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As filed with the Securities and Exchange Commission on November 3, 2017

File No.:       

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10

 

General Form for Registration of Securities

Pursuant to Section 12(b) or (g) of the Securities Exchange Act of 1934

 

KINDER MORGAN CANADA LIMITED

(Exact name of registrant as specified in its charter)

 

Alberta, Canada (State or other jurisdiction of incorporation)

N/A (I.R.S. Employer Identification No.)

 

Suite 2700, 300 — 5th Avenue S.W.

Calgary, Alberta T2P 5J2
(Address of principal executive offices, including zip code)

 

(403) 514-6780
(Registrant’s telephone number, including area code)

 

Copies to:
Troy L. Harder
Bracewell LLP
711 Louisiana Street, Suite 2300
Houston, Texas 77002

 

Securities to be registered pursuant to Section 12(b) of the Act: None.

 

Securities to be registered pursuant to Section 12(g) of the Exchange Act:

 

Restricted Voting Shares

(Title of class)

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or emerging growth company. See 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	o	Smaller reporting company  o
Emerging Growth Company	x

 

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 7(a)(2)(B) of the Securities Act.    x

 

 

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EXPLANATORY NOTE

 

We are an Alberta, Canada corporation that completed the initial public offering in Canada of our Restricted Voting Shares in May 2017. Such shares are traded on the Toronto Stock Exchange under the symbol “KML.” We are filing this registration statement on Form 10 pursuant to Section 12(g) of the Exchange Act to submit to Exchange Act reporting in the United States.

 

Once the registration of the Restricted Voting Shares becomes effective, we will be subject to the requirements of Section 13(a) of the Exchange Act, including the rules and regulations promulgated thereunder, which will require us to file, among other things, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and proxy or information statements with the SEC. Although we may be entitled to use certain abridged forms available to “foreign private issuers,” we have chosen to use the forms applicable to U.S. domestic issuers to satisfy our reporting obligations.

 

Capitalized terms used throughout this document are defined in “ Defined Terms ” 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 “US$” are to the currency of the United States. See “ Abbreviations, Conversions, Exchange Rates and Market Data .”

 

Our principal office is located at Suite 2700, 300 — 5 th  Avenue S.W., Calgary, Alberta T2G 4Y5, and our telephone number at such office is (403) 514-6780.

 

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

This document 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 Trans Mountain Expansion Project 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 Distributable Cash Flow;

 

·                                           the future commercial viability of our business;

 

·                                           the realization of benefits deriving from future growth projects, including the Trans Mountain Expansion Project 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 distributable cash flow 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;

 

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·                                           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 the successful development of the Trans Mountain Expansion Project. 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) the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project;

 

·                                           changes in the level or nature of support from the federal government and various provincial governments (including the Alberta and British Columbia 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;

 

·                                           changes in public opinions or damage to our reputation;

 

·                                           the resolution of issues relating to interested third party and/or Aboriginal rights, title and consultation;

 

·                                           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;

 

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·                                           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, 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;

 

·                                           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.

 

The prospective financial information included in this document has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP (Canada) has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP (Canada) does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP (Canada) report included in this document relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so. This prospective financial information was not prepared with a view toward compliance with published guidelines of the

 

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Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants for preparation, presentation of prospective financial information.

 

The forward-looking statements contained in this registration statement are expressly qualified by the foregoing cautionary statements.

 

DEFINED TERMS

 

In this document, unless otherwise indicated, the following terms shall have the indicated meanings. Singular words include the plural and vice versa and words importing any gender include all genders. A reference to an agreement means the agreement as it may be amended, supplemented or restated from time to time.

 

“ ABCA ” means the Business Corporations Act (Alberta) and the regulations thereunder, as amended from time to time;

 

“ AER ” means the Alberta Energy Regulator;

 

“ ASU ” means Accounting Standards Update;

 

“ BC OGC ” means the British Columbia Oil and Gas Commission;

 

“ BCUC ” means the British Columbia Utilities Commission;

 

“ Board of Directors ” means the board of directors of the Company;

 

“ Canadian Securities Laws ” means the securities legislation and regulations thereunder of each province and territory of Canada and the rules, instruments, policies and orders of each Canadian securities regulator made thereunder;

 

“ CAPP ” means the Canadian Association of Petroleum Producers;

 

“ Class A Units ” means the Class A limited partnership units of the Limited Partnership, as further described under “ Item 11. Description of Registrant’s Securities to be Registered ”;

 

“ Class B Units ” means the Class B limited partnership units of the Limited Partnership, as further described under “ Item 11. Description of Registrant’s Securities to be Registered ”;

 

“ CO 2 ” means carbon dioxide;

 

“ CO 2e ” means carbon dioxide equivalent;

 

“ Company Voting Shares ” means, collectively, the Restricted Voting Shares and the Special Voting Shares;

 

“ Cooperation Agreement ” means the cooperation agreement, between the Company, the General Partner, the Limited Partnership, KMCC, KM Canada Terminals and Kinder Morgan (in respect to certain provisions only) entered into in connection with the IPO, as described under “ Item 7. Certain Relationships and Related Transactions and Director Independence—Agreements Between the Company and Kinder Morgan—Cooperation Agreement” ;

 

“ Exchange Act ” means the United States Securities Exchange Act of 1934 , as amended from time to time;

 

“ FASB ” means the U.S. Financial Accounting Standards Board;

 

“ FERC ” means the U.S. Federal Energy Regulatory Commission;

 

“ GAAP ” means generally accepted accounting principles in the United States that the SEC has identified as having substantial authoritative support, as supplemented by Regulation S-X under Exchange Act, as amended from time to time;

 

“ General Partner ” means Kinder Morgan Canada GP Inc., a corporation organized under the laws of the Province of Alberta and a wholly-owned subsidiary of the Company;

 

“ GP Units ” means the general partnership units of the Limited Partnership held by the General Partner, as further described under “ Item 11. Description of the Registrant’s Securities to be Registered ”;

 

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“ investment grade ” means an issuer credit rating of BBB- or higher by S&P, BBB (low) or higher by Dominion Bond Rating Service or Baa3 or higher by Moody’s Investors Service;

 

“ Kinder Morgan ” means Kinder Morgan, Inc., and where the context requires, includes its majority-owned and/or controlled subsidiaries;

 

“ Kinder Morgan Canada Group ” means, 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 ” means 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;

 

“ KM Canada Marine Terminal ” means KM Canada Marine Terminal Limited Partnership, an indirect, wholly-owned partnership of the Limited Partnership;

 

“ KM Canada North 40 ” means KM Canada North 40 Limited Partnership, an indirect, wholly-owned partnership of the Limited Partnership;

 

“ KM Canada Rail ” means Kinder Morgan Canada Rail Holdings GP Limited, an indirect, wholly-owned subsidiary of the Limited Partnership;

 

“ KM Canada Terminals ” means KM Canada Terminals ULC, an indirect wholly-owned subsidiary of Kinder Morgan;

 

“ KMI Loans ” means certain indebtedness of the Operating Entities owed to Kinder Morgan and incurred prior to the IPO as more fully described in Note 5 “ Transactions with Related Parties ” to the September 30, 2017 unaudited interim financial statements attached hereto;

 

“ KMCC ” means Kinder Morgan Canada Company, an indirect, wholly-owned subsidiary of Kinder Morgan;

 

“ KMCI ” means Kinder Morgan Canada Inc., an indirect, wholly-owned subsidiary of the Limited Partnership;

 

“ KMCU ” means Kinder Morgan Cochin ULC, a direct, wholly-owned subsidiary of the Limited Partnership;

 

“ Land Agreements ” means rights-of-way, right of entry orders, Crown pipeline agreements, pipe rack agreements, temporary working space agreements, crossing agreements, road use agreements, and other similar land-related agreements which are required for construction, operation and maintenance of TMPL, the Trans Mountain Expansion Project, the Puget Sound pipeline system, the Jet Fuel pipeline system, the Canadian Cochin pipeline system or our other pipeline assets;

 

“ Limited Partnership ” means Kinder Morgan Canada Limited Partnership, a limited partnership formed under the laws of the Province of Alberta;

 

“ Limited Partnership Agreement ” means the limited partnership agreement of the Limited Partnership, as amended from time to time, the terms of which are further described under “ Item 11. Description of Registrant’s Securities to be Registered — Limited Partnership Units ”;

 

“ LP Units ” means, collectively, the Class A Units and the Class B Units;

 

“ NEB ” means the National Energy Board;

 

“ NEB Act ” means the National Energy Board Act (Canada) and the regulations thereunder, as amended from time to time;

 

“ Operating Entities ” means the corporation, 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, KM Canada North 40, KM Canada Rail, KMCI, TM Pipeline L.P., TM Jet Fuel, TM Puget Sound and Trans Mountain;

 

“ PADD ” means Petroleum Administration for Defense District;

 

“ PHMSA ” means the U.S. Department of Transportation Pipeline Hazardous Materials Safety Administration;

 

“ Pipeline Safety Act ” means the Pipeline Safety Act (Canada) and the regulations thereunder, as amended from time to time;

 

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“ Restricted Voting Shares ” means the restricted voting shares in the capital of the Company, as further described under “ Item 11. Description of Registrant’s Securities to be Registered ”;

 

“ S&P ” means Standard and Poor’s Rating Service;

 

“ SCADA ” or “ SCADA computer system ” means the Supervisory Control and Data Acquisition computer system;

 

“ SEC ” means the U.S. Securities and Exchange Commission;

 

“ Securities Act ” means the United States Securities Act of 1933 , as amended from time to time;

 

“ SEDAR ” means the System for Electronic Document Analysis and Retrieval;

 

“ Series 1 Preferred Shares ” means the 12,000,000 cumulative redeemable minimum rate reset Preferred Shares, Series 1, as further described under “ Item 11. Description of Registrant’s Securities to be Registered—Preferred Shares ”;

 

“ Series 2 Preferred Shares ” means the cumulative redeemable floating rate Preferred Shares, Series 2, as further described under “ Item 11. Description of Registrant’s Securities to be Registered—Preferred Shares ”;

 

“ Series 1 Preferred Units ” means the preferred limited partnership units, Series 1 in the Limited Partnership, as further described under “ Item 11. Description of Registrant’s Securities to be Registered—Limited Partnership Units—Preferred Shares ”;

 

“ Services Agreement ” means the services agreement between the Company, the General Partner, the Limited Partnership and KMCI entered into in connection with the IPO, as described under “ Item 7. Certain Relationships and Related Transactions, and Director Independence— Agreements Between the Company and Kinder Morgan—Services Agreement ”;

 

“ Special Voting Shares ” means the special voting shares in the capital of the Company, as further described under “ Item 11. Description of Registrant’s Securities to be Registered ”;

 

“ Tax Act ” means the Income Tax Act (Canada) and the regulations thereunder, as amended from time to time;

 

“ Terminals ” means, collectively, the Company’s merchant (non-regulated) terminal assets comprised of the Vancouver Wharves Terminal, the Edmonton South Terminal, the North 40 Terminal, the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal, as further described under “ Item 1. Business—Terminals Segment ”;

 

“ TM Jet Fuel ” means Trans Mountain (Jet Fuel) Inc., an indirect, wholly-owned subsidiary of the Limited Partnership;

 

“ TM Pipeline L.P. ” means Trans Mountain Pipeline L.P., a wholly-owned partnership of the Limited Partnership;

 

“ TMPL ”, “ TMPL system ” or “ Trans Mountain pipeline ” means the Trans Mountain pipeline system (including the related terminals assets) that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries on the West Coast, as further described under “ Item 1. Business—Pipeline Segment ”;

 

“ TM Puget Sound ” means Trans Mountain Pipeline (Puget Sound) LLC, which is an indirect, wholly-owned subsidiary of the Limited Partnership;

 

“ Trans Mountain ” means Trans Mountain Pipeline ULC and its predecessors, the general partner of TM Pipeline L.P. and the holder of the NEB certificates for the TMPL system, which is a direct, wholly-owned subsidiary of the Limited Partnership;

 

“ Trans Mountain Expansion Project ” means the proposed project to expand the TMPL as described under the heading “ Item 1. Business—Pipeline Segment — The Trans Mountain Expansion Project ”;

 

“ TSX ” means the Toronto Stock Exchange;

 

“ WCSB ” means the Western Canadian Sedimentary Basin.

 

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ABBREVIATIONS, CONVERSIONS, EXCHANGE RATES AND MARKET DATA

 

In this document, the following abbreviations have the meanings set forth below:

 

/d	=	per day
LLC	=	limited liability company
MBbl	=	thousand barrels
MMBbl	=	million barrels
MMtonne	=	million metric tons
WTI	=	West Texas Intermediate
WCS	=	Western Canada Select

 

 

All references to cubic feet measurements are at a pressure of 14.73 pounds per square inch.

 

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units), both of which are used in this document.

 

To Convert From		To		Multiply By
cubic feet		cubic meters		0.0283
cubic meters		cubic feet		35.301
barrels		cubic meters		0.159
cubic meters		barrels		6.290
feet		meters		0.305
meters		feet		3.281
kilometers		miles		0.621
miles		kilometers		1.609
millimeters		inches		0.039

 

The following tables set forth for the period indicated the rate used to convert one Canadian dollar to U.S. dollars, expressed in U.S. dollars.

 

		December 31, 2012		December 31, 2013		December 31, 2014		December 31, 2015		December 31, 2016		September 30, 2016		September 30, 2017
Daily Closing Rate		1.0051		0.9402		0.8620		0.7225		0.7448		0.7624		0.8013

 

		2012		2013		2014		2015		2016
Annual Average Rate		1.0006		0.9711		0.9064		0.7828		0.7556
Yearly High Closing Rate		1.0326		1.0171		0.9406		0.8502		0.7981
Yearly Low Closing Rate		0.9606		0.9340		0.8570		0.7163		0.6859

 

Certain market, independent third party and industry data contained in this document is based upon information from government or other independent industry publications and reports or based on estimates derived from such publications and reports. Government and industry publications and reports generally indicate that they have obtained their information from sources believed to be reliable, but we have not conducted our own independent verification of such information. This document also includes certain data respecting, among other things, WCSB crude supply, pipeline capacity, tolls and toll ranges, rail costs and industry activity levels, expected commodity prices and foreign exchange rates and commodity supply and demand projections generated by independent third parties.

 

In particular, certain information included in this document has been extracted directly from the following publicly available sources: (i) the 2016 CAPP Crude Oil Forecasts, Markets & Transportation, 2016-0007 report, which has been referenced with respect to WCSB pipeline takeaway capacity and crude supply, anticipated bitumen production growth, crude products consumption, demand and markets and crude products pricing information; (ii) the Environment and Climate Change Canada report respecting the Trans Mountain Expansion Project dated November, 2016, which has been referenced with respect to crude by rail transportation cost estimates; and (iii) the statistics and analysis of the U.S. Energy Information Administration, which has been referenced with respect to Alaskan North Slope crude supply data. In addition, the third party reportable right of way releases data provided in this document was compiled, and industry average pipeline release values calculated, from raw 2013 — 2015 PHMSA incident and annual report data.

 

While we believe this data to be reliable, market and industry data is subject to variations and cannot be verified with complete certainty due to limits on the availability and reliability of raw data, the voluntary nature of the data gathering process, and

 

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other limitations and uncertainties inherent in any statistical survey. In addition, this market, independent third party and industry data has been prepared as of a specific date and therefore does not contemplate changes in facts and circumstances following such date. We have not independently verified any of the data from independent third party sources referred to in this document or ascertained the underlying assumptions relied upon by such sources.

 

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T ABLE OF CONTENTS

 

				Page
EXPLANATORY NOTE				i
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS				i
DEFINED TERMS				iv
ABBREVIATIONS, CONVERSIONS, EXCHANGE RATES AND MARKET DATA				vii
INFORMATION REQUIRED IN REGISTRATION STATEMENT				1
ITEM 1.		BUSINESS		1
		Our Corporate History and Background		1
		Our Business Segments		3
		Pipeline Segment		5
		Cochin Pipeline System		21
		Terminals Segment		22
		Operations Management		27
		Regulatory Matters		30
ITEM 1A.		RISK FACTORS		33
		Risks Relating Our Business		33
		Risks Relating to Regulation		40
		Risks Relating to Our Relationship with Kinder Morgan		43
		Risks Relating to Ownership of Restricted Voting Shares		43
ITEM 2.		FINANCIAL INFORMATION		46
		Selected Historical Financial Information		46
		Interest Rate Risk		46
		Foreign Exchange Risk		47
		Counterparty Credit Risk		47
		Allowance for Funds Used During Construction		47
		Growth Estimates		47
		Management’s Discussion and Analysis		48
ITEM 3.		PROPERTIES		67
ITEM 4.		SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		67
ITEM 5.		DIRECTORS AND EXECUTIVE OFFICERS		67
		Directors and Executive Officers Biographical Information		69
		Code of Ethics		71
		Compliance with Section 16(a) of the Exchange Act		71
		Board Committees		71
ITEM 6.		EXECUTIVE COMPENSATION		73
		Compensation of Executive Officers		73
		Compensation of Directors		75
		Compensation Committee Interlocks and Insider Participation		77
ITEM 7.		CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		77
		Certain Relationships and Related Transactions		77
		Independence of the Board of Directors		79
ITEM 8.		LEGAL PROCEEDINGS		79

 

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ITEM 9.		MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	79
		Market Information	79
		Dividends	79
		Related Stockholder Matters	80
ITEM 10.		RECENT SALES OF UNREGISTERED SECURITIES	81
ITEM 11.		DESCRIPTION OF REGISTRANT’S SECURITIES TO BE REGISTERED	81
		Voting Rights	82
		Restrictions on Further Issuances	82
		Dividends	82
		Special Voting Shares	82
		Preferred Shares	83
		Limited Partnership Units	84
		Takeover Bid Protection — Coattail Arrangements	86
		Dividend Reinvestment Plan	86
ITEM 12.		INDEMNIFICATION OF DIRECTORS AND OFFICERS	87
ITEM 13.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	88
ITEM 14.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	88
ITEM 15.		FINANCIAL STATEMENTS AND EXHIBITS	89

 

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INFORMATION REQUIRED IN REGISTRATION STATEMENT

 

ITEM 1.                 BUSINESS.

 

Our Corporate History and Background

 

We were incorporated under the ABCA on April 7, 2017. The Limited Partnership was formed under the laws of the Province of Alberta and the General Partner was incorporated under the ABCA prior to the closing of our initial public offering (“ IPO ”) in Canada on May 25, 2017. The Limited Partnership owns, directly and indirectly, the Operating Entities. See “ Item 11. Description of Registrant’s Securities to be Registered—Limited Partnership Units. ” Unless otherwise noted or the context otherwise requires, the disclosure in this document is presented on the basis that the entirety of our Operating Entities is and has been, for all relevant periods, under common control, management and ownership. In reviewing the information set forth herein, you should note that we indirectly hold an approximate 30% interest in the Operating Entities through our minority interest in the Limited Partnership. Accordingly, while our consolidated financial information presents 100% of the Limited Partnership, our interest in the Limited Partnership is only 30%.

 

Prior to the closing of the IPO, the Limited Partnership acquired the Operating Entities from Kinder Morgan, through its subsidiaries KMCC and KM Canada Terminals, in exchange for the issuance to KMCC and KM Canada Terminals of Class B Units of the Limited Partnership and Special Voting Shares of the Company. Immediately following closing of our IPO, we used the proceeds from our IPO to indirectly subscribe for Class A Units representing an approximate 30% interest in the Limited Partnership, following which the Class B Units held indirectly by Kinder Morgan represented, in the aggregate, an approximate 70% interest in the Limited Partnership. KMCI, the Company, the General Partner and the Limited Partnership then entered into the Services Agreement pursuant to which KMCI provides certain operational and administrative services in connection with the management of the business and affairs of the Kinder Morgan Canada Group, and the Company, the Limited Partnership, KMCC, KM Canada Terminals and Kinder Morgan entered into the Cooperation Agreement. See “ Item 7. Certain Relationships and Related Transactions, and Director Independence—Agreements between the Company and Kinder Morgan. ”

 

Immediately following our IPO, purchasers under our IPO held 100% of issued and outstanding Restricted Voting Shares, comprising approximately 30% of the votes attached to all outstanding Company Voting Shares, and Kinder Morgan indirectly owned 100% of the Special Voting Shares, comprising approximately 70% of the votes attached to all outstanding Company Voting Shares.

 

On August 15, 2017, we issued 12,000,000 cumulative redeemable minimum rate reset Preferred Shares, Series 1 to the public at a price of $25.00 per share, and the Limited Partnership issued 12,000,000 corresponding preferred limited partnership units, Series 1 to the General Partner.  See “ Item 11. Description of Registrant’s Securities to be Registered—Preferred Shares. ”

 

The intercorporate relationships of the Company, the Limited Partnership and their material subsidiaries, partnerships and joint ventures are as follows:

 

1

 

 

Notes :

 

(1)          Approximate percentages based on ownership of total outstanding Company Voting Shares.

(2)          Approximate percentages based on ownership of total outstanding Class A Units and Class B Units. Distributions on the Series 1 Preferred Units will be made prior to any distributions on the Class A Units and Class B Units.

(3)          Held indirectly through KMCC and KM Canada Terminals.

(4)          Other operating entities include KMCU, KM Canada Marine Terminal Limited Partnership, KM Canada North 40, KM Canada Rail Holdings GP Limited, Kinder Morgan Canada Inc., Trans Mountain Pipeline L.P., Trans Mountain (Jet Fuel) Inc., Trans Mountain Pipeline (Puget Sound) LLC and Trans Mountain.

 

2

 

Each Class B Unit is accompanied by a Special Voting Share, conferring on the holder voting rights at meetings of our shareholders. Kinder Morgan owns (indirectly through KMCC and KM Canada Terminals) 100% of the outstanding Special Voting Shares and is our largest voting shareholder, with approximately 70% of the total outstanding Company Voting Shares. See “ Item 11. Description of Registrant’s Securities to be Registered—Special Voting Shares .”

 

Our Business 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: (a) Pipelines, which is comprised of the TMPL system including the Westridge Marine Terminal and other related terminaling assets, the Puget Sound pipeline system (“ Puget Sound ”) and the Jet Fuel pipeline system (“ Jet Fuel ”), as described below under “— Pipeline Segment ” and the Canadian Cochin pipeline system (“ Cochin ”), as described below under “— Cochin Pipeline System ”; and (b) Terminals, which is comprised of the Vancouver Wharves Terminal and the terminals located in the Edmonton, Alberta area, as described below under “— Terminals Segment .”

 

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 its existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;

 

·                                           leverage economies of scale from incremental acquisitions and expansions of assets that fit within its strategy and are accretive to cash flow; and

 

·                                           maintain a strong balance sheet and maximize value for its investors.

 

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Our business is comprised of a portfolio of strategic energy infrastructure assets across Western Canada. For over 60 years, the Trans Mountain pipeline system has been the only Canadian crude oil and refined products export pipeline with North American West Coast tidewater access. Current transportation capacity on the TMPL is approximately 300,000 barrels per day (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 British Columbia, 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 million barrels of liquids annually. In Washington State, 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 the Canadian Cochin pipeline system, which forms part of the Cochin pipeline system transporting light condensate to Fort Saskatchewan, Alberta, traversing two provinces in Canada and four states in the United States. 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.

 

Pipeline Segment

 

Trans Mountain

 

Trans Mountain Oil Pipe Line Company was established on March 21, 1951. Construction of the TMPL commenced in 1952 and the first shipment of oil reached Trans Mountain’s Burnaby Terminal on October 17, 1953. The initial capacity of the pipeline system was 150,000 barrels per day. Since 1953, the capacity of the TMPL has been increased a number of times by twinning parts of the line and adding associated facilities.

 

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In 2008, the Anchor Loop project was completed, which project 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, British Columbia, just west of Mount Robson Provincial Park. The Anchor Loop project increased the capacity of the pipeline system from 260,000 barrels per day to 300,000 barrels per day and involved the installation of two new pump stations.

 

The TMPL is approximately 1,150 kilometers long, beginning in Edmonton, Alberta and terminating on the west coast of British Columbia in Burnaby. Twenty-three active pump stations located along the TMPL route maintain the 300,000 barrels per day 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 barrels per day nominal capacity of the pipeline has been determined based on a throughput mix of 20% heavy oil and 80% light oil. As shown in the table below respecting TMPL’s historical throughput apportionment, 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 barrels per day and if it is delivering only heavy oil, the system’s delivery capacity is closer to approximately 280,000 barrels per day.

 

 

Notes:

 

(1)          Apportionment = 1 - (accepted nominations / total nominations).

(2)          On May 1, 2015 the NEB changed the nomination methodology by limiting the amount of accepted nominations to the best 18 of the last 24 months of historical nominations. This resulted in a decrease in nominations because there was less opportunity to achieve more accepted nominations.

 

The Trans Mountain pipeline 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 Trans Mountain’s tariff requirements, which include technical specifications for any products accepted for transportation in the TMPL system. 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, as illustrated below. Products that do mix are re-refined for use.

 

 

In order to optimize batches to achieve maximum throughput, Trans Mountain 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 barrels per day capacity to accumulate their product and have it pumped at the throughput capacity 300,000 barrels per day so as not to slow the line

 

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down. In addition to maximizing throughput, the tanks are also used to minimize the mixing or product interfaces. See “— Trans Mountain Terminals ” and “— Terminals Segment ” below.

 

As at the date hereof, the Trans Mountain pipeline 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 Terminals

 

Edmonton Terminal

 

The TMPL system 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 million barrels. 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 million barrels of total storage capacity, are currently used by Trans Mountain to serve the TMPL system’s regulated service. As noted above, these tanks are used by Trans Mountain to facilitate batching and maximize throughput on the TMPL mainline. See “— Trans Mountain ” above. The remaining 15 tanks at the Edmonton Terminal (referred to as the “Edmonton South Terminal” and as illustrated in the image below), ranging in size from 250,000 barrels to 400,000 barrels and constituting approximately 5.1 million barrels of the total storage capacity, are leased to KM Canada North 40’s Edmonton 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 built out 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 the Trans Mountain Expansion Project, 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 system. 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—Edmonton South Terminal ” below.

 

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In addition to its service as a storage and terminaling facility, the Edmonton Terminal houses the primary control center for the Trans Mountain pipeline, the Puget Sound pipeline, the Jet Fuel pipeline, the North 40 Terminal and the line to the Edmonton Rail Terminal. It will also control the supply lines to the Base Line Terminal, once the terminal is in service. Transfer of centralized control for the Westridge Marine Terminal to this control center is anticipated to be completed during the latter part of 2017. The control center located at the Edmonton Terminal does not operate the Cochin pipeline system, which is controlled from the United States. See “— Terminals Segment ” below.

 

Kamloops Terminal

 

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

 

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, British Columbia. The terminal is used to stage oil for delivery 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 Washington State via the Puget Sound pipeline system and two of which are used to route the product on the TMPL mainline to Burnaby, British Columbia.

 

Burnaby Terminal

 

The Burnaby Terminal, located in Burnaby, British Columbia, is the terminus of the TMPL mainline. It receives both crude oil and refined products for temporary storage and distribution 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 million barrels.

 

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

 

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Westridge Marine Terminal

 

The Westridge Marine Terminal is located within the Burrard Inlet in Burnaby, British Columbia. 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 the Trans Mountain pipeline system onto barges and tankers and to receive jet fuel to the three tanks at the terminal used for delivery into the Jet Fuel pipeline system.

 

The Westridge Marine Terminal houses three storage tanks, that are currently being leased to a third party, with total storage capacity of approximately 395,000 barrels. Significant modifications are planned for the Westridge Marine Terminal as part of the Trans Mountain Expansion Project. Limited construction activity on such modifications began in September 2017. See “— The Trans Mountain Expansion Project—Project Description ” below.

 

Puget Sound Pipeline System

 

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

 

 

The Puget Sound pipeline system 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 barrels per day (when transporting primarily light oil), with approximately 191,000 barrels per day transported in 2016. The transit time of products on the Puget Sound pipeline system 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 the TMPL system have, and following completion of the Trans Mountain Expansion Project will continue to have, the option to deliver their product to the Puget Sound pipeline system.

 

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Jet Fuel Pipeline System

 

The Jet Fuel pipeline system 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. The BC OGC regulates the integrity and safety of the pipeline and the BCUC regulates the Jet Fuel pipeline’s tolls.

 

 

The Trans Mountain Expansion Project

 

Background

 

At an estimated total capital cost of approximately $7.4 billion (including capitalized financing costs), upon completion, the Trans Mountain Expansion Project will provide western Canadian crude oil producers with an additional 590,000 barrels per day of shipping capacity and tidewater access to the western United States (most notably Washington State, 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 the 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 the Trans Mountain Expansion Project. 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 barrels per day based on a capacity of 890,000 barrels per day (the maximum amount that Trans Mountain anticipated the NEB would authorize) following completion of the Trans Mountain Expansion Project.

 

In January 2013, Trans Mountain made an application to the NEB for approval of the proposed transportation service to be provided; and the proposed toll methodology to be used in the event the Trans Mountain Expansion Project was approved by the NEB (key matters included approval of negotiated rates for contracted shippers, a 10% premium embedded in the toll methodology for spot shippers over 15-year contract shippers, the limitation of contract capacity to 80% of total capacity and the apportionment methodology for spot capacity). In May 2013, the NEB approved the commercial terms of the expansion proposal. See “ —Customers and Contractual Relationships—Expansion Shipping Agreements ” below.

 

In December 2013, Trans Mountain submitted its formal facilities application to the NEB. The NEB review process included approximately 1,650 participants, including commenters and approximately 400 intervenors. Key steps in the process included several rounds of information requests by the NEB and intervenors, information request responses from Trans Mountain and opportunities for intervenors to file written evidence. The process also included an oral hearing of Aboriginal groups’ traditional evidence in 2014 and oral argument respecting the Trans Mountain Expansion Project as a whole in 2015 and 2016.

 

On May 19, 2016, following a 29-month review, the NEB recommended that the Government of Canada approve the Trans Mountain Expansion Project, subject to the satisfaction of 157 required conditions. These conditions apply during various stages of the proposed project’s lifecycle, including before construction, during construction and during the operation of the expanded TMPL system. The conditions are designed to reduce possible risks that were identified by the NEB during the application process. The

 

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conditions cover a wide range of areas including safety and integrity, emergency preparedness and response, environmental protection, ongoing consultation with stakeholders, socio-economic matters, financial responsibility and affirmation of commercial support. The conditions, which are acceptable to us on both a cost and schedule basis, are comprised of five general conditions, 98 conditions that must be satisfied prior to commencing construction, 35 conditions that must be satisfied prior to commencing operations and 19 conditions that will require activities after operations have commenced.

 

On November 29, 2016, the Government of Canada approved the Trans Mountain Expansion Project, and on December 1, 2016, the NEB issued its Certificate of Public Convenience and Necessity. The approval of the Trans Mountain Expansion Project by the Government of Canada was provided in the context of a broader pipeline plan developed by the federal government designed to grow the Canadian economy while protecting environmentally sensitive areas. As a result, along with the announcement of the Trans Mountain Expansion Project approval, the Government of Canada also noted that, among other things: (i) a moratorium on persistent oil tankers along British Columbia’s north coast has been implemented; (ii) more than $300 million had been committed to Indigenous groups by Kinder Morgan under mutual benefit agreements and the Government of Canada had agreed to provide funding for an Indigenous advisory and monitoring committee to work with federal regulators and Kinder Morgan to oversee environmental aspects of the Trans Mountain Expansion Project and other projects throughout their applicable life cycles; (iii) before any shipping from the Trans Mountain Expansion Project begins, a recovery plan for the southern resident killer whale population and a $1.5 billion national ocean protection plan will be implemented to improve marine safety and responsible shipping; (iv) Trans Mountain is required to develop a construction-related emissions offset plan to achieve zero net emissions; and (v) through the climate leadership plan, the Government of Alberta had committed to cap oil sands emissions at 100 megatonnes of CO 2  per year to limit future potential upstream greenhouse gas emissions.

 

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

 

In addition, on January 11, 2017, the Government of British Columbia announced that the Trans Mountain Expansion Project had met the British Columbia Government’s five conditions relating to world-leading marine and land oil spill response, protection and recovery measures for British Columbia’s coast and land areas, environmental reviews, First Nations consultations and participation and economic agreements that reflect the level and nature of the risk the province bears with a heavy oil project. The meeting of such conditions is an important precursor to receiving approval of additional provincial permits. In connection with the British Columbia conditions, Trans Mountain has entered into an agreement to contribute a guaranteed amount of $25 million annually for 20 years to the British Columbia Government, and up to a maximum of $50 million annually, depending on spot volume shipments. The British Columbia Government has stated that all of the proceeds received from Trans Mountain pursuant to this agreement will be used and applied to a new British Columbia Clean Communities Program, or similar program, which has a mandate to provide funding for projects and initiatives that protect the environment and benefit communities, including local projects that protect, sustain and restore British Columbia’s natural and coastal environments.

 

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

 

The NEB-approved commercial terms for the Trans Mountain Expansion Project contemplate a capital cost risk sharing investment structure whereby the capital costs associated with the Trans Mountain Expansion Project will be classified into two segments: capped costs and uncapped costs. Uncapped costs, which account for approximately 24% of the capital cost of the Trans Mountain Expansion Project, will include some of the higher risk capital cost components of the Trans Mountain Expansion Project whereby any cost overruns will be reflected in increased tolls. These components include: (i) the price of steel for pipe; (ii) difficult pipeline construction spreads totaling approximately 10% of the Trans Mountain Expansion Project specifically, one mountain spread through the Coquihalla Summit near Hope, British Columbia and one urban spread between Langley and Burnaby, British Columbia (including the Burnaby tunnel); (iii) land acquisition costs between Langley and Burnaby, British Columbia; and (iv) all consultation and accommodation costs, including with respect to Aboriginal and non-Aboriginal communities. Costs above or below the uncapped cost amount will be reflected in higher or lower tolls for shippers by approximately $0.07 per barrel per $100 million of capital cost change. This structure is anticipated to not only allow Trans Mountain to recover its costs with respect to overruns on uncapped costs but also to earn returns following such cost recovery.

 

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Capped costs, which are expected to account for approximately 76% of the capital cost of the Trans Mountain Expansion Project, include all other costs associated with the construction of the Trans Mountain Expansion Project not classified as uncapped costs. Any capped costs above the pre-determined amount are the responsibility of Trans Mountain; however, capped costs below the pre-determined amount are reflected in lower tolls for shippers by approximately $0.07 per barrel per $100 million of capital cost change. Kinder Morgan has spent years advancing engineering designs for the Trans Mountain Expansion Project and has developed a comprehensive construction plan in conjunction with several of the world’s leading engineering, procurement and construction and general contractor construction companies. As of September 30, 2017, remaining cash construction costs on the Trans Mountain Expansion Project were estimated to be approximately $6.0 billion, excluding capitalized interest. The economics of the Trans Mountain Expansion Project are expected to remain attractive even in cases of significant cost increases and schedule delays; however, such increases or delays will affect the amount of capital raised and the timing of the realization of earnings and cash flows from the Trans Mountain Expansion Project.

 

Trans Mountain delivered the final cost estimate and tolls to shippers in February 2017. At that time 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 barrels per day (or 3% of the previously committed barrels). These 22,000 barrels per day were subsequently recommitted during an additional supplemental open season process in March 2017. As a result of the Trans Mountain Expansion Project’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 barrels per day, representing approximately 80% of the expanded system’s capacity (the maximum amount under the regulated limit imposed by the NEB). This maximum level of recommitment highlights the strong market demand for the expanded system’s takeaway capacity and has better aligned the Trans Mountain Expansion Project shipper composition with the changing Canadian crude producer landscape.

 

Following provincial elections in B.C. on May 9, 2017, the New Democratic Party (“ NDP ”) and the Green Party agreed to form a government resulting in a 44 seat majority in the B.C. legislature, consisting of 41 NDP seats and 3 Green Party seats. One component of the agreement between the NDP and the Green Party was the statement of intent to utilize all means available to the B.C. government to oppose the Trans Mountain Expansion Project. Despite this pledge to oppose the Trans Mountain Expansion Project, recently we were granted access to approximately 140 kilometers of B.C. Crown land and are advancing the additional provincial permits that enable us to start pre-construction work in B.C. In addition, we have received conditional permits from the NEB, B.C. Environmental Assessment Office, Vancouver Fraser Port Authority, and the federal Department of Fisheries and Oceans to proceed with water work at Westridge. Provincial and federal judicial reviews relating to project approvals are underway, with decisions from the British Columbia Supreme Court and the Federal Court of Appeal expected in the coming months.  The Trans Mountain Expansion Project has also received opposition from the City of Burnaby, B.C. After many months of working in good faith to obtain municipal permits from the City of Burnaby without success, we recently petitioned the NEB to permit us to proceed with work at the Westridge and Burnaby terminals under the terms and conditions of the Certificate of Public Necessity and Convenience and applicable NEB orders.  We remain willing to continue to work with the B.C. government and local officials; however, we cannot predict the impact that this change in government or opposition from the City of Burnaby may have on our ability to complete the Trans Mountain Expansion Project on current expected timelines or budget. See “Item 2. Financial Information—Management’s Discussion and Analysis—Results of Operations— Current Business Developments—Trans Mountain Expansion Project Construction Progress.”

 

The final investment approval with respect to the Trans Mountain Expansion Project was obtained May 25, 2017 and limited construction activity began in September of 2017. The Trans Mountain Expansion Project is targeted to be in service at the end of 2019. However, construction preparation activity is off to a slower start than planned in the project schedule primarily due to the time required to file for, process and obtain all necessary permits and regulatory approvals. We are assessing construction mitigation plans that maintain the current in-service schedule of December 31, 2019. Such plans will rely upon continued progress towards schedule-critical regulatory approvals and will assess the acceleration of construction activities that are behind schedule. Absent this mitigation, we currently estimate that project completion could be delayed by up to nine months. We will continue to evaluate spend and schedule in light of progress on permitting, and other relevant factors, in order to preserve and enhance shareholder value. All project planning and schedule mitigation efforts include cost management measures and spend control to maximize project returns, including a reduction in 2017 spending that has already been implemented. See “ Item 2. Financial Information —Management’s Discussion and Analysis—Results of Operations—Current Business Developments—Trans Mountain Expansion Project Construction Progress .”

 

Project Description

 

Upon the completion of the proposed Trans Mountain Expansion Project, the TMPL system is anticipated to have capacity of 890,000 barrels per day. The proposed expansion of the TMPL system 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 British Columbia, 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.

 

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

 

 

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

 

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

 

·                                           reactivating two 24 inch (610 mm) outside diameter buried pipeline segments that have been 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.

 

The Trans Mountain Expansion Project will result in two continuous pipelines between Edmonton and Burnaby:

 

·                                           Line 1 is expected to have a capacity of 350,000 barrels per day of light crude oil; and

 

·                                           Line 2 is expected to have a capacity of 540,000 barrels per day of heavy crude oil.

 

The existing TMPL has been operating safely for more than 60 years and its location is known to 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 Trans Mountain Expansion Project 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 avoids the need for additional construction in the highly sensitive Jasper National Park region.

 

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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 the Trans Mountain Expansion Project which will support mainline operation include:

 

·                                           adding 12 new pump stations;

 

·                                           reactivating the existing Niton pump station and adding one pumping unit at the Sumas pump station; and

 

·                                           deactivating some elements of the existing Wolf, Alberta and Blue River, British Columbia pump stations.

 

The major components of the associated facilities of the Trans Mountain Expansion Project include:

 

·                                           the addition of 20 new above-ground storage tanks, including the construction of four new tanks 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 mainline block valves work to limit the volume and consequences associated with a pipeline leak 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.

 

In addition, the Trans Mountain Expansion Project requires two power line connections to the BC Hydro system, an approximately 24 kilometer line to connect to a power station in Kingsvale, British Columbia and an approximately 1.5 kilometer connection to a power station in Black Pines, British Columbia. BC Hydro requires Trans Mountain to either build such lines and turn them over to BC Hydro for a minimal amount or continue to own, maintain and operate them. We are currently considering selling these power line assets to a third party and entering into a services contract in relation thereto.

 

Currently, up to approximately five vessels per month are loaded with heavy crude oil at the Westridge Marine Terminal. Upon completion of the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project. 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 barrels per day capacity of the expanded system, up to 630,000 barrels per day 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 the Trans Mountain Expansion Project.

 

We have signed a number of agreements with prime construction contractors and are currently in negotiations with other construction contractors to construct the various pipeline spreads on the Trans Mountain Expansion Project, 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. An illustration of the Trans Mountain Expansion Project pipeline spreads is set out below.

 

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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.

 

Trans Mountain continues to work towards obtaining all necessary permits, and we began limited construction on the Trans Mountain Expansion Project in September 2017. Construction preparation activity on the Trans Mountain Expansion Project is off to a slower start than planned in the project schedule due primarily to the time required to file for, process and obtain all necessary permits and regulatory approvals. We are assessing construction mitigation plans that maintain the current in-service schedule of December 31, 2019. That planning, with our contractors, will rely upon continued progress towards schedule-critical regulatory approvals and will assess the acceleration of construction activities that are behind schedule. Absent this mitigation, we currently estimate that project completion could be delayed by up to nine months. We will continue to evaluate spend and schedule in light of progress on permitting, and other relevant factors, in order to preserve and enhance shareholder value. See “ Item 2. Financial Information —Management’s Discussion and Analysis—Results of Operations—Current Business Developments—Trans Mountain Expansion Project Construction Progress ” and “ Item 1A. Risk Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped .”

 

As illustrated in the table below, assuming we are able to maintain the estimated project cost and the targeted in-service schedule of December 2019, the construction of the Trans Mountain Expansion Project is expected to add approximately $106 million of incremental Adjusted EBITDA associated with capitalized equity financing costs to our annual Adjusted EBITDA for 2018. In its first full fiscal year of operations following the completion of the Trans Mountain Expansion Project, the expansion is expected to result in a net increase to our annual Adjusted EBITDA of more than $900 million based solely on 707,500 barrels per day of contracted volumes and associated tolls and associated operating costs. Of this 707,500 barrels per day of contracted capacity, 658,000 barrels per day are contracted under a 20-year term and 49,500 barrels per day are contracted under a 15-year term. Excluded from this estimate is any value for the 182,500 barrels per day (or approximately 20% of total capacity) that will be available for spot shippers at a rate that is equal to a 10% premium on the 15-year contract rate, with the 15-year contract rate being higher than the 20-year contract rate. The incremental Adjusted EBITDA estimates provided in this document are based on a number of important assumptions including, without limitation, that (a) both the Trans Mountain Expansion Project and the Base Line Terminal will be completed on time and on budget; and (b) upon being placed in service, such assets will operate and generate revenue in accordance with current expectations, including with respect to the currently forecasted utilization driven by contracted volumes, associated approved tolls and estimated operating costs. Estimated operating costs are based on our historical experience with similar operating assets. As a result of the significance of these assumptions and the substantial risks to which these projects are subject, the actual impact of each of the Trans Mountain Expansion Project and Base Line Terminal on incremental projected Adjusted EBITDA, and our business generally, will vary and may vary materially. See “ Item 2. Financial Information—Growth Estimates, ” “ Item 1A. Risk Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped.” and “ Item 2. Financial Information —Management’s Discussion and Analysis—Results of Operations—Non-GAAP Financial Measures ” as well as the other information set forth herein.

 

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Based on the slower start discussed above, and absent mitigation, we currently estimate that project completion could be delayed by up to nine months.  To the extent the project is delayed, impacts could include higher overall project construction costs, higher capitalized equity financing costs (depending on the amount and pace of spending as compared to our original project schedule), and a delay in Adjusted EBITDA generation from the project.

 

Financial Highlights and Growth Estimates(1)(2)

 

 

Notes:

 

(1)          See “ Item 2. Financial Information—Growth Estimates ”, “ Item 1A. Risk Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped ” and “ Item 2. Financial Information —Management’s Discussion and Analysis—Results of Operations—Non-GAAP Financial Measures .”

 

(2)          Approximate Canadian/United States exchange rates of $0.91. $0.78 and $0.76 were used in 2014, 2015 and 2016, respectively. For periods beyond 2017, an exchange rate of $0.80 was assumed. Amounts in the “Financial Highlights and Growth Estimates” table above, including the corresponding notes, may contain differences due to rounding.

 

(3)          Base business, while expected to be relatively stable, is subject to re-contracting and other risks. See “ Item 2. Financial Information—Growth Estimates ” and “ Item 1A. Risk Factors .”

 

Upon completion of the Trans Mountain Expansion Project, 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

 

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expected continued demand in excess of 100,000 barrels per day on the 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 the project. 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 Washington State 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).

 

Alaskan North Slope Supply and Asian Crude Demand

 

 

Note:

 

(1)          Alaskan North Slope crude supply data sourced from U.S. Energy Information Administration and Asian crude demand sourced from CAPP 2016 Crude Oil Forecast, Markets and Transportation 2016-0007.

 

As of September 30, 2017, remaining cash construction costs on the Trans Mountain Expansion Project were estimated to be approximately $6.0 billion, excluding capitalized interest. We currently expect that a significant majority of the capital expenditure requirements related to the Trans Mountain Expansion Project will be funded through a combination of the Credit Facility, dividend and distribution reinvestments, term debt and the issuance of preferred equity and common equity. Our targeted funding mix during construction and following completion of the Trans Mountain Expansion Project is intended to be consistent with an investment grade credit rating.

 

See “ Item 1A. Risk Factors—Risks Relating to Our Business—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 .”

 

Customers and Contractual Relationships

 

Existing Shipping Agreements

 

The TMPL mainline 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 Trans Mountain takes custody of its shippers’ products, it does not own any of the product it ships. The TMPL system 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 California, Washington State and Asia.

 

Since late 2010, the TMPL system has been meaningfully over-subscribed, resulting in pipeline apportionment (nominating less volumes for shipment than shippers request). Shippers on the TMPL system are generally large and well-capitalized. In 2016, the top ten shippers on the Trans Mountain pipeline accounted for approximately 70% of the revenue generated from the system. Of these shippers, as a percentage of such revenue generated, 85% have, or are subsidiaries of a parent entity that has, an investment grade credit rating (however, such parent entity may not be a guarantor), with approximately 66% being rated A- to AA+ by S&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

 

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do not have a credit rating. In alphabetical order, current shippers on the Trans Mountain pipeline system include 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, Trans Mountain has entered into negotiated toll settlements with its shippers to establish final tolls on the TMPL system. We believe that negotiated settlements are advantageous from a cost perspective and may provide opportunities for additional returns.

 

In February 2016, the NEB approved Trans Mountain’s 2016 to 2018 (inclusive) negotiated toll settlement. The toll settlement provides for a three-year term and includes a rollover provision and a Trans Mountain Expansion Project 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 the TMPL system 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 determined by the shared service model using a methodology approved by the NEB. These costs are allocated to the system based on usage and are escalated at a set index during the toll settlement period. In addition, the toll settlement agreement provides power and capacity incentives. Specifically, 50% of the British Columbia power costs savings are allocated to the shipper and 50% are allocated to the pipeline system, and 75% of the transmission power costs savings are allocated to the shipper and 25% are allocated to pipeline sharing. The settlement agreement also provides for a capacity incentive which is allocated 50% to the shipper and 50% to the pipeline system above a formulaic 96% capacity target. Revenue variances resulting from volume are recovered from shippers in the following year. Trans Mountain’s current negotiated toll settlement includes a provision for extension, if the extension is mutually acceptable to Trans Mountain and the shipper, up until the Trans Mountain Expansion Project in-service date.

 

In 2011, Trans Mountain received approval from the NEB to implement firm service for 54,000 barrels per day of service to the Westridge Marine Terminal, and charge a premium on such barrels to fund expansion projects on the TMPL system. This service and the premiums associated with it will be in effect until the earlier of the in-service date of the TMPL expansion and ten years from the date of implementation. The premiums are approved to be used by Trans Mountain to offset the cost of projects designed to enhance existing and future operations including development costs relating to the Trans Mountain Expansion Project and equate to a total of approximately $28.6 million per year. As of December 31, 2016, $34 million had been used to construct a 250,000 barrel tank and associated infrastructure at the Edmonton Terminal and $104 million had been used to offset the development costs of the Trans Mountain Expansion Project. As part of its firm service implementation, 27,000 barrels per day of existing TMPL capacity was reallocated to the Westridge Marine Terminal, increasing the terminal’s allocation to a total of 79,000 barrels per day.

 

Rates charged on the Puget Sound pipeline system are regulated by the FERC and are based on a cost 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, 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 which were a basis for such rates. To date, no such complaints have been made. In 2016 approximately 80% of the revenue on the Puget Sound pipeline originated from customers 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).

 

The Jet Fuel pipeline system 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, Trans Mountain 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. The Jet Fuel pipeline system then transports such jet fuel to the Vancouver International Airport. Through this arrangement and the jet fuel shipped from the Burnaby refinery, the Jet Fuel pipeline system has a BCUC-approved negotiated settlement that ends in 2018.

 

Expansion Shipping Agreements

 

The NEB approval for the Trans Mountain Expansion Project requires that no less than 60% of the expanded system’s capacity remain contracted and that no shipper termination rights remain outstanding prior to the commencement of construction. As noted above, as a result of the Trans Mountain Expansion Project’s open season processes, 13 companies have entered into transportation service agreements with Trans Mountain, one having a 15-year term and 12 having a 20-year term, for a total of 707,500 barrels per day, representing approximately 80% of the expanded system’s capacity (the maximum amount under the regulated limit imposed by the NEB). As illustrated below, 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

 

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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.

 

 

Note:

 

(1)          On a barrels per day basis, approximately 93% of the post-expansion shippers have, or have a parent entity with, an investment grade credit rating (although such parent may not be a guarantor). Credit rating information sourced from Bloomberg.

 

Where a particular shipper is not investment grade or no support provider is available, Trans Mountain 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 Trans Mountain Expansion Project-related transportation service agreements provide for a sharing of risks between Trans Mountain and its shippers during the development stage, including the construction of the Trans Mountain Expansion Project 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.

 

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).

 

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The fixed toll to be paid by shippers under the Trans Mountain Expansion Project-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 system’s nominal capacity (182,500 barrels per day), 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.

 

Competition

 

Trans Mountain 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 Washington State 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 Washington State 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 British Columbia will continue to impact the long-term value and economics of the TMPL system.

 

Despite this potential competitive pressure, we believe that the TMPL system, both pre- and post-expansion, will maintain its strong competitive position as a result of a number of factors. For example, contracted tariff rates on Trans Mountain after the expansion will range from approximately $5.00 per barrel 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. dollars, 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. The Government of Alberta, as of January 2017, reported the differential between WTI (light oil at Cushing Oklahoma) and WCS (heavy crude at Hardisty, Alberta) was approximately U.S.$15.00 per barrel.

 

In addition, the TMPL offers significant optionality and flexibility to its customers. Its tolling methodology and transportation contracts have been designed to promote high operating standards while remaining cost-competitive for the foreseeable future. Trans Mountain remains the only pipeline that transports oil and other liquid petroleum products from the WCSB to the West Coast of Canada and the United States and this important outlet provides producers in the WCSB with improved market access and market diversification. Further, due to recent changes in U.S. legislation, oil from the Alaska North Slope may now be sold to markets outside of the United States. To the extent this additional access to alternative markets for Alaskan producers increases overall demand from Washington State and California refineries, the TMPL system, including through its Puget Sound pipeline connection to four refineries in Washington State, will be in a position to facilitate supply to such markets for WCSB producers. As evidence of these competitive advantages, capacity on the TMPL has been over-subscribed since 2010 and approximately 80% of the capacity of the TMPL upon completion of the Trans Mountain Expansion Project is subject to long-term firm commitments. Similarly, throughput on the Puget Sound pipeline system has remained strong in recent years, with 2015 and 2016 experiencing increases from previous years of over 15% and 30%, respectively, though throughput in the first half of 2017 returned to a similar level seen in the first half of 2015. In 2016, the Puget Sound pipeline transported average volumes of approximately 191,000 barrels per day, comprising approximately one-third of the collective capacity of all refineries in the Anacortes and Ferndale area.

 

Historically, the Jet Fuel pipeline has transported a significant proportion of the jet fuel used at the Vancouver International Airport. However, the airport also receives jet fuel through other means including trucks and, recently, an affiliate of each of the airlines using the airport received approval to construct a jet fuel barge-receiving terminal near the airport. In 2016, the entity owning the Burnaby refinery supplying products to Jet Fuel for shipment announced its intention to sell the refinery and in April 2017 announced that it had reached an agreement with a third party for such sale. As a result of this pending sale, we are unable to predict whether, and to what extent, that refinery will continue to supply jet fuel to the Jet Fuel pipeline. 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 the Jet Fuel pipeline in the future. To the extent it becomes uneconomic to continue shipping jet fuel to the Vancouver International Airport, we estimate that the decommissioning and abandonment costs of the Jet Fuel pipeline would be in the range of $2.0 million to $3.0 million, subject to regulatory approval of the BCUC and the BC OGC. We continue to assess our options relating to the Jet Fuel assets.

 

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Potential Growth Opportunities

 

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

 

The Puget Sound pipeline is capable of being expanded to increase its capacity to approximately 500,000 barrels per day from its current capacity of 240,000 barrels per day. See “ Item 1. Business—Our Business Segments .”

 

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

 

See “ Item 1A. Risk Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped .”

 

Cochin Pipeline System

 

Overview

 

The Cochin pipeline system consists of a 12 inch (305 mm) diameter pipeline which spans from Kankakee County, Illinois to Fort Saskatchewan, Alberta, totaling approximately 2,452 kilometers. The 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 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 Cochin, the U.S. portion of Cochin and the Canadian Cochin pipeline system are interdependent (including with respect to volumes shipped and financial and contractual obligations) and, as the bulk of the tariffs on the Cochin pipeline system are governed by a joint international tariff, revenue is shared between the U.S. portion of Cochin and the Canadian Cochin pipeline system.

 

 

In 2014, Kinder Morgan reversed the western leg of the Cochin pipeline system (which was previously used primarily to ship propane into the United States) 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 ”). The Cochin pipeline system is currently capable of transporting approximately 95,000 barrels per day of light condensate (constrained by the U.S. portion of the Cochin pipeline). If additional receipt points in Canada are established, and future demand supports it, throughput on the Canadian Cochin pipeline system has the potential to reach approximately 110,000 barrels per day. This additional volume would most likely come from the Bakken oil play in North Dakota.

 

KMCU is the operator of the Canadian Cochin pipeline system, 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 the Canadian Cochin pipeline system.

 

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Customers and Contractual Relationships

 

The Cochin pipeline system has three primary customers who, among them, have total contractual take-or-pay commitments of 85,000 barrels per day. 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. The Cochin pipeline 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.

 

Competition

 

Diluent used in Canada is primarily supplied by local production in Canada (both conventional and unconventional condensates, as well as refinery light naphtha) and imports from the United States. Historically, as production of bitumen in Canada increased, local Canadian diluent sources were insufficient to meet demand. First imports to Canada were by rail; however, rail transport of diluent has a higher cost basis than transport via pipeline and is thus limited to areas that do not have access to pipeline transportation. In 2014, the Cochin Reversal Project came online, bringing in an additional 95,000 barrels per day of pipeline import capacity and offering a low all-in cost for transportation of diluent to the Ft. Saskatchewan, Alberta region. While Cochin is exposed to competition from other pipeline systems that are capable of transporting significant volumes of diluent, 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. As evidence of this, through July of 2017, Cochin has had an approximate 92% utilization rate.

 

Potential Growth Opportunities

 

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). The Cochin pipeline system has an additional 15,000 barrels per day of capacity on the Canadian section of the pipeline 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 barrels per day, we are currently evaluating a number of other opportunities to utilize the existing 15,000 barrel per day 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, ND to allow for delivery of additional volumes onto the Cochin pipeline 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 NGL 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 Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped .”

 

Terminals Segment

 

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 “— Customers and Contractual Relationships ” and “— Competition ” below.

 

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Edmonton Area Terminals

 

 

Vancouver Wharves Terminal

 

 

Edmonton Rail Terminal

 

 

Vancouver Wharves Terminal

 

Located in North Vancouver, British Columbia, 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 million barrels 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 British Columbia 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.

 

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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 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 million barrels along with associated outbound pumps, meters and pipe connections to other facilities. As a result of the completion of the TMPL expansion, Trans Mountain currently expects to recall two of the tanks in merchant service at the Edmonton South Terminal upon the completion of the Trans Mountain Expansion Project 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. See “— Pipeline Segment — Trans Mountain Terminals —Edmonton Terminal ” above.

 

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 (which is 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), the TMPL system, 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.

 

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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 barrels per day. 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 barrels per day, for a total of 210,000 barrels per day. 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 barrels per day, 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 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 million barrels of crude oil capable of being stored at such terminals.

 

Alberta Crude Terminal

 

An unincorporated 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 Corp. 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 barrels per day 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 million barrels 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 will be a merchant crude oil storage terminal located on land at Keyera’s Alberta Enviro Fuels facility in Sherwood Park, Alberta. Construction commenced on this project in the second half of 2015. The initial build is expected to have 12 tanks with a total capacity of 4.8 million barrels. As of September 30, 2017, on-site facility mechanical work was materially completed and significant progress was made on the off-site pipe rack and bridges required to connect the terminal with other Edmonton-area facilities, including the North 40 Terminal, Edmonton South Terminal, and Edmonton Rail Terminal. Commissioning of the new-build facility is expected to begin in the first quarter of 2018 with tanks phased into service throughout that year. Our total investment for the Base Line Terminal project is expected to be approximately $396 million, including costs associated with the construction of a new pipeline segment that will be funded solely by us, with total spend to date of $250 million and remaining spend in 2017 of $33 million. The project is forecast to be on schedule and on budget. 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 “— Customers and Contractual Relationships ” and “— Competition ” below. The project is forecast to be on schedule and on budget.

 

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 million barrels of total storage (including regulated tankage) capacity in the Edmonton area upon completion of the Base Line Terminal.

 

The Base Line Terminal is expected to increase our annual Adjusted EBITDA by approximately $22 million during 2018 and approximately $44 million on an annualized basis thereafter based on contracted volumes, rates and expected operating costs. See the table set forth above titled “ Financial Highlights and Growth Estimates .” See also “ Item 2. Financial Information—Growth Estimates ” and “ Item 1A. Risk Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped ” and “ Item 2. Financial Information —Management’s Discussion and Analysis—Results of Operations—Non-GAAP Financial Measures .”

 

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Customers and Contractual Relationships

 

The Terminals business services over 20 liquids customers, made up of a diverse mix of production, refining, marketing and integrated companies, and over 12 bulk customers at any given point in time. Approximately 75% (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 Terminals customers account for approximately 45% of total Terminals revenue and the top ten Terminals customers account for approximately 75% of total Terminals 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 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, 2016, the remaining life of the contracts at our terminals in Edmonton, Alberta ranged between approximately one and 18 years, with an average 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, 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.

 

Competition

 

Vancouver Wharves is currently the largest mineral concentrate export and import facility on the west coast of North America. With respect to its liquids operations, Vancouver Wharves is the only merchant terminal for import and export distillates in Port Metro Vancouver. Competing liquids facilities are significantly smaller than Vancouver Wharves and Vancouver Wharves enjoys a superior and highly flexible dock, better storage, berth depth and ship loading capacity and unsurpassed rail access, when compared to the assets of the liquids terminal competitors. In terms of bulk products handling competition, significant capital investment and regulatory approval requirements are barriers to entry for new bulk or liquid handling terminals on the West Coast. While there are currently a number of potential competitive grain terminal projects contemplated or underway which may increase the competitive pressures on the Vancouver Wharves grain business, as a result of the Vancouver Wharves berth depth, rail access and location, we believe that the grain business will be able to maintain its strong competitive position. In addition, Vancouver Wharves enjoys a distinct advantage in the mineral concentrates business as it is one of only three facilities on the west coast of North America that is currently permitted to handle these commodities. Given this fact, along with its strategic location, Vancouver Wharves is well positioned to retain its current business and attract new concentrate business dependent on mine location. Sulphur competition is limited as Vancouver Wharves currently contracts with the owner of the only other sulphur terminal in Port Metro Vancouver.

 

Edmonton and Hardisty, Alberta are the two primary crude oil hubs in Canada, with a majority of crude gathering pipelines feeding into the Edmonton area. The TMPL system and the Enbridge Mainline System also originate in the Edmonton Area from Sherwood Park. While limited land availability and the significant capital investment required to enter this business are significant barriers to entry, the Alberta-based Terminals are subject to competition from other truck and rail terminals and storage facilities which are either in the general vicinity of the facilities or have gathering systems that are, or could potentially extend into, areas served by the Alberta-based terminals. The Alberta-based Terminals currently enjoy a leading market position in the Edmonton hydrocarbon storage and rail transporting business. The Terminals’ assets located in Alberta have excellent inbound and outbound connectivity, both in terms of the facilities to which these terminals are connected and the diversity of product that may be stored and transported by them. In addition to the considerable market access offered to customers via pipeline, through its Alberta Crude Terminal and Edmonton Rail Terminal origination crude-by-rail loading facilities, the Alberta-based Terminals are able to offer customers the flexibility to move crude oil to markets without pipeline access, supplement deliveries to markets with constrained pipeline capacity and supply different or unique crude types to refineries looking to maintain quality. In addition, revenues from the Terminals business are largely fixed and generally not subject to short term fluctuations in oil and gas market prices; however, as with the rest of our business, as the long-term terminals contracts expire, while fees for tankage are generally expected to increase on

 

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renewal, the storage and handling services of the Terminals segment’s terminals will have additional exposure to the longer-term trends in supply and demand for oil and gas products.

 

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 (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 Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped .”

 

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 effectively to serve our stakeholders and 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, the Canadian Cochin pipeline system, the TMPL system 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 the Trans Mountain, Jet Fuel, and Puget Sound pipeline systems 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.

 

Employees

 

At the head office located in Calgary, Alberta, a total of 168 staff service our business. Non-union Canadian employees are employed by KMCI and provide services to each of the Canadian operating assets. On the current TMPL system, 100 staff are employed in Alberta in Edmonton, Stony Plain, Edson, and Jasper. Through central British Columbia in the towns of Blue River, Clearwater, and Kamloops, an additional 33 operations personnel maintain the pipeline, while in southern British Columbia, 60 staff are located in Hope, Sumas and Burnaby. Seventeen staff are dedicated exclusively to work on the Canadian Cochin pipeline system 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, 11 staff at the Base Line Terminal and 62 staff at Vancouver Wharves.

 

With respect to the operation of Vancouver Wharves, KM Canada Marine Terminals is a member of the British Columbia 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.

 

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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 304 personnel for KMCI, 102 of which are temporary employees. These contracted employees augment the KMCI workforce and are utilized throughout our business, but they are primarily utilized on the Trans Mountain Expansion Project.

 

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. See “ —Our Business Segments ” above.

 

The integrity of each of the TMPL system and the Canadian Cochin pipeline system 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 system (including the Puget Sound and Jet Fuel pipeline systems) and the Cochin pipeline system has its own control center wherein CCOs monitor pipeline operations and operating conditions 24 hours a day, seven days a week using the sophisticated 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.

 

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 Segment ” 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, Trans Mountain 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 the Trans Mountain pipeline system to minimize response time. These caches typically include river boats and response trailers equipped with booms, pumps and liquid storage. Trans Mountain also provides

 

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training sessions to first responders along the TMPL system. These sessions, along with regular exercises, provide Trans Mountain with the opportunity to maintain working relationships with first responders and to facilitate mutual awareness of response programs.

 

Trans Mountain 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 Canada. Vancouver Wharves, KM Canada Marine Terminal is also a member of WCMRC for the liquid bulk distillates exports and imports. While WCMRC’s primary role is to respond to ship and terminal based oil spills, Trans Mountain maintains its position as a shareholder with respect to both the Westridge Marine Terminal and the pipeline. Trans Mountain 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, British Columbia.

 

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.

 

Trans Mountain, along with Suncor Energy Inc., Imperial Oil, Chevron Canada R&M ULC 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 British Columbia coast. To address changes in maritime shipping that will result from the Trans Mountain Expansion Project, 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 illustrated below, will satisfy certain of the NEB conditions for the Trans Mountain Expansion Project and double capacity and half 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. See “ —Pipeline Segment—Trans Mountain Terminals—Westridge Marine Terminal ” and “ —Terminals Segment—Vancouver Wharves Terminal ” above.

 

 

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.

 

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

 

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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 the TMPL system 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 the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project, and over the last five years, Trans Mountain has had more than 40,000 engagements with 133 separate Aboriginal communities with respect to the Trans Mountain Expansion Project and remains committed to continuing this engagement through the entire life of the project. See “ Item 1A. Risk Factors—Risks Relating to Our Business ” and “ Item 1A. Risk Factors — Risks 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 CO 2  emissions. In addition, KMCI was awarded an Emerald Award in 2010 for the excellent environmental initiatives associated with the Anchor Loop expansion project.

 

Regulatory Matters

 

Canadian Regulation

 

National Energy Board

 

Both the TMPL system and the Canadian Cochin pipeline system are primarily 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 of capital and return on equity. 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, the TMPL system currently operates under a fixed toll arrangement 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 the Canadian Cochin pipeline system. 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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British Columbia 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 the TMPL system are regulated by the BC OGC, which maintains certain incremental requirements with respect to, among other things, environmental management, pipeline crossings, integrity management and damage prevention.

 

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

 

Climate Change and GHG Regulations

 

We generate greenhouse gas (“ GHG ”) emissions through our operations, which GHG emissions 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 (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 will require 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 will 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 will 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 CO 2e  per annum as well as all residents are subject to a carbon tax of $20 per metric ton of carbon used. This tax will increase to $30/metric ton on January 1, 2018. Facilities that emit greater than 100,000 metric tons of CO 2e  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 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 CO 2e . To address the competiveness of trade-exposed sectors, the SGER will 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 British Columbia 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 CO 2e . 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.

 

British Columbia 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 British Columbia 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 CO 2e  annually beginning April 1, 2018 until rates are equal to $50 per metric ton of CO 2e  on April 1, 2021.

 

The imposition of carbon pricing is not expected to have a material direct effect on the TMPL system or the Trans Mountain Expansion Project. Existing and pending carbon taxes were considered in Trans Mountain’s $7.4 billion cost estimate for the Trans Mountain Expansion Project 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 system. In addition and as noted above, Trans Mountain has take-or-pay contracts for approximately 80% of the expanded throughput following the completion of the Trans Mountain Expansion Project. See “ Item 1A. Risk Factors—Risks Relating to Our Business. ”

 

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United States Regulation

 

Puget Sound is a common carrier interstate pipeline subject to the regulatory authority of the FERC under the provisions of the ICA; it has tariffs on file at the FERC and files quarterly and annual reports at FERC, among other regulatory requirements. Transportation by Puget Sound is of petroleum that crosses the international boundary and is delivered to refineries and/or terminals near the Washington State coast — i.e., the shipments are exclusively interstate in nature. Puget Sound is also subject to pipeline safety oversight and authority of the 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.

 

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 the Trans Mountain Expansion Project. 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) the Trans Mountain Expansion Project, 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.

 

Risks Relating to Our Business

 

Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped.

 

Our ability to commence and complete construction on the Trans Mountain Expansion Project, 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 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, public opposition, blockades, legal and regulatory proceedings (including judicial reviews, injunctions, detailed route hearings and land acquisition processes), delays to ancillary projects that are required for the Trans Mountain Expansion Project (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. In particular, detailed route hearings will be required where valid route objections arise. The NEB must approve the detailed route for the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project. 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 the Trans Mountain Expansion Project can commence. These additional processes and approvals could result in delays, increased costs and/or cost overruns or other issues with respect to the project.

 

We are currently undertaking significant projects and may, in the future, further expand existing assets and construct new assets. 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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We must obtain and maintain certain governmental, administrative and contractual rights to construct and operate our pipelines, including the rights to construct and operate pipelines on other owners’ land. If we were to lose these rights or be required to relocate our pipelines, our business could be negatively affected. See also “— 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 ” below .

 

While a number of key governmental approvals have been received with respect to the Trans Mountain Expansion Project, the completion, timing and costs of the Trans Mountain Expansion Project are still subject to significant risks. Following the NEB’s May 2016 recommendation of the Trans Mountain Expansion Project, a number of parties were granted leave to seek judicial review of the NEB’s recommendation. Similarly, following the receipt by Trans Mountain of the Certificate of Public Convenience and Necessity in December 2016, a number of parties were granted leave to seek judicial review of the Governor in Council’s approval of the Trans Mountain Expansion Project. 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 the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project proceed and, in the case of the Government of Canada, the Governor in Council’s approval of the Trans Mountain Expansion Project. 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, the Trans Mountain Expansion Project may be subject to additional significant regulatory reviews, there may be significant changes to the Trans Mountain Expansion Project plans, further obligations or restrictions may be imposed or the Trans Mountain Expansion Project may be stopped altogether. In the event that an applicant is unsuccessful at the Federal Court of Appeal, they may further appeal such decision to the Supreme Court of Canada and in the event that an 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, the Trans Mountain Expansion Project may be subject to additional significant regulatory reviews, there may be significant changes to the Trans Mountain Expansion Project plans, further obligations or restrictions may be imposed or the Trans Mountain Expansion Project 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 at the Supreme Court of British Columbia seeking to quash the Environmental Assessment Certificate that was issued by the BC Environmental Assessment Office. In the event that an applicant for judicial review is successful, among other things, the Environmental Assessment Certificate may be quashed, provincial permits may be revoked, the Trans Mountain Expansion Project may be subject to additional significant regulatory reviews, there may be significant changes to the Trans Mountain Expansion Project plans, further obligations or restrictions may be imposed or the Trans Mountain Expansion Project may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of British Columbia, they may further seek to appeal the decision to the British Columbia Court of Appeal. Any decision of the British Columbia 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 the Trans Mountain Expansion Project prior to the determination of such judicial review applications by the applicable court, the applicants may seek an injunction from the court to prevent us from proceeding with construction until the litigation has been resolved. If such injunctive relief is granted, the Trans Mountain Expansion Project may be significantly delayed or stopped altogether, and we may incur additional costs.

 

Additional efforts to block or revise the Trans Mountain Expansion Project (including through new litigation, changes in government, 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 the Trans Mountain Expansion Project (for example, the strong and likely unyielding opposition of the City of Burnaby), may cause such projects, including the Trans Mountain Expansion Project, 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, 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 the Trans Mountain Expansion Project 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 Trans Mountain Expansion Project plans or the imposition of further obligations or restrictions, could materially impact the overall feasibility or economic benefits of the Trans Mountain Expansion Project, which, in turn, would have a material adverse effect on the Trans Mountain Expansion Project (including the anticipated increases to Adjusted EBITDA referenced in this document) and, consequently, our business.

 

Although we have signed a number of agreements with prime construction contractors, we are currently in negotiations with other construction contractors to construct the various pipeline spreads on the Trans Mountain Expansion Project. 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 the Trans Mountain Expansion Project 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

 

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less favorable to us or contractual counterparties fail to perform their duties in accordance with the terms of the applicable contract, the Trans Mountain Expansion Project may be delayed or we may incur significant additional costs.

 

In addition to the Trans Mountain Expansion Project, we are currently undertaking certain other growth projects and a number of potential growth opportunities have been identified in this document. Such projects, and any potential growth opportunities that are undertaken will be subject to the same or similar risks as those identified above for the Trans Mountain Expansion Project and 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. Other than as disclosed in this document, we have made no definitive decisions to undertake any other material growth projects.

 

We could be adversely affected by our substantial level of debt.

 

We must incur substantial indebtedness to fund capital expenditure requirements related to the Trans Mountain Expansion Project. See Note 3 “ Debt ” to the Interim Consolidated Financial Statements attached hereto for a description of our indebtedness. As of September 30, 2017, we had approximately $165.0 million of debt outstanding.  A significant increase in our debt levels could have significant negative consequences, including in connection with the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project. We will have limited amounts of internally generated cash flows to fund growth capital expenditures and acquisitions. Kinder Morgan has stated that the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project, 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

 

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funds that are required to continue operating our business or complete the Trans Mountain Expansion Project 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.

 

The Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project. 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 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 the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project. 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 Trans Mountain Expansion Project-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 the Trans Mountain Expansion Project and the issuance of the British Columbia Environmental Assessment Certificate allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of the Trans Mountain Expansion Project were not adequately considered. In addition to the potential impacts of such claims noted above under “ —Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped ,” a successful claim respecting Aboriginal title along any portion of the Trans Mountain Expansion Project route could result in, among other things, a significant increase in costs and/or cost overruns, Trans Mountain Expansion Project delays, reduced support of the federal, provincial or municipal governments for the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project plans or additional obligations and/or restrictions placed on Trans Mountain in respect of the Trans Mountain Expansion Project, any of which could materially impact the overall feasibility or economic benefits of the Trans Mountain Expansion Project which, in turn, could have a material adverse effect on the Trans Mountain Expansion Project and, consequently, our business. In certain circumstances, these claims, if successful, could result in the total stoppage of the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project, 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

 

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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 the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project) 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.

 

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 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.

 

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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.

 

We are covered by an insurance program that is renewed annually and has $1 billion worth of financial capacity for spill events in accordance with the Pipeline Safety Act (see “ Item 1. Business—Regulatory Matters—Canadian 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 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 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 has 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

 

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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 British Columbia 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 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 “ Item 1. Business. ”

 

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)

 

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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 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 (the Trans Mountain pipeline system and the Canadian Cochin pipeline system) 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 the Trans Mountain pipeline system and Canadian Cochin pipeline system, we do not maintain dedicated abandonment trusts for our Puget Sound pipeline system, Jet Fuel pipeline system or Terminals. Additional or unexpected expenditures incurred in respect of abandonment costs could decrease distributable cash flow 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 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 the Trans Mountain

 

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Expansion Project. 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 the Trans Mountain Expansion Project 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 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.

 

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 we 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 distributable cash flow. See “ Item 1. Business—Regulatory Matters—Canadian Regulation—Climate 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.

 

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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 “ Item 1. Business—Regulatory Matters—Canadian 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 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 distributable cash flow.

 

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 distributable cash flow 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 distributable cash flow 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, distributable cash flow and financial condition.

 

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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 KM Canada Terminals, 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 7. Certain Relationships and Related Transactions, and Director Independence ” and “ —Risks Relating to Ownership of Restricted Voting Shares—There are limitations on voting power of the holders of Restricted Voting Shares ” below.

 

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 is 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, 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 has 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 7. Certain Relationships and Related Transactions and Director Independence—Agreements Between the Company and Kinder Morgan. ”

 

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

 

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 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

 

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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 7. Certain Relationships and Related Transactions and Director Independence—Agreements Between the Company and Kinder Morgan ” and “ Item 11. Description of Registrant’s Securities to be Registered. ”

 

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, 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 2 Preferred Shares are senior to the Restricted Voting Shares with respect to priority in payment of dividends and the distribution of assets in the event of liquidation, but such shares are not entitled to vote absent a default in payment of dividends. 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 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 preferred 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 units. Additionally, an issuance of additional securities by the Limited Partnership, including preferred 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 the Trans Mountain Expansion Project, 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 the Trans Mountain Expansion Project, a balance of debt and equity capital of 60% and 40%. See Note 3 “ Debt ” to the Interim Consolidated Financial Statements attached hereto. We expect to issue additional equity over the course of the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project 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 the Trans Mountain Expansion Project, 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 Business—We will require access to external capital ” above.

 

Cash dividend payments are not guaranteed.

 

The payment of dividends under our dividend policy is not guaranteed and amounts of such dividends could fluctuate with the performance of our business. Additionally, the Series 1 Preferred Shares and Series 2 Preferred Shares are, 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 and the Series 2 Preferred Shares prohibit us 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.

 

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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 will depend on distributions from the Limited Partnership, as determined in the discretion of the General Partner, which distributions 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 ABCA; contractual constraints; tax laws; and other relevant factors (including the Trans Mountain Expansion Project being over budget, delayed or stopped). There can be no guarantee as to the amount of distributions from the General Partner and any number of factors could cause the General Partner to revise its policies and/or strategies respecting distributions. Certain terms of the Credit Facility may prevent or 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 at any time in response to such circumstances or for other reasons. A decline in the market price or liquidity, or both, of the Restricted Voting 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 the Trans Mountain Expansion Project or the total stoppage of the Trans Mountain Expansion Project; (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.

 

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ITEM 2.                                                 FINANCIAL INFORMATION.

 

Selected Historical Financial Information

 

The following table sets forth, for the periods and at the dates indicated, our summarized historical GAAP income statement and balance sheet information as well as certain non-GAAP financial measures and financial information. The table is derived from and should be read in conjunction with unaudited and audited financial statements and accompanying notes attached hereto (in millions of Canadian dollars).

 

		As at and for the Nine Months Ended September 30,				As at and for the Years Ended December 31,
		2017		2016		2016		2015		2014
GAAP Income Statement Information:(1)
Revenues		500.2		501.9		676.1		645.9		505.2
Operating income		152.4		181.0		237.4		242.3		162.9
Foreign exchange (loss) gain		(5.3	)	59.3		32.6		(185.4	)	(78.3	)
Net income (loss)		114.3		184.0		201.8		(22.9	)	19.5
Non-GAAP Financial Measures:(1)(2)
DCF		240.0		251.0		318.2		272.7		147.3
Adjusted EBITDA		280.2		301.5		395.4		368.7		256.9
Financial Information:(2)
Preferred share dividends		2.0
Net income (loss) attributable to Kinder Morgan interest		96.4		184.0		201.8		(22.9	)	19.5
Net income available to Restricted Voting Stockholders		11.7
DCF available to Kinder Morgan interest		208.5		251.0		318.2		272.7		147.3
DCF available to Restricted Voting Stockholders(3)		30.7
GAAP Balance Sheet Information (at end of period):
Property, plant and equipment, net		3,540.0		3,103.7		3,181.1		3,008.3		2,827.0
Total assets		4,356.8		3,657.2		3,739.4		3,485.2		3,410.6
Long-term debt-affiliates		—		1,281.4		1,362.1		1,320.4		1,050.1
Total equity		3,392.8		1,434.3		1,436.0		1,251.0		1,296.8

 

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Notes:

 

(1)                                  Prior to our May 2017 IPO, net income and DCF were attributable only to Kinder Morgan.

(2)                                  See “— Financial Information —Management’s Discussion and Analysis—Results of Operations—Non-GAAP Financial Measures. ”

(3)                                  For further information respecting DCF on a per Restricted Voting Share basis, see “— Financial Information —Management’s Discussion and Analysis—Results of Operations—Non-GAAP Financial Measures —Distributable Cash Flow. ” 2017 amount excludes approximately $0.8 million of U.S. cash taxes attributable to Restricted Voting Stockholders.

 

In reviewing the above information, reference should be made to: (i) our unaudited interim consolidated financial statements for the three and nine months ended and as of September 30, 2017 (the “ Interim Consolidated Financial Statements ”) ; (ii) our audited consolidated financial statements as at December 31, 2016 and December 31, 2015 and for the years ended December 31, 2016, 2015 and 2014 (the “ Annual Consolidated Financial Statements ”), in each case together with the related notes; and (iii) the sections entitled “— Management’s Discussion and Analysis ” and “ Item 1A. Risk Factors ” in this document.

 

Interest Rate Risk

 

On June 16, 2017, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, our indirect subsidiaries, entered into a definitive credit agreement establishing (i) a $4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the Trans Mountain Expansion Project; (ii) a $1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional Trans Mountain Expansion Project costs (and, subject to the need to fund such additional costs, meeting the National Energy Board-mandated liquidity requirements); and (iii) a $500.0 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “ Credit Facility ”).

 

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The Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the Credit Facility will incur a standby fee of 0.30% to 0.625%, with the range dependent on our credit ratings. The Credit Facility is guaranteed by the Company and all of the non-borrower subsidiaries of the Company and is secured by a first lien security interest on all of the assets of the Company and the equity and assets of the other guarantors.

 

Foreign Exchange Risk

 

Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income.

 

Prior to our May 2017 IPO, we were exposed to foreign currency risk related to the U.S. dollar denominated KMI Loans that were paid off and terminated in the second quarter of 2017. As of December 31, 2016 and 2015, we had KMI Loans of $1,362.1 million, and $1,320.4 million, respectively, presented as “Long-term debt-affiliates” in our consolidated balance sheets. Foreign exchange rate changes on the KMI Loans, and associated interest expense, resulted in unrealized foreign exchange gains (losses) of $29.7 million, $(175.9) million and $(76.0) million for the years ended December 31, 2016, 2015 and 2014, respectively, and a loss of $(2.4) million for the 2017 period prior to the KMI Loans pay off.

 

Although the KMI Loans exposed us to significant foreign exchange risk, there had historically been no net foreign currency exchange risk from the KMI Loans on a Kinder Morgan consolidated basis. As a result, we did not historically enter into any foreign currency derivatives and did not historically engage in hedging activities related to foreign currency exchange risk.

 

The Puget Sound pipeline system operates in Washington State, and earns its revenues and incurs most of its expenses in U.S. dollars. In addition, our Cochin pipeline system earns its revenues in U.S. dollars. Fluctuations in the U.S. dollar to Canadian dollar exchange rate can affect the earnings contributed by the Puget Sound and Cochin pipeline systems to our overall results.

 

Counterparty Credit Risk

 

We are exposed to the risk of loss in the event of non-performance by our customers or other counterparties. The majority of our accounts receivable are due from entities in the oil and gas business and are subject to normal industry credit risks. Concentration of credit risk is mitigated to some degree by having a broad based domestic and international customer base. The majority of our customers have investment grade credit ratings, or are subsidiaries of investment grade rated parent companies (however such parent entity may not be a guarantor).

 

As of September 30, 2017, December 31, 2016 and December 31, 2015, we had no reserve for doubtful accounts receivable.

 

Allowance for Funds Used During Construction

 

This document includes references to allowance for funds used during construction (“ AFUDC ”). AFUDC, which is also referred to herein as “ capitalized financing costs ”, includes both a cost of debt component (“ capitalized debt financing costs ”) and, as approved by the regulator, a cost of equity component (“ capitalized equity financing costs ”). Capitalized debt financing costs result in a reduction in interest expense and capitalized equity financing costs result in the recognition of other income. See “ Item 2. Financial Information— Management’s Discussion and Analysis—Risks and Risk Management—Accounting Policies, Judgments and Estimates .”

 

Growth Estimates

 

Given historical and projected demand for our existing assets, and given their fee-based, contracted nature, they are, collectively, expected to be generally stable, consistent contributors of Adjusted EBITDA. Therefore, for the purposes of certain growth estimates included in this document, we have disclosed certain expected Adjusted EBITDA contribution from our material, identified and contractually committed projects, the Trans Mountain Expansion Project and the Base Line Terminal, on that basis. See “ Item 1A. Risk Factors ” for more information regarding our ongoing and future potential projects.

 

Trans Mountain Expansion

 

The projected Adjusted EBITDA contribution from the Trans Mountain Expansion Project includes contracted revenue only (excluding any potential contribution from spot volumes) less operating expenses. The forecasted annual revenue is equal to contracted volumes on an annual basis multiplied by the corresponding contracted tariff rates and is projected to begin contributing to the Company at the beginning of 2020, based on the current expected in-service schedule. However, construction preparation activity

 

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is off to a slower start than planned in the project schedule due primarily to the time required to file for, process and obtain all necessary permits and regulatory approvals. We are assessing construction mitigation plans that maintain the current in-service schedule of December 31, 2019. That planning, with our contractors, will rely upon continued progress towards schedule-critical regulatory approvals and will assess the acceleration of construction activities that are behind schedule. Absent this mitigation, we currently estimate that project completion could be delayed by up to nine months. If construction costs increase by 10%, the impact on Adjusted EBITDA from the Trans Mountain Expansion Project would be an increase of approximately 3%, assuming those costs were allocated approximately 24% to uncapped and approximately 76% to capped Trans Mountain Expansion Project costs. See “ Item 1A. Risk Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped .”

 

The forecasted operating costs are comprised of fixed costs, variable costs, and a fixed payment to the province of British Columbia. 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 the Trans Mountain Expansion Project would be an increase or decrease of less than 1.5% on a full year basis.

 

Base Line Terminal

 

The 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. This project is expected to begin contributing to the Company during 2018, based on the current expected in-service schedule. See “ Item 1A. Risk Factors—Risks Relating to Our Business—Major projects, including the Trans Mountain Expansion Project, may be inhibited, delayed or stopped .”

 

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.

 

Management’s Discussion and Analysis

 

Presentation of Information

 

The following MD&A is as of October 24, 2017, and should be read in conjunction with the Company’s Interim Consolidated Financial Statements and the Company’s Annual Consolidated Financial Statements included elsewhere in this Form 10.

 

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

 

The Interim Consolidated Financial Statements and Annual Consolidated Financial Statements have been prepared in accordance with GAAP. All financial information in this MD&A is presented in Canadian dollars, unless otherwise indicated.

 

In respect of forward-looking statements contained in this document, see “ Special Note Regarding Forward-Looking Statements. ” Also, the non-GAAP financial measures “Adjusted EBITDA” and “DCF” contained in this document are not prescribed by GAAP, see “ — Non-GAAP Financial Measures ” below.

 

Recent Developments

 

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

 

The Company was incorporated on April 7, 2017.  On May 30, 2017, we completed our 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, with Kinder Morgan retaining the remaining approximate 70% economic interest.

 

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Concurrent with closing of our IPO, the Limited Partnership acquired an interest in the Operating Entities from KMCC and KM Canada Terminals in exchange for the issuance to KMCC and KM Canada Terminals of Class B Units.  In addition, KMCC and KM Canada Terminals were issued Special Voting Shares in the Company for nominal consideration.

 

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

 

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

 

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

 

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

 

Series 1 Preferred Share Offering

 

On August 15, 2017, we completed an offering of 12,000,000 Series 1 Preferred Shares on the TSX at a price to the public of $25.00 per Series 1 Preferred Share for total gross proceeds of $300 million. The net proceeds of $293.0 million from the offering were used to indirectly subscribe for preferred units in the Limited Partnership, which in turn were used by the Limited Partnership to repay Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the Trans Mountain Expansion project and Base Line Terminal project, and for general corporate purposes.  We have the option to redeem the Series 1 Preferred Shares on November 15, 2022 and on November 15 in every fifth year thereafter by payment of $25.00 per Series 1 Preferred Share plus all accrued and unpaid dividends.  The holders of the Series 1 Preferred Shares will have the right to convert all or any of their Series 1 Preferred Shares into Series 2 Preferred Shares, subject to certain conditions, on November 15, 2022 and on November 15 in every fifth year thereafter.  The Series 1 Preferred Shares and the Series 2 Preferred Shares are series of shares in the same class.  The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of security.

 

Results of Operations

 

Overview

 

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

 

Our reportable business segments are:

 

·                   Pipelines - the ownership and operation of (i) the TMPL; (ii) the Canadian Cochin pipeline system; (iii) the Puget Sound pipeline system; (iv) the Jet Fuel pipeline system; and (v) KMCI.

 

·                   Terminals - the ownership and operation of liquid product merchant storage and rail terminals in the Edmonton, AB 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 earnings before depreciation and amortization of each segment (“ Segment EBDA ”). We believe that Segment EBDA is a useful measure of the operating performance of KML because it measures segment operating results before depreciation, depletion and amortization (“ DD&A ”) and certain

 

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expenses that are generally not controllable by the operating managers of the respective business segments of KML, such as certain general and administrative expense, foreign exchange losses (or gains) on the KMI Loans, interest expense, and income tax expense.  Our general and administrative expenses include such items as employee benefits, insurance, rentals, certain litigation and shared corporate services including accounting, information technology, human resources and legal services.  Certain general and administrative expenses attributable to Trans Mountain are billable as flow through items to shippers and result in incremental revenues. See Notes 11 and 17 to the Interim Consolidated Financial Statements and Annual Consolidated Financial Statements, respectively, for further discussion of our reportable business segments.

 

Current Business Developments

 

Pipelines

 

We have spent a cumulative total, net of contributions in aid of construction, of $778.8 million on the Trans Mountain Expansion Project, which includes capitalized equity financing costs, on development of the Trans Mountain Expansion Project as of September 30, 2017 (December 31, 2016—$480.0 million).  All available long-term firm service capacity remains contracted on the pipeline expansion with a diverse group of 13 customers.  This demonstrates strong market support for the Trans Mountain Expansion Project and the much-needed access to new markets it will bring to Canadian producers, as well as providing a secure supply of Canadian crude to refineries throughout the Pacific basin, including Washington State.  Collectively, the firm shippers have made 15- and 20-year commitments of 707,500 barrels per day, or approximately 80 percent of the capacity on the expanded pipeline, with the remaining 20 percent reserved for spot volumes consistent with NEB requirements.  Aboriginal support for the Trans Mountain Expansion Project continues to grow, with 42 Aboriginal communities in support of the Trans Mountain Expansion Project.

 

Trans Mountain Expansion Project Construction Progress

 

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

 

We are assessing construction mitigation plans that maintain the current in-service schedule of December 31, 2019. That planning, with our contractors, will rely upon continued progress towards schedule-critical regulatory approvals and will assess the acceleration of construction activities that are behind schedule. Absent this mitigation, we currently estimate that project completion could be delayed by up to nine months.  We will continue to evaluate spend and schedule in light of progress on permitting, and other relevant factors, in order to preserve and enhance shareholder value.  All project planning and schedule mitigation efforts include cost management measures and spend control to maximize project returns, including a reduction in 2017 spend that has already been implemented.

 

Terminals

 

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

 

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Consolidated Earnings Results

 

		Three Months Ended September 30,				Nine Months Ended September 30,
(In millions of Canadian dollars)		2017		2016		2017		2016
Segment EBDA (1)
Pipelines		58.5		58.2		169.0		184.3
Terminals		52.7		52.0		159.1		162.6
Total segment EBDA (1)		111.2		110.2		328.1		346.9
DD&A		(37.2	)	(34.3	)	(107.6	)	(102.5	)
Foreign exchange gain (loss) on the KMI Loans (2)		0.6		(15.7	)	(2.4	)	54.2
General and administrative expenses		(16.2	)	(15.2	)	(50.5	)	(45.4	)
Interest, net		(1.3	)	(7.0	)	(10.9	)	(22.9	)
Income before income taxes		57.1		38.0		156.7		230.3
Income tax expense		(14.7	)	(17.7	)	(42.4	)	(46.3	)
Net income		42.4		20.3		114.3		184.0
Preferred share dividend		(2.0	)	—		(2.0	)	—
Net income attributable to Kinder Morgan interest		(28.7	)	(20.3	)	(96.4	)	(184.0	)
Net income available to restricted voting stockholders		11.7		—		15.9		—

 

Years Ended December 31, (In millions of Canadian dollars)		2016		2015		2014
Segment EBDA(1)
Pipelines		241.9		249.5		220.9
Terminals		211.2		180.5		98.5
Total Segment EBDA(1)		453.1		430.0		319.4
DD&A		(137.2	)	(123.5	)	(88.7	)
Unrealized foreign exchange gain (loss) on the KMI Loans( 2)		29.7		(175.9	)	(76.0	)
General and administrative expense		(57.6	)	(61.3	)	(59.2	)
Interest, net		(29.9	)	(30.1	)	(49.4	)
Income before income taxes		258.1		39.2		46.1
Income tax expense		(56.3	)	(62.1	)	(26.6	)
Net income (loss)		201.8		(22.9	)	19.5

 

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Notes:

 

(1)          Includes revenues and other (income) expense less operating expenses and other, net. Operating expenses primarily include operations and maintenance expenses, and taxes, other than income taxes.

 

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

 

Segment EBDA for the year ended December 31, 2016, 2015 and 2014 includes (i) $17.9 million, $12.9 million and $11.2 million, respectively, of capitalized equity financing costs and (ii) $2.9 million, $(9.5) million and $(2.3) million of unrealized foreign exchange gains (losses) due to changes in exchange rates between the Canadian dollar and the U.S. dollar on U.S. dollar denominated balances.

 

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

 

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

 

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

 

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

 

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

 

Year Ended December 31, 2016 vs. 2015 and 2015 vs. 2014

 

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 KMI Loans denominated in U.S. dollars. 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 $175.8 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.

 

The decrease in net income of $42.4 million (217%) from the prior year in net income is primarily attributable to an increase in the unrealized foreign exchange losses on the KMI Loans denominated in U.S. dollars. Due to changes in the exchange rates between Canadian and U.S. dollars, we recorded unrealized foreign exchange losses of $175.8 million and $76.0 million in 2015 and 2014, respectively. Increases of $110.6 million in segment EBDA and $34.8 million of DD&A were driven by the commissioning of new terminals facilities, including two new joint ventures in 2014 and 2015, incremental earnings from completion of the Cochin Reversal Project in 2014 and higher volumes on the Puget Sound pipeline system.

 

Non-GAAP Financial Measures

 

In addition to using financial measures prescribed by GAAP, references are made in this document to DCF and Adjusted EBITDA which are measures that do not have any standardized meaning as prescribed by GAAP.  Neither Adjusted EBITDA nor DCF 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 Adjusted EBITDA and DCF may differ from similarly titled measures used by others.  Accordingly, use of such terms may not be comparable to similarly defined measures presented by other entities. Investors should not consider these non-GAAP financial measures in isolation or as a substitute for an analysis of results as reported under GAAP.  The limitations of these non-GAAP financial 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 Adjusted EBITDA, or DCF in this document is expressly qualified by this cautionary statement.

 

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

 

DCF is an important performance measure used by us and by external users of our financial statements to evaluate our performance and to measure and estimate our ability to generate cash earnings after servicing our debt and preferred share dividends, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as distributions or expansion capital expenditures.  We use this performance measure and believe it provides users of our financial statements a useful performance measure reflective of our ability to generate cash earnings to supplement the comparable 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 available to Kinder Morgan Interest and Restricted Voting Shareholders.  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.

 

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Table of Contents

 

Reconciliation of Net Income to DCF

 

		Three Months Ended September 30,				Nine Months Ended September 30,
(In millions of Canadian dollars)		2017		2016		2017		2016
Net Income (1)		42.4		20.3		114.3		184.0
Add/(Subtract):
DD&A		37.2		34.3		107.6		102.5
Certain items(2)		(0.4	)	15.7		3.6		(54.2	)
Total book taxes(3)		14.6		17.7		43.8		46.3
Cash income taxes refunded (paid)		0.3		0.2		—		(1.0	)
Preferred share dividends		(2.0	)	—		(2.0	)	—
Sustaining capital expenditures		(14.9	)	(11.0	)	(27.3	)	(26.6	)
DCF		77.2		77.2		240.0		251.0
Weighted average Restricted Voting Shares outstanding for dividends(4)		103.6		n/a		103.4		n/a
DCF per Restricted Voting Share		0.214		n/a		0.297		n/a
Declared dividend per Restricted Voting Share		0.1625		n/a		0.2196		n/a

 

		Years Ended December 31,
(In millions of Canadian dollars)		2016		2015		2014
Net Income (Loss)(1)		201.8		(22.9	)	19.5
Add/(Subtract):
DD&A		137.2		123.5		88.7
Certain items(2)		(29.7	)	175.9		(72.7	)
Total book taxes		56.3		62.1		26.6
Cash income taxes (paid) refunded		(1.2	)	0.4		(1.5	)
Sustaining capital expenditures		(46.2	)	(66.3	)	(58.7	)
DCF		318.2		272.7		147.3

 

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

 

Reconciliation of Net Income to Adjusted EBITDA

 

		Three Months Ended September 30,				Nine Months Ended September 30,
(In millions of Canadian dollars)		2017		2016		2017		2016
Net Income(1)		42.4		20.3		114.3		184.0
Add/(Subtract):
DD&A		37.2		34.3		107.6		102.5
Certain items(2)		(0.4	)	15.7		3.6		(54.2	)
Total book taxes(3)		14.6		17.7		43.8		46.3
Interest, net		1.3		7.0		10.9		22.9
Adjusted EBITDA		95.1		95.0		280.2		301.5

 

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