 
2016

 
2015

(In millions of Canadian dollars, except operating statistics)
 
 
 
 
 
Revenues
298.6

 
287.5

 
262.2

Operating expenses, except DD&A
(82.8
)
 
(79.1
)
 
(67.4
)
Other expense, net
(3.1
)
 
(0.3
)
 
(0.4
)
Other income and unrealized foreign exchange loss, net
5.6

 
3.1

 
(13.9
)
Segment EBDA
218.3

 
211.2

 
180.5

 
 
 
 
 
 
Change from prior period
Increase/(Decrease)
 
 
Revenues
11.1

 
25.3

 
 
Segment EBDA
7.1

 
30.7

 
 
 
 
 
 
 
 
Operating statistics
2017

 
2016

 
2015

Bulk transload tonnage (MMtonnes)(a)
4.5

 
4.3

 
4.4

Liquids leaseable capacity (MMBbl)
7.3

 
7.3

 
7.3

Liquids utilization %(b)
100
%
 
100
%
 
100
%
________
(a)
Includes our share of joint venture tonnage.
(b)
The ratio of our storage capacity under contract to our estimated storage capacity.

Below are the changes in both Segment EBDA and revenues in 2017 and 2016, when compared with the respective prior year:

Year ended December 31, 2017 versus Year ended December 31, 2016
 
Segment EBDA
increase/(decrease)
 
Revenues
 increase/(decrease)
(In millions of Canadian dollars, except percentages)
 
Edmonton Rail Terminal joint venture
8.0

 
14
 %
 
5.4

 
8
 %
Edmonton South Terminal
4.8

 
6
 %
 
3.9

 
5
 %
North 40 Terminal
0.4

 
1
 %
 
1.9

 
5
 %
Alberta Crude Terminal joint venture
(5.4
)
 
(64
)%
 
(6.2
)
 
(43
)%
Vancouver Wharves Terminal
(0.3
)
 
(1
)%
 
6.1

 
7
 %
All others (including eliminations)
(0.4
)
 
(200
)%
 

 
 %
Total Terminals
7.1

 
3.4
 %
 
11.1

 
3.9
 %

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 years of 2017 and 2016:

increase of $8.0 million (14%) from Edmonton Rail Terminal joint venture primarily due to an adjustment in terminal fees in connection with a favorable arbitration ruling and an increase in unrealized foreign exchange gains primarily related to U.S. dollar denominated accounts payable to Kinder Morgan;
increase of $4.8 million (6%) from Edmonton South Terminal primarily due to higher ancillary service fees driven by escalations in fixed and take-or-pay terminaling contract rates and higher throughput volumes in 2017 and lower operating costs in 2017;
increase of $0.4 million (1%), from North 40 Terminal primarily due to increase in revenues due to higher throughput volumes and ancillary service fees partially offset by a decrease in unrealized foreign exchange gains primarily related to a U.S. dollar denominated payable to Kinder Morgan;
decrease of $5.4 million (64%) from Alberta Crude Terminal joint venture which was primarily driven by a contracted throughput fee reduction; and

60


decrease of $0.3 million (1%) from Vancouver Wharves Terminal primarily due to lower margins associated with bulk handling operations partially offset by an increase in earnings related to a customer contract buy-out, net of associated project write-off costs.

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 years of 2016 and 2015:

The Terminals business segment had an increase in Segment EBDA of $30.7 million (17%) driven primarily by Edmonton-area expansion projects including (i) the commissioning of the Edmonton Rail Terminal joint venture which contributed $23.1 million and $18.6 million of additional revenue and Segment EBDA, respectively; (ii) rail terminal connectivity additions at the Edmonton South Terminal that contributed $6.5 million and $4.8 million of additional revenues and Segment EBDA, respectively; and (iii) $16.6 million favorable change in foreign exchange effects. The Vancouver Wharves Terminal’s 2015 revenues included a contract buyout and additional ‘‘take-or-pay’’ revenue totaling $5.5 million.

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

During June 2017 we repaid the principal on the 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 U.S. dollar per Canadian dollar. Prior to then we were exposed to foreign currency risk related to the U.S. dollar denominated KMI Loans. 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 rate on December 31, 2016 was 1.3427.

The $32.1 million unfavorable change between the year ended December 31, 2017 and 2016 on foreign exchange rate gains (losses) 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. The $205.6 million favorable change between the year ended December 31, 2016 and 2015 on foreign exchange rate gains (losses) associated with the KMI Loans was due to a slight strengthening of the Canadian dollar against the U.S. dollar in 2016, as compared to a significant weakening in 2015. In addition, the KMI Loans balance increased by $270.3 million from December 31, 2014 to December 31, 2015.

General and Administrative Expense

The $7.8 million increase in general and administrative expense before certain items of $2.8 million in 2017 for the comparable years ended 2017 and 2016 was primarily driven by increased benefits costs, and increased legal and audit fees related to TMEP financing activities.

General and administrative costs were higher in 2015 than in 2016 because we allocated fewer labor costs to new construction projects in 2015 as compared to 2016 after completion of several projects in 2014 and early 2015, and before the 2016 ramp-up of work on TMEP.

Interest, net

Interest expense is presented as net of interest income and capitalized interest.

Interest, net decreased $14.1 million in 2017 when compared to the respective prior year, driven primarily by a $26.0 million decrease due to the repayment of the KMI Loans with proceeds from our IPO and an $8.5 million increase in capitalized debt financing costs partially offset by an increase of $18.8 million in interest expense, including interest on revolver, commitment fees and amortization of debt issue costs associated with our new June 2017 Credit Facility, See —Liquidity and Capital Resources below.

Interest, net decreased $0.2 million in 2016 when compared with the respective prior year. The 2016 interest expense was relatively flat compared to 2015 because the KMI Loans balances were relatively consistent during those two years.

Net Income Attributable to Kinder Morgan Interest

Net income attributable to Kinder Morgan interest, represents the allocation of our consolidated net income attributable to the outstanding ownership interests in our consolidated subsidiaries that are owned by Kinder Morgan’s wholly owned subsidiaries. The decrease in net income attributable to Kinder Morgan interest for the year ended December 31, 2017 when compared with the respective prior period was $75.6 million which was primarily attributable to our IPO and associated reduction in Kinder Morgan’s interest in us.

61


Income Taxes 

Year Ended December 31, 2017 vs. 2016

Income tax expense for the year ended December 31, 2017 was $64.2 million, as compared with the prior year income tax expense of $56.3 million. The $7.9 million increase in income tax expense was primarily due to (i) an increase in the B.C. provincial tax rate from 11% to 12%; (ii) an increase in depreciation expense on capitalized inter-corporate charges that were incurred prior to our IPO that were deemed not deductible for income tax purposes; and (iii) income attributable to foreign subsidiaries that is partially taxable to us subsequent to our IPO.

Year Ended December 31, 2016 vs. 2015

Income tax expense for the year ended December 31, 2016 was $56.3 million, as compared with the prior year income tax expense of $62.1 million. The $5.8 million decrease in income tax expense was due primarily to the capital gain from the impact of exchange rate fluctuations in respect of the KMI Loans which resulted in the release of the valuation allowance. These decreases were partially offset by the tax impact on higher pre-tax earnings.

Liquidity and Capital Resources

General

On June 16, 2017, we closed on a five-year Credit Facility which includes: (i) a $4.0 billion Revolving Construction Facility; (ii) a $1.0 billion Revolving Contingent Facility; and (iii) a $500.0 million Revolving Working Capital Facility. On January 23, 2018, we entered into an agreement amending certain terms of the Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of the Credit Facility. As of December 31, 2017, we had no outstanding borrowings on our Credit Facility. See “—Credit Facility” below.

As of December 31, 2017, we had no outstanding debt under our $5.5 billion Credit Facility. As of December 31, 2017, we had $238.8 million of cash and cash equivalents, an increase of $79.8 million (50%) 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 adequate to manage our day-to-day cash requirements.

We generated cash flows from operating activities of $250.5 million and $309.9 million in the years ended December 31, 2017 and 2016, respectively, (the decrease of 19% in 2017 versus 2016 is discussed below in ‘‘Cash Flows Operating Activities’’). During the year ended December 31, 2017 and prior to our IPO, we also received $70.2 million of borrowings and $10.7 million of contributions from Kinder Morgan subsidiaries that were used to partially fund our expansion capital expenditures.

Short-term Liquidity

As of December 31, 2017 and 2016, our principal source of short-term liquidity was cash from operating activities. We had a working capital (defined as current assets less current liabilities) excess of $42.3 million and a deficit of $200.6 million as of December 31, 2017 and 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 operate with a working capital deficit during the construction of TMEP. Such a deficit will be funded primarily through the use of our Revolving Construction Facility, which has been put in place to fund the cost of TMEP, as well as retained cash from dividend and distribution reinvestments, and proceeds from term debt and preferred shares and restricted voting share equity issuances. We received $292.9 million of net proceeds from the issuance of the Series 1 Preferred Shares in August, 2017 and $243.2 million of net proceeds, including $0.7 million of accrued costs, from the issuance of the Series 3 Preferred Shares in December 2017. In addition, we will be in a position to utilize the $500.0 million Working Capital Facility, of which $447.0 million is available after reducing the capacity for the $53.0 million in letters of credit, for general corporate purposes, including the funding of growth capital expenditures for expansion projects other than TMEP.

Long-term Financing

We expect to fund TMEP capital expenditures through (i) additional borrowings under 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 shares; or a combination thereof.


62


Preferred Share Offerings

On August 15, 2017, we issued 12,000,000 Series 1 Preferred Shares to the public in Canada at a price of $25.00 per share for gross proceeds of $300.0 million. In addition, on December 15, 2017, we issued 10,000,000 Series 3 Preferred Shares to the public in Canada at a price of $25.00 per share for gross proceeds of $250.0 million. In each case, we used the proceeds to subscribe for a corresponding number of Preferred LP Units of the Limited Partnership, which then, directly or indirectly, used such proceeds to repay then outstanding indebtedness incurred to, directly or indirectly, finance the development, construction and completion, as applicable, of TMEP and the Base Line Terminal project.
 
Credit Facility

 On June 16, 2017, we closed on a five-year Credit Facility which includes: (i) a $4.0 billion Revolving Construction Facility; (ii) a $1.0 billion Revolving Contingent Facility; and (iii) a $500.0 million Revolving Working Capital Facility of which $446.8 million was available after reducing the capacity for the $53.2 million in outstanding letters of credit.

On January 23, 2018, we entered into an agreement amending certain terms of the Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of the Credit Facility. Material terms of the Credit Facility are described below and such description is subject to, and qualified in its entirety by, the terms of such agreements, which are filed as Exhibits 10.3 and 10.4 and incorporated by reference hereto.

Any drawn funds on the Credit Facility bear interest based on various index rates plus fixed spreads determined by the type of borrowing (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 our credit ratings. 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 our credit ratings. 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 our credit ratings. The Credit Facility is guaranteed by the Company and all of our non-borrower subsidiaries and are secured by a first lien security interest on all of our assets and the equity and assets of the other guarantors. The Credit Facility provides for customary positive and negative covenants, including limitations on liens, dispositions, amalgamations, liquidations and dissolutions. Drawdowns on each of the Credit Facilities are subject to satisfaction of certain conditions precedent set out in the credit agreement relating thereto.

As of December 31, 2017, we were in compliance with all Credit Facility required covenants and had no outstanding balance. For the year ended December 31, 2017, we incurred $8.7 million in standby fees. During the period the Credit Facility was available in 2017, we made borrowings and repaid these borrowings with the combined net proceeds from the issuance of our Series 1 Preferred Shares and Series 3 Preferred Shares. 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.

Credit Ratings

The following credit ratings information is provided as it relates to our financing costs and liquidity. Specifically, credit ratings affect our ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current ratings our debt by its rating agencies, particularly a downgrade below investment-grade, could adversely affect our cost of financing and our access to sources of liquidity and capital. In addition, changes in credit ratings may affect our 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.

KMCU is a wholly owned subsidiary of the Limited Partnership and is the primary borrower under the Credit Facility. DBRS Limited (“DBRS”) has assigned a debt rating of 'BBB' (high) to KMCU with a stable trend. A BBB rating is the fourth highest of DBRS’ ten rating categories for long-term debt, which range from AAA (highest) to D (lowest). DBRS uses “high”

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and “low” designations on ratings from AA to C to indicate the relative standing of securities being rated within a particular rating category. The absence of a “high” or “low” designation indicates that a rating is in the middle of the category. A BBB rating indicates that, in DBRS’s view, the rated securities are of adequate credit quality, with the acceptable protection of principal and interest; however, issuers are fairly susceptible to adverse changes in financial and economic conditions. DBRS also assigned a Pfd-3 (high) stable rating to our preferred shares.

When a significant event occurs that directly impacts the credit quality of a particular entity or group of entities, DBRS will attempt to provide an immediate rating opinion. However, if there is uncertainty regarding the outcome of the event, and DBRS is unable to provide an objective, forward-looking opinion in a timely fashion then the ratings of the issuer will be placed “Under Review.”

Standard & Poor’s Rating Services (“S&P”) has assigned a rating of 'BBB' corporate credit rating to the Company and KMCU and an issue-level rating of 'BBB' to KMCU's Credit Facility with a stable outlook. A BBB rating is the fourth highest rating, of S&P’s ten rating categories for long-term debt which range from “AAA” to “D.” The ratings from “AA” to “CCC” may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories. A “BBB” rating indicates that in S&P’s view the obligor has adequate capacity to meet its financial commitments. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. S&P also assigned a P-3 (high) rating to our preferred shares.

Moody’s Investors Service (“Moody’s”) has assigned a Baa3 senior secured rating to KMCU’s Credit Facility with a stable outlook. 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.

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.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion 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 business segments from which we generally expect 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 expansion capital expenditures are not deducted from DCF, while those classified as sustaining capital expenditures are.


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Our capital expenditures for the year ended December 31, 2017, and the amount that is expected to be spent to sustain and grow our business in 2018 are as follows:
 
2017
 
Expected 2018
(In millions of Canadian dollars)
 
 
 
Sustaining capital expenditures
43.0

 
64.1

Expansion capital expenditures(a)
632.7

 
1,899.3

________
(a)
2017 includes $57.2 million of net changes from accrued capital expenditures, contractor retainage, capitalized equity financing costs and other. Expected 2018 includes $71.0 million of budgeted capitalized equity financing costs.

Off Balance Sheet Arrangements

As at December 31, 2017, we had no off balance sheet arrangements other than those included below under “—Contractual Obligations and Commercial Commitments.”

Contractual Obligations and Commercial Commitments