EX-13.2 3 trp-12312015xmda.htm FORM 40-F MD&A Exhibit
EXHIBIT 13.2

Management's discussion and analysis
February 10, 2016
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, 2015.
This MD&A should be read with our accompanying December 31, 2015 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
8

ABOUT OUR BUSINESS
12

 
•  Three core businesses
12

 
•  Our strategy
16

 
•  Capital program
17

 
•  2015 financial highlights
19

 
•  Outlook
27

NATURAL GAS PIPELINES
29

LIQUIDS PIPELINES
47

ENERGY
57

CORPORATE
78

FINANCIAL CONDITION
82

OTHER INFORMATION
94

 
•  Risks and risk management
94

 
•  Controls and procedures
100

 
•  Critical accounting estimates
101

 
•  Financial instruments
104

 
•  Accounting changes
106

 
•  Reconciliation of non-GAAP measures
108

 
•  Quarterly results
111

GLOSSARY
118


 
 
 
 
TransCanada Management's discussion and analysis 2015 7



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 10, 2016 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 may include information about the following, among other things:
anticipated business prospects
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 costs for planned projects, including projects under construction and in development
expected schedules for planned projects (including anticipated construction and completion dates)
expected regulatory processes and outcomes
expected common share purchases under our normal course issuer bid
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
inflation rates, commodity prices and capacity prices
timing of financings and hedging
regulatory decisions and outcomes
foreign exchange rates
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
acquisitions and divestitures.

 
 
 
8  TransCanada Management's discussion and analysis 2015
 
 


Risks and uncertainties
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 U.S. Securities and Exchange Commission (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 184 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 2015 9



NON-GAAP MEASURES
We use the following non-GAAP measures:
EBITDA
EBIT
funds generated from operations
distributable cash flow
distributable cash flow per common share
comparable earnings
comparable earnings per common share
comparable EBITDA
comparable EBIT
comparable distributable cash flow
comparable distributable cash flow per common share
comparable income from equity investments
comparable depreciation and amortization
comparable interest expense
comparable interest income and other
comparable income tax expense
comparable income attributable to non-controlling interests.
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.
EBITDA and EBIT
We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings.
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.
Distributable cash flow
Distributable cash flow is defined as funds generated from operations plus distributions in excess of equity earnings less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures represent costs which are necessary to preserve the operating ability of our assets and investments. We believe it 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.

 
 
 
10  TransCanada Management's discussion and analysis 2015
 
 


Comparable measures
We calculate the 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.
Comparable measure
Original measure
 
 
comparable earnings
net income attributable to common shares
comparable earnings per common share
net income per common share
comparable EBITDA
EBITDA
comparable EBIT
segmented earnings
comparable distributable cash flow
distributable cash flow
comparable distributable cash flow per common share
distributable cash flow per common share
comparable income from equity investments
income from equity investments
comparable depreciation and amortization
depreciation and amortization
comparable interest expense
interest expense
comparable interest income and other
interest income and other
comparable income tax expense
income tax expense
comparable net income attributable to non-controlling interests
net income attributable to non-controlling interests
 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
gains or losses on sales of assets
legal, contractual and bankruptcy settlements
impact of regulatory or arbitration decisions relating to prior year earnings
restructuring costs
impairment of assets and investments.
In calculating comparable earnings and other comparable measures we exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives 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 unrealized changes in fair value do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.

 
 
 
 
TransCanada Management's discussion and analysis 2015 11



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.
THREE CORE BUSINESSES
We operate our business in three segments – Natural Gas Pipelines, Liquids Pipelines and Energy. We also have a non-operational Corporate segment consisting of corporate and administrative functions that provide support and governance to our operational business segments.
Our $64 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, 36 U.S. states and Mexico.

 
 
 
12  TransCanada Management's discussion and analysis 2015
 
 



 
 
 
 
TransCanada Management's discussion and analysis 2015 13



Year at a glance
at December 31
 
 
 
 
(millions of $)
2015

 
2014

 
 
 
 
 
Total assets
 
 
 
 
Natural Gas Pipelines
 
31,072

 
27,103

Liquids Pipelines
 
16,046

 
16,116

Energy
 
15,558

 
14,197

Corporate
 
1,807

 
1,109

 
 
64,483

 
58,525

year ended December 31
 
 
 
 
(millions of $)
2015

 
2014

 
 
 
 
 
Total revenues
 
 
 
 
Natural Gas Pipelines
 
5,383

 
4,913

Liquids Pipelines
 
1,879

 
1,547

Energy
 
4,038

 
3,725

 
 
11,300

 
10,185

 
 
 
 
 
year ended December 31
 
 
 
 
(millions of $)
2015

 
2014

 
 
 
 
 
Comparable EBIT
 
 
 
 
Natural Gas Pipelines
 
2,345

 
2,178

Liquids Pipelines
 
1,056

 
843

Energy
 
944

 
1,039

Corporate
 
(202
)
 
(150
)
 
 
4,143

 
3,910


                        

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

 
 
 
 
2015
709

 
2014
708

 
2013
707

 
 
 
 

 
 
 
14  TransCanada Management's discussion and analysis 2015
 
 


as at February 5, 2016
issued and outstanding

 

Common shares
 
 
 
 
702
 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

 
 
 
options to buy common shares
outstanding

exercisable

 
 
 
 
10
 million
6
 million

 
 
 
 
TransCanada Management's discussion and analysis 2015 15



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 $58 billion capital program, comprised of $13 billion in
   near-term projects and $45 billion in medium to long-term projects. These will contribute incremental earnings over the
   near, medium and long terms as our investments are placed in service.
• Our expertise in 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 energy and pipeline facilities.
• Our growing investment in natural gas, nuclear, wind, hydro and solar generating facilities demonstrates our commitment
   to clean, sustainable energy.
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.
Maximize our competitive strengths
 
 
• We are continually developing core competencies in areas such as 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 business cycles.
• 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: excellent reputation for consistent 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.
 

 
 
 
16  TransCanada Management's discussion and analysis 2015
 
 


CAPITAL PROGRAM
We are developing quality projects under our long-term 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 $13 billion of near-term projects and $45 billion of commercially secured medium and longer-term projects. Amounts presented exclude the impact of foreign exchange, 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.
at December 31, 2015
 
Estimated project cost

 
Carrying value

(billions of $)
Summary
 
 
 
 
Near-term
 
13.4

 
3.9

Medium to longer-term
 
45.2

 
2.1

Total capital program
 
58.6

 
6.0

 
 
 
 
 
Foreign exchange impact on Capital Program1
 
4.5

 
0.8

1 
Reflects U.S. foreign exchange rate of $1.38 at December 31, 2015.
Near-term projects
at December 31, 2015
 
Segment
 
Expected
in-service date
 
Estimated project cost

 
Carrying value

(billions of $)
 
 
 
 
 
 
 
 
 
Ironwood Acquisition
 
Energy
 
2016
 
US 0.7

 

Houston Lateral and Terminal
 
Liquids Pipelines
 
2016
 
US 0.6

 
US 0.5

Topolobampo
 
Natural Gas Pipelines
 
2016
 
US 1.0

 
US 0.9

Mazatlan
 
Natural Gas Pipelines
 
2016
 
US 0.4

 
US 0.3

Grand Rapids Phase 11
 
Liquids Pipelines
 
2017
 
0.9

 
0.5

Northern Courier
 
Liquids Pipelines
 
2017
 
1.0

 
0.6

Tuxpan-Tula
 
Natural Gas Pipelines
 
2017
 
US 0.5

 

Canadian Mainline  Other
 
Natural Gas Pipelines
 
20162017
 
0.7

 
0.1

NGTL System  North Montney
 
Natural Gas Pipelines
 
2017
 
1.7

 
0.3

 – 2016/17 Facilities
 
Natural Gas Pipelines
 
20162018
 
2.7

 
0.3

   2018 Facilities
 
Natural Gas Pipelines
 
2018
 
0.6

 

   Other
 
Natural Gas Pipelines
 
20162017
 
0.4

 
0.1

Napanee
 
Energy
 
2017 or 2018
 
1.0

 
0.3

Bruce Power – life extension1
 
Energy
 
20162020
 
1.2

 

Total near-term projects
 
 
 
 
 
13.4

 
3.9

1 
Our proportionate share.

 
 
 
 
TransCanada Management's discussion and analysis 2015 17



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 disclosed. 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, 2015
 
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 0.4

Keystone Hardisty Terminal2
 
Liquids Pipelines
 
0.3

 
0.1

Energy East projects
 
 
 
 
 
 
Energy East3
 
Liquids Pipelines
 
15.7

 
0.7

Eastern Mainline Project
 
Natural Gas Pipelines
 
2.0

 
0.1

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

 
0.3

Prince Rupert Gas Transmission
 
Natural Gas Pipelines
 
5.0

 
0.4

NGTL System – Merrick
 
Natural Gas Pipelines
 
1.9

 

Total medium to longer-term projects
 
 
 
45.2

 
2.1

1 
Our proportionate share.
2 
Carrying value reflects amount remaining after impairment charge.
3 
Excludes transfer of Canadian Mainline natural gas assets.

 
 
 
18  TransCanada Management's discussion and analysis 2015
 
 


2015 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, funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share are all non-GAAP measures. See page 10 for more information about the non-GAAP measures we use and pages 84 and 108 for a reconciliation to their GAAP equivalents.
year ended December 31
 
 
 
 
 
 
(millions of $, except per share amounts)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Income
 
 
 
 
 
 
Revenues
 
11,300

 
10,185

 
8,797

Net (loss)/income attributable to common shares
 
(1,240
)
 
1,743

 
1,712

per common share – basic & diluted
 

($1.75
)
 

$2.46

 

$2.42

Comparable EBITDA
 
5,908

 
5,521

 
4,859

Comparable earnings
 
1,755

 
1,715

 
1,584

per common share
 

$2.48

 

$2.42

 

$2.24

 
 
 
 
 
 
 
Cash flows
 
 
 
 
 
 
Funds generated from operations
 
4,513

 
4,268

 
4,000

Increase in working capital
 
(398
)
 
(189
)
 
(326
)
Net cash provided by operations
 
4,115

 
4,079

 
3,674

 
 
 
 
 
 
 
Comparable distributable cash flow
 
3,546

 
3,406

 
3,234

per common share
 
$5.00
 
$4.81
 
$4.57
 
 
 
 
 
 
 
Capital spending – capital expenditures
 
3,918

 
3,489

 
4,264

Capital spending – projects in development
 
511

 
848

 
488

Contributions to equity investments
 
493

 
256

 
163

Acquisitions, net of cash acquired
 
236

 
241

 
216

Proceeds from sale of assets, net of transaction costs
 

 
196

 

 
 
 
 
 
 
 
Balance sheet
 
 
 
 
 
 
Total assets
 
64,483

 
58,525

 
53,898

Long-term debt
 
31,584

 
24,757

 
22,865

Junior subordinated notes
 
2,422

 
1,160

 
1,063

Preferred shares
 
2,499

 
2,255

 
1,813

Non-controlling interests
 
1,717

 
1,583

 
1,611

Common shareholders' equity
 
13,939

 
16,815

 
16,712

 
 
 
 
 
 
 
Dividends declared
 
 
 
 
 
 
per common share
 

$2.08

 

$1.92

 

$1.84

per Series 1 preferred share
 

$0.8165

 

$1.15

 

$1.15

per Series 2 preferred share1
 

$0.6299

 

 

per Series 3 preferred share
 

$0.769

 

$1.00

 

$1.00

per Series 4 preferred share2
 

$0.2269

 

 

per Series 5 preferred share
 

$1.10

 

$1.10

 

$1.10

per Series 7 preferred share
 

$1.00

 

$1.00

 
$0.91
per Series 9 preferred share3
 

$1.0625

 
$1.09
 

per Series 11 preferred share4
 

$0.704

 

 

1 
Issued December 2014 upon conversion of Series 1 preferred shares.
2 
Issued June 2015 upon conversion of Series 3 preferred shares.
3 
Issued January 2014.
4 
Issued March 2015.

 
 
 
 
TransCanada Management's discussion and analysis 2015 19



Consolidated results
year ended December 31
 
 
 
 
 
 
(millions of $, except per share amounts)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Segmented earnings/(losses)
 
 
 
 
 
 
Natural Gas Pipelines
 
2,220

 
2,187

 
1,881

Liquids Pipelines
 
(2,630
)
 
843

 
603

Energy
 
812

 
1,051

 
1,113

Corporate
 
(301
)
 
(150
)
 
(124
)
Total segmented earnings
 
101

 
3,931

 
3,473

Interest expense
 
(1,370
)
 
(1,198
)
 
(985
)
Interest income and other
 
163

 
91

 
34

(Loss)/income before income taxes
 
(1,106
)
 
2,824

 
2,522

Income tax expense
 
(34
)
 
(831
)
 
(611
)
Net (loss)/income
 
(1,140
)
 
1,993

 
1,911

Net income attributable to non-controlling interests
 
(6
)
 
(153
)
 
(125
)
Net (loss)/income attributable to controlling interests
 
(1,146
)
 
1,840

 
1,786

Preferred share dividends
 
(94
)
 
(97
)
 
(74
)
Net (loss)/income attributable to common shares
 
(1,240
)
 
1,743

 
1,712

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

($1.75
)
 

$2.46

 

$2.42

Net (loss)/income attributable to common shares
 
Net (loss)/income per share
 
 
 
Net (loss)/income attributable to common shares in 2015 was a loss of $1,240 million (2014 – income of $1,743 million; 2013 –income of $1,712 million). The following specific items were recognized in net (loss)/income attributable to common shares in 2013 to 2015 and were excluded from comparable earnings for the relevant periods:
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 expected to close in early 2016
a net charge of $74 million after tax for restructuring charges 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 form 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

 
 
 
20  TransCanada Management's discussion and analysis 2015
 
 


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.
2013
net income of $84 million recorded in 2013 related to 2012 from the NEB 2013 decision on the Canadian Restructuring Proposal (NEB 2013 Decision)
a favourable tax adjustment of $25 million due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax.
Certain unrealized fair value adjustments relating to risk management activities are also excluded from comparable earnings. The remainder of net (loss)/income is equivalent to comparable earnings. A reconciliation of net (loss)/income 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.

 
 
 
 
TransCanada Management's discussion and analysis 2015 21



Reconciliation of net (loss)/income to comparable earnings
year ended December 31
 
 
 
 
 
 
(millions of $, except per share amounts)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Net (loss)/income attributable to common shares
 
(1,240
)
 
1,743

 
1,712

Specific items (net of tax):
 
 
 
 
 
 
Keystone XL impairment charge
 
2,891

 

 

TC Offshore loss on sale
 
86

 

 

Restructuring costs
 
74

 

 

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
)
 

NEB 2013 Decision – 2012
 

 

 
(84
)
Part VI.I income tax adjustment
 

 

 
(25
)
Risk management activities1
 
39

 
47

 
(19
)
Comparable earnings
 
1,755

 
1,715

 
1,584

 
 
 
 
 
 
 
Net (loss)/income per common share
 

($1.75
)
 
$2.46
 
$2.42
Specific items (net of tax):
 
 
 
 
 
 
Keystone XL impairment charge
 
4.08

 

 

TC Offshore loss on sale
 
0.12

 

 

Restructuring costs
 
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
)
 

NEB 2013 Decision – 2012
 

 

 
(0.12
)
Part VI.I income tax adjustment
 

 

 
(0.04
)
Risk management activities
 
0.06

 
0.07

 
(0.02
)
Comparable earnings per common share
 
$2.48
 
$2.42
 
$2.24
1 
 
year ended December 31
 
 
 
 
 
 
 
 
(millions of $)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
 
 
 
 
Canadian Power
 
(8
)
 
(11
)
 
(4
)
 
 
U.S. Power
 
(30
)
 
(55
)
 
50

 
 
Natural Gas Storage
 
1

 
13

 
(2
)
 
 
Foreign exchange
 
(21
)
 
(21
)
 
(9
)
 
 
Income tax attributable to risk management activities
 
19

 
27

 
(16
)
 
 
Total (losses)/gains from risk management activities
 
(39
)
 
(47
)
 
19


 
 
 
22  TransCanada Management's discussion and analysis 2015
 
 


Comparable earnings
 
Comparable earnings per share
 
 
 
Comparable earnings in 2015 were $40 million higher than in 2014, an increase of $0.06 per common share.
The 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 Pipeline and our Mexico pipelines
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.
The stronger U.S. dollar in 2015 compared to 2014 positively impacted the translated results in our U.S. businesses, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our exposure.
Comparable earnings in 2014 were $131 million higher than 2013, an increase of $0.18 per common share.
The increase in comparable earnings was primarily the net result of:
incremental earnings from the Gulf Coast extension of the Keystone Pipeline System which was placed in service in January 2014
higher interest expense from debt issuances and lower capitalized interest due to projects placed in service
lower earnings from Western Power as a result of lower realized power prices
higher earnings from the Tamazunchale Extension which was placed in service in 2014
higher earnings from U.S. Natural Gas Pipelines due to higher transportation revenues at Great Lakes reflecting colder winter weather and increased demand, partially offset by lower contributions from GTN and Bison following the reductions in our effective ownership in July 2013 (GTN and Bison) and October 2014 (Bison)
higher earnings from U.S. Power mainly because of higher realized capacity prices in New York and higher realized power prices at our New York and New England facilities
higher earnings from the Canadian Mainline due to higher incentive earnings
incremental earnings from Eastern Power primarily due to solar facilities acquired in 2013 and 2014.

 
 
 
 
TransCanada Management's discussion and analysis 2015 23



Cash flows
Funds generated from operations
Funds generated from operations were six per cent higher in 2015 compared to 2014 primarily due to higher comparable earnings, as described above.
Comparable distributable cash flow
 
Comparable distributable cash flow per share
 
 
 

Comparable distributable cash flow and comparable distributable cash flow per common share increased in 2015 compared to 2014 primarily due to higher comparable earnings, as described above. See the Financial condition section for more information on the calculation of comparable distributable cash flow.

 
 
 
24  TransCanada Management's discussion and analysis 2015
 
 


Funds used in investing activities
Capital spending1 
year ended December 31
 
 
 
 
 
 
(millions of $)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Natural Gas Pipelines
 
2,699

 
2,136

 
2,021

Liquids Pipelines
 
1,290

 
1,949

 
2,529

Energy
 
376

 
206

 
152

Corporate
 
64

 
46

 
50

 
 
4,429

 
4,337

 
4,752

1 Capital spending includes capital expenditures, maintenance capital expenditures and capital projects in development.
Capital spending
We invested $4.4 billion in capital projects in 2015 as part of our ongoing growth program which is a key part of our strategy 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.
Contributions to equity investments and acquisitions
In 2015, we made contributions of $493 million to our equity investments primarily related to the construction of Grand Rapids and we spent $236 million to increase our ownership in Bruce Power.
Balance sheet
We continue to maintain a solid balance sheet while growing our total assets by $10.6 billion since 2013. At December 31, 2015, common equity represented 30 per cent (38 per cent in 2014) of our capital structure, after giving effect to the various 2015 specific items outlined on pages 20 and 21. See page 83 for more information about our capital structure.
Common shares repurchased
On November 19, 2015, we announced that the Toronto Stock Exchange (TSX) approved our normal course issuer bid (NCIB), which allows 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.
As of February 10, 2016, we repurchased 7.1 million common shares at an weighted-average price per common share of $43.36 for a total cost of $307 million.

 
 
 
 
TransCanada Management's discussion and analysis 2015 25



Dividends
We increased the quarterly dividend on our outstanding common shares by nine per cent to $0.565 per common share for the quarter ending March 31, 2016 which equates to an annual dividend of $2.26 per common share and reflects our commitment to grow our common share dividend at an average annual rate of eight to ten per cent through 2020. This is the 16th consecutive year we have increased the dividend on our common shares.
Dividends declared per common share
Dividend reinvestment plan
Under our dividend reinvestment plan (DRP), eligible holders of TransCanada common or preferred shares can reinvest their dividends and make optional cash payments to buy additional TransCanada common shares on the open market.
Quarterly dividend on our common shares
$0.565 per common share (for the quarter ending March 31, 2016)
Annual dividends on our preferred shares1 
Series 1 $0.81652 
Series 2 $0.60453 
Series 3 $0.5384 
Series 4 $0.44453 
Series 5 $0.565755
Series 6 $0.509256
Series 7 $1.00
Series 9 $1.0625
Series 11 $0.95
1 
Annual dividend based on applicable annual or quarterly floating rate as of February 10, 2016.
2 
Dividend rate changed in December 2014.
3 
Floating quarterly dividend rate resets each quarter. See the Financial condition section for more information.
4 
Series 3 preferred shares dividend rate changed in June 2015.
5 
Series 5 preferred shares dividend rate changed in February 2016.
6 
Series 6 preferred shares were issued February 1, 2016.
Cash dividends
year ended December 31
 
 
 
 
 
 
(millions of $)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Common shares
 
1,446

 
1,345

 
1,285

Preferred shares
 
92

 
94

 
71


 
 
 
26  TransCanada Management's discussion and analysis 2015
 
 


OUTLOOK
Earnings
We anticipate our 2016 earnings, after excluding specific items, to be higher than 2015 mainly due to the following:
Expected earnings from Topolobampo and Mazatlan Pipeline projects coming into service
Positive impact of a stronger U.S. dollar on U.S. denominated earnings
Increase in the average investment base for the NGTL System
Higher earnings associated with incremental contracts from ANR
Cost savings achieved as a result of corporate restructuring
Consistent earnings in Energy with higher earnings in U.S. Power, relatively consistent earnings in Western Power and Bruce Power and slightly lower earnings in Eastern Power.
Partially offset by:
Reduced capitalized interest due to the Keystone XL Pipeline project Presidential permit denial
Lower anticipated earnings from the Keystone Pipeline System based on expiring short-term contracts for Cushing Marketlink.
Natural Gas Pipelines
Earnings from the Natural Gas Pipelines segment are 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 Mainline earnings are anticipated to be lower in 2016 due to a declining investment base. These lower earnings are expected to be largely offset by growth in the NGTL System investment base as we continue to invest in connecting new natural gas supply and respond to growing demand in the northeastern B.C. and Alberta markets.
U.S. and International Gas Pipelines earnings in 2016 are expected to be higher than 2015 as we pursue opportunities for continued growth in end use markets for natural gas and evaluate our commercial and operational positions in ANR and Great Lakes in response to positive developments in supply fundamentals in those market areas. On January 29th, 2016, ANR filed a Section 4 Rate Case with the FERC to increase its base rates. We anticipate that the proposed rates, which are subject to customer refund and pending final FERC approval, will take effect in third quarter 2016.
Mexico Pipeline earnings are expected to be higher in 2016 as the Topolobampo and Mazatlan Pipeline projects come into service in late 2016.
Liquids Pipelines
With the exception of the Keystone XL impairment impact, our 2016 earnings are expected to be slightly lower than our 2015 earnings due to short term contract expiration and market conditions related to the lower crude oil price environment.
Energy
Earnings in the Energy segment are generally maximized by maintaining and optimizing the operations of our power plants and through various marketing activities. Although a significant portion of Energy’s output is sold under long-term contracts, output that is sold under shorter-term arrangements or at spot prices will continue to be affected by fluctuations in commodity prices. Overall we expect Energy earnings in 2016 to be consistent with 2015.
Western Power earnings in 2016 are anticipated to be consistent with 2015 as a result of a well-supplied Alberta power market, slower demand growth and lower natural gas prices. Negative pressure on earnings in 2016 is expected due to the increase in the government imposed emissions reductions targets and higher per tonne GHG emissions costs.
Eastern Power earnings in 2016 are expected to be slightly lower as a result of the lower contractual earnings at Bécancour and reduced earnings from the sale of unused natural gas transportation.
Bruce Power equity income in 2016 is expected to be consistent with 2015 results. The net impact of the additional ownership interest obtained in Bruce Power in 2015 is anticipated to be largely offset by the increased planned maintenance activity in 2016.
U.S. Power results in 2016 are expected to be higher than 2015 due to the net impact of the additional earnings from the acquisition of the Ironwood natural gas fired, combined cycle power plant and lower marketing margins reflecting the return to normalized levels of costs and decreased volatility of forward natural gas and power prices in the New England market.
Natural Gas Storage earnings are expected to be higher as a modest recovery of seasonal spreads is expected to occur in 2016.

 
 
 
 
TransCanada Management's discussion and analysis 2015 27



Consolidated capital spending, equity investments and acquisition
We expect to spend approximately $6 billion in 2016 on new and existing capital projects. Capital spending includes capital expenditures on growth projects, maintenance capital expenditures and contributions to equity investments. The 2016 capital spending relates to Natural Gas Pipelines projects including NGTL System expansion, the Canadian Mainline, Tuxpan-Tula and Topolobampo; Liquids Pipelines projects including Grand Rapids, Northern Courier and Energy East; and Energy projects including Bruce Power and Napanee. Additionally, on February 1, 2016 we acquired Ironwood Power Plant for approximately US$657 million before post closing adjustments.

 
 
 
28  TransCanada Management's discussion and analysis 2015
 
 


Natural Gas Pipelines
Our natural gas pipeline network transports natural gas to local distribution companies, power generation facilities and other businesses across Canada, the U.S. and Mexico. We serve more than 80 per cent of the Canadian demand and approximately 15 per cent of the U.S. demand on a daily basis by connecting major natural gas supply basins and markets through:
wholly-owned natural gas pipelines – 56,600 km (35,200 miles)
partially-owned natural gas pipelines – 10,700 km (6,700 miles).
We also have regulated natural gas storage facilities in Michigan with a total capacity of 250 Bcf, making us one of the largest providers of natural gas storage and related services in North America.
Strategy at a glance
Optimizing the value of our existing natural gas pipelines 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:
•  greenfield development projects, such as infrastructure for liquefied natural gas (LNG) exports from the west coast of Canada and the Gulf of Mexico
•  additional new pipeline developments within Mexico
•  connections to emerging Canadian and U.S. shale gas and other supplies
•  connections to new and growing markets
all of which play a critical role in meeting the transportation requirements for supply and demand for natural gas in North America.
Highlights from 2015
We were awarded the contract to build, own and operate the 36-inch diameter Tuxpan-Tula pipeline in Mexico which is approximately 250 km (155 miles) long and has a contracted capacity of 866 MMcf/d. The pipeline is expected to begin construction in 2016 and be in-service in fourth quarter 2017.
The NEB approved the NGTL System’s $1.7 billion North Montney Mainline Project on June 11, 2015. Construction remains subject to a positive FID on the proposed Pacific Northwest LNG Project.
The NEB approved the Canadian Mainline's compliance filing on the NEB 2014 Decision as applied for. The approval was the last step in getting the NEB 2014 Decision implemented and allowing the Canadian Mainline to recognize incentive earnings. 
The NEB approved the Kings North Connection project on the Canadian Mainline which will increase gas transmission capacity into the greater Toronto area and provide shippers with the flexibility to source growing supplies of Marcellus gas from the U.S. Northeast.
An agreement was reached with eastern LDCs that resolves their issues with Energy East and the Eastern Mainline Project. The agreement honours our previously stated commitment to ensure that Energy East and the Canadian Mainline's Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs.
We continued the drop down of U.S. natural gas pipeline assets into TC PipeLines, LP, with the sale of the remaining 30% of GTN in April 2015 and 49.9% of PNGTS on January 1, 2016.
NGTL signed contracts for an additional 2.7 Bcf/d of new firm natural gas transportation service that will require a further $600 million expansion of the System for its 2018 Facilities program.

 
 
 
 
TransCanada Management's discussion and analysis 2015 29




 
 
 
30  TransCanada Management's discussion and analysis 2015
 
 


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
 
24,544 km
(15,251 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
 
14,114 km
(8,770 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 connects with the Portland pipeline system that serves the northeast U.S.
 
50
%
 
 
U.S. pipelines
 
 
 
 
 
 

 
5
ANR Pipeline
 
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
%
5a
ANR Storage
 
250 Bcf
 
Provides regulated underground natural gas storage service from facilities located in Michigan
 
 

 
6
Bison
 
488 km
(303 miles)
 
Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP
 
28
%
 
7
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 28 per cent of the system through our interest in TC PipeLines, LP
 
28
%
 
8
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 66.6 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 28 per cent interest in TC PipeLines, LP
 
66.6
%
 
9
Iroquois
 
669 km
(416 miles)
 
Connects with Canadian Mainline near Waddington, New York to deliver natural gas to customers in the U.S. northeast
 
44.5
%
 
10
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 28 per cent of the system through our interest in TC PipeLines, LP
 
28
%
 
 
 
 
 
 
 
 
11
Northern Border
 
2,264 km
(1,407 miles)
 
Transports WCSB and Rockies natural gas with connections to Foothills and Bison to U.S. Midwest markets. We effectively own 14 per cent of the system through our 28 per cent interest in TC PipeLines, LP
 
14
%
 
 
 
 
 
 
 
 
12
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 25.8 per cent of the system through the combination of 11.8 per cent direct ownership and our 28 per cent interest in TC PipeLines, LP. Prior to January 1, 2016 we had direct ownership of 61.7 per cent.
 
25.8
%
 
 
 
 
 
 
 
 
13
Tuscarora
 
491 km
(305 miles)
 
Transports natural gas from GTN at Malin, Oregon to markets in northeastern California and northwestern Nevada. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP
 
28
%

 
 
 
 
TransCanada Management's discussion and analysis 2015 31



 
 
 
length
 
description
 
effective
ownership

 
 
U.S. pipelines
 
 
 
 
 
 
 
14
TC Offshore1
 
958 km
(595 miles)
 
Gathers and transports natural gas within the Gulf of Mexico with subsea pipeline and seven offshore platforms to connect in Louisiana with our ANR Pipeline system.
 
100%

 
 
 
 
 
 
 
 
 
Mexican pipelines
 
 
 
 
 
 

 
15
Guadalajara
 
315 km
(196 miles)
 
Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco
 
100
%
 
16
Tamazunchale
 
365 km
(227 miles)
 
Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potosi and on to El Sauz, Queretaro
 
100
%
 
 
Under construction
 
 
 
 
 
 

 
17
Mazatlan Pipeline
 
413 km*
(257 miles)
 
To deliver natural gas from El Oro to Mazatlan, Sinaloa in Mexico. Will connect to the Topolobampo Pipeline at El Oro
 
100
%
 
18
Topolobampo Pipeline
 
530 km*
(329 miles)
 
To deliver natural gas to Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico
 
100
%
 
 
 
 
 
 
 
 
19
Tuxpan-Tula Pipeline
 
250 km*
(155 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%

 
 
 
 
 
 
 
 
 
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%

 
 
 
 
 
 
 
 
 
In development
 
 
 
 
 
 

 
20
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%

 
21
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%

 
 
 
 
 
 
 
 
22
North Montney Mainline
 
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%

 
 
 
 
 
 
 
 
23
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%

 
 
 
 
 
 
 
 
24
Eastern Mainline Project
 
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%

 
 
 
 
 
 
 
 
 
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 in 2018.
 
100%

 
 
 
 
 
 
 
 
*
**
Final pipe lengths are subject to changes during construction and/or final design considerations.
Facilities are not shown on the map
 
 
1 
As at December 31, 2015, TC Offshore was classified as Assets held for sale. See Significant Events for further information.

 
 
 
32  TransCanada Management's discussion and analysis 2015
 
 


RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Comparable depreciation and amortization is also a non-GAAP measure. See page 10 for more information on non-GAAP measures we use and page 108 for reconciliation to its GAAP equivalent.
year ended December 31
 
 
 
 
 
 
(millions of $)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Comparable EBITDA
 
3,477

 
3,241

 
2,852

Comparable depreciation and amortization
 
(1,132
)
 
(1,063
)
 
(1,013
)
Comparable EBIT
 
2,345

 
2,178

 
1,839

Specific items:
 
 
 
 
 
 
TC Offshore loss on sale
 
(125
)
 

 

Gas Pacifico/INNERGY gain on sale
 

 
9

 

NEB 2013 Decision – 2012
 

 

 
42

Segmented earnings
 
2,220

 
2,187

 
1,881

Natural Gas Pipelines segmented earnings in 2015 increased by $33 million compared to 2014 and included a $125 million before tax loss provision ($86 million after tax) as a result of a December 2015 agreement to sell TC Offshore, which is expected to close in early 2016. See Significant Events for more information. Segmented earnings in 2014 included $9 million related to the gain on sale of Gas Pacifico/INNERGY in November 2014 and, in 2013, included $42 million related to the 2012 impact of the NEB 2013 Decision. These amounts have been excluded from our calculation of comparable EBIT. Comparable EBIT and comparable EBITDA are discussed below.

 
 
 
 
TransCanada Management's discussion and analysis 2015 33



year ended December 31
 
 
 
 
 
 
(millions of $)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Canadian Pipelines
 
 
 
 
 
 
Canadian Mainline
 
1,230

 
1,334

 
1,121

NGTL System
 
934

 
856

 
846

Foothills
 
107

 
106

 
114

Other Canadian pipelines1
 
27

 
22

 
26

Canadian Pipelines – comparable EBITDA
 
2,298

 
2,318

 
2,107

Comparable depreciation and amortization
 
(845
)
 
(821
)
 
(790
)
Canadian Pipelines – comparable EBIT
 
1,453

 
1,497

 
1,317

U.S. and International Pipelines (US$)
 
 
 
 
 
 
ANR
 
232

 
189

 
188

TC PipeLines, LP1,2
 
106

 
88

 
72

Great Lakes3
 
63

 
49

 
34

Other U.S. pipelines (Bison4, GTN5, Iroquois1, Portland6)
 
84

 
132

 
183

Mexico (Guadalajara, Tamazunchale)
 
181

 
160

 
100

International and other1,7
 
4

 
(10
)
 
(4
)
Non-controlling interests8
 
292

 
241

 
186

U.S. and International Pipelines – comparable EBITDA
 
962

 
849

 
759

Comparable depreciation and amortization
 
(224
)
 
(219
)
 
(217
)
U.S. and International Pipelines – comparable EBIT
 
738

 
630

 
542

Foreign exchange impact
 
206

 
68

 
15

U.S. and International Pipelines – comparable EBIT (Cdn$)
 
944

 
698

 
557

Business Development comparable EBITDA and comparable EBIT
 
(52
)
 
(17
)
 
(35
)
Natural Gas Pipelines – comparable EBIT
 
2,345

 
2,178

 
1,839

Summary
 
 
 
 
 
 
Natural Gas Pipelines – comparable EBITDA
 
3,477

 
3,241

 
2,852

Comparable depreciation and amortization
 
(1,132
)
 
(1,063
)
 
(1,013
)
Natural Gas Pipelines – comparable EBIT
 
2,345

 
2,178

 
1,839

1 
Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments. In November 2014, we sold our interest in Gas Pacifico/INNERGY.
2 
Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program which, when utilized, decreases our ownership interest in TC PipeLines, LP. On October 1, 2014, we sold our remaining 30 per cent direct interest in Bison to TC PipeLines, LP. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP. Effective May 22, 2013 our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold 45 per cent of GTN and Bison to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Bison and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.
 
 
 
Ownership percentage as of
 
 
 
 
December 31,
2015
 
April 1,
 2015
 
October 1, 2014
 
January 1, 2014
 
July 1, 2013
 
May 22, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TC PipeLines, LP
 
28.0
 
28.3
 
28.3
 
28.9
 
28.9
 
28.9
 
Effective ownership through TC PipeLines, LP:
 
 
 
 
 
 
 
 
 
 
 
 
 
  Bison
 
28.0
 
28.3
 
28.3
 
20.2
 
20.2
 
7.2
 
  GTN
 
28.0
 
28.3
 
19.8
 
20.2
 
20.2
 
7.2
 
  Great Lakes
 
13.0
 
13.1
 
13.1
 
13.4
 
13.4
 
13.4
3 
Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.
4 
Effective October 1, 2014 we have no direct ownership in Bison. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.
5 
Effective April 1, 2015 we have no direct ownership in GTN. Prior to that our direct ownership was 30 per cent effective July 1, 2013.
6 
Represents our 61.7 per cent ownership interest.
7 
Includes our share of the equity income from TransGas and Gas Pacifico/INNERGY as well as general and administration costs relating to our U.S. and International

 
 
 
34  TransCanada Management's discussion and analysis 2015
 
 


Pipelines. In November 2014, we sold our interest in Gas Pacifico/INNERGY.
8 
Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.
Canadian Pipelines
year ended December 31
 
 
 
 
 
 
(millions of $)
 
2015

 
2014

 
2013

 
 
 
 
 
 
 
Net income
 
 
 
 
 
 
  Canadian Mainline – net income
 
213

 
300

 
361

  Canadian Mainline – comparable earnings
 
213

 
300

 
277

  NGTL System
 
269

 
241

 
243

Average investment base
 
 
 
 
 
 
  Canadian Mainline
 
4,784

 
5,690

 
5,841

  NGTL System
 
6,698

 
6,236

 
5,938

Net income and comparable EBITDA for our rate-regulated Canadian Pipelines are primarily affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenue on a flow-through basis.
In 2014, the Canadian Mainline operated under the NEB 2013 Decision for the years 2013-2017, which included an approved ROE of 11.5 per cent on deemed common equity of 40 per cent and an incentive mechanism based on total net revenues.
In 2015, the Canadian Mainline began operating under the NEB 2014 Decision which was approved by the NEB in November 2014 and superseded the NEB 2013 Decision. The NEB 2014 Decision included an approved ROE of 10.1 per cent with a possible range of achieved ROE outcomes between 8.7 per cent to 11.5 per cent. This decision also included an incentive mechanism that has both upside and downside risk and a $20 million annual after-tax contribution from us. Toll stabilization is achieved through the continued use of deferral accounts to capture the surplus or shortfall between our revenues and cost of service for each year over the six-year fixed toll term.
Canadian Mainline’s comparable earnings in 2015 decreased by $87 million compared to 2014 mainly due to a lower approved ROE on a lower average investment base, lower incentive earnings and a $20 million after-tax contribution from us resulting in a lower realized ROE of 11.15 per cent compared to the realized ROE of 13.18 per cent in 2014. The lower average investment base in 2015 was mainly due to the deferral of the 2014 net revenue surplus in the 2015 investment base.
Comparable earnings in 2014 were $23 million higher than 2013 because of higher incentive earnings partially offset by a lower average investment base. Net income of $361 million recorded in 2013 included $84 million related to the 2012 impact of the NEB 2013 Decision, which was excluded from comparable earnings.
Net income for the NGTL System was $28 million higher in 2015 compared to 2014 mainly due to a higher average investment base and OM&A incentive losses realized in 2014. Net income in 2014 was $2 million lower than 2013 due to the 2014 OM&A incentive losses realized partially offset by a higher average investment base. The 2015 NGTL Settlement included an ROE of 10.1 per cent on deemed common equity of 40 per cent and an annual cost-sharing mechanism for cost variances between actual and fixed OM&A costs. The 2013-2014 NGTL Settlement included an ROE of 10.1 per cent on deemed common equity of 40 per cent and fixed annual OM&A costs with any variance between actual and fixed OM&A accruing to us.
Comparable EBITDA and EBIT for the Canadian pipelines reflect the variances discussed above as well as variances in depreciation, financial charges and income tax which are substantially recovered in revenue on a flow-through basis and, therefore, do not have a significant impact on net income.

 
 
 
 
TransCanada Management's discussion and analysis 2015 35



U.S. and International Pipelines
EBITDA for our U.S. operations is affected by contracted volume levels, actual volumes delivered and the rates charged, and the total cost of providing services.
ANR earnings are also affected by the level of contracting and the determination of rates driven by the market value of its storage capacity, storage related transportation services, and incidental commodity sales. ANR's pipeline and storage volumes and revenues are generally higher in the winter months because of the seasonal nature of its business.
Comparable EBITDA for the U.S. and International Pipelines was US$113 million higher in 2015 than 2014. This was due to the net effect of:
higher ANR Southeast Mainline transportation revenue, incidental commodity sales and ANR's first quarter 2015 settlement with an owner of adjacent facilities for commercial interruption of ANR's service, partially offset by increased spending on ANR pipeline integrity work
higher earnings from the Tamazunchale Extension which was placed in service in 2014
lower contributions from other U.S. Pipelines due to ownership interests in GTN and Bison sold to TC PipeLines, LP  in April 2015 and October 2014, respectively. These drop downs increased EBITDA from TC PipeLines, LP and also increased the partially offsetting non-controlling interests
a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.
Comparable EBITDA for the U.S. and International Pipelines was US$90 million higher in 2014 than 2013. This was due to the net effect of:
higher earnings from the Tamazunchale Extension which was placed in service in 2014
higher transportation revenue at Great Lakes mainly due to colder winter weather and increased demand
lower contributions from GTN and Bison following the reductions in our effective ownership in each pipeline in July 2013 (GTN and Bison) and October 2014 (Bison)
a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.
Comparable depreciation and amortization
Comparable depreciation and amortization was $69 million higher in 2015 compared to 2014 mainly because of a higher investment base for the NGTL System, depreciation for the completed Tamazunchale Extension and the effect of a stronger U.S. dollar. Depreciation and amortization was $50 million higher in 2014 than in 2013 mainly because of a higher investment base for the NGTL System, as well as the impact of the Mainline NEB 2013 Decision.
Business development
In 2015, business development expenses were $35 million higher than 2014 primarily due to increased business development activity related to our Mexico projects. Also in third quarter 2014, we recovered amounts from partners for 2013 Alaska Gasline Inducement Act costs. Business development expenses were $18 million lower in 2014 compared to 2013 mainly due to a change in scope on the Alaska project as well as the recovery discussed above. See page 44 for further discussion on Alaska.

 
 
 
36  TransCanada Management's discussion and analysis 2015
 
 


OUTLOOK
Earnings
Canadian Pipelines
Net income for rate-regulated pipelines is affected by changes in investment base, ROE and regulated capital structure, and also by the terms of toll settlements or other toll proposals approved by the NEB.
In 2016, the Canadian Mainline will continue to operate under the terms of the NEB 2014 Decision. We expect Canadian Mainline 2016 earnings to be slightly lower than 2015 due to a declining investment base. 
We expect the NGTL System investment base to continue to grow as we connect new natural gas supply in northeastern B.C. and western Alberta and respond to continued growth in market demand and that this will continue to have a positive impact on NGTL System earnings in 2016. The terms of the recently negotiated NGTL 2016-2017 Revenue Requirement Settlement generally include a continuation of the ROE, depreciation rates and incentive sharing mechanism as those established in the 2015 Revenue Requirement Settlement.
We also anticipate a modest level of investment in our other Canadian rate-regulated natural gas pipelines, but expect the average investment bases of these pipelines to continue to decline as annual depreciation outpaces capital investment, reducing their year-over-year earnings.
Under the current regulatory model, earnings from Canadian rate-regulated natural gas pipelines are not materially affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contracted capacity levels.
U.S. Pipelines
U.S. Pipeline earnings are affected by the level of contracted capacity and the rates charged to customers. Our ability to recontract or sell capacity at favourable rates is influenced by prevailing market conditions and competitive factors, including alternatives available to end use customers in the form of competing natural gas pipelines and supply sources, in addition to broader conditions that might impact demand from certain customers or market segments. Earnings are also affected by the level of OM&A and other costs, which includes the impact of safety, environmental and other regulators' decisions.
Many of our U.S. natural gas pipelines are backed by long-term take-or-pay contracts that are expected to deliver stable and consistent financial performance.
ANR has secured new long term contracts and extended terms at maximum recourse rates for significant volumes originating from the Utica/Marcellus shale plays with contract start dates through late 2015 that resulted in increased revenues. On January 29th, 2016, ANR submitted a filing with the FERC under Section 4 of the Natural Gas Act seeking to increase its base rates. We anticipate that the proposed rates will take effect in third quarter 2016. These rates are subject to customer refund as a result of the rates ultimately approved by FERC, which is based on the outcome of the regulatory process or settlement negotiations with ANR's customers.
Also, Great Lakes, Northern Border and GTN have benefited from recent market conditions that increased the value of their services. We continue to seek opportunities to expand upon this success along with those opportunities associated with continued growth in end use markets for natural gas as we examine commercial, regulatory and operational changes to continue to optimize our pipelines' positions in response to positive developments in supply fundamentals.
Mexican Pipelines
Overall earnings from our Mexican pipelines are expected to increase in 2016 due to the addition of two new pipelines, Topolobampo and Mazatlan, which are expected to be placed in service in fourth quarter 2016. The 2016 earnings for our current operating assets in Mexico are expected to be consistent with 2015 earnings due to the nature of the long-term contracts underpinning our Mexican pipeline systems.
Capital spending
We spent a total of $2.7 billion in 2015 for our natural gas pipelines in Canada, the U.S. and Mexico, and expect to spend approximately $4 billion in 2016 primarily on the NGTL System expansion projects, ANR maintenance capital, the Tuxpan-Tula and Topolobampo pipelines in Mexico and Canadian Mainline capacity projects.

 
 
 
 
TransCanada Management's discussion and analysis 2015 37



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 in North America that connects gas production to end use markets. The network includes pipelines that are buried underground and transport natural gas under high pressure, compressor stations that act like pumps to move the large volumes of natural gas along the pipeline and meter stations that record the amount of natural gas coming on the network at receipt locations and leaving the network at delivery locations.
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. Three major pipeline systems account for approximately 80 per cent of the total owned and operated pipe length. These systems are:
NGTL System: This is the major 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 very 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 basin across Canada to Ontario and Québec to deliver gas to downstream Canadian and U.S. markets. The Canadian Mainline continues this role, but is also transitioning to accommodate additional supply connections that are closer to the market served by this pipeline.
ANR System: This is the largest US-based gas pipeline asset we own and operate and is comparable in length to the Canadian Mainline. This pipeline system was originally designed predominantly to transport natural gas supply from the Gulf Coast and northern Texas areas northward to serve markets in the U.S. Midwest. With the large increase of supply from the U.S. Northeast region, the southeast leg of ANR is transitioning from a predominantly south to north system to a bi-directional system with more gas moving north to south.
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, or payments, for services. Costs of operating the systems 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.
Within their respective jurisdictions, the FERC and CRE approve maximum transportation rates. These rates are cost based and are designed to recover the pipeline's investment, operating expenses and a reasonable return for our investors. As the pipeline operator within these jurisdictions, we may negotiate lower rates with shippers.
Sometimes we enter into agreements or settlements with our shippers for tolls and cost recovery, which may include mutually beneficial performance incentives. The regulator must approve a settlement, including any performance incentives, for it to be put into effect.
Generally, Canadian natural gas pipelines request the NEB to approve the pipeline's cost of service and tolls once a year and recover or refund the variance between actual and expected revenues and costs in future years. The Canadian Mainline, however, operates under a fixed toll arrangement for its longer-term firm transportation services and has the flexibility to price its shorter-term and interruptible services in order to maximize its revenue. In addition, the NGTL System has recently reached a two-year revenue requirement settlement for 2016 and 2017 that remains subject to NEB approval.
The FERC does not require U.S. interstate pipelines to calculate rates annually, nor do they allow for the collection or refund of the variance between actual and expected revenue and costs into future years. This difference in U.S. regulation puts our U.S. pipelines

 
 
 
38  TransCanada Management's discussion and analysis 2015
 
 


at risk for the difference in expected and actual costs and revenues between rate cases. If revenues no longer provide a reasonable opportunity to recover costs, we can file with the FERC for a new determination of rates, subject to any moratorium in effect. Similarly, the FERC may institute proceedings to lower tolls if they consider the return on the capital invested to be too high.
Our Mexican pipelines have approved tariffs, services and related rates. However, most of the contracts underpinning the construction and operation of the facilities in Mexico are long-term, fixed-rate contracts designed to recover the cost of our service.
Business environment and strategic priorities
The North American natural gas pipeline network has developed to connect supply to market. 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 a significant pipeline footprint in the WCSB and transport approximately 75 per cent of total WCSB production to markets within and outside of the basin. Our pipelines also source natural gas, to a lesser degree, from the other major basins including the Appalachian (Utica and Marcellus), Rockies, Williston, Haynesville, Fayetteville and Anadarko as well as the Gulf of Mexico.
North American Natural Gas Basins
Increasing supply
The WCSB spans almost all of Alberta and extends into B.C., Saskatchewan, Yukon and Northwest Territories and is Canada's primary source of natural gas supply. The WCSB is currently estimated to have 150 trillion cubic feet of remaining conventional resources and a technically accessible unconventional resource base of over 700 trillion cubic feet. The total recoverable WCSB resource base has recently more than quadrupled with the advent of technology that can economically access unconventional gas areas in the basin. After decreasing every year since 2007, production from the WCSB increased slightly in 2014 and 2015 to 14.7 Bcf/d. The Montney and Horn River shale play formations and the Liard basin in northeastern B.C. are part of the WCSB and have recently become a significant source of natural gas. We expect production from the Montney play that is currently 3 Bcf/d to grow to approximately 6 Bcf/d by 2020, depending on the economics of exploration and production compared to other, mainly U.S., sources and the progress of proposed B.C. west coast LNG exports.

 
 
 
 
TransCanada Management's discussion and analysis 2015 39



The primary sources of natural gas in the U.S. are the U.S. shale areas, Gulf of Mexico and the Rockies. The U.S. shales are the biggest area of growth which we estimate will meet almost 50 per cent of the overall North American gas demand by 2020. The largest shale developments for natural gas are the Utica/Marcellus basins in the northeast U.S. These basins have grown from essentially no production prior to 2008 to over 18 Bcf/d at the end of 2015. They are forecast to grow to 25 Bcf/d by 2020. Other natural gas supply from shale in the U.S. includes the Haynesville, Barnett, Eagle Ford and Fayetteville plays.
The overall supply of natural gas in North America is forecast to increase significantly over the next decade (by almost 20 Bcf/d or 22 per cent by 2020) and is expected to continue to increase over the long term for several reasons:
continued technological progress with horizontal drilling and multi-stage hydraulic fracturing or fracking. This is increasing the technically accessible resource base of existing basins and emerging regions, such as the Marcellus and Utica in the U.S. northeast and the Montney and Horn River areas in northeastern B.C.
these technologies are also being applied to existing oil fields where further recovery of the resource is now possible. There is often associated gas discovered in the exploration and production of liquids-rich hydrocarbon basins (for example, the Bakken oil fields) which also contributes to an increase in the overall gas supply for North America.
The development of shale gas basins that are located close to existing markets, particularly in the northeast U.S., has led to an increase in the number of supply choices and is changing historical gas pipeline flow patterns, generally from long-haul to shorter haul pipelines. Along with our competitors, we have and continue to assess further opportunities to restructure our tolls and service offerings to capture this growing northeast supply and North American demand.
Growing northeast supply has had a positive impact for both the Mainline, with new proposed facilities in eastern Canada, and our ANR pipeline assets, with significant new long-term contracts for service. The increase in supply in northeastern B.C. and northwest Alberta has created opportunities for us to plan and build, subject to regulatory approval and positive final investment decisions (FID), new large pipeline infrastructure on the NGTL System to move the natural gas to markets, including proposed LNG exports and growing Alberta market demand.
Changing demand
The growing supply of natural gas has resulted in relatively low natural gas prices in North America, which has supported increased demand for natural gas 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 which are proposed primarily along the west coast of B.C. and the U.S. Gulf of Mexico. Assuming the receipt of all necessary regulatory and other approvals, the proposed facilities along the west coast of B.C. are expected to become operational later this decade. The U.S. Gulf Coast also has several LNG export facilities in various stages of development or construction. LNG exports are expected to ramp up from this area, including one facility being commissioned to accommodate full deliveries in early 2016. 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 our shippers may choose to accelerate or delay certain projects. This can impact the timing for the demand of transportation services and/or new gas pipeline infrastructure. There is also a relationship between other fuel sources and their prices, including LNG export contracts which have historically been tied to the price of oil. In this current low oil price environment, the ability of gas producers to advance LNG projects that are tied to oil prices will be more challenging. On the other hand, low natural gas prices compete extremely well with coal-fired electric generation. In 2015, we have seen record levels of power generation with natural gas as the fuel source, particularly in the U.S.

 
 
 
40  TransCanada Management's discussion and analysis 2015
 
 


More competition
Changes in supply and demand levels and locations have resulted in increased competition for transportation services throughout North America. Development of technology for shale gas supply basins that are closer to markets historically served by long-haul pipelines has resulted in changes to flow patterns of existing natural gas pipeline infrastructure that includes reversing direction of flow and different distances of haul, particularly with the large development of U.S. northeast supply. Along with other pipelines, we have and continue to assess further opportunities to restructure our tolls and service offerings to capture this growing northeast supply and North American demand.
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 2016, we will continue to advance the planned conversion of portions of the Canadian Mainline from natural gas service to crude oil service. The Energy East Pipeline is a planned project, subject to regulatory approval, to convert approximately 3,000 km (1,864 miles) of the Canadian Mainline from the Alberta border to a point in eastern Ontario, southeast of Ottawa, to crude oil service. We announced in August 2015 that we had reached an agreement with eastern LDCs that ensures the net result of the pipeline asset transfer to Energy East and Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs. We are also advancing new facilities in Eastern Canada to enable more supply into our system from sources that are closer to the end market.
We will continue to advance the previously announced 2016/2017 Facilities project on our NGTL System that is driven by contracts for approximately 4 Bcf/d of new firm service transportation requests as well as our new 2018 program that is underpinned by an additional 2.7 Bcf/d of new firm transportation service on the System.
Our ANR Pipeline has operated under the existing rate settlement for nearly 20 years. As a result of changes to traditional supply sources and markets, necessary operational changes, needed infrastructure updates, and evolving regulatory requirements that are driving required investment in facility maintenance, reliability and system integrity, along with an increase in operating costs, we are seeking to restate our transportation rates to appropriately recover our cost of providing service. Our preferred process to restate our rates is to reach a mutually beneficial outcome with our shippers through a settlement negotiation and that will be a focus area for us in 2016. In parallel to the settlement process, on January 29, 2016 ANR filed a Section 4 rate case with FERC.
We will also continue to pursue further connections to growth in supply and markets for our U.S. assets.
The drop down of our remaining U.S. natural gas pipeline assets into TC PipeLines, LP remains an important financing lever for us as we execute our capital growth program, subject to actual funding needs, market conditions, the relative attractiveness of alternate capital sources and the approvals of TC PipeLines LP’s board and our board.
Our focus in Mexico in 2016 is to complete construction and bring into service the Mazatlan and Topolobampo pipelines and to begin permitting and construction of our recently awarded Tuxpan-Tula pipeline. We also remain focused on continuing to operate our existing facilities safely and reliably. We continue to be very interested in the further development of natural gas infrastructure in Mexico and will work to secure future projects that align with our strategic priorities.

 
 
 
 
TransCanada Management's discussion and analysis 2015 41



SIGNIFICANT EVENTS
Canadian Regulated Pipelines
NGTL System
In 2015, we placed approximately $350 million of facilities in service. For 2016, the NGTL System continues to develop a further approximately $7.3 billion of new supply and demand facilities. We have approximately $2.3 billion of facilities that have received regulatory approval with approximately $450 million currently under construction. We have filed for approval for a further approximately $2.0 billion of facilities which are currently under regulatory review. Applications for approval to construct and operate an additional $3.0 billion of facilities have yet to be filed.
Included in our capital program described above is the recently announced 2018 expansion of a further $600 million of facilities required on the NGTL System. The 2018 expansion includes multiple projects totaling approximately 88 km (55 miles) of 20- to 48-inch diameter pipeline, one new compressor, approximately 35 new and expanded meter stations and other associated facilities. Applications to construct and operate the various components of the 2018 expansion program will be filed with the NEB between second quarter and fourth quarter 2016. Subject to regulatory approvals, construction is expected to start in 2017, with all facilities expected to be in service in 2018.
North Montney Mainline
The North Montney Mainline is a pipeline project that will provide substantial new capacity on the NGTL System to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The project will connect Montney and other WCSB supply to both existing and new natural gas markets, including LNG markets.
The North Montney Mainline project will consist of two large diameter 42-inch pipeline sections, Aitken Creek and Kahta, totaling approximately 301 km (187 miles) in length, and associated metering facilities, valve sites and compression facilities. The project will also include an interconnection with our proposed Prince Rupert Gas Transmission Project (PRGT) to provide natural gas supply to the proposed Pacific NorthWest (PNW) LNG liquefaction and export facility near Prince Rupert, B.C. We expect to have the Aitken Creek and Kahta sections in service in 2017.
The NEB approved the $1.7 billion project in June 2015 subject to certain terms and conditions. Under one of these conditions, construction on the North Montney Mainline project can only begin after a positive FID has been made on the proposed PNW LNG project.
Merrick Mainline
The proposed Merrick Mainline pipeline project that will transport natural gas sourced through the NGTL System to the inlet of the proposed Pacific Trail Pipeline terminating at the Kitimat LNG Terminal near Kitimat, B.C. has been delayed. In late 2015, the Kitimat LNG partners advised us that they are re-phasing the pace of Kitimat LNG facility development. Since the Merrick Mainline is dependent upon the construction of the downstream infrastructure, the in-service date of the Merrick Mainline will be no earlier than 2021.
The Merrick Mainline is a $1.9 billion project that will consist of approximately 260 kilometres (161 miles) of 48-inch diameter pipe.
Canadian Mainline
Energy East and the Eastern Mainline Project
In October 2014, an application was filed with the NEB for the Energy East project and to transfer a portion of the Canadian Mainline from natural gas service to crude oil service. An application was also filed for the Eastern Mainline Project, consisting of new gas facilities in southeastern Ontario required as a result of the proposed transfer of Canadian Mainline assets to crude oil service for the Energy East project.
Application amendments were filed in December 2015 that reflect the agreement we announced in August 2015 with eastern LDCs resolving their issues with Energy East and the Eastern Mainline Project. The agreement provides gas consumers in eastern Canada with sufficient natural gas transmission capacity and provides for reduced natural gas transmission costs. 
The Eastern Mainline Project capital cost is now estimated to be $2.0 billion with the increase in the cost estimate due to the revised project scope resulting from the LDC agreement and updated cost estimates.

 
 
 
42  TransCanada Management's discussion and analysis 2015
 
 


The Eastern Mainline Project is conditioned on the approval and construction of the Energy East pipeline. On January 27, 2016, the Canadian federal government announced interim measures for its review of the Energy East pipeline project. The government announced it will undertake additional consultations with aboriginal groups, help facilitate expanded public input into the NEB, and assess upstream GHG emissions associated with the project. The government will seek a six month extension to the NEB’s legislative review and a three month extension to the legislative time limit for the government’s decision. We are reviewing these changes and will assess the impacts to the Eastern Mainline Project.
Other Canadian Mainline Expansions
In addition to the Eastern Mainline Project, new facilities investments totaling approximately $700 million over the 2016 to 2017 period in the Eastern Triangle portion of the Canadian Mainline are required to meet contractual commitments from shippers.
U.S. Pipelines
ANR Section 4 Rate Case