EX-13.2 3 trp-12312016xmda.htm FORM 40-F MD&A Exhibit
EXHIBIT 13.2

Management's discussion and analysis
February 15, 2017
This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the year ended December 31, 2016.
This MD&A should be read with our accompanying December 31, 2016 audited comparative consolidated financial statements and notes for the same period, which have been prepared in accordance with U.S. generally accepted accounting principles (GAAP).
 
 
 
 
 
Contents
ABOUT THIS DOCUMENT
6

ABOUT OUR BUSINESS
10

 
•  Three core businesses
11

 
•  Our strategy
13

 
•  Acquisition of Columbia Pipeline Group, Inc.
14

 
•  Capital program
16

 
•  2016 financial highlights
18

 
•  Outlook
26

NATURAL GAS PIPELINES BUSINESS
27

CANADIAN NATURAL GAS PIPELINES
34

U.S. NATURAL GAS PIPELINES
38

MEXICO NATURAL GAS PIPELINES
43

NATURAL GAS PIPELINES BUSINESS RISKS
45

LIQUIDS PIPELINES
47

ENERGY
57

CORPORATE
73

FINANCIAL CONDITION
78

OTHER INFORMATION
92

 
•  Risks and risk management
92

 
•  Controls and procedures
99

 
•  Critical accounting estimates
100

 
•  Financial instruments
103

 
•  Accounting changes
106

 
•  Reconciliation of comparable EBITDA and comparable EBIT
    to segmented earnings
109

 
•  Quarterly results
110

GLOSSARY
118


 
TransCanada Management's discussion and analysis 2016

5


About this document
Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries. Abbreviations and acronyms that are not defined in the document are defined in the glossary on page 118. All information is as of February 15, 2017 and all amounts are in Canadian dollars, unless noted otherwise.
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A include information about the following, among other things:
planned changes in our business including the divestiture of certain assets
our financial and operational performance, including the performance of our subsidiaries
expectations or projections about strategies and goals for growth and expansion
expected cash flows and future financing options available to us
expected dividend growth
expected costs for planned projects, including projects under construction, permitting and in development
expected schedules for planned projects (including anticipated construction and completion dates)
expected regulatory processes and outcomes
expected impact of regulatory outcomes
expected outcomes with respect to legal proceedings, including arbitration and insurance claims
expected capital expenditures and contractual obligations
expected operating and financial results
the expected impact of future accounting changes, commitments and contingent liabilities
expected industry, market and economic conditions.
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.
Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:
Assumptions
planned monetization of our U.S. Northeast power business
inflation rates, commodity prices and capacity prices
nature and scope of hedging
regulatory decisions and outcomes
the Canadian dollar to U.S. dollar exchange rate remains at or near current levels
interest rates
tax rates
planned and unplanned outages and the use of our pipeline and energy assets
integrity and reliability of our assets
access to capital markets
anticipated construction costs, schedules and completion dates.


6
 TransCanada Management's discussion and analysis 2016
 


Risks and uncertainties
our ability to realize the anticipated benefits from the acquisition of Columbia Pipeline Group, Inc. (Columbia)
timing and execution of our planned asset sales
our ability to successfully implement our strategic initiatives
whether our strategic initiatives will yield the expected benefits
the operating performance of our pipeline and energy assets
amount of capacity sold and rates achieved in our pipeline businesses
the availability and price of energy commodities
the amount of capacity payments and revenues we receive from our energy business
regulatory decisions and outcomes
outcomes of legal proceedings, including arbitration and insurance claims
performance and credit risk of our counterparties
changes in market commodity prices
changes in the political environment
changes in environmental and other laws and regulations
competitive factors in the pipeline and energy sectors
construction and completion of capital projects
costs for labour, equipment and materials
access to capital markets
interest, tax and foreign exchange rates
weather
cyber security
technological developments
economic conditions in North America as well as globally.
You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC.
As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.
FOR MORE INFORMATION
See Supplementary information beginning on page 195 for other consolidated financial information on TransCanada for the last five years.
You can also find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).

 
TransCanada Management's discussion and analysis 2016

7


NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
comparable earnings
comparable earnings per common share
comparable EBITDA
comparable EBIT
funds generated from operations
comparable funds generated from operations
comparable distributable cash flow
comparable distributable cash flow per common share.
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be similar to measures presented by other entities.
Comparable measures
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:
certain fair value adjustments relating to risk management activities
income tax refunds and adjustments and changes to enacted tax rates
gains or losses on sales of assets or assets held for sale
legal, contractual and bankruptcy settlements
impact of regulatory or arbitration decisions relating to prior year earnings
restructuring costs
impairment of goodwill, investments and other assets including certain ongoing maintenance and liquidation costs
acquisition costs.
We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.
Comparable earnings
Comparable earnings represents earnings or loss attributable to common shareholders on a consolidated basis adjusted for specific items. Comparable earnings is comprised of segmented earnings, interest expense, AFUDC, interest income and other, income taxes and non-controlling interests adjusted for the specific items.
Comparable EBIT and comparable EBITDA
Comparable EBIT represents segmented earnings adjusted for the specific items described above. We use comparable EBIT as a measure of our earnings from ongoing operations as it is a useful measure of our performance and an effective tool for evaluating trends in each segment. Comparable EBITDA is calculated the same way as comparable EBIT but excludes the non-cash charges for depreciation and amortization.
Funds generated from operations
Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. See the Financial condition section for a reconciliation to net cash provided by operations.

8
 TransCanada Management's discussion and analysis 2016
 


Comparable distributable cash flow
Comparable distributable cash flow is defined as comparable funds generated from operations less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability, and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, in certain of our rate-regulated businesses, maintenance capital expenditures are included in their respective rate bases, on which we earn a regulated return and recover depreciation through future tolls.
Effective December 31, 2016, we adopted, on a retrospective basis, a new accounting standard under U.S. GAAP which allows us to classify certain distributed earnings received from equity investments as cash from operations on the consolidated statement of cash flows, which had previously been included in Investing activities. As a result, we no longer need to adjust for distributions in excess of equity earnings in the calculation of comparable distributable cash flow.
We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. See the Financial condition section for a reconciliation to net cash provided by operations.
The following table identifies our non-GAAP measures against their equivalent GAAP measures.
Comparable measure
Original measure
 
 
comparable earnings
net income/(loss) attributable to common shares
comparable earnings per common share
net income/(loss) per common share
comparable EBITDA
segmented earnings
comparable EBIT
segmented earnings
comparable funds generated from operations
net cash provided by operations
comparable distributable cash flow
net cash provided by operations


 
TransCanada Management's discussion and analysis 2016

9


About our business
With over 65 years of experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and natural gas storage facilities.
tcmapsfullassetfeb15675x8312.jpg

10
 TransCanada Management's discussion and analysis 2016
 



THREE CORE BUSINESSES
We operate in three core businesses – Natural Gas Pipelines, Liquids Pipelines and Energy. As a result of our acquisition of Columbia on July 1, 2016 and the pending monetization of the U.S. Northeast power business, we have determined that a change in our operating segments is appropriate. Accordingly, we consider ourselves to be operating in the following segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. This provides information that is aligned with how management decisions about our business are made and how performance of our business is assessed. We also have a non-operational Corporate segment consisting of corporate and administrative functions that provide governance and other support to our operational business segments. Prior period segment information has been adjusted to reflect the new segments.
Our $88 billion portfolio of energy infrastructure assets meets the needs of people who rely on us to deliver their energy safely and reliably every day. We operate in seven Canadian provinces, 38 U.S. states and Mexico.
Year at a glance
at December 31
 
 
 
 
(millions of $)
2016

 
2015

 
 
 
 
 
Total assets
 
 
 
 
Canadian Natural Gas Pipelines
 
15,816

 
15,038

U.S. Natural Gas Pipelines1
 
34,422

 
12,207

Mexico Natural Gas Pipelines
 
5,013

 
3,787

Liquids Pipelines
 
16,896

 
16,046

Energy2
 
13,169

 
15,614

Corporate
 
2,735

 
1,706

 
 
88,051

 
64,398

a20483totasstpmspieengb.jpg
1
2016 includes Columbia.
2
Includes the U.S. Northeast power assets held for sale.
year ended December 31
 
 
 
 
(millions of $)
2016

 
2015

 
 
 
 
 
Total revenues
 
 
 
 
Canadian Natural Gas Pipelines
 
3,682

 
3,680

U.S. Natural Gas Pipelines1
 
2,526

 
1,444

Mexico Natural Gas Pipelines
 
378

 
259

Liquids Pipelines
 
1,755

 
1,879

Energy
 
4,164

 
4,038

 
 
12,505

 
11,300

a20483totrevpmspieenga01.jpg
1
Includes Columbia effective July 1, 2016.
year ended December 31
 
 
 
 
(millions of $)
2016

 
2015

 
 
 
 
 
Comparable EBIT
 
 
 
 
Canadian Natural Gas Pipelines
 
1,373

 
1,413

U.S. Natural Gas Pipelines1
 
1,286

 
731

Mexico Natural Gas Pipelines
 
290

 
171

Liquids Pipelines
 
881

 
1,043

Energy
 
996

 
924

Corporate
 
(118
)
 
(139
)
 
 
4,708

 
4,143

a20483totebitpmspieenga01.jpg
1
Includes Columbia effective July 1, 2016.

                        

 
TransCanada Management's discussion and analysis 2016

11


Common share price
Common shares outstanding – average
at December 31
 
 
 
a20483shrprcepmslineeng.jpg
(millions)
 

 
 
 
 
2016
759

 
2015
709

 
2014
708

 
 
 
 
as at February 13, 2017
issued and outstanding

 

Common shares
 
 
 
 
867
 million
 

 
 
 
Preferred shares
issued and outstanding

convertible to

 
 
 
Series 1
9.5
 million
Series 2 preferred shares

Series 2
12.5
 million
Series 1 preferred shares

Series 3
8.5
 million
Series 4 preferred shares

Series 4
5.5
 million
Series 3 preferred shares

Series 5
12.7
 million
Series 6 preferred shares

Series 6
1.3
 million
Series 5 preferred shares

Series 7
24
 million
Series 8 preferred shares

Series 9
18
 million
Series 10 preferred shares

Series 11
10
 million
Series 12 preferred shares

Series 13
20
 million
Series 14 preferred shares

Series 15
40
 million
Series 16 preferred shares

 
 
 
options to buy common shares
outstanding

exercisable

 
 
 
 
11
 million
6
 million

12
 TransCanada Management's discussion and analysis 2016
 


OUR STRATEGY
Our energy infrastructure business is made up of pipeline and power generation assets that gather, transport, produce, store or deliver natural gas, crude oil and other petroleum products and electricity to support businesses and communities in North America.
Our vision is to be the leading energy infrastructure company in North America, focusing on pipeline and power generation opportunities in regions where we have or can develop a significant competitive advantage.
Key components of our strategy at a glance
1
Maximize the full-life value of our infrastructure assets and commercial positions
 
 
 
•  Long-life infrastructure assets and long-term commercial arrangements are the cornerstones of our low risk business model.
•  Our pipeline assets include large-scale natural gas and crude oil pipelines that connect long-life supply basins with stable and growing markets, generating predictable and sustainable cash flow and earnings.
•  In Energy, long-term power sale agreements and shorter-term power sales to wholesale and load customers are used to manage and optimize our portfolio and to manage price volatility.
2
Commercially develop and build new asset investment programs
 
 
 
•  We are developing high quality, long-life assets under our current $71 billion capital program, comprised of $23 billion in near-term projects and $48 billion in commercially-secured medium to long-term projects. These will contribute incremental earnings and cash flow over the near, medium and long terms as our investments are placed in service.
•  Our expertise in project development, managing construction risks and maximizing capital productivity ensures a disciplined approach to reliability, cost and schedule, resulting in superior service for our customers and returns to shareholders.
•  As part of our growth strategy, we rely on this experience and our regulatory, commercial, financial, legal and operational expertise to successfully build and integrate new pipeline and other energy facilities.
•  Our investment in natural gas, nuclear, wind and solar generating facilities demonstrates our commitment to clean, sustainable energy.
3
Cultivate a focused portfolio of high quality development and investment options
 
 
 
•  We assess opportunities to acquire and develop energy infrastructure that complements our existing portfolio and diversifies access to attractive supply and market regions.
•  We focus on pipelines and energy growth initiatives in core regions of North America and prudently manage development costs, minimizing capital-at-risk in early stages of projects.
•  We will advance selected opportunities to full development and construction when market conditions are appropriate and project risks and returns are acceptable.
4
Maximize our competitive strengths
 
 
 
•  We are continually developing core competencies in areas such as safety, operational excellence, supply chain management, project execution and stakeholder management to ensure we provide maximum shareholder value over the short, medium and long terms.
 
A competitive advantage
 
 
Years of experience in the energy infrastructure business and a disciplined approach to project and operational
management and capital investment give us our competitive edge.
• Strong leadership: scale, presence, operating capabilities and strategy development; expertise in regulatory, legal,
     commercial and financing support.
•  High quality portfolio: a low-risk and enduring business model that maximizes the full-life value of our long-life assets
     and commercial positions throughout all points in the business cycle.
•  Disciplined operations: highly skilled in designing, building and operating energy infrastructure; focus on operational
     excellence; and a commitment to health, safety and the environment are paramount parts of our core values.
•  Financial positioning: consistently strong financial performance and long-term financial stability and
     profitability; disciplined approach to capital investment; ability to access sizable amounts of competitively priced capital
     to support our growth; ability to balance an increasing dividend on our common shares while preserving financial
     flexibility to fund our industry-leading capital program in all market conditions.
•  Long-term relationships: long-term, transparent relationships with key customers and stakeholders; clear
     communication of our value to equity and debt investors – both the upside and the risks – to build trust and support.
 

 
TransCanada Management's discussion and analysis 2016

13


ACQUISITION OF COLUMBIA PIPELINE GROUP, INC.
Acquisition
On July 1, 2016, we acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash. The acquisition was initially financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, following the closing of the acquisition, were exchanged into 96.6 million TransCanada common shares. See Financial condition section for additional information on the acquisition bridge facilities and the subscription receipts.
Columbia operates a portfolio of approximately 24,500 km (15,200 miles) of regulated natural gas pipelines, 285 Bcf of natural gas storage facilities and related midstream assets. We acquired Columbia to expand our natural gas business in the U.S. market, positioning ourselves for additional long-term growth opportunities. The acquisition also includes a large portfolio of new capital growth projects which currently includes seven significant pipeline expansions designed to transport growing supply from the Marcellus / Utica production basins to markets as well as a scheduled program for modernization of existing infrastructure through 2020 to ensure the continuation of a safe, reliable and efficient system. We continue to execute on plans to ensure an effective integration of Columbia into the TransCanada organization, and remain on track to realizing our targeted US$250 million of annual cost, revenue and financing benefits by 2018.
Throughout this MD&A, we refer to Columbia as the overall corporate entity we acquired, however, we also make reference to specific businesses or assets within Columbia:
Columbia Gas – We own and operate this interstate natural gas transportation pipeline and storage system which has largely operated as a means to transport gas from the Gulf Coast via Columbia Gulf, from various pipeline interconnects and from production areas in the Appalachian region to markets in the midwest, Atlantic, and northeast regions.
Columbia Gulf – We own and operate this long-haul interstate natural gas transportation pipeline system that was originally designed to transport supply from the Gulf of Mexico to major supply markets in the U.S. Northeast. The pipeline is now transitioning and expanding to accommodate new supply in the Appalachian basin and its interconnect with Columbia Gas and other pipelines to deliver gas across various Gulf Coast markets.
Millennium – We operate and own a 47.5 per cent ownership interest in Millennium which transports natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections.
Crossroads – We own and operate this interstate natural gas pipeline operating in Indiana and Ohio.
Midstream – This midstream business provides natural gas producer services including gathering, treating, conditioning, processing, compression and liquids handling in the Appalachian Basin.
Columbia's wholly-owned natural gas storage business is one of North America’s largest and includes 37 storage fields in four states and is highly integrated with the Columbia pipeline assets.
Hardy Storage – We also operate and own a 50 per cent interest in Hardy Storage, a natural gas storage field in Hardy and Hampshire counties in West Virginia.
The following table summarizes the acquisition related costs for Columbia that have been excluded from comparable earnings.
year ended December 31
 
 
(millions of $)
 
2016

 
 
 
Plant operating costs and other  U.S. Natural Gas Pipelines
 
63

Plant operating costs and other Corporate
 
116

Interest expense
 
115

Interest income and other
 
(6
)
Income tax expense
 
(10
)
Net income attributable to non-controlling interests
 
(5
)
Total excluded from comparable earnings
 
273


14
 TransCanada Management's discussion and analysis 2016
 


The $273 million of after-tax costs which were excluded from comparable earnings included $109 million of dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $90 million of retention, severance and integration costs, $36 million of acquisition costs and a $44 million deferred income tax adjustment upon acquisition, partially offset by $6 million of interest earned on the subscription receipt funds held in escrow pending their conversion to common shares.
As part of the initial financing plan for the Columbia acquisition, we announced the planned monetization of our U.S. Northeast power business and the sale of a minority interest in our Mexican pipelines.
Monetization of U.S. Northeast power business
On November 1, 2016, we announced the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors for US$2.2 billion and TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC for US$1.065 billion. These two sale transactions are expected to close in the first half of 2017 subject to certain regulatory and other approvals and will include customary closing adjustments. These asset dispositions are expected to result in an approximate $1.1 billion after-tax net loss which is comprised of a $656 million after-tax goodwill impairment charge, an approximate $863 million after-tax net loss on the sale of the thermal and wind package and an approximate $440 million after-tax gain on the sale of the hydro assets to be recorded upon close of that transaction. We are also in the process of monetizing the U.S. Northeast power marketing business. Proceeds from these sales and future realization of value of the marketing business will be used to repay the remaining portion of the acquisition bridge facilities which were used to partially finance the Columbia acquisition.
Minority interest in Mexican pipelines
As part of the initial Columbia acquisition financing plan, we previously disclosed our intention to monetize a minority interest in our Mexico natural gas pipeline business. On November 1, 2016, we announced a decision to maintain our full ownership interest in this growing portfolio of natural gas pipeline assets in Mexico rather than sell a minority interest in six of these pipelines, which also is consistent with our strategy of maximizing shareholder value and maintaining a simplified corporate structure.
Common equity offering
On November 1, 2016, in conjunction with our decision to maintain our current ownership interest in our growing Mexican natural gas pipelines business, we entered into an agreement with a group of underwriters for a bought deal offering of common shares which included an over-allotment option. On November 16, 2016, including full exercise of the over-allotment option by the underwriters, we issued 60.2 million common shares at a price of $58.50 for total proceeds of approximately $3.5 billion. Proceeds from the offering were used to repay a portion of the US$6.9 billion acquisition bridge facilities which were used to partially finance the Columbia acquisition.
MLP Strategy/CPPL Acquisition
Following a review of our master limited partnership (MLP) strategy, on November 1, 2016, we announced an agreement and plan of merger through which our wholly-owned subsidiary, Columbia Pipeline Group, Inc., agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL). The acquisition is expected to close in first quarter 2017. TC PipeLines, LP remains a core element of our future strategy.

 
TransCanada Management's discussion and analysis 2016

15


CAPITAL PROGRAM
We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow.
Our capital program consists of $23 billion of near-term projects and $48 billion of commercially secured medium and longer-term projects. Amounts presented exclude maintenance capital expenditures, capitalized interest and AFUDC.
All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
Near-term projects
at December 31, 2016
 
Segment
 
Expected
in-service date
 
Estimated project cost

 
Carrying value

(billions of $)
 
 
 
 
 
 
 
 
 
Canadian Mainline
 
Canadian Natural Gas Pipelines
 
2017-2018
 
0.3

 
0.1

NGTL System – North Montney
 
Canadian Natural Gas Pipelines
 
2018+1
 
1.7

 
0.3

 – Saddle West
 
Canadian Natural Gas Pipelines
 
2019
 
0.6

 

 – 2016/17 Facilities
 
Canadian Natural Gas Pipelines
 
2017-2020
 
2.2

 
0.5

 – 2018 Facilities
 
Canadian Natural Gas Pipelines
 
2018-2020
 
0.6

 

 – Other
 
Canadian Natural Gas Pipelines
 
2017-2020
 
0.3

 

Grand Rapids2
 
Liquids Pipelines
 
2017
 
0.9

 
0.8

Northern Courier
 
Liquids Pipelines
 
2017
 
1.0

 
0.9

Columbia Gas3  – Leach XPress
 
U.S. Natural Gas Pipelines
 
2017
 
US 1.4

 
US 0.4

 – Modernization I
 
U.S. Natural Gas Pipelines
 
2017
 
US 0.2

 

– WB XPress
 
U.S. Natural Gas Pipelines
 
2018
 
US 0.8

 
US 0.2

– Mountaineer XPress
 
U.S. Natural Gas Pipelines
 
2018
 
US 2.0

 
US 0.1

– Modernization II
 
U.S. Natural Gas Pipelines
 
2018-2020
 
US 1.1

 

Columbia Gulf3 – Rayne XPress
 
U.S. Natural Gas Pipelines
 
2017
 
US 0.4

 
US 0.2

– Cameron Access
 
U.S. Natural Gas Pipelines
 
2018
 
US 0.3

 
US 0.1

– Gulf XPress
 
U.S. Natural Gas Pipelines
 
2018
 
US 0.6

 

Midstream – Gibraltar
 
U.S. Natural Gas Pipelines
 
2017
 
US 0.3

 
US 0.2

Tula
 
Mexico Natural Gas Pipelines
 
2018
 
US 0.6

 
US 0.3

White Spruce
 
Liquids Pipelines
 
2018
 
0.2

 

Napanee
 
Energy
 
2018
 
1.1

 
0.7

Villa de Reyes
 
Mexico Natural Gas Pipelines
 
2018
 
US 0.6

 
US 0.2

Sur de Texas2
 
Mexico Natural Gas Pipelines
 
2018
 
US 1.3

 
US 0.1

Bruce Power – life extension4
 
Energy
 
up to 2020+
 
1.1

 
0.1

 
 
 
 
 
 
19.6

 
5.2

Foreign exchange impact on near-term projects5
 
 
 
3.3

 
0.6

Total near-term projects (billions of Cdn$)
 
 
 
22.9

 
5.8

1
In-service date is dependent on a positive final investment decision on Prince Rupert Gas Transmission.
2
Our proportionate share.
3
The Columbia projects exclude AFUDC, whereas previously announced estimated project costs included AFUDC.
4
Amounts reflect our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of major refurbishment outages which are expected to begin in 2020.
5
Reflects U.S./Canada foreign exchange rate of $1.34 at December 31, 2016.

16
 TransCanada Management's discussion and analysis 2016
 


Medium to longer-term projects
The medium to longer-term projects have greater uncertainty with respect to timing and estimated project costs. The expected in-service dates of these projects are 2019 and beyond, and costs provided in the schedule below reflect the most recent costs for each project as filed with the various regulatory authorities or otherwise determined. These projects have all been commercially secured but are subject to approvals that include sponsor FID and/or complex regulatory processes. Please refer to the Significant events section in each Business Segment for further information on each of these projects.
at December 31, 2016
 
Segment
 
Estimated project cost

 
Carrying value

(billions of $)
 
 
 
 
 
 
 
Heartland and TC Terminals
 
Liquids Pipelines
 
0.9

 
0.1

Upland
 
Liquids Pipelines
 
US 0.6

 

Grand Rapids Phase 21
 
Liquids Pipelines
 
0.7

 

Bruce Power – life extension1
 
Energy
 
5.3

 

Keystone projects
 
 
 
 
 
 
Keystone XL2
 
Liquids Pipelines
 
US 8.0

 
US 0.3

Keystone Hardisty Terminal2
 
Liquids Pipelines
 
0.3

 
0.1

Energy East projects
 
 
 
 
 
 
Energy East3
 
Liquids Pipelines
 
15.7

 
0.8

Eastern Mainline Project
 
Canadian Natural Gas Pipelines
 
2.0

 
0.1

BC west coast LNG-related projects
 
 
 
 
 
 
Coastal GasLink
 
Canadian Natural Gas Pipelines
 
4.8

 
0.4

Prince Rupert Gas Transmission
 
Canadian Natural Gas Pipelines
 
5.0

 
0.5

NGTL System – Merrick
 
Canadian Natural Gas Pipelines
 
1.9

 

 
 
 
 
45.2

 
2.3

Foreign exchange impact on medium to longer-term projects4
 
 
 
2.9

 
0.1

Total medium to longer-term projects (billions of Cdn$)
 
 
 
48.1

 
2.4

1
Our proportionate share.
2
Carrying value reflects amount remaining after impairment charge recorded in 2015.
3
Excludes transfer of Canadian Mainline natural gas assets.
4
Reflects U.S./Canada foreign exchange rate of $1.34 at December 31, 2016.

 
TransCanada Management's discussion and analysis 2016

17


2016 FINANCIAL HIGHLIGHTS
We use certain financial measures that do not have a standardized meaning under GAAP because we believe they improve our ability to compare results between reporting periods and enhance understanding of our operating performance. Known as non-GAAP measures, they may not be similar to measures provided by other companies.
Comparable EBITDA (comparable earnings before interest, taxes, depreciation and amortization), comparable EBIT (comparable earnings before interest and taxes), comparable earnings, comparable earnings per common share, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share are all non-GAAP measures. See page 8 for more information about the non-GAAP measures we use and pages 80, 81 and 109 for a reconciliation to the GAAP equivalents.
year ended December 31
 
 
 
 
 
 
(millions of $, except per share amounts)
 
2016

 
2015

 
2014

 
 
 
 
 
 
 
Income
 
 
 
 
 
 
Revenues
 
12,505

 
11,300

 
10,185

Net income/(loss) attributable to common shares
 
124

 
(1,240
)
 
1,743

per common share – basic & diluted
 

$0.16

 

($1.75
)
 

$2.46

Comparable EBITDA
 
6,647

 
5,908

 
5,521

Comparable earnings
 
2,108

 
1,755

 
1,715

per common share
 

$2.78

 

$2.48

 

$2.42

 
 
 
 
 
 
 
Cash flows
 
 
 
 
 
 
Net cash provided by operations
 
5,069

 
4,384

 
4,226

Comparable funds generated from operations
 
5,171

 
4,815

 
4,458

Comparable distributable cash flow
 
3,665

 
3,562

 
3,405

per common share
 
$4.83
 
$5.02
 
$4.81
 
 
 
 
 
 
 
Capital spending – capital expenditures
 
5,007

 
3,918

 
3,489

Capital spending – projects in development
 
295

 
511

 
848

Contributions to equity investments
 
765

 
493

 
256

Acquisitions, net of cash acquired
 
13,608

 
236

 
241

Proceeds from sale of assets, net of transaction costs
 
6

 

 
196

 
 
 
 
 
 
 
Balance sheet
 
 
 
 
 
 
Total assets
 
88,051

 
64,398

 
58,525

Long-term debt
 
40,150

 
31,456

 
24,757

Junior subordinated notes
 
3,931

 
2,409

 
1,160

Preferred shares
 
3,980

 
2,499

 
2,255

Non-controlling interests
 
1,726

 
1,717

 
1,583

Common shareholders' equity
 
20,277

 
13,939

 
16,815

 
 
 
 
 
 
 
Dividends declared1
 
 
 
 
 
 
per common share
 

$2.26

 

$2.08

 

$1.92

per Series 1 preferred share
 

$0.8165

 

$0.8165

 

$1.15

per Series 2 preferred share
 

$0.60648

 
$0.6299
 

per Series 3 preferred share
 

$0.538

 

$0.769

 

$1.00

per Series 4 preferred share
 

$0.44648

 
$0.2269
 

per Series 5 preferred share
 

$0.56575

 

$1.10

 

$1.10

per Series 6 preferred share
 

$0.50648

 

 

per Series 7 preferred share
 

$1.00

 

$1.00

 
$1.00
per Series 9 preferred share
 

$1.0625

 
$1.0625
 

$1.09

per Series 11 preferred share
 

$1.1875

 
$0.7040
 

per Series 13 preferred share
 

$0.18525

 

 

per Series 15 preferred share
 

$0.3323

 

 

1
See financial condition section on page 85 for details on the preferred share dividends.


18
 TransCanada Management's discussion and analysis 2016
 


Consolidated results
year ended December 31
 
 
 
 
 
 
(millions of $, except per share amounts)
 
2016

 
2015

 
2014

 
 
 
 
 
 
 
Segmented earnings/(losses)
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
1,373

 
1,413

 
1,454

U.S. Natural Gas Pipelines
 
1,219

 
606

 
556

Mexico Natural Gas Pipelines
 
290

 
171

 
142

Liquids Pipelines
 
827

 
(2,643
)
 
830

Energy
 
(1,140
)
 
792

 
1,036

Corporate
 
(256
)
 
(238
)
 
(87
)
Total segmented earnings
 
2,313

 
101

 
3,931

Interest expense
 
(1,998
)
 
(1,370
)
 
(1,198
)
Allowance for funds used during construction
 
419

 
295

 
136

Interest income and other
 
103

 
(132
)
 
(45
)
Income/(loss) before income taxes
 
837

 
(1,106
)
 
2,824

Income tax expense
 
(352
)
 
(34
)
 
(831
)
Net income/(loss)
 
485

 
(1,140
)
 
1,993

Net income attributable to non-controlling interests
 
(252
)
 
(6
)
 
(153
)
Net income/(loss) attributable to controlling interests
 
233

 
(1,146
)
 
1,840

Preferred share dividends
 
(109
)
 
(94
)
 
(97
)
Net income/(loss) attributable to common shares
 
124

 
(1,240
)
 
1,743

Net income/(loss) per common share – basic and diluted
 

$0.16

 

($1.75
)
 

$2.46

Net income/(loss) attributable
 to common shares
Net income/(loss) per share
a2016netincome.jpg
 
a2016netincomepershare.jpg
 
Net income attributable to common shares in 2016 was $124 million or $0.16 per share (2015 – loss of $1,240 million or ($1.75) per share; 2014 – income of $1,743 million or $2.46 per share). On a per share basis, net income attributable to common shares in 2016 increased by $1.91 per share compared to 2015 due to the changes in net income as described below partially offset by the dilutive effect of issuing 161 million common shares in 2016.

 
TransCanada Management's discussion and analysis 2016

19


The following specific items were recognized in net income/(loss) attributable to common shares in 2014 to 2016 and were excluded from comparable earnings for the relevant periods:
2016
a $656 million after-tax impairment of Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeds its carrying value
an $873 million after-tax loss on U.S. Northeast power assets held for sale which included an $863 million after-tax loss on the thermal and wind package held for sale and $10 million of after-tax costs related to the monetization
a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs (both directly and through our equity investment in ASTC Power Partnership) as a result of our decision to terminate the PPAs and a $68 million after-tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the PPA terminations
costs associated with the acquisition of Columbia resulting in an after-tax charge of $273 million which included $109 million of dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $90 million of retention, severance and integration costs, $36 million of acquisition costs and a $44 million deferred income tax adjustment upon acquisition partially offset by $6 million of interest earned on the subscription receipt funds held in escrow prior to their conversion to common shares
$28 million of income tax recoveries related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our fourth quarter 2015 impairment charge, but the related income tax recoveries could not be recorded until realized
an after-tax charge of $42 million related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project
an after-tax charge of $16 million for restructuring mainly related to expected future losses under lease commitments. These charges form part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs
an additional $3 million after-tax loss on the sale of TC Offshore which closed in early 2016.
2015
a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects
an $86 million after-tax loss provision related to the sale of TC Offshore which closed in early 2016
a net charge of $74 million after tax for restructuring comprised of $42 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges formed part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs
a $43 million after-tax charge relating to an impairment in value on turbine equipment held for future use in our Energy business
a $34 million adjustment to income tax expense due to the enactment of a two per cent increase in the Alberta corporate income tax rate in June 2015
a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships
a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes.
2014
a gain of $99 million after tax on the sale of Cancarb Limited and its related power generation business
a net loss of $32 million after tax resulting from a termination payment to Niska Gas Storage for contract restructuring
a gain of $8 million after tax on the sale of our 30 per cent interest in Gas Pacifico/INNERGY.
Certain unrealized fair value adjustments relating to risk management activities are also excluded from comparable earnings. The remainder of net income/(loss) is equivalent to comparable earnings. A reconciliation of net income/(loss) attributable to common shares to comparable earnings is shown in the following table.
Refer to the Results section in each business segment and the Financial condition section of this MD&A for further discussion of these highlights.

20
 TransCanada Management's discussion and analysis 2016
 


Reconciliation of net income/(loss) to comparable earnings
year ended December 31
 
 
 
 
 
 
(millions of $, except per share amounts)
 
2016

 
2015

 
2014

 
 
 
 
 
 
 
Net income/(loss) attributable to common shares
 
124

 
(1,240
)
 
1,743

Specific items (net of tax):
 
 
 
 
 
 
Ravenswood goodwill impairment
 
656

 

 

Loss on U.S. Northeast power assets held for sale
 
873

 

 

Alberta PPA terminations and settlement
 
244

 

 

Acquisition related costs – Columbia
 
273

 

 

Keystone XL income tax recoveries
 
(28
)
 

 

Keystone XL asset costs
 
42

 

 

Restructuring costs
 
16

 
74

 

TC Offshore loss on sale
 
3

 
86

 

Keystone XL impairment charge
 

 
2,891

 

Turbine equipment impairment charge
 

 
43

 

Alberta corporate income tax rate increase
 

 
34

 

Bruce Power merger – debt retirement charge
 

 
27

 

Non-controlling interests (TC PipeLines, LP – Great Lakes impairment)
 

 
(199
)
 

Cancarb gain on sale
 

 

 
(99
)
Niska contract termination
 

 

 
32

Gas Pacifico/ INNERGY gain on sale
 

 

 
(8
)
Risk management activities1
 
(95
)
 
39

 
47

Comparable earnings
 
2,108

 
1,755

 
1,715

 
 
 
 
 
 
 
Net income/(loss) per common share
 

$0.16

 
$(1.75)
 
$2.46
Specific items (net of tax):
 
 
 
 
 
 
Ravenswood goodwill impairment
 
0.86

 

 

Loss on U.S. Northeast power assets held for sale
 
1.15

 

 

Alberta PPA terminations and settlement
 
0.32

 

 

Acquisition related costs – Columbia
 
0.37

 

 

Keystone XL income tax recoveries
 
(0.04
)
 

 

Keystone XL asset costs
 
0.06

 

 

Keystone XL impairment charge
 

 
4.08

 

TC Offshore loss on sale
 

 
0.12

 

Restructuring costs
 
0.02

 
0.10

 

Turbine equipment impairment charge
 

 
0.06

 

Alberta corporate income tax rate increase
 

 
0.05

 

Bruce Power merger – debt retirement charge
 

 
0.04

 

Non-controlling interests (TC PipeLines, LP – Great Lakes impairment)
 

 
(0.28
)
 

Cancarb gain on sale
 

 

 
(0.14
)
Niska contract termination
 

 

 
0.04

Gas Pacifico/ INNERGY gain on sale
 

 

 
(0.01
)
Risk management activities
 
(0.12
)
 
0.06

 
0.07

Comparable earnings per common share
 
$2.78
 
$2.48
 
$2.42

 
TransCanada Management's discussion and analysis 2016

21


1
 
year ended December 31
 
 
 
 
 
 
 
 
(millions of $)
 
2016

 
2015

 
2014

 
 
 
 
 
 
 
 
 
 
 
Canadian Power
 
4

 
(8
)
 
(11
)
 
 
U.S. Power
 
113

 
(30
)
 
(55
)
 
 
Liquids marketing
 
(2
)
 

 

 
 
Natural Gas Storage
 
8

 
1

 
13

 
 
Foreign exchange
 
26

 
(21
)
 
(21
)
 
 
Income taxes attributable to risk management activities
 
(54
)
 
19

 
27

 
 
Total unrealized gains/(losses) from risk management activities
 
95

 
(39
)
 
(47
)
Comparable earnings
 
Comparable earnings per share
compearnings2016.jpg
 
compearnpershare2016.jpg
 
Comparable earnings per share in 2016 were impacted by the dilutive effect of issuing 161 million common shares that year. See the Financial condition section of this MD&A for further information on the common share issuances.
Comparable earnings in 2016 were $353 million higher than in 2015. The 2016 increase in comparable earnings was primarily the net result of:
higher earnings from our U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition, higher ANR transportation revenue resulting from higher rates effective August 1, 2016, new contracts on ANR Southeast Mainline transportation revenues and lower OM&A expenses
higher interest expense from debt issuances and lower capitalized interest
higher interest income and other due to realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income
lower earnings from Liquids Pipelines due to the net effect of higher contracted and lower uncontracted volumes on Keystone and lower volumes on Marketlink
higher AFUDC on our rate-regulated projects including those for the NGTL System, Energy East, Columbia and Mexico pipelines
higher contribution from Mexico Natural Gas Pipelines primarily due to earnings from Topolobampo beginning in July 2016
higher earnings from Natural Gas Storage due to higher realized natural gas storage price spreads.
Comparable earnings in 2015 were $40 million higher than 2014, an increase of $0.06 per common share.
The 2015 increase in comparable earnings was primarily the net result of:
higher earnings from Liquids Pipelines due to higher volumes on the Keystone Pipeline System
lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes
higher interest expense as a result of long term debt issuances net of maturities
higher interest income and other as a result of increased AFUDC related to our rate-regulated pipeline projects including Energy East and our Mexico pipelines

22
 TransCanada Management's discussion and analysis 2016
 


higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower capacity revenue in New York and lower realized prices at our northeastern U.S. Power facilities
higher earnings from U.S. Natural Gas Pipelines due to higher ANR, Great Lakes and GTN transportation revenues
higher earnings from Eastern Power primarily due to four solar facilities acquired in 2014
higher earnings from the Tamazunchale Extension which was placed in service in 2014.

 
TransCanada Management's discussion and analysis 2016

23


Cash flows
Net cash provided by operations
 
Comparable funds generated from operations
 
cashfromops2016.jpg
 
compfgfo2016.jpg
 
Net cash provided by operations was 16 per cent higher and comparable funds generated from operations were seven per cent higher in 2016 compared to 2015, primarily due to higher comparable earnings, as described above. In addition, net cash provided by operations was affected by the timing of working capital changes.
Comparable distributable
cash flow
 
Comparable distributable
cash flow per share
 
compdcf2016.jpg
 
compdcfpershare2016.jpg
 
Comparable distributable cash flow increased in 2016 compared to 2015 primarily due to higher comparable earnings as described above, partially offset by higher maintenance capital expenditures in 2016. Comparable distributable cash flow per common share decreased year over year due to the common share issuances in 2016. See the Financial condition section for more information on the calculation of comparable distributable cash flow.

24
 TransCanada Management's discussion and analysis 2016
 


Funds used in investing activities
Capital spending1 
year ended December 31
 
 
 
 
 
 
(millions of $)
 
2016

 
2015

 
2014

 
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
1,525

 
1,596

 
1,141

U.S. Natural Gas Pipelines
 
1,517

 
537

 
277

Mexico Natural Gas Pipelines
 
944

 
566

 
718

Liquids Pipelines
 
810

 
1,290

 
1,949

Energy
 
473

 
376

 
206

Corporate
 
33

 
64

 
46

 
 
5,302

 
4,429

 
4,337

1 Capital spending includes capacity capital expenditures, maintenance capital expenditures and capital projects in development.
Capital spending
 
 
 
a2016capspenda01.jpg
 
 
 
We invested $5.3 billion in capital projects in 2016 to optimize the value of our existing assets and develop new, complementary assets in high demand areas that are expected to generate stable, predictable earnings and cash flow and to maximize returns to shareholders for years to come.
Other investing activities
In 2016, we made contributions of $765 million to our equity investments primarily related to our investment in Bruce Power, Grand Rapids and Sur de Texas.
In 2016, we acquired Columbia for a purchase price of US$10.3 billion in cash.
In 2016, Bruce Power issued bonds and borrowed under its bank credit facility as part of its financing program to fund its capital program and made distributions to its partners, including $725 million to us.
Balance sheet
We continue to maintain a solid financial position while growing our total assets by $29.5 billion since 2014. At December 31, 2016, common equity represented 32 per cent (30 per cent in 2015) of our capital structure, while other subordinated capital in the form of junior subordinated notes and preferred shares represented an additional 11 per cent. See page 79 for more information about our capital structure.
Common shares repurchased
In November 2015, we announced that the TSX had approved our normal course issuer bid (NCIB), which allowed for the repurchase and cancellation of up to 21.3 million of our common shares, representing three per cent of our issued and outstanding common shares, between November 23, 2015 and November 22, 2016, at prevailing market prices plus brokerage fees, or such other prices as may be permitted by the TSX. During that period, 7.1 million shares were repurchased at an average price of $43.36. The NCIB has now expired and has not been renewed. With the acquisition of Columbia, we do not anticipate further repurchases in the foreseeable future.

 
TransCanada Management's discussion and analysis 2016

25


Dividends
We increased the quarterly dividend on our outstanding common shares by 10.6 per cent to $0.625 per common share for the quarter ending March 31, 2017 which equates to an annual dividend of $2.50 per common share and reflects our expectation of being able to grow our common share dividend at an average annual rate at the upper end of an eight to ten per cent range through the end of the decade. This is the 17th consecutive year we have increased the dividend on our common shares.
Dividends declared per common share
 
 
divdeclared2016.jpg
 
 
 
Dividend reinvestment plan
Under our DRP, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent rather than purchased on the open markets to satisfy participation in the DRP.
Quarterly dividend on our common shares
$0.625 per common share (for the quarter ending March 31, 2017)
Annual dividends on our preferred shares1 
Series 1 $0.8165
Series 2 $0.60452 
Series 3 $0.538
Series 4 $0.44452 
Series 5 $0.565753  
Series 6 $0.509252,4
 
Series 7 $1.00
Series 9 $1.0625
Series 11 $0.95
Series 13 $1.3755
Series 15 $1.32926

1
Annual dividend based on applicable fixed or quarterly floating rate as of February 15, 2017.
2
Floating quarterly dividend rate resets each quarter. See the Financial condition section for more information.
3
Series 5 preferred shares dividend rate changed in February 2016.
4
Series 6 preferred shares were issued February 2016.
5
Series 13 preferred shares were issued April 2016.
6
Series 15 preferred shares were issued November 2016.
Cash dividends paid
year ended December 31
 
 
 
 
 
 
(millions of $)
 
2016

 
2015

 
2014

 
 
 
 
 
 
 
Common shares
 
1,436

 
1,446

 
1,345

Preferred shares
 
100

 
92

 
94


26
 TransCanada Management's discussion and analysis 2016
 


OUTLOOK
Earnings
We anticipate our 2017 earnings, after excluding specific items, to be higher than 2016 mainly due to the following:
Full year contribution from Columbia including new assets coming into service in late 2017
Full year of operations from Topolobampo and Mazatlán in Mexico
Growth in the average investment base for the NGTL System
Higher expected Bruce Power equity income due to lower planned maintenance activity
Expected earnings from new liquids pipeline interconnections and the Northern Courier and Grand Rapids projects being placed in service
Full year impact of the ANR settlement
Partially offset by:
Loss of operational earnings as a result of the monetization of U.S. Northeast power business in the first half of 2017.
In addition, on a per share basis, the full year impact of 2016 equity issuances is expected to have a partially dilutive effect on 2017 earnings.
Natural Gas Pipelines
Earnings from the Natural Gas Pipelines segments are primarily affected by regulatory decisions and the timing of these decisions. Earnings are also impacted by market conditions, which drive the level of demand and the rates we secure for our services.
Canadian Natural Gas Pipelines earnings in 2017 are expected to be higher than 2016 due to continued growth in the NGTL System as we continue to invest in connecting new natural gas supply in northeastern British Columbia and Alberta markets and respond to growing demand in intra-basin and export markets.
U.S. Natural Gas Pipelines earnings are expected to be higher in 2017 compared to 2016 as a result of a full year of earnings from our Columbia assets, the ANR settlement in 2016 and new long term contracts associated with the Leach XPress and Rayne XPress projects.
Mexico Natural Gas Pipelines earnings are expected to be higher in 2017 reflecting the addition of the Topolobampo and Mazatlán Pipeline assets in 2016 and AFUDC from our equity interest in the Sur de Texas pipeline project.
Liquids Pipelines
Earnings from the Liquids Pipelines business are mainly generated from offering pipeline capacity supported by long term contracts. Uncontracted capacity is offered to the market providing opportunities to generate incremental earnings.
Liquids Pipelines earnings in 2017 are expected to be slightly higher than 2016 as additional pipeline interconnections and the Northern Courier and Grand Rapids projects are placed into service.
Energy
Earnings in the Energy segment are generally maximized by maintaining and optimizing the operations of our power plants and through various marketing activities. The monetization of the U.S. Northeast power assets will result in the vast majority of Energy's remaining generation being sold under long-term contracts.
Overall we expect Energy earnings in 2017 to be lower compared to 2016 primarily as a result of the monetization of the U.S. Northeast power assets. Canadian Power earnings are expected to be higher in 2017 due to higher Bruce Power equity income resulting from lower planned maintenance activity.
Consolidated capital spending and equity investments
We expect to spend approximately $9 billion in 2017 on new and existing capital projects which includes capital expenditures on growth projects, maintenance activities and contributions to equity investments. The 2017 capital program primarily relates to Natural Gas Pipelines projects including Columbia projects, NGTL System expansions, Sur de Texas, ANR, Canadian Mainline, Tula and Villa de Reyes; Liquids Pipelines projects including Grand Rapids, Northern Courier and White Spruce; and Energy projects including Bruce Power and Napanee.

 
TransCanada Management's discussion and analysis 2016

27


NATURAL GAS PIPELINES BUSINESS
Our natural gas pipeline network transports natural gas from supply basins to local distribution companies, power generation facilities, interconnecting pipelines and other businesses across Canada, the U.S. and Mexico. Our network of pipelines taps into virtually every major supply basin and transports over 25 per cent of continental daily natural gas needs through:
Wholly-owned natural gas pipelines – 80,400 km (50,000 miles)
Partially-owned natural gas pipelines – 11,100 km (6,900 miles).
In addition to our interstate natural gas pipelines, we also have regulated natural gas storage facilities in the U.S. with a total working gas capacity of 535 Bcf, making us one of the largest providers of natural gas storage and related services to key markets in North America. We also own and manage Columbia's midstream services which provides specific natural gas producer services including gathering, treatment, conditioning, processing and liquids handling with a focus on the Appalachian Basin.
Our Natural Gas Pipelines business is split into three operating segments representing its geographic diversity: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines.
Strategy at a glance
Optimizing the value of our existing natural gas pipeline systems, while responding to the changing flow patterns of natural gas in North America, is a top priority.
We are also pursuing new pipeline opportunities to add incremental value to our business. Our key areas of focus include:
•   Expansion and extension of our existing large North American natural gas pipeline footprint
•   Connections to new and growing industrial, LDC, interconnect and electric power generation markets
•  Connections to growing Canadian and U.S. shale gas and other supplies
•   Additional new pipeline developments within Mexico
•  Greenfield development projects, such as infrastructure for LNG exports from the west coast of Canada and the Gulf of
       Mexico
all of which play a critical role in meeting the transportation requirements for supply and demand for natural gas in North 
America.
 
Highlights
Acquisition of Columbia: On July 1, 2016, we acquired Columbia for US$10.3 billion in cash, creating one of North America's largest regulated natural gas transmission and storage businesses
Awarded Sur de Texas and Villa de Reyes pipeline projects in Mexico: Sur de Texas is a US$2.1 billion pipeline with a planned in-service date of late 2018, while Villa de Reyes is a US$0.6 billion pipeline with an anticipated in-service date of early 2018
NGTL's $1.3 billion 2017 Facilities Application approved by the Government of Canada: Consists of five pipeline loops and two compressor stations
ANR Section 4 Rate Case resolved through Settlement: FERC approved an uncontested settlement that resolved all issues in the Section 4 Rate Case filed by ANR
NGTL Saddle West Project: The $0.6 billion commercially secured expansion is a combination of pipeline looping and five new compressor units at existing sites, which is subject to regulatory approval and planned to be in-service in 2019

28
 TransCanada Management's discussion and analysis 2016
 


UNDERSTANDING THE NATURAL GAS PIPELINES BUSINESS
Natural gas pipelines move natural gas from major sources of supply to locations or markets that use natural gas to meet their energy needs.
Our natural gas pipeline business builds, owns and operates a network of natural gas pipelines across North America that connects gas production to interconnects and end use markets. The network includes pipelines that are buried underground and transport natural gas predominantly under high pressure, compressor stations that act like pumps to move the large volumes of natural gas along the pipeline, meter stations that record the amount of natural gas coming on the network at receipt locations and leaving the network at delivery locations, and natural gas storage facilities that provide services to customers and help maintain the overall balance of the pipeline systems.
Our Major Pipeline Systems
The Natural Gas Pipelines map on page 30 shows our extensive pipeline network in North America that connects major supply sources and markets. Our major pipeline systems in Canada and the U.S. account for approximately 85 per cent of the total owned and operated pipe network within our extensive footprint.
NGTL System: This is our natural gas gathering and transportation system for the WCSB, connecting most of the natural gas production in western Canada to domestic and export markets. We believe we are very well positioned to connect growing supply in northeast B.C. and northwest Alberta and it is these two supply areas, along with growing demand for firm transportation in the oil sands area, that is driving our large capital program for new pipeline facilities on the NGTL System. The NGTL System is also well positioned to connect WCSB supply to potential LNG export facilities on the Canadian west coast.
Canadian Mainline: This is a major pipeline that was originally designed as a long haul delivery system transporting supply from the WCSB across Canada to Ontario and Québec to deliver gas to downstream Canadian and U.S. markets. The Canadian Mainline is also growing to accommodate additional supply connections closer to these markets.
Columbia Gas: This is our natural gas transportation system for the Appalachian basin, which contains the Marcellus and Utica shale plays. The Marcellus and Utica plays are two of the fastest growing natural gas shale plays in North America. Similar to our footprint in the WCSB, Columbia assets are very well positioned to connect growing supply and market in this area. This system also interconnects with other pipelines that provide access to key markets in the U.S. Northeast and south to the Gulf of Mexico and its growing demand for natural gas to serve LNG exports. Access to markets from producers in the region is driving the large capital program for new pipeline facilities on this system.
ANR Pipeline System: ANR is our pipeline system that connects supply basins and markets throughout the U.S. Midwest, and south to the Gulf of Mexico. This includes connecting supply in Texas, Oklahoma, the Appalachian basin and the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois and Ohio.
Columbia Gulf: This is our pipeline system originally designed as a long haul delivery system transporting supply from the Gulf of Mexico to major supply markets in the U.S. Northeast. The pipeline is now transitioning and expanding to accommodate new supply in the Appalachian basin and its interconnect with Columbia Gas and other pipelines to deliver gas to various Gulf Coast markets.
Mexico Pipeline Network: In addition to the five major Canadian and U.S. pipeline systems above, we also have, in Mexico, a growing network of natural gas pipelines in service coupled with a large portfolio of projects under construction, including two on-shore pipeline projects, Tula and Villa de Reyes, that together consist of 720 km (445 miles) of 16, 24 and 36-inch pipelines, plus the Sur de Texas project, which is a 800 km (497 miles) 42-inch off-shore pipeline. We own 60 per cent of Sur de Texas through our joint venture with IEnova.
Regulation of tolls and cost recovery
Our natural gas pipelines are generally regulated by the NEB in Canada, by the FERC in the U.S. and by the CRE in Mexico. The regulators approve construction of new pipeline facilities and ongoing operations of the infrastructure.
Regulators in Canada, the U.S. and Mexico allow us to recover costs to operate the network by collecting tolls for services. These tolls generally include a return on our capital invested in the assets or rate base, as well as the recovery of the rate base over time through depreciation. Other costs recovered include OM&A costs, income and property taxes and interest on debt. The regulator reviews our costs to ensure they are reasonable and prudently incurred and approves tolls that provide us a reasonable opportunity to recover them.

 
TransCanada Management's discussion and analysis 2016

29


Business environment and strategic priorities
The North American natural gas pipeline network has been developed to connect diverse supply regions to domestic markets and increasingly, to meet demand for LNG facilities. Use and growth of this infrastructure is affected by changes in the location and relative cost of natural gas supplies as well as changes in the location of markets and level of demand.
We have significant pipeline footprints that serve the two major supply regions of North America, which are the WCSB and the Appalachian basin. Our pipelines also source natural gas, to a lesser degree, from other significant basins including the Rockies, Williston, Haynesville, Fayetteville and Anadarko as well as the Gulf of Mexico. We expect continued growth in North American natural gas production to meet growing domestic markets, particularly in the electric generation and industrial sectors which benefit from a relatively low gas price. In addition, North American supply is expected to benefit from access to international markets via LNG exports. This view is consistent with those of independent third parties including the U.S. Energy Information Administration (EIA) in their Annual Energy Outlook 2017 and International Energy Outlook 2016 reports. According to these reports, North American gas demand for 2016 was nearly 90 Bcf/d and, with the growth in domestic markets and most particularly due to the addition of LNG markets, is expected to grow to approximately 100 Bcf/d by 2020.
This increased demand for natural gas, coupled with the annual decline rate of 15 per cent to 20 per cent for natural gas production, implies up to 25 Bcf/d of new production per year will be required to meet current and forecasted demand. That new production provides investment opportunities for pipeline infrastructure companies seeking to build new facilities to connect new supply and/or increase utilization of the existing footprint.
Changing demand
The growing supply of natural gas has resulted in relatively low natural gas prices in North America, which has supported increased demand particularly in the following areas:
natural gas-fired power generation
petrochemical and industrial facilities
the production of Alberta oil sands, although new greenfield projects that have not begun construction may be delayed in the current low oil price environment
exports to Mexico to fuel new power generation facilities.
Natural gas producers continue to progress opportunities to sell natural gas to global markets, which involves connecting natural gas supplies to new LNG export terminals being proposed primarily along the west coast of Canada and the U.S. Gulf of Mexico. The demand created by the addition of these new markets creates opportunities for us to build new pipeline infrastructure and to increase throughput on our existing pipelines.
Commodity prices
In general, the profitability of our gas pipelines business is not directly tied to commodity prices given we are a transporter of the commodity and the transportation costs are not tied to the price of natural gas. However, the cyclical supply and demand nature of commodities and related pricing can have an indirect impact on our business where producers may choose to accelerate or delay exploration or, similarly on the demand side, projects requiring natural gas may be accelerated or delayed depending on market or price conditions. Lower prices have allowed natural gas to gain market share versus coal in serving power generation markets. We continue to see record levels of natural gas consumed as the fuel source for electric power generation. In addition, U.S. LNG export levels continue to increase, primarily in the Gulf Coast area.
More competition
Changes in supply and demand levels and locations have resulted in increased competition for transportation services throughout North America. With our well distributed footprint of natural gas pipelines, and particularly our new presence in the growing Appalachian region, we are well positioned to compete. Along with other pipelines, we have and continue to assess further opportunities to restructure our tolls and service offerings to capture growing supply and North American demand that now includes access to world markets through LNG exports.
Strategic priorities
We are focused on capturing opportunities resulting from growing natural gas supply, and connecting new markets, while satisfying increasing demand for natural gas within existing markets. We are also focused on adapting our existing assets to the changing gas flow dynamics.
In 2017, one of our key focus areas will be on the continued execution of our large existing capital program that includes further expansion of the existing NGTL and Columbia systems and advancing several new natural gas pipeline projects in Mexico. Our

30
 TransCanada Management's discussion and analysis 2016
 


near-term capital program in excess of $16 billion of projects, excluding North Montney, will see a continued progression of projects being placed in service over the next few years. Our goal is to ensure all of our projects are placed in service on time and on budget while ensuring the safety of our staff, contractors, and anyone impacted by the construction and operation of these facilities.
tcnatgasmapfeb157x83125.jpg



 
TransCanada Management's discussion and analysis 2016

31



We are the operator of all of the following natural gas pipelines and regulated natural gas storage assets except for Iroquois.
 
 
 
Length
 
Description
 
Effective
ownership

 
 
 
 
Canadian pipelines
 
 
 
 
 
 

 
 
 
1
NGTL System
 
24,012 km
(14,920 miles)
 
Receives, transports and delivers natural gas within Alberta and B.C., and connects with the Canadian Mainline, Foothills system and third-party pipelines.
 
100
%
 
 
 
2
Canadian Mainline
 
14,125 km
(8,777 miles)
 
Transports natural gas from the Alberta/Saskatchewan border and the Ontario/U.S. border to serve eastern Canada and interconnects to the U.S.
 
100
%
 
 
 
3
Foothills
 
1,241 km
(771 miles)
 
Transports natural gas from central Alberta to the U.S. border for export to the U.S. Midwest, Pacific northwest, California and Nevada.
 
100
%
 
 
 
4
Trans Québec & Maritimes (TQM)
 
572 km
(355 miles)
 
Connects with Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montréal to Québec City corridor, and interconnects with the Portland pipeline system that serves the Northeast U.S.
 
50
%
 
 
 
 
 
 
 
 
 
 
5
Ventures LP
 
161 km
(100 miles)
 
Transports natural gas to the oil sands region near Fort McMurray, Alberta. It also includes a 27 km (17 miles) pipeline supplying natural gas to a petrochemical complex at Joffre, Alberta.
 
100
%
 
 
 
 
U.S. pipelines
 
 
 
 
 
 

 
 
 
6
ANR
 
15,109 km
(9,388 miles)
 
Transports natural gas from supply basins to markets throughout the mid-west and south to the Gulf of Mexico.
 
100
%
 
6a
ANR Storage
 
250 Bcf
 
Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key mid-western markets.
 
 

 
 
 
7
Bison
 
488 km
(303 miles)
 
Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 26.8 per cent of the system through our interest in TC PipeLines, LP.
 
26.8
%
 
 
 
8
Columbia Gas
 
18,113 km
(11,255 miles)
 
Transports natural gas from supply primarily in the Appalachian basin to markets throughout the U.S. Northeast.
 
100
%
1 
8a
Columbia Storage
 
285 Bcf
 
Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key eastern markets. We also own a 50 per cent interest in the 12 Bcf Hardy Storage facility.
 
100
%
1 
8b
Midstream**
 
295 km
(185 miles)
 
Provides infrastructure between the producer upstream well-head and the downstream (interstate pipeline and distribution) sector and includes a 47 per cent interest in Pennant Midstream.
 
100
%
1 
 
 
 
 
 
 
 
 
 
9
Columbia Gulf
 
5,377 km
(3,341 miles)
 
Transports natural gas to on-system customers and to pipeline interconnects serving markets in the U.S. Midwest and Southeast.
 
100
%
1 
 
 
 
 
 
 
 
 
 
10
Crossroads
 
325 Km
(202 miles)
 
Interstate natural gas pipeline operating in Indiana and Ohio with multiple interconnects to other pipelines.
 
100
%
1 
 
 
 
 
 
 
 
 
 
11
Gas Transmission Northwest (GTN)
 
2,216 km
(1,377 miles)
 
Transports natural gas from the WCSB and the Rocky Mountains to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 26.8 per cent of the system through our interest in TC PipeLines, LP.
 
26.8
%
 
 
 
12
Great Lakes
 
3,404 km
(2,115 miles)
 
Connects with the Canadian Mainline near Emerson, Manitoba and St Clair, Ontario, plus interconnects with ANR at Crystal Falls and Farwell in Michigan, to transport natural gas to eastern Canada and the U.S. upper midwest. We effectively own 66 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 26.8 per cent interest in TC PipeLines, LP.
 
66
%
 
 
 
13
Iroquois
 
669 km
(416 miles)
 
Connects with Canadian Mainline near Waddington, New York to deliver natural gas to customers in the U.S. Northeast.
 
50
%
 
 
 

32
 TransCanada Management's discussion and analysis 2016
 


 
 
 
Length
 
Description
 
Effective
ownership

 
 
 
14
Millennium
 
407 km
(253 miles)
 
Natural gas pipeline supplied by local production, storage fields and interconnecting upstream pipelines to serve markets along its route and to the U.S. Northeast.
 
47.5
%
1 
 
 
 
 
 
 
 
 
 
15
North Baja
 
138 km
(86 miles)
 
Transports natural gas between Arizona and California, and connects with a third-party pipeline on the California/Mexico border. We effectively own 26.8 per cent of the system through our interest in TC PipeLines, LP.
 
26.8
%
 
 
 
 
 
 
 
 
 
 
16
Northern Border
 
2,272 km
(1,412 miles)
 
Transports WCSB and Rockies natural gas with connections to Foothills and Bison to U.S. Midwest markets. We effectively own 13.4 per cent of the system through our 26.8 per cent interest in TC PipeLines, LP.
 
13.4
%
 
 
 
 
 
 
 
 
 
 
17
Portland (PNGTS)
 
475 km
(295 miles)
 
Connects with TQM near East Hereford, Québec to deliver natural gas to customers in the U.S. Northeast. We effectively own 25.2 per cent of the system through the combination of 11.8 per cent direct ownership and our 26.8 per cent interest in TC PipeLines, LP. Prior to January 1, 2016 we had direct ownership of 61.7 per cent.
 
25.2
%
 
 
 
 
 
 
 
 
 
 
18
Tuscarora
 
491 km
(305 miles)
 
Transports natural gas from GTN at Malin, Oregon to markets in northeastern California and northwestern Nevada. We effectively own 26.8 per cent of the system through our interest in TC PipeLines, LP.
 
26.8
%
 
 
Mexican pipelines
 
 
 
 
 
 

 
 
 
19
Guadalajara
 
315 km
(196 miles)
 
Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco.
 
100
%
 
 
 
20
Mazatlán
 
413 km(257 miles)
 
Transports natural gas from El Oro to Mazatlán, Sinaloa in Mexico. Connects to the Topolobampo Pipeline at El Oro.
 
100
%
 
 
 
 
 
 
 
 
 
 
21
Tamazunchale
 
359 km
(223 miles)
 
Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potosi and on to El Sauz, Querétaro.
 
100
%
 
 
 
 
 
 
 
 
 
 
22
Topolobampo
 
530 km
(329 miles)
 
Transports natural gas to Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico.
 
100
%
 
 
 
 
Under construction
 
 
 
 
 
 

 
 
 
23
Tula
 
300 km*
(186 miles)
 
The pipeline will originate in Tuxpan in the state of Veracruz and extend through the states of Puebla and Hidalgo, supplying natural gas to CFE combined-cycle power generating facilities in each of those jurisdictions as well as to the central and western regions of Mexico.
 
100%

 
 
 
 
 
 
 
 
 
 
24
Villa de Reyes
 
420 km*
(261 miles)
 
The pipeline will deliver natural gas from Tula, Hildago to Villa de Reyes, and San Luis Potosi, connecting to the Tamazunchale and Tula pipelines.
 
100%

 
 
 
 
 
 
 
 
 
 
 
NGTL 2016/17 Facilities**
 
540 km*
(336 miles)
 
An expansion program comprised of 21 integrated projects of pipes, compression and metering to meet new incremental firm service requests received in 2014 on the NGTL System and expected to be completed between 2016 and 2018.
 
100%

 
 
 
 
 
 
 
 
 
 
 
Gibraltar**
 
42 km*
(26 miles)
 
A Midstream project designed to transport supply from the Marcellus and Utica shale plays into Columbia Gas and the Leach XPress pipeline project.
 
100%

1 
 
 
 
 
 
 
 
 
 
25
Leach XPress
 
260 km*
(160 miles)
 
A Columbia Gas project designed to transport supply from the Marcellus and Utica shale plays to points along the system.
 
100%

1 
 
 
 
 
 
 
 
 
 
 
Rayne XPress**
 
 
 
A Columbia Gulf project designed to transport supply from an interconnect with the Leach XPress pipeline project, plus another interconnect to markets along the system and to the Gulf Coast.
 
100%

1 
 
 
 
 
 
 
 
 
 
 
Cameron Access**
 
55 km*
(34 miles)
 
A Columbia Gulf pipeline to deliver natural gas from points along the Columbia Gulf system to the Cameron LNG facility.
 
100%

1 
 
 
 
 
 
 
 
 
 

 
TransCanada Management's discussion and analysis 2016

33


 
 
 
Length
 
Description
 
Effective
ownership
 
 
 
 
 
 
 
 
 
 
 
Permitting and pre-construction phase
 
 
 
 
 
 
 
 
 
 
 
 
 
 
26
Sur de Texas
 
800 km*
(497 miles)
 
The natural gas pipeline will begin offshore in the Gulf of Mexico at the border point near Brownsville Texas and end in Tuxpan, in the state of Veracruz, connecting with the Tamazunchale and Tula pipelines.
 
60%
 
 
 
 
 
 
 
 
 
 
27
Mountaineer XPress
 
275 km*
(171 miles)
 
A Columbia Gas project designed to transport supply from the Marcellus and Utica shale plays to points along the system.
 
100%
1 
 
 
 
 
 
 
 
 
 
 
NGTL 2018 Facilities**
 
88 km*
(55 miles)
 
An expansion program comprised of multiple projects of 20- to 48-inch diameter pipelines, one new compressor unit and multiple meter stations to meet new incremental firm service requests received in 2015 on the NGTL System and expected to be completed by 2020.
 
100%
 
 
 
 
 
 
 
 
 
 
 
NGTL Saddle West Expansion**
 
29 km*
(18 miles)
 
An expansion program comprised of multiple projects including mainline looping, five compressor units at existing stations plus new metering facilities.
 
100%
 
 
 
 
 
 
 
 
 
 
 
Gulf XPress**
 
 
 
A Columbia Gulf project designed to interconnect with the Mountaineer XPress pipeline project to markets along the pipelines and to the Gulf Coast.
 
100%
1 
 
 
 
 
 
 
 
 
 
 
WB XPress**
 
47 km*
(29 miles)
 
A Columbia Gas project designed to transport Marcellus supply both eastbound (to interconnects and mid-Atlantic markets) and westbound (to interconnect pipeline).
 
100%
1 
 
 
 
 
 
 
 
 
 
 
In development
 
 
 
 
 
 
 
 
 
28
Coastal GasLink
 
670 km*
(416 miles)
 
To deliver natural gas from the Montney gas producing region at an expected interconnect on NGTL near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C.
 
100%
 
 
 
 
 
 
 
 
 
 
29
Prince Rupert Gas Transmission
 
900 km*
(559 miles)
 
To deliver natural gas from the North Montney gas producing region at an expected interconnect on NGTL near Fort St. John, B.C. to the proposed Pacific Northwest LNG facility near Prince Rupert, B.C.
 
100%
 
 
 
 
 
 
 
 
 
 
30
North Montney
 
301 km*
(187 miles)
 
An extension of the NGTL System to receive natural gas from the North Montney gas producing region and connect to NGTL's existing Groundbirch Mainline and the proposed Prince Rupert Gas Transmission project.
 
100%
 
 
 
 
 
 
 
 
 
 
31
Merrick Mainline
 
260 km*
(161 miles)
 
To deliver natural gas from NGTL's existing Groundbirch Mainline near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C.
 
100%
 
 
 
 
 
 
 
 
 
 
32
Eastern Mainline
 
279 km*
(173 miles)
 
Pipeline and compression facilities expected to be added in the Eastern Triangle of the Canadian Mainline to meet the requirements of the existing shippers as well as new firm service requirements following the conversion of components of the Mainline to facilitate the Energy East project.
 
100%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1
Effective ownership of Columbia assets assumes the first quarter 2017 expected close of the acquisition of the outstanding publicly held common units of CPPL.
 
 
 
*
**
Final pipe lengths are subject to changes during construction and/or final design considerations.
Facilities and some pipelines are not shown on the map
 
 
 


34
 TransCanada Management's discussion and analysis 2016
 


Canadian Natural Gas Pipelines
UNDERSTANDING THE CANADIAN NATURAL GAS PIPELINES SEGMENT
The Canadian natural gas business is subject to regulation by various federal and provincial governmental agencies. The NEB, however, has comprehensive jurisdiction over our Canadian gas business. The NEB approves tolls and services that are in the public interest and provides a reasonable opportunity for a pipeline to recover its costs to operate the pipeline. Included in the overall costs to operate the pipeline is a return on the investment the company has made in the assets, referred to as the return on equity. Typically tolls are based on the cost of providing service divided by a forecast of throughput volumes. Any variance in either costs or the actual volumes transported can result in an over-collection or under-collection of revenue that is normally trued up the following year in the calculation of the tolls for that period. The return on equity, however, would continue to be earned at the rate approved by the NEB.
We and our shippers can also establish settlement arrangements, subject to approval by the NEB, that may have elements that vary from the typical toll-setting process. Settlements can include longer terms and mechanisms such as incentive agreements that can have an impact on the actual return on equity achieved. Examples include fixing the OM&A component in determining revenue requirements, where variances are to the pipeline's account or shared in some fashion between the pipeline and shippers.
The NGTL System is currently in the second year of a two-year settlement arrangement that includes a fixed OM&A component with variances shared, depending on the amount, between the shippers and the pipeline. The Mainline system has a five-year fixed toll settlement in place, but has an incentive arrangement where it has discretion to price certain of its short term services, like Interruptible Transportation Service at market prices. Settlements of this nature provide the pipeline an incentive to either decrease costs and/or increase revenues on the pipeline with a beneficial sharing mechanism to both the shippers and us.
SIGNIFICANT EVENTS
Canadian Regulated Pipelines
NGTL System
On October 6, 2016, the NEB recommended government approval of the $0.4 billion Towerbirch Project. This project consists of a 55 km (34 miles) 36-inch pipeline loop and a 32 km (20 miles) 30-inch pipeline extension of the NGTL System in northwest Alberta and northeast B.C. The NEB approved the continued use of the existing rolled-in toll methodology for this project.
On October 31, 2016, the Government of Canada approved our $1.3 billion NGTL 2017 Facilities Application, which is a major component of the 2016/2017 Facilities program. This NGTL expansion program consists of five pipeline loops ranging in size from 24-inch up to 48-inch pipe of approximately 230 km (143 miles) in length, plus two compressor station unit additions of approximately 46.5 MW (62,360 HP).
On December 7, 2016, we announced the $0.6 billion Saddle West expansion of the NGTL System to increase natural gas transportation capacity on the northwest portion of our system. The project will consist of 29 km (18 miles) of 36-inch pipeline looping of existing mainlines, the addition of five compressor units at existing station sites and new metering facilities. The project is underpinned by incremental firm service contracts and is expected to be in-service in 2019.
NGTL currently has a $3.7 billion near-term capital program for completion to 2020, including the Saddle West expansion and excluding the $1.7 billion North Montney and $1.9 billion Merrick pipeline projects. In 2016, we have placed in service approximately $0.5 billion of facilities. We currently have regulatory approval for $2.0 billion of facilities and plan to place in service $1.6 billion of new facilities in 2017.

 
TransCanada Management's discussion and analysis 2016

35


North Montney
On December 9, 2016, the Canadian Government approved the sunset clause extension for the North Montney project Certificate of Public Convenience and Necessity for one year to June 10, 2017. The extension continues to be subject to the condition that construction shall not begin until a positive FID has been made on the Pacific NorthWest LNG Project (PNW LNG). NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the $1.7 billion North Montney facilities, however, the in-service date will be finalized once a FID has been made.
Canadian Mainline Kings North and Station 130 Facilities
In fourth quarter 2016, we placed in service the approximate $310 million Kings North Connector and the approximate $75 million compressor unit addition at Station 130 on the Canadian Mainline system. These two projects are consistent with our current 2015-2020 Mainline Settlement with our shippers and provide optionality to access alternative supply sources while contracting for increased short haul transportation service within the Eastern Triangle area of the Canadian Mainline system.
Canadian Mainline Eastern Mainline Project
This $2 billion project consists of new gas facilities in southeastern Ontario that will be required as a result of the proposed Energy East project that includes a planned transfer of a portion of Canadian Mainline from natural gas service to crude oil service. The Eastern Mainline Project is conditioned on the approval and construction of the Energy East pipeline. See the Liquids Pipelines section for an update on Energy East .
Canadian Mainline Other Expansions
In addition to the Eastern Mainline Project, new facilities investments in the Eastern Triangle portion of the Canadian Mainline are planned for 2017. Including the Vaughan Loop, with a planned in-service date of November 2017, we have approximately $300 million of additional investment to meet contractual commitments from shippers.
LNG Pipeline Projects
Prince Rupert Gas Transmission (PRGT)
On September 27, 2016, PNW LNG received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. PNW LNG has indicated they will conduct a total project review over the coming months prior to announcing next steps for the project. The project has key approvals in place and construction will advance following direction from PNW LNG as the in-service date for PRGT will be aligned with PNW LNG's liquefaction facility timeline.
On December 21, 2016, PNW LNG received an LNG export license from the NEB which extended the export term from 25 years to 40 years.
We are continuing our engagement with Indigenous groups and have now signed project agreements with 14 First Nation groups along the pipeline route. Project agreements outline financial and other benefits and commitments that will be provided to each First Nation for as long as the project is in service.
PRGT is a 900 km (559 mile) natural gas pipeline that will deliver gas from the North Montney producing region at an expected interconnect on the NGTL System near Fort St. John, B.C. to PNW LNG's proposed LNG facility near Prince Rupert, B.C. Should the project not proceed, our project costs (including carrying charges) are fully recoverable.
Coastal GasLink
On July 11, 2016, the LNG Canada joint venture participants announced a delay to their FID for the proposed liquefied natural gas facility in Kitimat, B.C. A future FID date has not been disclosed. We are working with LNG Canada to maintain the appropriate pace of the Coastal GasLink development schedule and work activities.
We are continuing our engagement with Indigenous groups along our pipeline route and have now concluded long-term project agreements with 17 First Nation communities. We look to continue discussions with the remaining First Nations who have not signed Project Agreements.
Coastal GasLink is a 670 km (416 mile) pipeline that will deliver natural gas from the Dawson Creek, B.C. area, to LNG Canada’s proposed gas liquefaction facility near Kitimat, BC. Should the project not proceed, our project costs (including carrying charges) are fully recoverable.


36
 TransCanada Management's discussion and analysis 2016
 


FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). See page 8 for more information on non-GAAP measures we use. Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 and 2014 results have been adjusted to reflect this change.
year ended December 31
 
 
 
 
 
 
(millions of $)
 
2016

 
2015