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TRP-03.31.2014-6-K


SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

For the month of May 2014

Commission File No. 1-31690

TransCanada Corporation
(Translation of Registrant's Name into English)

450 – 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada
(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F                      o                      Form 40-F                      þ


Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):  o

Exhibits 13.1 and 13.2 to this report, furnished on Form 6-K, shall be incorporated by reference into each of the following Registration Statements under the Securities Act of 1933, as amended, of the registrant: Form S-8 (File Nos. 333-5916, 333-8470, 333-9130, 333-151736 and 333-184074), Form F-3 (File Nos. 33-13564 and 333-6132) and Form F-10 (File Nos. 333-151781, 333-161929 and 333-192561).

Exhibit 99.1 to this report, furnished on Form 6-K, is furnished, not filed, and will not be incorporated by reference into any registration statement filed by the registrant under the Securities Act of 1933, as amended.




SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Date: May 2, 2014
TRANSCANADA CORPORATION
 
 
 
 
By:
/s/ Donald R. Marchand
 
 
Donald R. Marchand
 
 
Executive Vice-President and
 
 
Chief Financial Officer
 
 
 
 
By:
/s/ G. Glenn Menuz
 
 
G. Glenn Menuz
 
 
Vice-President and Controller




EXHIBIT INDEX

13.1
Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended March 31, 2014.
 
 
13.2
Consolidated comparative interim unaudited financial statements of the registrant for the period ended March 31, 2014 (included in the registrant's First Quarter 2014 Quarterly Report to Shareholders).
 
 
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
 
 
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
 
 
32.1
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
 
 
32.2
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
 
 
99.1
A copy of the registrant’s news release of May 2, 2014.


TRP-03.31.2014-MD&A
EXHIBIT 13.1

Quarterly report to shareholders

First quarter 2014
 
Financial highlights
 
Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See non-GAAP measures section for more information.  
 
 
three months ended March 31
(unaudited - millions of $, except per share amounts)
 
2014

 
2013

 
 
 
 
 
Income
 
 
 
 
Revenue
 
2,884

 
2,252

Comparable EBITDA
 
1,396

 
1,168

Net income attributable to common shares
 
412

 
446

per common share - basic and diluted
 

$0.58

 

$0.63

Comparable earnings
 
422

 
370

per common share
 

$0.60

 

$0.52

 
 
 
 
 
Operating cash flow
 
 

 
 

Funds generated from operations
 
1,102

 
916

Increase in operating working capital
 
(123
)
 
(210
)
Net cash provided by operations
 
979

 
706

 
 
 
 
 
Investing activities
 
 

 
 

Capital expenditures
 
778

 
929

Equity investments
 
89

 
32

 
 
 
 
 
Dividends
 
 

 
 

Per common share
 

$0.48

 

$0.46

 
 
 
 
 
Basic common shares outstanding (millions)
 
 

 
 

Average for the period
 
708

 
706

End of period
 
708

 
706





TRANSCANADA [2
FIRST QUARTER 2014

Management’s discussion and analysis
 
May 1, 2014
 
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 three months ended March 31, 2014, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months ended March 31, 2014 which have been prepared in accordance with U.S. GAAP.
 
This MD&A should also be read in conjunction with our December 31, 2013 audited consolidated financial statements and notes and the MD&A in our 2013 Annual Report, which have been prepared in accordance with U.S. GAAP. 

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 this MD&A are defined in the glossary in our 2013 Annual Report.
 
All information is as of May 1, 2014 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 impact of regulatory outcomes
•
expected outcomes with respect to legal proceedings, including arbitration
•
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.

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


TRANSCANADA [3
FIRST QUARTER 2014

•
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
•
performance of our counterparties
•
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 and foreign exchange rates
•
weather
•
cyber security
•
technological developments
•
economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2013 Annual Report.
 
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
You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).
 
NON-GAAP MEASURES
We use the following non-GAAP measures:
•
EBITDA
•
EBIT
•
funds generated from operations
•
comparable earnings
•
comparable earnings per common share
•
comparable EBITDA
•
comparable EBIT
•
comparable depreciation and amortization
•
comparable interest expense
•
comparable interest income and other
•
comparable income tax expense.
 
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar 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 better measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings. It is calculated in the same way as EBITDA, less depreciation and amortization.
 
Funds generated from operations
Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a better 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. See Financial condition section for a reconciliation to net cash provided by operations.
 
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.
 


TRANSCANADA [4
FIRST QUARTER 2014

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
EBIT
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
 
Our decision not to include a specific item is subjective and made after careful consideration. These 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
•
write-downs of assets and investments.

We calculate comparable earnings by excluding 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 amounts 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 [5
FIRST QUARTER 2014

Reconciliation of non-GAAP measures
 
 
three months ended March 31
(unaudited - millions of $, except per share amounts)
 
2014

 
2013

 
 
 
 
 
EBITDA
 
1,385

 
1,219

NEB decision - 2012
 
—

 
(55
)
Non-comparable risk management activities affecting EBITDA
 
11

 
4

Comparable EBITDA
 
1,396

 
1,168

Comparable depreciation and amortization
 
(393
)
 
(354
)
Comparable EBIT
 
1,003

 
814

Other income statement items
 
 

 
 

Comparable interest expense
 
(274
)
 
(257
)
Comparable interest income and other
 
(6
)
 
18

Comparable income tax expense
 
(224
)
 
(159
)
Net income attributable to non-controlling interests
 
(54
)
 
(31
)
Preferred share dividends
 
(23
)
 
(15
)
Comparable earnings
 
422

 
370

Specific items (net of tax):
 
 

 
 

NEB decision - 2012
 
—

 
84

Risk management activities1
 
(10
)
 
(8
)
Net income attributable to common shares
 
412

 
446

 
 
 
 
 
Comparable depreciation and amortization
 
(393
)
 
(354
)
Specific item:
 
 

 
 

NEB decision - 2012
 
—

 
(13
)
Depreciation and amortization
 
(393
)
 
(367
)
 
 
 
 
 
Comparable interest expense
 
(274
)
 
(257
)
Specific item:
 
 

 
 

NEB decision - 2012
 
—

 
(1
)
Interest expense
 
(274
)
 
(258
)
 
 
 
 
 
Comparable interest income and other
 
(6
)
 
18

Specific items:
 
 

 
 

NEB decision - 2012
 
—

 
1

Risk management activities1
 
(2
)
 
(6
)
Interest income and other
 
(8
)
 
13

 
 
 
 
 
Comparable income tax expense
 
(224
)
 
(159
)
Specific items:
 
 

 
 

NEB decision - 2012
 
—

 
42

Risk management activities1
 
3

 
2

Income tax expense
 
(221
)
 
(115
)
 
 
 
 
 
Comparable earnings per common share
 

$0.60

 

$0.52

Specific items (net of tax):
 
 
 
 
NEB decision - 2012
 
—

 
0.12

Risk management activities1
 
(0.02
)
 
(0.01
)
Net income per common share
 

$0.58

 

$0.63




TRANSCANADA [6
FIRST QUARTER 2014

1
 
Risk management activities

three months ended
March 31
 
 
(unaudited - millions of $)

2014

 
2013

 
 







 
 
Canadian Power

—

 
(2
)
 
 
U.S. Power

(2
)
 
1

 
 
Natural Gas Storage

(9
)
 
(3
)
 
 
Foreign exchange

(2
)
 
(6
)
 
 
Income tax attributable to risk management activities

3

 
2

 
 
Total losses from risk management activities

(10
)
 
(8
)




Comparable EBITDA and EBIT by business segment
three months ended March 31, 2014
 
Natural Gas

 
Liquids

 
 
 
 
 
 
(unaudited - millions of $)

Pipelines


Pipelines1


Energy


Corporate


Total

 
 
 
 
 
 
 
 
 
 
 
EBITDA
 
848

 
241

 
334

 
(38
)
 
1,385

Non-comparable risk management activities affecting EBITDA
 
—

 
—

 
11

 
—

 
11

Comparable EBITDA

848

 
241

 
345

 
(38
)
 
1,396

Comparable depreciation and amortization

(262
)
 
(49
)
 
(77
)
 
(5
)
 
(393
)
Comparable EBIT

586

 
192

 
268

 
(43
)
 
1,003


three months ended March 31, 2013
 
Natural Gas

 
Liquids

 
 
 
 
 
 
(unaudited - millions of $)

Pipelines


Pipelines1


Energy


Corporate


Total

 
 
 
 
 
 
 
 
 
 
 
EBITDA
 
801

 
179

 
273

 
(34
)
 
1,219

NEB decision - 2012
 
(55
)
 
—

 
—

 
—

 
(55
)
Non-comparable risk management activities affecting EBITDA
 
—

 
—

 
4

 
—

 
4

Comparable EBITDA

746

 
179

 
277

 
(34
)
 
1,168

Comparable depreciation and amortization

(240
)
 
(37
)
 
(74
)
 
(3
)
 
(354
)
Comparable EBIT

506

 
142

 
203

 
(37
)
 
814


1
Previously Oil Pipelines.



TRANSCANADA [7
FIRST QUARTER 2014

Results - First quarter 2014
 
Net income attributable to common shares is comprised of comparable earnings and specific income statement items excluded from comparable earnings. Net income attributable to common shares was $412 million this quarter compared to $446 million in first quarter 2013. The first quarter 2013 results included $84 million of net income related to the 2012 impact of the NEB decision (RH-003-2011). This amount was excluded from comparable earnings. Net income also includes net unrealized after-tax gains or losses resulting from changes in the fair value of certain risk management activities, which are excluded from comparable earnings. For the three months ended March 31, 2014 comparable earnings excluded losses of $10 million ($13 million before tax) compared to losses of $8 million ($10 million before tax) for the same period in 2013 resulting from these risk management activities.

The discussion of segmented results will focus on the remaining aspects of net income through a discussion of comparable earnings.
 
Comparable earnings this quarter were $52 million higher than first quarter 2013, an increase of $0.08 per share.
 
This was primarily the net effect of the following:
•
incremental earnings from the Gulf Coast extension of the Keystone Pipeline System which was placed in service on January 22, 2014
•
higher equity income from Bruce Power because of higher earnings from Bruce B, reflecting lower planned outage days, and higher earnings from Bruce A Unit 4, following the completion of the planned life extension outage which began in third quarter 2012 and was completed in April 2013
•
higher earnings from U.S. Power mainly because of higher realized capacity and power prices
•
higher earnings from U.S. and international pipelines due to higher transportation revenue at Great Lakes and higher contributions from TC PipeLines, LP reflecting colder weather and increased demand
•
higher OM&A costs at ANR as well as lower storage revenues
•
higher interest expense due to new debt issuances.

The stronger U.S. dollar this quarter compared to the same period in 2013 positively impacted the results in our U.S. businesses, which were mostly 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 net exposure through our hedging program.




TRANSCANADA [8
FIRST QUARTER 2014

CAPITAL PROGRAM
We are developing quality projects under our long-term capital program. With the Gulf Coast extension of the Keystone Pipeline System in service in January 2014, our commercially secured growth portfolio now stands at $36 billion. 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 cashflow.

Our capital program is comprised of $10 billion of small to medium-sized projects and $26 billion of large scale projects. Amounts presented exclude the impact of foreign exchange and capitalized interest.
at March 31, 2014
 
Expected
 
Estimated

 
 
(billions of $)
 
In-Service Date
 
Project Cost

 
Amount Spent

 
 
 
 
 
 
 
Small to medium-sized projects
 
 
 
 
 
 
Tamazunchale Extension
 
2014
 
US 0.6

 
US 0.5

Ontario Solar
 
2014-2015
 
0.5

 
0.2

Houston Lateral and Terminal
 
2015
 
US 0.4

 
US 0.2

Heartland and TC Terminals
 
2016
 
0.9

 
—

Keystone Hardisty Terminal
 
2016
 
0.3

 
0.1

Topolobampo
 
2016
 
US 1.0

 
US 0.4

Mazatlan
 
2016
 
US 0.4

 
US 0.1

Grand Rapids1
 
2015-2017
 
1.5

 
0.1

Northern Courier
 
2017
 
0.8

 
0.1

NGTL System
 
2014-2018
 
2.2

 
0.3

Napanee
 
2017 or 2018
 
1.0

 
—

 
 
 
 
9.6

 
2.0

Large scale projects2
 
 
 
 
 
 
Keystone XL3
 
Approximately 2 years
from date permit received
 
US 5.4

 
US 2.3

Energy East4
 
2018
 
12.0

 
0.2

Prince Rupert Gas Transmission
 
2018
 
5.0

 
0.2

Coastal GasLink
 
2018+
 
4.0

 
0.1

 
 
 
 
26.4

 
2.8

 
 
 
 
36.0

 
4.8

1
Represents our 50 per cent share.
2
Subject to cost adjustments due to market conditions, route refinement, permitting conditions and scheduling.
3
Estimated project cost will increase depending on the timing of the Presidential permit.
4
Excludes transfer of Canadian Mainline natural gas assets.

Outlook

The sale of Cancarb Limited and its related power generation facility on April 15, 2014 is expected to result in an after-tax gain of approximately $95 million to our second quarter 2014 earnings. In addition, effective April 30, 2014, we terminated a long-term natural gas storage contract with a third party provider in Alberta, which is expected to result in a charge of approximately $33 million after-tax to our second quarter 2014 earnings.

See the MD&A in our 2013 Annual Report for further information about our outlook.


TRANSCANADA [9
FIRST QUARTER 2014

Natural Gas Pipelines
 
Comparable EBITDA and comparable EBIT are non-GAAP measures. Comparable EBIT is equivalent to our Natural Gas Pipelines segmented earnings after adjusting for $42 million of EBIT in 2013 related to the 2012 impact from the NEB decision (RH-003-2011). See non-GAAP measures section for more information.
 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Canadian Pipelines
 
 
 
 
Canadian Mainline
 
315

 
280

NGTL System
 
219

 
182

Foothills
 
27

 
29

Other Canadian pipelines (TQM1, Ventures LP)
 
5

 
6

Canadian Pipelines - comparable EBITDA
 
566

 
497

Comparable depreciation and amortization
 
(203
)
 
(184
)
Canadian Pipelines - comparable EBIT
 
363

 
313

 
 
 
 
 
U.S. and International (US$)
 
 

 
 

ANR
 
78

 
90

TC PipeLines, LP1,2
 
26

 
17

Great Lakes3
 
19

 
10

Other U.S. pipelines (Bison4, Iroquois1, GTN4, Portland5)
 
45

 
71

Mexico (Guadalajara, Tamazunchale)
 
25

 
26

International and other (Gas Pacifico/INNERGY1, TransGas1)
 
(1
)
 
(2
)
Non-controlling interests6
 
73

 
43

U.S. Pipelines and International - comparable EBITDA
 
265

 
255

Comparable depreciation and amortization
 
(54
)
 
(55
)
U.S. Pipelines and International - comparable EBIT
 
211

 
200

Foreign exchange impact
 
21

 
2

U.S. Pipelines and International - comparable EBIT (Cdn$)
 
232

 
202

Business Development comparable EBITDA and EBIT
 
(9
)
 
(9
)
Natural Gas Pipelines - comparable EBIT
 
586

 
506

 
 
 
 
 
Summary
 
 

 
 

Natural Gas Pipelines - comparable EBITDA
 
848

 
746

Comparable depreciation and amortization
 
(262
)
 
(240
)
Natural Gas Pipelines - comparable EBIT
 
586

 
506


1
Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments.
2
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 of GTN, Bison, and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.
 
 
 
Ownership percentage as of
 
 
 
July 1, 2013
 
May 22, 2013
 
January 1, 2013
 
 
 
 
 
 
 
 
 
TC PipeLines, LP
 
28.9
 
28.9
 
33.3
 
Effective ownership through TC PipeLines, LP:
 
 
 
 
 
 
 
  GTN/Bison
 
20.2
 
7.2
 
8.3
 
  Great Lakes
 
13.4
 
13.4
 
15.5

3
Represents our 53.6 per cent direct ownership interest.
4
Effective July 1, 2013, represents our 30 per cent direct ownership interest. Prior to July 1, 2013, our direct ownership interest was 75 per cent.
5
Represents our 61.7 per cent ownership interest.
6
Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.



TRANSCANADA [10
FIRST QUARTER 2014

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES
 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Canadian Mainline - net income
 
66

 
151

Canadian Mainline - comparable earnings
 
66

 
67

NGTL System
 
63

 
56

Foothills
 
4

 
4

 
OPERATING STATISTICS - WHOLLY OWNED PIPELINES
three months ended March 31
 
Canadian Mainline1
 
NGTL System2
 
ANR3
(unaudited)
 
2014

 
2013

 
2014

 
2013

 
2014

 
2013

 
 
 
 
 
 
 
 
 
 
 
 
 
Average investment base (millions of $)
 
5,706

 
5,870

 
6,137

 
5,824

 
n/a

 
n/a

Delivery volumes (Bcf)
 
 

 
 

 
 

 
 

 
 

 
 

Total
 
528

 
426

 
1,131

 
994

 
525

 
465

Average per day
 
5.9

 
4.7

 
12.6

 
11.0

 
5.8

 
5.2

 
1
Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2014 were 357 Bcf (2013 – 231 Bcf). Average per day was 4.0 Bcf (2013 – 2.6 Bcf).
2
Field receipt volumes for the NGTL System for the three months ended March 31, 2014 were 933 Bcf (2013 – 916 Bcf). Average per day was 10.4 Bcf (2013 – 10.2 Bcf).
3
Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.
 
CANADIAN PIPELINES
Comparable EBITDA and net income for our rate-regulated Canadian Pipelines are affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and comparable EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.
 
Canadian Mainline’s comparable earnings reflect an ROE of 11.50 per cent on deemed common equity of 40 per cent and have decreased by $1 million for the three months ended March 31, 2014 compared to the same period in 2013 because of a lower average investment base. Net income for the three months ended March 31, 2014 was $85 million lower than the same period in 2013 as net income in 2013 included $84 million related to the 2012 impact of the NEB decision (RH-003-2011), which was excluded from comparable earnings.
 
Net income for the NGTL System increased by $7 million for the three months ended March 31, 2014 compared to the same periods in 2013 primarily due to a higher average investment base as well as an increase in the ROE. The 2013-2014 NGTL Settlement approved by the NEB in November 2013 included an ROE of 10.10 per cent on deemed common equity of 40 per cent. Results for the three months ended March 31, 2013 reflected the previously approved ROE of 9.70 per cent on deemed common equity of 40 per cent.
 
U.S. AND INTERNATIONAL PIPELINES
Earnings for our U.S. pipelines operations is generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.
 
Comparable EBITDA for the U.S. and international pipelines increased US$10 million for the three months ended March 31, 2014 compared to the same period in 2013. This was the net effect of:
•
higher transportation revenues at Great Lakes and higher contributions from TC PipeLines, LP reflecting colder weather and increased demand
•
higher OM&A costs at ANR as well as lower storage revenues
•
a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings in our U.S. operations.

COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization increased $22 million for the three months ended March 31, 2014 compared to the same period in 2013 mainly because of a higher investment base and higher depreciation rates on the NGTL System.


TRANSCANADA [11
FIRST QUARTER 2014

Liquids Pipelines1 
 
Comparable EBITDA and comparable EBIT are non-GAAP measures. Comparable EBIT is equivalent to our Liquids Pipelines segmented earnings. See non-GAAP measures section for more information.
 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Keystone Pipeline System
 
248

 
186

Liquids Pipelines Business Development
 
(7
)
 
(7
)
Liquids Pipelines - comparable EBITDA
 
241

 
179

Comparable depreciation and amortization
 
(49
)
 
(37
)
Liquids Pipelines - comparable EBIT
 
192

 
142

 
 
 
 
 
Comparable EBIT denominated as follows:
 
 

 
 

Canadian dollars
 
49

 
47

U.S. dollars
 
129

 
94

Foreign exchange impact
 
14

 
1

 
 
192

 
142


1
Previously Oil Pipelines. 

Comparable EBITDA from our Keystone Pipeline System is generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings.

Comparable EBITDA for the Keystone Pipeline System increased by $62 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase is primarily due to:
•
incremental earnings from the Gulf Coast extension which was placed in service on January 22, 2014
•
a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings in our U.S. operations.

COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization increased by $12 million for the three months ended March 31, 2014 compared to the same period in 2013 due to the Gulf Coast extension.


TRANSCANADA [12
FIRST QUARTER 2014

Energy
 
Comparable EBITDA and comparable EBIT are non-GAAP measures. Comparable EBIT is equivalent to our Energy segmented earnings after adjusting for $11 million (2013 - $4 million) related to unrealized losses on risk management activities. See non-GAAP measures section for more information.
 
 
three months ended March 31
(unaudited -  millions of $)
 
2014

 
2013

 
 
 
 
 
Canadian Power
 
 
 
 
Western Power
 
72

 
74

Eastern Power1
 
93

 
90

Bruce Power
 
64

 
31

Canadian Power - comparable EBITDA2
 
229

 
195

Comparable depreciation and amortization
 
(44
)
 
(43
)
Canadian Power - comparable EBIT2
 
185

 
152

U.S. Power (US$)
 
 

 
 

U.S. Power - comparable EBITDA
 
86

 
67

Comparable depreciation and amortization
 
(27
)
 
(28
)
U.S. Power - comparable EBIT
 
59

 
39

Foreign exchange impact
 
5

 
1

U.S. Power - comparable EBIT (Cdn$)
 
64

 
40

Natural Gas Storage and other
 
 

 
 

Natural Gas Storage and other - comparable EBITDA
 
27

 
18

Comparable depreciation and amortization
 
(3
)
 
(3
)
Natural Gas Storage and other - comparable EBIT
 
24

 
15

Business Development comparable EBITDA and EBIT
 
(5
)
 
(4
)
Energy - comparable EBIT2
 
268

 
203

 
 
 
 
 
Summary
 
 

 
 

 
 
 
 
 
Energy - comparable EBITDA2
 
345

 
277

Comparable depreciation and amortization
 
(77
)
 
(74
)
Energy - comparable EBIT2
 
268

 
203


1
Includes four Ontario solar facilities acquired between June and December 2013.
2
Includes our share of equity income from our investments in ASTC Power Partnership, Portlands Energy and Bruce Power.
 
Comparable EBITDA for Energy increased by $68 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was the result of:
•
higher equity income from Bruce Power because of higher earnings from Bruce B, reflecting lower planned outage days, and higher earnings from Bruce A Unit 4, following the completion of the planned life extension outage which began in third quarter 2012 and was completed in April 2013
•
higher earnings from U.S. Power mainly because of higher realized capacity and power prices
•
higher earnings from natural gas storage mainly due to increased proprietary revenues, partially offset by decreased third party storage revenues.


TRANSCANADA [13
FIRST QUARTER 2014

CANADIAN POWER
 
Western and Eastern Power1 
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.
 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Revenue
 
 
 
 
Western Power
 
181

 
142

Eastern Power1
 
142

 
109

Other2
 
51

 
31

 
 
374

 
282

Income from equity investments3
 
20

 
22

Commodity purchases resold
 
(101
)
 
(67
)
Plant operating costs and other
 
(128
)
 
(73
)
Comparable EBITDA
 
165

 
164

Comparable depreciation and amortization
 
(44
)
 
(43
)
Comparable EBIT
 
121

 
121

 
 
 
 
 
Breakdown of comparable EBITDA
 
 
 
 
Western Power
 
72

 
74

Eastern Power
 
93

 
90

Comparable EBITDA
 
165

 
164


1
Includes four Ontario solar facilities acquired between June and December 2013.
2
Includes sale of excess natural gas purchased for generation and sales of thermal carbon black.
3
Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy.

Sales volumes and plant availability
Includes our share of volumes from our equity investments.
 
 
three months ended March 31
(unaudited)
 
2014

 
2013

 
 
 
 
 
Sales volumes (GWh)
 
 
 
 
Supply
 
 
 
 
Generation
 
 
 
 
Western Power
 
609

 
670

Eastern Power1
 
1,277

 
1,346

Purchased
 
 

 
 

Sundance A & B and Sheerness PPAs2
 
2,800

 
1,707

Other purchases
 
5

 
—

 
 
4,691

 
3,723

Sales
 
 

 
 

Contracted
 
 

 
 

Western Power
 
2,461

 
1,707

Eastern Power1
 
1,277

 
1,346

Spot
 
 

 
 

Western Power
 
953

 
670

 
 
4,691

 
3,723

Plant availability3
 
 

 
 

Western Power4
 
96
%
 
97
%
Eastern Power1,5
 
98
%
 
96
%

1
Includes four Ontario solar facilities acquired between June and December 2013.
2
Sundance A Unit 1 returned to service in September 2013 and Unit 2 returned to service in October 2013.
3
The percentage of time the plant was available to generate power, regardless of whether it was running.
4
Does not include facilities that provide power to TransCanada under PPAs.


TRANSCANADA [14
FIRST QUARTER 2014

5
Does not include Bécancour because power generation has been suspended since 2008.

Western Power
Western Power’s comparable EBITDA decreased by $2 million for the three months ended March 31, 2014 compared to the same period in 2013 due to the net effect of:
•
lower realized power prices
•
incremental earnings from the return to service of the Sundance A PPA Unit 1 in September 2013 and Unit 2 in October 2013 which also resulted in increased volume purchases and sales.

Average spot market power prices in Alberta decreased by 3 per cent to $62/MWh for the three months ended March 31, 2014 compared to the same period in 2013. Realized power prices on power sales can be higher or lower than spot market power prices in any given period, as a result of contracting activities.

72 per cent of Western Power sales volumes were sold under contract in first quarter 2014 and 2013.
 
Eastern Power
Eastern Power’s comparable EBITDA increased by $3 million for the three months ended March 31, 2014 compared to the same period in 2013 mainly due to the incremental earnings from the Ontario solar facilities acquired in 2013.

BRUCE POWER
Our proportionate share
 
 
three months ended March 31
(unaudited - millions of $ unless noted otherwise)
 
2014

 
2013

 
 
 
 
 
Income/(loss) from equity investments1
 
 
 
 
Bruce A
 
49

 
36

Bruce B
 
15

 
(5
)
 
 
64

 
31

Comprised of:
 
 

 
 

Revenues
 
300

 
287

Operating expenses
 
(157
)
 
(173
)
Depreciation and other
 
(79
)
 
(83
)
 
 
64

 
31

Bruce Power - Other information
 
 

 
 

Plant availability2
 
 

 
 

Bruce A
 
80
%
 
66
%
Bruce B
 
85
%
 
78
%
Combined Bruce Power
 
83
%
 
72
%
Planned outage days
 
 

 
 

Bruce A
 
—

 
90

Bruce B
 
49

 
70

Unplanned outage days
 
 

 
 

Bruce A
 
60

 
8

Bruce B
 
—

 
9

Sales volumes (GWh)1
 
 

 
 

Bruce A
 
2,527

 
2,097

Bruce B
 
1,924

 
1,735

 
 
4,451

 
3,832

Realized sales price per MWh3
 
 

 
 

Bruce A
 

$71

 

$68

Bruce B
 

$56

 

$53

Combined Bruce Power
 

$63

 

$59


1
Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. Sales volumes exclude deemed generation.
2
The percentage of time the plant was available to generate power, regardless of whether it was running.
3
Calculated based on actual and deemed generation. Bruce B realized sales prices per MWh includes revenues under the floor price mechanism and revenues from contract settlements.


TRANSCANADA [15
FIRST QUARTER 2014


Equity income from Bruce A increased by $13 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was mainly a result of higher earnings from Unit 4, following the completion of the planned life extension outage which began in third quarter 2012 and was completed in April 2013. The increase was partially offset by:
•
lower volumes from Units 1 and 2 due to higher unplanned outage days
•
the impact of an insurance recovery of approximately $40 million recognized in first quarter 2013.

Equity income from Bruce B increased by $20 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was mainly due to higher volumes and lower operating costs resulting from lower planned and unplanned outage days.
 
Under the contract with the OPA, all of the output from Bruce A Units 1 to 4 is sold at a fixed price/MWh. The fixed price is adjusted annually on April 1 for inflation and other provisions under the OPA contract. Bruce A also recovers fuel costs from the OPA.
Bruce A Fixed price
Per MWh
 
 
April 1, 2014 - March 31, 2015
$71.70
April 1, 2013 - March 31, 2014
$70.99
April 1, 2012 - March 31, 2013
$68.23
 
Under the same contract, all output from Bruce B Units 5 to 8 is subject to a floor price adjusted annually for inflation on April 1.
Bruce B Floor price
Per MWh
 
 
April 1, 2014 - March 31, 2015
$52.86
April 1, 2013 - March 31, 2014
$52.34
April 1, 2012 - March 31, 2013
$51.62
 
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. Although the first quarter 2014 average spot price exceeded the floor price, spot prices are expected to fall below the floor price for the remainder of 2014. As a result, amounts received above the floor price in first quarter 2014 are not expected to be realized under the Bruce B floor price mechanism and therefore, have not been reflected in equity income.

Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.
 
The overall plant availability percentage in 2014 is expected to be in the mid 80s for Bruce A and high 80s for Bruce B. Planned maintenance on a Bruce A unit will occur in second quarter 2014. Planned maintenance on one of the Bruce B units is scheduled to occur in fourth quarter 2014.

U.S. POWER
Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information. 
 
 
three months ended March 31
(unaudited - millions of US $)
 
2014

 
2013

 
 
 
 
 
Revenue
 
 
 
 
Power1
 
745

 
462

Capacity
 
70

 
47

 
 
815

 
509

Commodity purchases resold
 
(549
)
 
(306
)
Plant operating costs and other2
 
(180
)
 
(136
)
Comparable EBITDA
 
86

 
67

Comparable depreciation and amortization
 
(27
)
 
(28
)
Comparable EBIT
 
59

 
39


1
The realized gains and losses from financial derivatives used to buy and sell power, natural gas and fuel oil to manage U.S. Power’s assets are presented on a net basis in power revenues.
2
Includes the cost of fuel consumed in generation.



TRANSCANADA [16
FIRST QUARTER 2014

Sales volumes and plant availability 
 
 
three months ended March 31
(unaudited)
 
2014

 
2013

 
 
 
 
 
Physical sales volumes (GWh)
 
 
 
 
Supply
 
 
 
 
Generation
 
1,238

 
1,051

Purchased
 
2,829

 
2,479

 
 
4,067

 
3,530

 
 
 
 
 
Plant availability1
 
85
%
 
79
%

1
The percentage of time the plant was available to generate power, regardless of whether it was running.
 
U.S. Power’s comparable EBITDA increased US$19 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was the net effect of:
•
higher realized capacity prices in New York
•
higher realized power prices in New England
•
higher realized power prices and higher generation in New York offset by higher plant operating costs due to higher fuel prices
•
higher prices and related costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers
•
a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings in our U.S. operations.

Wholesale electricity prices in New York and New England were significantly higher for the three months ended March 31, 2014 compared to the same period in 2013. Average spot power prices for the Western/Central Massachusetts load zone in New England increased 75 per cent to $143/MWh and in New York City spot power prices increased 78 per cent to an average of $126/MWh. Colder winter temperatures compared to the same period in 2013 and gas transmission constraints resulted in higher natural gas prices in the predominantly gas-fired New England and New York power markets for the three months ended March 31, 2014.

Spot capacity prices in New York City were 102 per cent higher in first quarter 2014 compared to the same period in 2013. This increase in spot capacity prices and the impact of hedging activities resulted in higher realized capacity prices in New York. 
Physical sales volumes for the three months ended March 31, 2014 were higher than the same period in 2013 due to higher purchased volumes sold to wholesale, commercial and industrial customers in our PJM markets and higher generation at our Ravenswood facility in New York.
 
As at March 31, 2014, approximately 5,300 GWh or 63 per cent of U.S. Power’s planned generation is contracted for the remainder of 2014, and 3,200 GWh or 38 per cent for 2015. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage. 

NATURAL GAS STORAGE AND OTHER
Comparable EBITDA increased $9 million for the three months ended March 31, 2014 compared to the same period in 2013 primarily due to increased proprietary revenues as a result of higher realized natural gas storage spreads, partially offset by decreased third party storage revenues. The seasonal nature of natural gas storage generally results in higher revenues in the winter season.



TRANSCANADA [17
FIRST QUARTER 2014

Recent developments
 
NATURAL GAS PIPELINES
 
Canadian Pipelines

NGTL System
The NEB has approved $400 million in NGTL facility expansions that were in various stages of development or construction at March 31, 2014. In addition, we have approximately $1.8 billion in projects that have been applied for but are not yet approved by the NEB, mainly comprised of the $1.7 billion North Montney project.

On February 5, 2014, we received a Hearing Order for the North Montney project, which is an extension and expansion of the NGTL System to receive and transport natural gas from the North Montney area of B.C. The hearing will begin August 19, 2014 with a second portion beginning September 8, 2014. The proposed project consists of approximately 300 km (186 miles) of pipeline.

On March 5, 2014, we received an NEB Safety Order in response to the recent pipeline releases on the NGTL system. The order required us to reduce the maximum operating pressure on three per cent of NGTL's pipeline segments. On March 28, 2014, we filed a request for a review and variance of the Order that would minimize gas disruptions while still maintaining a high level of safety.  On April 14, 2014, the NEB granted the review and variance request with certain conditions. We are accelerating components of our integrity management program to address the NEB order as reviewed and varied.

Canadian Mainline

LDC Settlement
On March 31, 2014, the NEB responded to the LDC Settlement application we filed on December 20, 2013. The NEB did not approve the application but provided direction that we can continue with the application as a contested tolls application, amend the application or terminate the processing of the application. We will be amending the application with additional information in second quarter 2014. On April 22, 2014, the NEB issued a notice advising that it will hold a public hearing on the amended application and setting the list of issues. A further letter from the NEB setting out the hearing process and schedule is expected in the next few weeks.

U.S. Pipelines

ANR Pipeline
We have secured almost 2.0 Bcf/d of firm natural gas transportation commitments on the ANR Pipeline's Southeast Main Line at maximum rates for an average term of 23 years. Approximately 1.25 Bcf/d of new contracts will commence in late 2014 including volume commitments from the ANR Lebanon Lateral Reversal project, with the remaining volume commencing in 2015. These contracts will enable growing Utica and Marcellus shale gas supply to move to both northern delivery points and southbound to the U.S. Gulf Coast. As a result, approximately US$100 million of capital investment will be required to bring this additional supply to market. We are also assessing further demand which could result in incremental opportunities to enhance and expand the ANR Pipeline system.

Mexican Pipelines

Tamazunchale Pipeline Extension Project
Construction activity on the US$600 million extension continues. The extension is currently expected to be in service at the end of July 2014.

LNG Pipeline Projects

Coastal GasLink
In January 2014, we filed the Application for an Environmental Assessment Certificate with the B.C. Environmental Assessment Office. The 180-day Environmental Assessment Office public review period began in March 2014 and includes a 45-day public comment period. In addition, the B.C. Oil and Gas Commission application was filed in March 2014, together with an addendum to the B.C. Environmental Assessment application to capture recent route refinements.

Prince Rupert Gas Transmission
The project completed two key milestones in April 2014. The Environmental Assessment application was submitted to the B.C. Environmental Assessment Office for a completeness review and the application was filed with the B.C. Oil and Gas Commission.

Alaska
In April 2014, the State of Alaska passed new legislation that will transition from the Alaska Gasline Inducement Act and enable a new commercial arrangement to be established with us, the three major Alaska North Slope producers, and the Alaska Gasline


TRANSCANADA [18
FIRST QUARTER 2014

Development Corp. It was also agreed that an LNG export project, rather than a pipeline to Alberta, is currently the best opportunity to commercialize Alaska North Slope gas resources in current market conditions. It is anticipated that two years of pre-front end engineering will be completed before further decisions to commercialize the project will be made.


LIQUIDS PIPELINES

Keystone Pipeline System
We finished constructing the 780 km (485 mile) 36-inch pipeline of the Gulf Coast extension of the Keystone Pipeline System, from Cushing, Oklahoma to the U.S. Gulf Coast. Crude oil transportation service on the project began January 22, 2014. We are projecting an average pipeline capacity of 520,000 Bbl/d for the first year of operation.

Keystone XL
On January 31, 2014, the DOS released its Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL project. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is “unlikely to significantly impact the rate of extraction in the oil sands” and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more greenhouse gas emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period that was to last up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment. The 30 day public comment period has concluded. On April 18, 2014, the DOS announced the National Interest Determination period has been extended indefinitely. The DOS has said only that the permit process will conclude once factors that have a significant impact on determining national interest of the proposed project have been evaluated.

In February 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Dave Heineman, has the authority to approve an alternative route through Nebraska for the Keystone XL project. We disagree with the decision of the Nebraska district court and are continuing to analyze the judgment and decide what next steps may be taken. Nebraska’s Attorney General has filed an appeal and the Nebraska Supreme Court is expected to hear the appeal in third quarter 2014. As of March 31, 2014, we have invested US$2.3 billion in the Keystone XL project.

Energy East Pipeline
On March 4, 2014, we filed the project description with the NEB. This is the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.

Subject to regulatory approvals, the pipeline is anticipated to commence deliveries to Québec in 2018, with service to New Brunswick to follow in late 2018. We continue to participate in Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. We intend to file the necessary regulatory applications in mid-2014 for approvals to construct and operate the pipeline project and terminal facilities.

Heartland Pipeline and TC Terminals
The Heartland Pipeline and TC Terminals will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton, Alberta. In February 2014, the application for the terminal facility was approved by the Alberta Energy Regulator.

ENERGY

Ontario Solar
We expect the acquisition of four additional Ontario solar generation facilities to close in fourth quarter 2014, with the acquisition of the ninth and final facility now expected to close in mid-2015, subject to satisfactory completion of the related construction activities, regulatory approvals, and purchase agreement conditions for each facility. All power produced by the solar facilities is currently or will be sold under 20-year PPAs with the OPA.

Cancarb Limited and Cancarb Waste Heat Facility
On January 20, 2014, we announced we had reached an agreement for the sale of Cancarb Limited, our thermal carbon black business, and its related power generation facility. The sale closed on April 15, 2014 for proceeds of $190 million, subject to closing adjustments. We expect to realize a gain on the sale of approximately $95 million, net of tax, in second quarter 2014.

Natural Gas Storage
Effective April 30, 2014, we terminated a 38 Bcf long-term natural gas storage contract in Alberta with Niska Gas Storage. The contract contained provisions allowing for possible early termination. In consideration for this termination, we expect to record an after-tax charge of approximately $33 million in second quarter 2014. We have re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six year period and a reduced average volume.


TRANSCANADA [19
FIRST QUARTER 2014

Other income statement items

 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Comparable interest expense
 
274

 
257

Comparable interest income and other
 
6

 
(18
)
Comparable income tax expense
 
224

 
159

Net income attributable to non-controlling interests
 
54

 
31

Preferred share dividends
 
23

 
15

 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Comparable interest on long-term debt
(including interest on junior subordinated notes)
 
 
 
 
Canadian dollar-denominated
 
114

 
122

U.S. dollar-denominated (US$)
 
207

 
188

Foreign exchange impact
 
22

 
1

 
 
343

 
311

Other interest and amortization expense
 
10

 
1

Capitalized interest
 
(79
)
 
(55
)
Comparable interest expense
 
274

 
257

 
Comparable interest expense increased $17 million for the three months ended March 31, 2014 compared to the same period in 2013 because of the net effect of the following:
•
higher interest expense due to debt issues of:
◦
US$1.25 billion in February 2014
◦
US$1.25 billion in October 2013
◦
US$500 million in July 2013
◦
$750 million in July 2013
◦
US$750 million in January 2013
◦
US$500 million in July 2013 by TC PipeLines, LP
•
higher capitalized interest primarily for the Keystone XL project, Mexican projects and other liquids and LNG pipeline projects partially offset by the Gulf Coast extension of the Keystone Pipeline System, which was placed in service in first quarter 2014
•
higher foreign exchange on interest expense related to U.S. denominated debt, partially offset by Canadian and U.S. dollar-denominated debt maturities.

Comparable interest income and other decreased $24 million for the three months ended March 31, 2014 compared to the same period in 2013 reflecting higher realized losses in 2014 compared to 2013 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Comparable income tax expense increased $65 million for the three months ended March 31, 2014 compared to the same period in 2013. The increase was mainly the result of higher pre-tax earnings in 2014, compared to 2013, combined with changes in the proportion of income earned between Canadian and foreign jurisdictions as well as higher flow-through taxes in 2014 on Canadian regulated pipelines.

Net income attributable to non-controlling interests increased $23 million for the three months ended March 31, 2014 compared to the same period in 2013 primarily due to the sale of a 45 per cent interest in each of GTN LLC and Bison to TC PipeLines, LP in July 2013.

Preferred share dividends increased $8 million for the three months ended March 31, 2014, compared to the same period in 2013 following the issuances of Series 7 preferred shares in March 2013 and Series 9 preferred shares in January 2014.


TRANSCANADA [20
FIRST QUARTER 2014

Financial condition
 
We strive to maintain strong financial capacity and flexibility in all parts of an economic cycle, and rely on our cash flow from operations to sustain our business, pay dividends and fund a portion of our growth.
 
We believe we have the capacity to fund our existing capital program through predictable cash flow from operations, access to capital markets, cash on hand and substantial committed credit facilities.

We access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.
 
CASH PROVIDED BY OPERATING ACTIVITIES 
 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Funds generated from operations1
 
1,102

 
916

Increase in operating working capital
 
(123
)
 
(210
)
Net cash provided by operations
 
979

 
706


1
See the non-GAAP measures section in this MD&A for further discussion of funds generated from operations.
 
Net cash provided by operations was $979 million for the three months ended March 31, 2014 compared to $706 million for the same period in 2013 mainly due to higher earnings in each of our operating segments and higher distributions from equity investments.

At March 31, 2014, our current assets were $3.5 billion and current liabilities were $5.1 billion, leaving us with a working capital deficit of $1.6 billion compared to $2.2 billion at December 31, 2013. This working capital deficiency is considered to be in the normal course of business and is managed through our ability to generate cash flow from operations and our ongoing access to the capital markets.
 
CASH USED IN INVESTING ACTIVITIES 
 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Capital expenditures
 
778

 
929

Equity investments
 
89

 
32

 
Our capital expenditures this quarter were primarily related to the Gulf Coast extension of the Keystone Pipeline System, expansion of the NGTL System and construction of the Mexican pipelines.

Our cash used in equity investments increased this quarter due to our investment in the Grand Rapids Pipeline.
  
CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES 
 
 
three months ended March 31
(unaudited - millions of $)
 
2014

 
2013

 
 
 
 
 
Long-term debt issued, net of issue costs
 
1,364

 
734

Long-term debt repaid
 
(777
)
 
(14
)
Notes payable repaid, net
 
(747
)
 
(829
)
Dividends and distributions paid
 
(390
)
 
(350
)
Common shares issued, net of issue costs
 
10

 
32

Preferred shares issued, net of issue costs
 
440

 
586

Preferred shares of subsidiary redeemed
 
(200
)
 
—

 

LONG-TERM DEBT ISSUED
Amount
(unaudited - millions of $)
 
Type
 
Maturity date
 
Interest rate

 
Date issued
 
 
 
 
 
 
 
 
 
US$1,250
 
Senior unsecured notes
 
March 1, 2034
 
4.625
%
 
February 2014


TRANSCANADA [21
FIRST QUARTER 2014


LONG-TERM DEBT RETIRED
Amount
(unaudited - millions of $)
 
Type
 
Retirement date
 
Interest rate

 
 
 
 
 
 
 
$450
 
Medium term notes
 
January 2014
 
5.65
%
$300
 
Medium term notes
 
February 2014
 
5.05
%

PREFERRED SHARE ISSUANCE AND REDEMPTION
In January 2014, we completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. Investors are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The preferred shares are redeemable by us on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. Investors will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annualized rate equal to the then 90-day Government of Canada treasury bill rate and 2.35 per cent.

In March 2014, we redeemed all four million Series Y preferred shares of TCPL at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends. The total face value of the outstanding Series Y Shares was $200 million and carried an aggregate of $11 million in annualized dividends.
The net proceeds of the above debt and equity offerings were used for general corporate purposes and to reduce short-term indebtedness.
DIVIDENDS
On May 1, 2014, we declared quarterly dividends as follows:
Quarterly dividend on our common shares
 
 
$0.48 per share
Payable on July 30, 2014 to shareholders of record at the close of business on June 30, 2014
 
 
Quarterly dividends on our preferred shares
 
 
Series 1
$0.2875
Series 3
$0.25
Payable on June 30, 2014 to shareholders of record at the close of business on June 2, 2014
Series 5
$0.275
Series 7
$0.25
Series 9
$0.266
Payable on July 30, 2014 to shareholders of record at the close of business on June 30, 2014
 
SHARE INFORMATION
April 28, 2014
 
 
 
 
 
Common shares
Issued and outstanding
 
 
708 million
 
Preferred shares
Issued and outstanding
Convertible to
Series 1
22 million
22 million Series 2 preferred shares
Series 3
14 million
14 million Series 4 preferred shares
Series 5
14 million
14 million Series 6 preferred shares
Series 7
24 million
24 million Series 8 preferred shares
Series 9
18 million
18 million Series 10 preferred shares
 
 
 
Options to buy common shares
Outstanding
Exercisable
 
9 million
5 million
 


TRANSCANADA [22
FIRST QUARTER 2014

CREDIT FACILITIES
We use committed, revolving credit facilities to support our commercial paper programs along with additional demand facilities for general corporate purposes including issuing letters of credit and providing additional liquidity.
 
At March 31, 2014, we had $6 billion in unsecured credit facilities, including:
Amount
Unused
capacity
Subsidiary
For
 
Matures
 
 
 
 
 
 
$3.0 billion
$3.0 billion
TCPL
Committed, syndicated, revolving, extendible credit facility that supports TCPL’s Canadian commercial paper program
 
December 2018
US$1.0 billion
US$1.0 billion
TCPL USA
Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes
 
November 2014
US$1.0 billion
US$1.0 billion
TransCanada American Investments Ltd. (TAIL)
Committed, syndicated, revolving, extendible credit facility that supports the TAIL U.S. dollar commercial paper program in the U.S.
 
November 2014
$1.1 billion
$0.3 billion
TCPL,
TCPL USA
Demand lines for issuing letters of credit and as a source of additional liquidity. At March 31, 2014, we had $0.7 billion outstanding in letters of credit under these lines
 
Demand

See Financial risks and financial instruments for more information about liquidity, market and other risks.
 
CONTRACTUAL OBLIGATIONS
Our capital commitments have decreased by $522 million since December 31, 2013, primarily due to the completion or advancement of capital projects. There were no other material changes to our contractual obligations in first quarter 2014 or to payments due in the next five years or after. See the MD&A in our 2013 Annual Report for more information about our contractual obligations.


TRANSCANADA [23
FIRST QUARTER 2014

Financial risks and financial instruments
 
We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.
 
See our 2013 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2013.
 
LIQUIDITY RISK
We manage our liquidity risk by continuously forecasting our cash requirements for a rolling twelve month period and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.
 
COUNTERPARTY CREDIT RISK
We have exposure to counterparty credit risk in the following areas:
•
accounts receivable
•
the fair value of derivative assets
•
notes receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2014, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $220 million with one counterparty at March 31, 2014 (December 31, 2013 - $240 million). This amount is secured by a guarantee from the counterparty’s parent company and we anticipate collecting the full amount.
 
We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
 
FOREIGN EXCHANGE AND INTEREST RATE RISK
Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, our exposure to changes in currency rates increases. Some of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.

We have floating interest rate debt which subjects us to interest rate cash flow risk. We manage this using a combination of interest rate swaps and options.

Average exchange rate - U.S. to Canadian dollars
First quarter 2014
1.11

First quarter 2013
1.01

 
The impact of changes in the value of the U.S. dollar on our U.S. dollar-denominated operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below. Comparable EBIT is a non-GAAP measure.
 
Significant U.S. dollar-denominated amounts
 
 
three months ended March 31
(unaudited - millions of US$)
 
2014

 
2013

 
 
 
 
 
U.S. and International Natural Gas Pipelines comparable EBIT
 
211

 
200

U.S. Liquids Pipelines comparable EBIT
 
129

 
94

U.S. Power comparable EBIT
 
59

 
39

Interest expense on U.S. dollar-denominated long-term debt
 
(207
)
 
(188
)
Capitalized interest on U.S. capital expenditures
 
52

 
44

U.S. non-controlling interests and other
 
(79
)
 
(48
)
 
 
165

 
141

 


TRANSCANADA [24
FIRST QUARTER 2014

NET INVESTMENT IN FOREIGN OPERATIONS
We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:
 
 
March 31, 2014
 
December 31, 2013
(unaudited - millions of $)
 
Fair value1


Notional or principal amount

Fair value1


Notional or principal amount
 
 
 
 
 
 
 
 
 
Asset/(liability)
 







U.S. dollar cross-currency swaps
 
 

 

 

 
(maturing 2014 to 2019)2
 
(326
)
 
US 3,550
 
(201
)
 
US 3,800
U.S. dollar foreign exchange forward contracts
 
 

 
 
 
 

 
 
(maturing 2014)
 
(17
)
 
US 1,000
 
(11
)
 
US 850
 
 
(343
)
 
US 4,550
 
(212
)
 
US 4,650
 
1
Fair values equal carrying values.
2
Net Income in the three months ended March 31, 2014 included net realized gains of $6 million (2013 - gains of $7 million) related to the interest component of cross-currency swap settlements.
 
U.S. dollar-denominated debt designated as a net investment hedge
(unaudited - millions of $)
 
March 31, 2014
 
December 31, 2013
 
 
 
 
 
Carrying value
 
16,200 (US 14,600)
 
14,200 (US 13,400)
Fair value
 
18,500 (US 16,700)
 
16,000 (US 15,000)
 
The balance sheet classification of the fair value of derivatives used to hedge our net investment in foreign operations is as follows:
(unaudited - millions of $)
 
March 31, 2014

 
December 31, 2013

 
 
 
 
 
Other current assets
 
5

 
5

Intangible and other assets
 
1

 
—

Accounts payable and other
 
(93
)
 
(50
)
Other long-term liabilities
 
(256
)
 
(167
)
 
 
(343
)
 
(212
)
 
FINANCIAL INSTRUMENTS

All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchases and normal sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.

Non-derivative financial instruments

Fair value of non-derivative financial instruments
The fair value of our notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt has been estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.

Certain non-derivative financial instruments including cash and cash equivalents, accounts receivable, intangibles and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity.

Derivative instruments
We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify.  The effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in Other comprehensive income (OCI) in the period of change. Any ineffective portion is recognized in net income in the same financial


TRANSCANADA [25
FIRST QUARTER 2014

category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other and interest expense.

Derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.  

The recognition of gains and losses on the derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered through the tolls charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.

Fair value of derivative instruments
The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses current market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives have been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.
 
Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of the derivative instruments is as follows:
(unaudited - millions of $)
 
March 31, 2014

 
December 31, 2013

 
 
 
 
 
Other current assets
 
364

 
395

Intangible and other assets
 
100

 
112

Accounts payable and other
 
(434
)
 
(357
)
Other long-term liabilities
 
(341
)
 
(255
)
 
 
(311
)
 
(105
)
 
The effect of derivative instruments on the consolidated statement of income
The following summary does not include hedges of our net investment in foreign operations.
 
 
three months ended March 31
(unaudited - millions of $, pre-tax)
 
2014

 
2013

Derivative instruments held for trading1
 
 
 
 
Amount of unrealized gains/(losses) in the period
 
 
 
 
  Power
 
9

 
(8
)
  Natural gas
 
(7
)
 
9

  Foreign exchange
 
(2
)
 
(6
)
Amount of realized (losses)/gains in the period
 
 
 
 
  Power
 
(28
)
 
(7
)
  Natural gas
 
50

 
(2
)
  Foreign exchange
 
(17
)
 
(1
)
Derivative instruments in hedging relationships2,3
 
 
 
 
Amount of realized gains in the period
 
 
 
 
  Power
 
192

 
73

  Interest
 
1

 
2


1
Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included net in interest expense and interest income and other, respectively.
2
At March 31, 2014, all hedging relationships were designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $6 million (2013 - $10 million) and a notional amount of US$300 million (2013 - US$350 million). For the three months ended March 31, 2014, net realized gains on fair value hedges were $1 million (2013 - $2 million) and were included in interest expense. For the three months ended March 31, 2014 and 2013, we did not record any amounts in net income related to ineffectiveness for fair value hedges.
3
The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles. For the three months ended March 31, 2014 and 2013, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.


TRANSCANADA [26
FIRST QUARTER 2014


Derivatives in cash flow hedging relationships
The components of the Condensed Consolidated Statement of OCI related to derivatives in cash flow hedging relationships is as follows:
 
 
three months ended March 31
(unaudited - millions of $, pre-tax)
 
2014

 
2013

 
 
 
 
 
Change in fair value of derivative instruments recognized in OCI (effective portion)
 
 
 
 
Power
 
41

 
36

Foreign Exchange
 
10

 
2

 
 
51

 
38

Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)
 
 
 
 
Power
 
(108
)
 
(11
)
Interest
 
5

 
4

 
 
(103
)
 
(7
)
Losses on derivative instruments recognized in earnings (ineffective portion)
 
 
 
 
Power
 
(13
)
 
(5
)
 
 
(13
)
 
(5
)

Credit risk related contingent features of derivative instruments
Derivatives contracts often contain financial assurance provisions that may require us to provide collateral if a credit risk related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade).
 
Based on contracts in place and market prices at March 31, 2014, the aggregate fair value of all derivative contracts with credit risk related contingent features that were in a net liability position was $19 million (December 31, 2013 - $16 million), with collateral provided in the normal course of business of nil (December 31, 2013 – nil). If the credit risk related contingent features in these agreements had been triggered on March 31, 2014, we would have been required to provide collateral of $19 million (December 31, 2013 - $16 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
 
We feel we have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
 
Other information
 
CONTROLS AND PROCEDURES
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2014, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
 
There were no changes in first quarter 2014 that had or are likely to have a material impact on our internal control over financial reporting, other than noted below.
 
Effective January 1, 2014, management implemented an ERP system. As a result of the ERP system, certain processes supporting our internal control over financial reporting have changed. Management will continue to monitor the effectiveness of these processes going forward.
 
CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES
When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2013 Annual Report.
 
Our significant accounting policies have remained unchanged since December 31, 2013 other than described below. You can find a summary of our significant accounting policies in our 2013 Annual Report.
 


TRANSCANADA [27
FIRST QUARTER 2014

Changes in accounting policies for 2014
 
Obligations resulting from joint and several liability arrangements
In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This new guidance was effective January 1, 2014. There was no material impact on our consolidated financial statements as a result of applying this new standard.

Foreign currency matters - cumulative translation adjustment
In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This new guidance was effective prospectively from January 1, 2014 and will be applied for all applicable transactions after that date.

Unrecognized tax benefit
In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014. There was no material impact on our consolidated financial statements as a result of applying this new standard.


TRANSCANADA [28
FIRST QUARTER 2014

QUARTERLY RESULTS
 
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
 
2014
 
2013
 
2012
(unaudited - millions of $, except per share amounts)
First

 
Fourth

 
Third

 
Second

 
First

 
Fourth

 
Third

 
Second

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
2,884

 
2,332

 
2,204

 
2,009

 
2,252

 
2,089

 
2,126

 
1,847

Net income attributable to common shares
412

 
420

 
481

 
365

 
446

 
306

 
369

 
272

Comparable earnings
422

 
410

 
447

 
357

 
370

 
318

 
349

 
300

Comparable earnings per share

$0.60

 

$0.58

 

$0.63

 

$0.51

 

$0.52

 

$0.45

 

$0.50

 

$0.43

Share statistics
 
 
 
 
 
 
 

 
 

 
 

 
 

 
 

Net Income per common share - basic and diluted

$0.58

 

$0.59

 

$0.68

 

$0.52

 

$0.63

 

$0.43

 

$0.52

 

$0.39

Dividends declared per common share

$0.48

 

$0.46

 

$0.46

 

$0.46

 

$0.46

 

$0.44

 

$0.44

 

$0.44

 
FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT
Quarter-over-quarter revenues and net income sometimes fluctuate. The causes of these fluctuations vary across our business segments.
 
In Natural Gas Pipelines, quarter-over-quarter revenues and net income from the Canadian regulated pipelines generally remain relatively stable during any fiscal year. Our U.S. natural gas pipelines are generally seasonal in nature with higher earnings in the winter months as a result of increased customer demands. Over the long term, however, results from both our Canadian and U.S. natural gas pipelines fluctuate because of:
•
regulatory decisions
•
negotiated settlements with shippers
•
acquisitions and divestitures
•
developments outside of the normal course of operations
•
newly constructed assets being placed in service.

In Liquids Pipelines, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable.
 
In Energy, quarter-over-quarter revenues and net income are affected by:
•
weather
•
customer demand
•
market prices
•
capacity prices and payments
•
planned and unplanned plant outages
•
acquisitions and divestitures
•
certain fair value adjustments
•
developments outside of the normal course of operations
•
newly constructed assets being placed in service
•
regulatory decisions.

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.
Comparable earnings 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 amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.
In second quarter 2013, comparable earnings excluded a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax in June 2013.
In first quarter 2013, comparable earnings excluded $84 million of net income in 2013 related to 2012 from the NEB decision (RH-003-2011).
In second quarter 2012, comparable earnings excluded a $15 million after-tax charge ($20 million pre-tax) from the Sundance A PPA arbitration decision.


TRP-03.31.2014-Fin Stmts
EXHIBIT 13.2


Condensed consolidated statement of income
 
 
 
three months ended
March 31
(unaudited - millions of Canadian $ except per share amounts)
 
2014

 
2013

 
 
 
 
 
Revenues
 
 
 
 
Natural gas pipelines
 
1,215

 
1,157

Liquids pipelines
 
359

 
271

Energy
 
1,310

 
824

 
 
2,884

 
2,252

Income from Equity Investments
 
135

 
93

Operating and Other Expenses
 
 

 
 

Plant operating costs and other
 
805

 
641

Commodity purchases resold
 
706

 
376

Property taxes
 
123

 
109

Depreciation and amortization
 
393

 
367

 
 
2,027

 
1,493

Financial Charges/(Income)
 
 

 
 

Interest expense
 
274

 
258

Interest income and other
 
8

 
(13
)
 
 
282

 
245

Income before Income Taxes
 
710

 
607

Income Tax Expense
 
 

 
 

Current
 
59

 
79

Deferred
 
162

 
36

 
 
221

 
115

Net Income
 
489

 
492

Net income attributable to non-controlling interests
 
54

 
31

Net Income Attributable to Controlling Interests
 
435

 
461

Preferred share dividends
 
23

 
15

Net Income Attributable to Common Shares
 
412

 
446

 
 
 
 
 
Net Income per Common Share
 
 

 
 

Basic and diluted
 

$0.58

 

$0.63

Dividends Declared per Common Share
 

$0.48

 

$0.46

Weighted Average Number of Common Shares (millions)
 
 

 
 

Basic
 
708

 
706

Diluted
 
708

 
707

 
See accompanying notes to the condensed consolidated financial statements.


TRANSCANADA [30
FIRST QUARTER REPORT 2014


Condensed consolidated statement of comprehensive income
 
 
 
three months ended
March 31
(unaudited - millions of Canadian $)
 
2014

 
2013

 
 
 
 
 
Net Income
 
489

 
492

Other Comprehensive Income, Net of Income Taxes
 
 

 
 

Foreign currency translation gains and losses on net investment in foreign operations
 
240

 
111

Change in fair value of net investment hedges
 
(127
)
 
(49
)
Change in fair value of cash flow hedges
 
31

 
21

Reclassification to Net Income of gains and losses on cash flow hedges
 
(62
)
 
(4
)
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans
 
4

 
6

Other comprehensive loss on equity investments
 
—

 
(1
)
Other comprehensive income (Note 7)
 
86

 
84

Comprehensive Income
 
575

 
576

Comprehensive income attributable to non-controlling interests
 
98

 
51

Comprehensive Income Attributable to Controlling Interests
 
477

 
525

Preferred share dividends
 
25

 
15

Comprehensive Income Attributable to Common Shares
 
452

 
510

 
See accompanying notes to the condensed consolidated financial statements.



TRANSCANADA [31
FIRST QUARTER REPORT 2014


Condensed consolidated statement of cash flows
 
 
 
three months ended
March 31
(unaudited - millions of Canadian $)
 
2014

 
2013

 
 
 
 
 
Cash Generated from Operations
 
 
 
 
Net income
 
489

 
492

Depreciation and amortization
 
393

 
367

Deferred income taxes
 
162

 
36

Income from equity investments
 
(135
)
 
(93
)
Distributed earnings received from equity investments
 
170

 
84

Employee post-retirement benefits funding lower than expense
 
10

 
15

Other
 
13

 
15

Increase in operating working capital
 
(123
)
 
(210
)
Net cash provided by operations
 
979

 
706

Investing Activities
 
 

 
 

Capital expenditures
 
(778
)
 
(929
)
Equity investments
 
(89
)
 
(32
)
Deferred amounts and other
 
(23
)
 
(20
)
Net cash used in investing activities
 
(890
)
 
(981
)
Financing Activities
 
 

 
 

Dividends on common and preferred shares
 
(345
)
 
(315
)
Distributions paid to non-controlling interests
 
(45
)
 
(35
)
Notes payable repaid, net
 
(747
)
 
(829
)
Long-term debt issued, net of issue costs
 
1,364

 
734

Repayment of long-term debt
 
(777
)
 
(14
)
Common shares issued, net of issue costs
 
10

 
32

Preferred shares issued, net of issue costs
 
440

 
586

Preferred shares of subsidiary redeemed
 
(200
)
 
—

Net cash (used in)/provided by financing activities
 
(300
)
 
159

Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents
 
33

 
8

Decrease in Cash and Cash Equivalents
 
(178
)
 
(108
)
Cash and Cash Equivalents
 
 

 
 

Beginning of period
 
927

 
551

Cash and Cash Equivalents
 
 

 
 

End of period
 
749

 
443

 
See accompanying notes to the condensed consolidated financial statements.



TRANSCANADA [32
FIRST QUARTER REPORT 2014


Condensed consolidated balance sheet
 
 
 
March 31

 
December 31

(unaudited - millions of Canadian $)
 
2014

 
2013

 
 
 
 
 
ASSETS
 
 
 
 
Current Assets
 
 
 
 
Cash and cash equivalents
 
749

 
927

Accounts receivable
 
1,517

 
1,122

Inventories
 
236

 
251

Other
 
962

 
847

 
 
3,464

 
3,147

Plant, Property and Equipment,
net of accumulated depreciation of $18,349 and $17,851, respectively
 
38,625

 
37,606

Equity Investments
 
5,800

 
5,759

Regulatory Assets
 
1,705

 
1,735

Goodwill
 
3,842

 
3,696

Intangible and Other Assets
 
2,058

 
1,955

 
 
55,494

 
53,898

LIABILITIES
 
 

 
 

Current Liabilities
 
 

 
 

Notes payable
 
1,137

 
1,842

Accounts payable and other
 
2,431

 
2,155

Accrued interest
 
379

 
388

Current portion of long-term debt
 
1,109

 
973

 
 
5,056

 
5,358

Regulatory Liabilities
 
221

 
229

Other Long-Term Liabilities
 
746

 
656

Deferred Income Tax Liabilities
 
4,808

 
4,564

Long-Term Debt
 
22,997

 
21,892

Junior Subordinated Notes
 
1,105

 
1,063

 
 
34,933

 
33,762

EQUITY
 
 

 
 

Common shares, no par value
 
12,161

 
12,149

Issued and outstanding:
March 31, 2014 - 708 million shares
 
 

 
 

 
December 31, 2013 - 707 million shares
 
 

 
 

Preferred shares
 
2,255

 
1,813

Additional paid-in capital
 
396

 
401

Retained earnings
 
5,167

 
5,096

Accumulated other comprehensive loss (Note 7)
 
(892
)
 
(934
)
Controlling Interests
 
19,087

 
18,525

Non-controlling interests
 
1,474

 
1,611

 
 
20,561

 
20,136

 
 
55,494

 
53,898

Contingencies and Guarantees (Note 10)
 
 

 
 

Subsequent Events (Note 11)
 
 

 
 

 
See accompanying notes to the condensed consolidated financial statements.



TRANSCANADA [33
FIRST QUARTER REPORT 2014


Condensed consolidated statement of equity
 
 
 
three months ended
March 31
(unaudited - millions of Canadian $)
 
2014

 
2013

 
 
 
 
 
Common Shares
 
 
 
 
Balance at beginning of period
 
12,149

 
12,069

Shares issued on exercise of stock options
 
12

 
37

Balance at end of period
 
12,161

 
12,106

Preferred Shares
 
 

 
 

Balance at beginning of period
 
1,813

 
1,224

Shares issued under public offering, net of issue costs
 
442

 
586

Balance at end of period
 
2,255

 
1,810

Additional Paid-In Capital
 
 

 
 

Balance at beginning of period
 
401

 
379

Exercise of stock options, net of issuances
 
1

 
(3
)
Redemption of subsidiary's preferred shares
 
(6
)
 
—

Balance at end of period
 
396

 
376

Retained Earnings
 
 

 
 

Balance at beginning of period
 
5,096

 
4,687

Net income attributable to controlling interests
 
435

 
461

Common share dividends
 
(339
)
 
(324
)
Preferred share dividends
 
(25
)
 
(15
)
Balance at end of period
 
5,167

 
4,809

Accumulated Other Comprehensive Loss
 
 

 
 

Balance at beginning of period
 
(934
)
 
(1,448
)
Other comprehensive income
 
42

 
64

Balance at end of period
 
(892
)
 
(1,384
)
Equity Attributable to Controlling Interests
 
19,087

 
17,717

Equity Attributable to Non-Controlling Interests
 
 

 
 

Balance at beginning of period
 
1,611

 
1,425

Net income attributable to non-controlling interests
 
 

 
 

TC PipeLines, LP
 
45

 
19

Preferred share dividends of TCPL
 
2

 
6

Portland
 
7

 
6

Other comprehensive income attributable to non-controlling interests
 
44

 
20

Distributions to non-controlling interests
 
(51
)
 
(35
)
Redemption of subsidiary's preferred shares
 
(194
)
 
—

Foreign exchange and other
 
10

 
3

Balance at end of period
 
1,474

 
1,444

Total Equity
 
20,561

 
19,161

 
See accompanying notes to the condensed consolidated financial statements.



TRANSCANADA [34
FIRST QUARTER REPORT 2014


Notes to condensed consolidated financial statements
(unaudited)
 
1. Basis of presentation

These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada’s annual audited consolidated financial statements for the year ended December 31, 2013. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada’s 2013 Annual Report.
 
These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2013 audited consolidated financial statements included in TransCanada’s 2013 Annual Report. Certain comparative figures have been reclassified to conform with the current period’s presentation.
 
Earnings for interim periods may not be indicative of results for the fiscal year in the Company’s Natural Gas Pipelines segment due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines.  Earnings for interim periods may also not be indicative of results for the fiscal year in the Company’s Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company’s investments in electrical power generation plants and non-regulated gas storage facilities.
 
USE OF ESTIMATES AND JUDGEMENTS
In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies included in the consolidated financial statements for the year ended December 31, 2013, except as described in Note 2, Changes in accounting policies.

2. Changes in accounting policies

CHANGES IN ACCOUNTING POLICIES FOR 2014

Obligations resulting from joint and several liability arrangements
In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This new guidance was effective January 1, 2014. There was no material impact on the Company’s consolidated financial statements as a result of applying this new standard.
 
Foreign currency matters - cumulative translation adjustment
In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This new guidance was effective prospectively from January 1, 2014 and will be applied for all applicable transactions after that date.

Unrecognized tax benefit
In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014. There was no material impact on the Company's consolidated financial statements as a result of applying this new standard.



TRANSCANADA [35
FIRST QUARTER REPORT 2014


3. Segmented information
 
three months ended March 31
 
Natural Gas Pipelines
 
Liquids Pipelines1
 
Energy
 
Corporate
 
Total
(unaudited - millions of Canadian $)
 
2014

 
2013

 
2014

 
2013

 
2014

 
2013

 
2014

 
2013

 
2014

 
2013

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
1,215

 
1,157

 
359

 
271

 
1,310

 
824

 
—

 
—

 
2,884

 
2,252

Income from equity investments
 
52

 
40

 
—

 
—

 
83

 
53

 
—

 
—

 
135

 
93

Plant operating costs and other
 
(333
)
 
(318
)
 
(101
)
 
(79
)
 
(333
)
 
(210
)
 
(38
)
 
(34
)
 
(805
)
 
(641
)
Commodity purchases resold
 
—

 
—

 
—

 
—

 
(706
)
 
(376
)
 
—

 
—

 
(706
)
 
(376
)
Property taxes
 
(86
)
 
(78
)
 
(17
)
 
(13
)
 
(20
)
 
(18
)
 
—

 
—

 
(123
)
 
(109
)
Depreciation and amortization
 
(262
)
 
(253
)
 
(49
)
 
(37
)
 
(77
)
 
(74
)
 
(5
)
 
(3
)
 
(393
)
 
(367
)
Segmented earnings
 
586

 
548

 
192

 
142

 
257

 
199

 
(43
)
 
(37
)
 
992

 
852

Interest expense
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
(274
)
 
(258
)
Interest income and other
 
(8
)
 
13

Income before income taxes
 
710

 
607

Income tax expense
 
(221
)
 
(115
)
Net income
 
489

 
492

Net income attributable to non-controlling interests
 
(54
)
 
(31
)
Net income attributable to controlling interests
 
435

 
461

Preferred share dividends
 
(23
)
 
(15
)
Net income attributable to common shares
 
412

 
446


1
Previously Oil Pipelines.

TOTAL ASSETS 
(unaudited - millions of Canadian $)
 
March 31, 2014

 
December 31, 2013

 
 
 
 
 
Natural Gas Pipelines
 
25,765

 
25,165

Liquids Pipelines1
 
14,047

 
13,253

Energy
 
13,954

 
13,747

Corporate
 
1,728

 
1,733

 
 
55,494

 
53,898

 

1
Previously Oil Pipelines.


4. Income taxes
 
At March 31, 2014, the total unrecognized tax benefit of uncertain tax positions was approximately $24 million (December 31, 2013 - $23 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. There is $1 million of interest expense and nil for penalties included in net tax expense for the three months ended March 31, 2014 (March 31, 2013 - $1 million and nil for penalties). At March 31, 2014, the Company had $7 million accrued for interest expense and nil accrued for penalties (December 31, 2013 - $6 million accrued for interest expense and nil for penalties).
 
The effective tax rates for the three-month periods ended March 31, 2014 and 2013 were 31 per cent and 19 per cent, respectively. The higher effective tax rate in 2014 compared to 2013 was primarily the result of the impact of the 2013 NEB decision (RH-003-2011) and changes in the proportion of income earned between Canadian and foreign jurisdictions in 2014 as well as higher flow-through taxes in 2014 on Canadian regulated pipelines.
 
5. Long-term debt

In the three months ended March 31, 2014, TransCanada capitalized interest related to capital projects of $79 million (March 31, 2013 - $55 million).



TRANSCANADA [36
FIRST QUARTER REPORT 2014


LONG-TERM DEBT ISSUED
Amount
(unaudited - millions of $)
 
Type
 
Maturity date
 
Interest rate

 
Date issued
US$1,250
 
Senior unsecured notes
 
March 1, 2034
 
4.63
%
 
February 2014

LONG-TERM DEBT RETIRED
Amount 
(unaudited - millions of Canadian $)
 
Type
 
Retirement date
 
Interest rate

$450
 
Medium term notes
 
January 2014
 
5.65
%
$300
 
Medium term notes
 
February 2014
 
5.05
%

6. Equity and share capital

PREFERRED SHARE ISSUANCE
In January 2014, TransCanada completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. The holders of the Series 9 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The dividend rate will reset on October 30, 2019 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 2.35 per cent. The preferred shares are redeemable by TransCanada on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends.
 
The Series 9 preferred shareholders will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 2.35 per cent.

PREFERRED SHARE REDEMPTION
On March 5, 2014, TCPL redeemed all of the four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series Y at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to the redemption date.


7. Other comprehensive income/(loss) and accumulated other comprehensive loss

Components of other comprehensive income including non-controlling interests and the related tax effects are as follows: 
three months ended March 31, 2014
 
Before tax


Income tax
recovery/


Net of tax

(unaudited - millions of Canadian $)
 
amount


(expense)


amount

 
 
 
 
 
 
 
Foreign currency translation gains and losses on net investment in foreign operations
 
191

 
49

 
240

Change in fair value of net investment hedges
 
(171
)
 
44

 
(127
)
Change in fair value of cash flow hedges
 
51

 
(20
)
 
31

Reclassification to net income of gains and losses on cash flow hedges
 
(103
)
 
41

 
(62
)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans
 
6

 
(2
)
 
4

Other comprehensive (loss)/income
 
(26
)
 
112

 
86



TRANSCANADA [37
FIRST QUARTER REPORT 2014


three months ended March 31, 2013
 
Before tax

 
Income tax
recovery/

 
Net of tax

(unaudited - millions of Canadian $)
 
amount

 
(expense)

 
amount

 
 
 
 
 
 
 
Foreign currency translation gains and losses on net investment in foreign operations
 
77

 
34

 
111

Change in fair value of net investment hedges
 
(66
)
 
17

 
(49
)
Change in fair value of cash flow hedges
 
38

 
(17
)
 
21

Reclassification to net income of gains and losses on cash flow hedges
 
(7
)
 
3

 
(4
)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans
 
10

 
(4
)
 
6

Other comprehensive loss on equity investments
 
(1
)
 
—

 
(1
)
Other comprehensive income
 
51

 
33

 
84

 
The changes in accumulated other comprehensive loss by component are as follows:
three months ended March 31, 2014
 
Currency
translation

 
Cash flow

 
Pension and
OPEB plan

 
Equity

 
 
(unaudited - millions of Canadian $)
 
adjustments

 
hedges

 
adjustments

 
Investments

 
Total1

 
 
 
 
 
 
 
 
 
 
 
AOCI balance at January 1, 2014
 
(629
)
 
(4
)
 
(197
)
 
(104
)
 
(934
)
Other comprehensive income before reclassifications2
 
69

 
31

 
—

 
—

 
100

Amounts reclassified from accumulated other comprehensive loss3
 
—

 
(62
)
 
4

 
—

 
(58
)
Net current period other comprehensive income/(loss)
 
69

 
(31
)
 
4

 
—

 
42

AOCI balance at March 31, 2014
 
(560
)
 
(35
)
 
(193
)
 
(104
)
 
(892
)

1
All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.
2
Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $44 million.
3
Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $34 million ($21 million, net of tax) at March 31, 2014. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

Details about reclassifications out of accumulated other comprehensive loss are as follows: 
three months ended March 31, 2014
 
Amounts reclassified from
accumulated other
 
Affected line item
in the condensed
consolidated
(unaudited - millions of Canadian $)
 
comprehensive loss1

statement of income
 
 
 
 
 
Cash flow hedges
 
 
 
 
Power
 
108

 
Revenue (Energy)
Interest
 
(5
)
 
Interest expense
 
 
103

 
Total before tax
 
 
(41
)
 
Income tax expense
 
 
62

 
Net of tax
Pension and other post-retirement plan adjustments
 
 

 
 
Amortization of actuarial loss and past service cost 2
 
(6
)
 
Total before tax
 
 
2

 
Income tax expense
 
 
(4
)
 
Net of tax

1
All amounts in parentheses indicate expenses to the condensed consolidated statement of income.
2
These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 8 for additional detail.



TRANSCANADA [38
FIRST QUARTER REPORT 2014


8. Employee post-retirement benefits
 
The net benefit cost recognized for the Company’s defined benefit pension plans and other post-retirement benefit plans is as follows:
 
 
three months ended March 31
 
 
Pension benefit plans
 
Other post-retirement benefit plans
(unaudited - millions of Canadian $)
 
2014

 
2013

 
2014

 
2013

 
 
 
 
 
 
 
 
 
Service cost
 
22

 
19

 
1

 
1

Interest cost
 
28

 
24

 
2

 
2

Expected return on plan assets
 
(35
)
 
(29
)
 
—

 
—

Amortization of actuarial loss
 
5

 
9

 
1

 
1

Amortization of regulatory asset
 
5

 
7

 
—

 
—

Net benefit cost recognized
 
25

 
30

 
4

 
4

 

9. Risk Management and Financial Instruments
 
RISK MANAGEMENT OVERVIEW
TransCanada has exposure to counterparty credit risk and market risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and, ultimately, shareholder value.

COUNTERPARTY CREDIT RISK
TransCanada’s maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets and notes, and loans and advances receivable. The majority of counterparty credit exposure is with counterparties that are investment grade or the exposure is supported by financial assurances provided by investment grade parties. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At March 31, 2014, there were no significant amounts past due or impaired, and there were no significant credit losses during the period.
 
At March 31, 2014, the Company had a credit risk concentration of $220 million (December 31, 2013 - $240 million) due from one counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty’s investment grade parent company.
 
NET INVESTMENT IN FOREIGN OPERATIONS
The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options.
 
U.S. dollar-denominated debt designated as a net investment hedge
(unaudited - millions of  Canadian $)

March 31, 2014

December 31, 2013





Carrying value

16,200 (US 14,600)
 
14,200 (US 13,400)
Fair value

18,500 (US 16,700)
 
16,000 (US 15,000)
 
Derivatives designated as a net investment hedge
 
 
March 31, 2014
 
December 31, 2013
(unaudited - millions of Canadian $)

Fair Value1


Notional or principal amount

Fair value1


Notional or principal amount
 
 
 
 
 
 
 
 
 
Asset/(liability)








U.S. dollar cross-currency interest rate swaps

 

 

 

 
(maturing 2014 to 2019)2

(326
)
 
US 3,550
 
(201
)
 
US 3,800
U.S. dollar foreign exchange forward contracts

 

 
 
 
 

 
 
(maturing 2014)

(17
)
 
US 1,000
 
(11
)
 
US 850
 

(343
)
 
US 4,550
 
(212
)

US 4,650



TRANSCANADA [39
FIRST QUARTER REPORT 2014


1
Fair values equal carrying values.
2
Net income in the three months ended March 31, 2014 included net realized gains of $6 million (2013 - gains of $7 million) related to the interest component of cross-currency swap settlements and are included in interest expense.

The balance sheet classification of the fair value of derivatives used to hedge the Company's net investment in foreign operations is as follows: 
(unaudited - millions of Canadian $)
 
March 31, 2014

 
December 31, 2013

 
 
 
 
 
Other current assets
 
5

 
5

Intangible and other assets
 
1

 
—

Accounts payable and other
 
(93
)
 
(50
)
Other long-term liabilities
 
(256
)
 
(167
)
 
 
(343
)
 
(212
)

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments
The fair value of the Company's notes receivables is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity and would be classified in Level II of the fair value hierarchy.

Balance sheet presentation of non-derivative financial instruments
The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts equal fair value, and would be classified in Level II of the fair value hierarchy: 
 
 
March 31, 2014
 
December 31, 2013
(unaudited - millions of Canadian $)
 
Carrying
amount1

 
Fair
value

 
Carrying
amount1

 
Fair
value

 
 
 
 
 
 
 
 
 
Notes receivable and other1
 
199

 
246

 
226

 
269

Available for sale assets2
 
45

 
45

 
47

 
47

Current and long-term debt3,4
 
(24,106
)
 
(28,239
)
 
(22,865
)
 
(26,134
)
Junior subordinated notes
 
(1,105
)
 
(1,144
)
 
(1,063
)
 
(1,093
)
 
 
(24,967
)
 
(29,092
)
 
(23,655
)
 
(26,911
)

1
Notes receivable are included in other current assets and intangible and other assets on the condensed consolidated balance sheet.
2
Available for sale assets are included in intangible and other assets on the condensed consolidated balance sheet.
3
Long-term debt is recorded at amortized cost, except for US$300 million (December 31, 2013 - US$200 million) that is attributed to hedged risk and recorded at fair value.
4
Consolidated net income for the three months ended March 31, 2014 included losses of $6 million (2013 - losses of $10 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$300 million of long-term debt at March 31, 2014 (December 31, 2013 - US$200 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Derivative instruments

Fair value of derivative instruments
The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses current market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives and available for sale assets has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

Where possible, derivative instruments are designated as hedges, but in some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment and are


TRANSCANADA [40
FIRST QUARTER REPORT 2014


accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.

Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of the derivative instruments is as follows:
(unaudited - millions of Canadian $)
 
March 31, 2014

 
December 31, 2013

 
 
 
 
 
Other current assets
 
364

 
395

Intangible and other assets
 
100

 
112

Accounts payable and other
 
(434
)
 
(357
)
Other long-term liabilities
 
(341
)
 
(255
)
 
 
(311
)
 
(105
)

2014 derivative instruments summary
The following summary does not include hedges of our net investment in foreign operations.
(unaudited - millions of Canadian $ unless noted otherwise)
 
Power

 
Natural
gas

 
Foreign
exchange

 
Interest

 
 
 
 
 
 
 
 
 
Derivative instruments held for trading1
 
 
 
 
 
 
 
 
Fair values2,3
 
 
 
 
 
 
 
 
Assets
 

$288

 

$67

 

$—

 

$7

Liabilities
 

($303
)
 

($73
)
 

($12
)
 

($7
)
Notional values3
 
 

 
 

 
 

 
 

Volumes4
 
 

 
 

 
 

 
 

Purchases
 
39,687

 
110

 
—

 
—

Sales
 
38,719

 
60

 
—

 
—

Canadian dollars
 
—

 
—

 
—

 
—

U.S. dollars
 
—

 
—

 
US 985

 
US 100

Net unrealized gains/(losses) in the period5
 
 

 
 

 
 

 
 

three months ended March 31, 2014
 

$9

 

($7
)
 

($2
)
 

$—

Net realized (losses)/gains in the period5
 
 

 
 

 
 

 
 

three months ended March 31, 2014
 

($28
)
 

$50

 

($17
)
 

$—

Maturity dates3
 
2014-2018

 
2014-2016

 
2014

 
2016

Derivative instruments in hedging relationships6,7
 
 

 
 

 
 

 
 

Fair values2,3
 
 

 
 

 
 

 
 

Assets
 

$90

 

$—

 

$—

 

$6

Liabilities
 

($30
)
 

$—

 

$—

 

($1
)
Notional values3
 
 

 
 

 
 

 
 

Volumes4
 
 

 
 

 
 

 
 

Purchases
 
8,887

 
—

 
—

 
—

Sales
 
6,299

 
—

 
—

 
—

U.S. dollars
 
—

 
—

 
—

 
US 450

Net realized gains in the period5
 
 

 
 

 
 

 
 

three months ended March 31, 2014
 

$192

 

$—

 

$—

 

$1

Maturity dates3
 
2014-2018

 
—

 
—

 
2015-2018


1
All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company’s risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company’s exposures to market risk.
2
Fair values equal carrying values.
3
As at March 31, 2014.
4
Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
5
Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in interest expense and interest income and other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles.


TRANSCANADA [41
FIRST QUARTER REPORT 2014


6
All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $6 million and a notional amount of US$300 million as at March 31, 2014. For the three months ended March 31, 2014, net realized gains on fair value hedges were $1 million and were included in interest expense. For the three months ended March 31, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.
7
For the three months ended March 31, 2014, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

2013 derivative instruments summary
The following summary does not include hedges of our net investment in foreign operations.
(unaudited – millions of  Canadian $ unless noted otherwise)
 
Power

 
Natural
gas

 
Foreign
exchange

 
 Interest

 
 
 
 
 
 
 
 
 
Derivative instruments held for trading1
 
 
 
 
 
 
 
 
Fair values2,3
 
 
 
 
 
 
 
 
Assets
 

$265

 

$73

 

$—

 

$8

Liabilities
 

($280
)
 

($72
)
 

($12
)
 

($7
)
Notional values3
 
 

 
 

 
 

 
 
Volumes4
 
 

 
 

 
 

 
 
Purchases
 
29,301

 
88

 
—

 
—

Sales
 
28,534

 
60

 
—

 
—

Canadian dollars
 
—

 
—

 
—

 
400

U.S. dollars
 
—

 
—

 
US 1,015

 
US 100

Net unrealized (losses)/gains in the period5
 
 

 
 

 
 

 
 
three months ended March 31, 2013
 

($8
)
 

$9

 

($6
)
 

$—

Net realized losses in the period5
 
 

 
 

 
 

 
 
three months ended March 31, 2013
 

($7
)
 

($2
)
 

($1
)
 

$—

Maturity dates3
 
2014-2017

 
2014-2016

 
2014

 
2014-2016

Derivative instruments in hedging relationships 6,7
 
 

 
 

 
 
 
 

Fair values2,3
 
 

 
 

 
 
 
 

Assets
 

$150

 

$—

 

$—

 

$6

Liabilities
 

($22
)
 

$—

 

($1
)
 

($1
)
Notional values3
 
 

 
 

 
 
 
 

Volumes4
 
 

 
 

 
 
 
 

Purchases
 
9,758

 
—

 
—

 
—

Sales
 
6,906

 
—

 
—

 
—

U.S. dollars
 
—

 
—

 
US 16

 
US 350

Net realized gains in the period5
 
 

 
 

 
 

 
 
three months ended March 31, 2013
 

$73

 

$—

 

$—

 

$2

Maturity dates3
 
2014-2018

 
—

 
2014

 
2015-2018

 
1
All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company’s risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company’s exposures to market risk.
2
Fair values equal carrying values.
3
As at December 31, 2013.
4
Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
5
Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in interest expense and interest income and other, respectively. The effective portion of change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles.
6
All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $5 million and a notional amount of US$200 million as at December 31, 2013. Net realized gains on fair value hedges for the three months ended March 31, 2013 were $2 million and were included in Interest expense. In the three months ended March 31, 2013, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.
7
For the three months ended March 31, 2013, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.



TRANSCANADA [42
FIRST QUARTER REPORT 2014


Derivatives in cash flow hedging relationships
The components of OCI (Note 7) related to derivatives in cash flow hedging relationships are as follows: 
 
 
three months ended March 31
(unaudited - millions of Canadian $, pre-tax)
 
2014

 
2013

 
 
 
 
 
Change in fair value of derivative instruments recognized in OCI (effective portion)1
 
 
 
 
Power
 
41

 
36

Foreign exchange
 
10

 
2

 
 
51

 
38

Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)1
 
 
 
 
Power2
 
(108
)
 
(11
)
Interest
 
5

 
4

 
 
(103
)
 
(7
)
Losses on derivative instruments recognized in net income (ineffective portion)
 
 
 
 
Power
 
(13
)
 
(5
)
 
 
(13
)
 
(5
)

1
No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.
2
Reported within Energy revenues on the condensed consolidated statement of income.
 
Offsetting of derivative instruments
The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights of offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:
at March 31, 2014
 
Gross derivative instruments

 
Amounts available

 
 
(unaudited - millions of Canadian $)
 
presented on the balance sheet

 
for offset1

 
Net amounts

 
 
 
 
 
 
 
Derivative - Asset
 
 
 
 
 
 
Power
 
378

 
(261
)
 
117

Natural gas
 
67

 
(51
)
 
16

Foreign exchange
 
6

 
(9
)
 
(3
)
Interest
 
13

 
—

 
13

Total
 
464

 
(321
)
 
143

Derivative - Liability
 
 

 
 

 
 

Power
 
(333
)
 
261

 
(72
)
Natural gas
 
(73
)
 
51

 
(22
)
Foreign exchange
 
(361
)
 
9

 
(352
)
Interest
 
(8
)
 
—

 
(8
)
Total
 
(775
)
 
321

 
(454
)
 
1
Amounts available for offset do not include cash collateral pledged or received.

With respect to all financial arrangements, including the derivative instruments presented above, as at March 31, 2014, the Company had provided cash collateral of $78 million and letters of credit of $41 million to its counterparties. The Company held $2 million in cash collateral and $29 million in letters of credit on asset exposures at March 31, 2014. 


TRANSCANADA [43
FIRST QUARTER REPORT 2014


The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2013:
at December 31, 2013
 
Gross derivative instruments

 
Amounts available

 
 
(unaudited - millions of Canadian $)
 
presented on the balance sheet

 
for offset1

 
Net amounts

 
 
 
 
 
 
 
Derivative - Asset
 
 
 
 
 
 
Power
 
415

 
(277
)
 
138

Natural gas
 
73

 
(61
)
 
12

Foreign exchange
 
5

 
(5
)
 
—

Interest
 
14

 
(2
)
 
12

Total
 
507

 
(345
)
 
162

Derivative - Liability
 
 

 
 

 
 

Power
 
(302
)
 
277

 
(25
)
Natural gas
 
(72
)
 
61

 
(11
)
Foreign exchange
 
(230
)
 
5

 
(225
)
Interest
 
(8
)
 
2

 
(6
)
Total
 
(612
)
 
345

 
(267
)
 
1
Amounts available for offset do not include cash collateral pledged or received.

With respect to all financial arrangements, including the derivative instruments presented above as at December 31, 2013, the Company had provided cash collateral of $67 million and letters of credit of $85 million to its counterparties. The Company held $11 million in cash collateral and $32 million in letters of credit on asset exposures at December 31, 2013.
 
Credit risk related contingent features of derivative instruments
Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit risk related contingent event occurs, such as a downgrade in the Company’s credit rating to non-investment grade.
 
Based on contracts in place and market prices at March 31, 2014, the aggregate fair value of all derivative instruments with credit risk related contingent features that were in a net liability position was $19 million (December 31, 2013 - $16 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2013 - nil). If the credit risk related contingent features in these agreements were triggered on March 31, 2014, the Company would have been required to provide collateral of $19 million (December 31, 2013 - $16 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
 
The Company feels it has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
 


TRANSCANADA [44
FIRST QUARTER REPORT 2014


FAIR VALUE HIERARCHY
The Company’s assets and liabilities recorded at fair value have been classified into three categories based on the fair value hierarchy.
Levels
How fair value has been determined
Level I
Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level II
Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly.
 
Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers.
 
This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and power and natural gas commodity derivatives where fair value is determined using the market approach.
 
Transfers between Level I and Level II would occur when there is a change in market circumstances.
Level III
Valuation of assets and liabilities measured on a recurring basis using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. This category includes long-dated commodity transactions in certain markets where liquidity is low. Long-term electricity prices are estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which we operate.
 
Model inputs include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas is expected to or may result in a lower fair value measurement of contracts included in Level III.
 
Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.
 
The fair value of the Company’s assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:
at March 31, 2014
 
Quoted prices in active markets


Significant other observable inputs


Significant unobservable inputs




(unaudited - millions of Canadian $, pre-tax)
 
(Level I)1


(Level II)1


(Level III)1


Total

 
 
 
 
 
 
 
 
 
Derivative instrument assets:
 
 
 
 
 
 
 
 
Power commodity contracts
 
—

 
374

 
4

 
378

Natural gas commodity contracts
 
48

 
19

 
—

 
67

Foreign exchange contracts
 
—

 
6

 
—

 
6

Interest rate contracts
 
—

 
13

 
—

 
13

Derivative instrument liabilities:
 
 

 
 

 
 

 
 

Power commodity contracts
 
—

 
(330
)
 
(3
)
 
(333
)
Natural gas commodity contracts
 
(46
)
 
(27
)
 
—

 
(73
)
Foreign exchange contracts
 
—

 
(361
)
 
—

 
(361
)
Interest rate contracts
 
—

 
(8
)
 
—

 
(8
)
Non-derivative financial instruments:
 
 
 
 
 
 
 
 
Available for sale assets
 
—

 
45

 
—

 
45

 
 
2

 
(269
)
 
1

 
(266
)

1
There were no transfers from Level I to Level II or from Level II to Level III for the three months ended March 31, 2014.



TRANSCANADA [45
FIRST QUARTER REPORT 2014


The fair value of the Company’s assets and liabilities measured on a recurring basis, including both current and non-current portions for 2013, are categorized as follows:
at December 31, 2013
 
Quoted prices in active markets

 
Significant other observable inputs

 
Significant unobservable inputs

 
 
(unaudited - millions of Canadian $, pre-tax)
 
(Level I)1

 
(Level II)1

 
(Level III)1

 
Total

 
 
 
 
 
 
 
 
 
Derivative instrument assets:
 
 
 
 
 
 
 
 
Power commodity contracts
 
—

 
411

 
4

 
415

Natural gas commodity contracts
 
48

 
25

 
—

 
73

Foreign exchange contracts
 
—

 
5

 
—

 
5

Interest rate contracts
 
—

 
14

 
—

 
14

Derivative instrument liabilities:
 
 

 
 

 
 

 
 

Power commodity contracts
 
—

 
(299
)
 
(3
)
 
(302
)
Natural gas commodity contracts
 
(50
)
 
(22
)
 
—

 
(72
)
Foreign exchange contracts
 
—

 
(230
)
 
—

 
(230
)
Interest rate contracts
 
—

 
(8
)
 
—

 
(8
)
Non-derivative financial instruments:
 
 
 
 
 
 
 
 
Available for sale assets
 
—

 
47

 
—

 
47

 
 
(2
)
 
(57
)
 
1

 
(58
)

1
There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2013.

The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:
 
 
Derivatives1
 
 
three months ended
March 31
(unaudited - millions of Canadian $, pre-tax)
 
2014

 
2013

 
 
 
 
 
Balance at beginning of period
 
1

 
(2
)
Total gains included in OCI
 
—

 
3

Balance at end of period
 
1

 
1


1
Energy revenues include unrealized gains or losses attributed to derivatives in the Level III category that were still held at March 31, 2014 of nil (2013 - nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at March 31, 2014. 

10. Contingencies and guarantees
 
TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business.  While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company’s consolidated financial position or results of operations.

GUARANTEES
TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust (BPC), have each severally guaranteed certain contingent financial obligations of Bruce B related to a lease agreement and contractor and supplier services. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement and certain other financial obligations. The Company’s exposure under certain of these guarantees is unlimited.
 
In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to delivery of natural gas, PPA payments and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.


TRANSCANADA [46
FIRST QUARTER REPORT 2014


 
The carrying value of these guarantees has been included in other long-term liabilities. Information regarding the Company’s guarantees is as follows:
 
 
 
 
 
at March 31, 2014
 
at December 31, 2013
(unaudited - millions of Canadian $)
 
 
Term
 
Potential
Exposure1

 
Carrying
Value

 
Potential
Exposure1

 
Carrying
Value

 
 
 
 
 
 
 
 
 
 
 
Bruce Power
 
ranging to 20192
 
708

 
8

 
740

 
8

Other jointly owned entities
 
ranging to 2040 
 
62

 
10

 
51

 
10

 
 
 
 
770

 
18

 
791

 
18


1
TransCanada’s share of the potential estimated current or contingent exposure.
2
Except for one guarantee with no termination date.

11. Subsequent events

CANCARB ASSET SALE
As previously announced, on January 20, 2014, TransCanada reached an agreement to sell Cancarb Limited and its related power generation facility. On April 15, 2014, the sale was completed for aggregate gross proceeds of $190 million, subject to post-closing adjustments. TransCanada expects to realize a gain on the sale of approximately $95 million, net of tax, in second quarter 2014. These assets are classified as assets held for sale and presented in other current assets and accounts payable and other in the condensed consolidated balance sheet as at March 31, 2014.

NATURAL GAS STORAGE
Effective April 30, 2014, TransCanada terminated a 38 Bcf long-term natural gas storage contract in Alberta with Niska Gas Storage. The contract contained provisions allowing for possible early termination. In consideration for this termination, TransCanada expects to record an after-tax charge of approximately $33 million in second quarter 2014. TransCanada has re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six year period and a reduced average volume.




TRP-03.31.2014-EX-31.1


EXHIBIT 31.1
Certifications
 
I, Russell K. Girling, certify that:

1.
I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.
The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.
The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.
 
Dated: May 2, 2014
/s/ Russell K. Girling
 
Russell K. Girling
 
President and Chief Executive Officer


TRP-03.31.2014-EX-31.2


EXHIBIT 31.2
Certifications
 
I, Donald R. Marchand, certify that:
 
1.
I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.
The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.
The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.
 
Dated: May 2, 2014
/s/ Donald R. Marchand
 
Donald R. Marchand
 
Executive Vice-President
and Chief Financial Officer


TRP-03.31.2014-EX32.1


EXHIBIT 32.1
 
TRANSCANADA CORPORATION

450 – 1st Street S.W.
Calgary, Alberta, Canada
T2P 5H1


CERTIFICATION OF CHIEF EXECUTIVE OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS


I, Russell K. Girling, the Chief Executive Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended March 31, 2014 with the Securities and Exchange Commission (the “Report”), that:

1.
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


 
/s/ Russell K. Girling
 
Russell K. Girling
 
Chief Executive Officer
 
May 2, 2014


TRP-03.31.2014-EX-32.2


EXHIBIT 32.2
 
TRANSCANADA CORPORATION

450 – 1st Street S.W.
Calgary, Alberta, Canada
T2P 5H1


CERTIFICATION OF CHIEF FINANCIAL OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS


I, Donald R. Marchand, the Chief Financial Officer of TransCanada Corporation (the “Company”), in compliance with 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended March 31, 2014 with the Securities and Exchange Commission (the “Report”), that:

1.
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


 
/s/ Donald R. Marchand
 
Donald R. Marchand
 
Chief Financial Officer
 
May 2, 2014


TRP-03.31.2014-EX-99.1 Part A

 
 
EXHIBIT 99.1
QuarterlyReport to Shareholders
 
 
 
 

TransCanada Reports 15 Per Cent Increase in First Quarter Comparable Earnings
Funds Generated from Operations Exceed $1.1 Billion

CALGARY, Alberta – May 2, 2014 – TransCanada Corporation (TSX, NYSE: TRP) (TransCanada or the Company) today announced comparable earnings for first quarter 2014 of $422 million or $0.60 per share compared to $370 million or $0.52 per share for the same period in 2013, a 15 per cent increase on a per share basis. Funds generated from operations for first quarter 2014 were $1.102 billion, a 20 per cent increase compared to $916 million for the same period in 2013. TransCanada’s Board of Directors also declared a quarterly dividend of $0.48 per common share for the quarter ending June 30, 2014, equivalent to $1.92 per common share on an annualized basis.

"The significant increase in earnings and cash flow reflects the strong performance of our existing assets as well as contributions from recently completed projects including the Keystone Gulf Coast extension,” said Russ Girling, TransCanada’s president and chief executive officer. “An unseasonably cold winter resulted in strong demand for our critical pipeline and power infrastructure assets and underscores their importance and value to the North American economy. As we move forward, we will remain focused on the safe and reliable operation of our assets and the careful execution of our future growth plans which are expected to generate significant shareholder value.”  
Today we are advancing $36 billion of commercially secured capital projects, all of which are backed by long-term contracts or cost of service business models. This unprecedented capital program will see a significant expansion of all three of our core businesses. Over the course of 2014, we expect to place approximately $3.6 billion of assets into service, including the recently completed Keystone Gulf Coast extension, the Tamazunchale Pipeline Extension, further expansions of the NGTL System and four additional Ontario Solar facilities. Over the remainder of the decade, subject to required approvals, our blue-chip portfolio of contracted energy infrastructure projects is expected to generate significant growth in earnings and cash flow.

Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
•
First quarter financial results
◦
Net income attributable to common shares of $412 million or $0.58 per share
◦
Comparable earnings of $422 million or $0.60 per share
◦
Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.4 billion
◦
Funds generated from operations of $1.1 billion
•
Declared a quarterly dividend of $0.48 per common share for the quarter ending June 30, 2014
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Placed the US$2.6 billion Keystone Gulf Coast extension into service on January 22, 2014
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Secured 2.0 billion cubic feet a day (Bcf/d) of long-term contracts on the ANR Pipeline
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Filed a Project Description with the National Energy Board (NEB) for the $12 billion Energy East Project
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Coastal GasLink and Prince Rupert Gas Transmission both submitted applications for an Environmental Assessment Certificate and applications with the British Columbia (B.C.) Oil and Gas Commission

Comparable earnings for first quarter 2014 were $422 million or $0.60 per share compared to $370 million or $0.52 per share for the same period in 2013. Higher earnings from the NGTL System, Keystone, Bruce Power, U.S. Power, and Natural Gas Storage all contributed to the increased results.

Net income attributable to common shares for first quarter 2014 was $412 million or $0.58 per share compared to $446 million or $0.63 per share in first quarter 2013. The first quarter 2013 results included $84 million of net income related to the 2012 impact of the NEB decision on the Canadian Mainline. This amount was excluded from comparable earnings.

Notable recent developments in Liquids Pipelines, Natural Gas Pipelines, Energy and Corporate include:

Liquids Pipelines:
 
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Keystone Pipeline System: We finished constructing the 780 kilometre (km) (485 mile) Gulf Coast extension of the Keystone Pipeline System, from Cushing, Oklahoma to the U.S. Gulf Coast. Crude oil transportation service on the


pipeline began January 22, 2014 and we expect an average capacity of 520,000 barrels per day during its first year of operation.
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Keystone XL: On January 31, 2014, the Department of State (DOS) released its Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL project. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is “unlikely to significantly impact the rate of extraction in the oil sands” and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more greenhouse gas emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period that was to last up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment. The 30 day public comment period has concluded. On April 18, 2014, the DOS announced the 90 day National Interest Determination period has been extended indefinitely. The DOS has said only that the permit process will conclude once factors that have a significant impact on determining national interest of the proposed project have been evaluated.

In February 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Heineman, has the authority to approve an alternative route through Nebraska for the Keystone XL project. We disagree with the decision of the Nebraska district court and are continuing to analyze the judgment and decide what next steps may be taken. Nebraska’s Attorney General has filed an appeal and the Nebraska Supreme Court is expected to hear the appeal in third quarter 2014.

As of March 31, 2014, we have invested US$2.3 billion in the Keystone XL project.

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Energy East Pipeline: On March 4, 2014, we filed the project description with the NEB. This is the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.

Subject to regulatory approvals, the pipeline is anticipated to commence deliveries to Québec in 2018, with service to New Brunswick to follow in late 2018. We continue to participate in Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. We intend to file the necessary regulatory applications in mid-2014 for approvals to construct and operate the pipeline project and terminal facilities.

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Heartland Pipeline and TC Terminals: In February 2014, the application for the terminal facility was approved by the Alberta Energy Regulator. The Heartland Pipeline and TC Terminals will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton, Alberta.

Natural Gas Pipelines:

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NGTL System: The NEB has approved approximately $400 million of expansion projects that are currently in various stages of development or construction at March 31, 2014. In addition, we have approximately $1.8 billion in other projects that have been applied for but are not yet approved by the NEB, mainly comprised of the $1.7 billion North Montney Project.

On February 5, 2014, we received a Hearing Order for the North Montney Project. The hearing will begin in August 2014. The project includes approximately 300 km (186 miles) of new pipeline on the NGTL System to receive and transport natural gas from the North Montney area of B.C.

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Canadian Mainline: On March 31, 2014, the NEB responded to the LDC Settlement application we filed on December 20, 2013. The NEB did not approve the application but provided direction that we can continue with the application as a contested tolls application, amend the application or terminate the processing of the application. We will be amending the application with additional information in second quarter 2014. On April 22, 2014, the NEB issued a notice advising that it will hold a public hearing on the amended application and setting the list of issues. A further letter from the NEB setting out the hearing process and schedule is expected in the next few weeks.

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ANR Pipeline: In March 2014, we announced that we secured approximately 2.0 Bcf/d of firm natural gas transportation commitments on the ANR Pipeline system's Southeast Main Line at maximum rates for an average term of 23 years. Approximately 1.25 Bcf/d will commence in 2014, including volume commitments from the ANR Lebanon Lateral Reversal Project, with the remaining volume commencing in 2015. These contracts will enable growing Utica and Marcellus shale gas supply to move to both northern delivery points and southbound to the U.S. Gulf Coast. Approximately US$100 million of capital investment will be required to bring this additional supply to market. We are also assessing further demand for services which could result in incremental opportunities to enhance and expand the ANR Pipeline system.



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Tamazunchale Pipeline Extension Project: Construction activity on the US$600 million extension continues. The project is currently expected to be in service at the end of July 2014.

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Coastal GasLink: We submitted an Environmental Assessment application to the B.C. Environmental Assessment Office (BCEAO) in January 2014 and a public comment period is currently underway. In addition, the B.C. Oil and Gas Commission application was filed on March 24, 2014, together with an addendum to the Environmental Assessment application to capture recent route refinements.

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Prince Rupert Gas Transmission: We completed two key milestones in April 2014. The Environmental Assessment application was submitted to the BCEAO on April 2, 2014 for a completeness review and the application to the B.C. Oil and Gas Commission was filed on April 4, 2014. 

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Alaska LNG Project: On April 20, 2014, the State of Alaska passed new legislation that will transition from the Alaska Gasline Inducement Act and enable a new commercial arrangement to be established with us, the three major Alaska North Slope producers, and the Alaska Gasline Development Corp. It was also agreed that an LNG export project, rather than a pipeline to Alberta, is currently the best opportunity to commercialize Alaska North Slope gas resources in current market conditions. It is anticipated that two years of pre-front end engineering will be completed before further decisions to commercialize the project will be made.

Energy:

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Ontario Solar: We expect the acquisition of four additional facilities to close in fourth quarter 2014, with the acquisition of the ninth and final facility now expected to close in mid-2015, subject to satisfactory completion of the related construction activities, regulatory approvals, and purchase agreement conditions for each facility. All power produced by the solar facilities is sold under 20-year power purchase arrangements with the Ontario Power Authority.

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Cancarb: In January 2014, we reached an agreement to sell Cancarb and its related power generation business for proceeds of $190 million, subject to closing adjustments. The sale closed on April 15, 2014 and we expect to realize an after-tax gain of approximately $95 million in our second quarter 2014 results.

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Natural Gas Storage: Effective April 30, 2014, we terminated a 38 billion cubic feet, long-term natural gas storage contract in Alberta with Niska Gas Storage. The contract contained provisions allowing for possible early termination. In consideration for this termination, we expect to record an after-tax charge of approximately $33 million in second quarter 2014. We have re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six year period and a reduced average volume.

Corporate:

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Our Board of Directors declared a quarterly dividend of $0.48 per share for the quarter ending June 30, 2014 on TransCanada’s outstanding common shares. The quarterly amount is equivalent to $1.92 per common share on an annualized basis.

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In January 2014, we completed a public offering of 18 million Series 9 Cumulative Redeemable First Preferred Shares at a price of $25 per share, resulting in gross proceeds of $450 million. The initial dividend rate is fixed to October 30, 2019 at $1.0625 per share per annum paid quarterly.

In February 2014, we issued US$1.25 billion of senior notes maturing on March 1, 2034, bearing interest at 4.625 per cent.

The net proceeds of these offerings will be used for general corporate purposes and to reduce short-term indebtedness, which was used to fund a portion of our capital program and for general corporate purposes.

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In March 2014, we redeemed all four million outstanding TransCanada PipeLines Limited (TCPL) 5.60 per cent Cumulative Redeemable First Preferred Shares Series Y at a price of $50 per share plus $0.2455 of accrued and unpaid dividends. The total face value of the outstanding Series Y Shares was $200 million and they carried an aggregate of $11 million in annualized dividends.

Teleconference – Audio and Slide Presentation:

We will hold a teleconference and webcast on Friday, May 2, 2014 to discuss our first quarter 2014 financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 1 p.m. (MT) / 3 p.m. (ET).



Analysts, members of the media and other interested parties are invited to participate by calling 800.565.0813 or 416.340.8527 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on May 9, 2014. Please call 800.408.3053 or 905.694.9451 and enter pass code 1890056.

The unaudited interim Consolidated Financial Statements and Management’s Discussion and Analysis (MD&A) are available on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com.

With more than 60 years’ experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,500 kilometres (42,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with more than 400 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 11,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com or check us out on Twitter @TransCanada or http://blog.transcanada.com.

Forward Looking Information
This news release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as “anticipate”, “expect”, “believe”, “may”, “will”, “should”, “estimate”, “intend” or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management’s assessment of TransCanada’s and its subsidiaries’ future plans and financial outlook. All forward-looking statements reflect TransCanada’s beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada’s Quarterly Report to Shareholders dated May 1, 2014 and 2013 Annual Report on our website at www.transcanada.com or filed under TransCanada’s profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov.

Non-GAAP Measures
This news release contains references to non-GAAP measures, including comparable earnings, EBITDA, funds generated from operations and comparable earnings per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada’s Quarterly Report to Shareholders dated May 1, 2014.

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TransCanada Media Enquiries:
Shawn Howard/Grady Semmens/Davis Sheremata
403.920.7859 or 800.608.7859

TransCanada Investor & Analyst Enquiries:    
David Moneta/Lee Evans
403.920.7911 or 800.361.6522