EX-13.1 2 trp-06302017xmda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS Exhibit
EXHIBIT 13.1

Quarterly report to shareholders
Second quarter 2017
Financial highlights
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $, except per share amounts)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Income
 
 
 
 
 
 
 
 
Revenues
 
3,217

 
2,751

 
6,608

 
5,254

Net income attributable to common shares
 
881

 
365

 
1,524

 
617

per common share - basic
 

$1.01

 

$0.52

 

$1.76

 

$0.88

 - diluted
 

$1.01

 

$0.52

 

$1.75

 

$0.88

Comparable EBITDA1
 
1,830

 
1,369

 
3,807

 
2,871

Comparable earnings1
 
659

 
366

 
1,357

 
860

per common share1
 

$0.76

 

$0.52

 

$1.56

 

$1.22

 
 
 
 
 
 
 
 
 
Cash flows
 
 

 
 

 
 

 
 

Net cash provided by operations
 
1,353

 
1,148

 
2,655

 
2,229

Comparable funds generated from operations1
 
1,408

 
1,056

 
2,916

 
2,305

Comparable distributable cash flow1
 
936

 
702

 
2,158

 
1,676

per common share1
 

$1.08

 

$1.00

 

$2.49

 

$2.38

Capital spending - capital expenditures
 
1,792

 
982

 
3,352

 
1,818

- projects in development
 
56

 
90

 
98

 
157

- contributions to equity investments
 
473

 
114

 
665

 
284

Acquisitions, net of cash acquired
 
—

 
4

 
—

 
999

Proceeds from sales of assets, net of transaction costs
 
4,147

 
—

 
4,147

 
6

 
 
 
 
 
 
 
 
 
Dividends declared
 
 

 
 
 
 

 
 
Per common share
 

$0.625

 

$0.565

 

$1.25

 

$1.13

Basic common shares outstanding (millions)
 
 

 
 

 
 

 
 
Average for the period
 
870

 
703

 
868

 
703

End of period
 
871

 
703

 
871

 
703

1 
Comparable EBITDA, comparable earnings, comparable earnings per common share, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share are all non-GAAP measures. See the non-GAAP measures section for more information.



TRANSCANADA [2
SECOND QUARTER 2017

Management’s discussion and analysis
July 27, 2017
This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and six months ended June 30, 2017, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2017 which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2016 audited consolidated financial statements and notes and the MD&A in our 2016 Annual Report. 
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management’s assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A include information about the following, among other things:
•
planned changes in our business
•
our financial and operational performance, including the performance of our subsidiaries
•
expectations or projections about strategies and goals for growth and expansion
•
expected cash flows and future financing options available to us
•
expected dividend growth
•
expected costs for planned projects, including projects under construction, permitting and in development
•
expected schedules for planned projects (including anticipated construction and completion dates)
•
expected regulatory processes and outcomes
•
expected impact of regulatory outcomes
•
expected outcomes with respect to legal proceedings, including arbitration and insurance claims
•
expected capital expenditures and contractual obligations
•
expected operating and financial results
•
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
•
nature and scope of 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


TRANSCANADA [3
SECOND QUARTER 2017

•
integrity and reliability of our assets
•
access to capital markets
•
anticipated construction costs, schedules and completion dates.
Risks and uncertainties
•
our ability to realize the anticipated benefits from the acquisition of Columbia
•
our ability to successfully implement our strategic initiatives
•
whether our strategic initiatives will yield the expected benefits
•
the operating performance of our pipeline and energy assets
•
amount of capacity sold and rates achieved in our pipeline businesses
•
the availability and price of energy commodities
•
the amount of capacity payments and revenues we receive from our energy business
•
regulatory decisions and outcomes
•
outcomes of legal proceedings, including arbitration and insurance claims
•
performance and credit risk of our counterparties
•
changes in market commodity prices
•
changes in the political environment
•
changes in environmental and other laws and regulations
•
competitive factors in the pipeline and energy sectors
•
construction and completion of capital projects
•
costs for labour, equipment and materials
•
access to capital markets
•
interest, tax and foreign exchange rates
•
weather
•
cyber security
•
technological developments
•
economic conditions in North America as well as globally.
You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2016 Annual Report.
As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.
FOR MORE INFORMATION
You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).


TRANSCANADA [4
SECOND QUARTER 2017

NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
•
comparable earnings
•
comparable earnings per common share
•
comparable EBITDA
•
comparable EBIT
•
funds generated from operations
•
comparable funds generated from operations
•
comparable distributable cash flow
•
comparable distributable cash flow per common share.
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be similar to measures presented by other entities.
Comparable measures
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:
•
certain fair value adjustments relating to risk management activities
•
income tax refunds and adjustments and changes to enacted tax rates
•
gains or losses on sales of assets
•
legal, contractual and bankruptcy settlements
•
impact of regulatory or arbitration decisions relating to prior year earnings
•
restructuring costs
•
impairment of goodwill, investments and other assets including certain ongoing maintenance and liquidation costs
•
acquisition costs.
We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.
The following table identifies our non-GAAP measures against their equivalent GAAP measures.
Comparable measure
Original measure
 
 
comparable earnings
net income attributable to common shares
comparable earnings per common share
net income per common share
comparable EBITDA
segmented earnings
comparable EBIT
segmented earnings
comparable funds generated from operations
net cash provided by operations
comparable distributable cash flow
net cash provided by operations


TRANSCANADA [5
SECOND QUARTER 2017

Comparable earnings and comparable earnings per share
Comparable earnings represent earnings or loss attributable to common shareholders on a consolidated basis adjusted for specific items. Comparable earnings is comprised of segmented earnings, interest expense, AFUDC, interest income and other, income taxes and non-controlling interests adjusted for the specific items. See the Consolidated results section for a reconciliation to net income attributable to common shares.
Comparable EBIT and comparable EBITDA
Comparable EBIT represents segmented earnings adjusted for the specific items described above. We use comparable EBIT as a measure of our earnings from ongoing operations as it is a useful measure of our performance and an effective tool for evaluating trends in each segment. Comparable EBITDA is calculated the same way as comparable EBIT but excludes the non-cash charges for depreciation and amortization. See the Reconciliation of non-GAAP measures section for a reconciliation to segmented earnings.
Funds generated from operations and comparable funds generated from operations
Funds generated from operations reflects net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. Comparable funds generated from operations is adjusted for the cash impact of specific items noted above. See the Financial condition section for a reconciliation to net cash provided by operations.
Comparable distributable cash flow and comparable distributable cash flow per share
We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. Comparable distributable cash flow is defined as comparable funds generated from operations less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability, and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, in certain of our rate-regulated businesses, maintenance capital expenditures are included in their respective rate bases, on which we earn a regulated return and recover depreciation through future tolls. See the Financial condition section for a reconciliation to net cash provided by operations.


TRANSCANADA [6
SECOND QUARTER 2017

Consolidated results - second quarter 2017
Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $, except per share amounts)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
305

 
342

 
587

 
614

U.S. Natural Gas Pipelines
 
401

 
188

 
962

 
455

Mexico Natural Gas Pipelines
 
120

 
41

 
238

 
86

Liquids Pipelines
 
251

 
198

 
478

 
410

Energy
 
645

 
371

 
843

 
245

Corporate
 
(40
)
 
(24
)
 
(73
)
 
(51
)
Total segmented earnings
 
1,682

 
1,116

 
3,035

 
1,759

Interest expense
 
(524
)
 
(514
)
 
(1,024
)
 
(934
)
Allowance for funds used during construction
 
121

 
111

 
222

 
212

Interest income and other
 
89

 
6

 
109

 
106

Income before income taxes
 
1,368

 
719

 
2,342

 
1,143

Income tax expense
 
(393
)
 
(274
)
 
(593
)
 
(344
)
Net income
 
975

 
445

 
1,749

 
799

Net income attributable to non-controlling interests
 
(55
)
 
(52
)
 
(145
)
 
(132
)
Net income attributable to controlling interests
 
920

 
393

 
1,604

 
667

Preferred share dividends
 
(39
)
 
(28
)
 
(80
)
 
(50
)
Net income attributable to common shares
 
881

 
365

 
1,524

 
617

Net income per common share - basic
 
$1.01
 
$0.52
 
$1.76
 

$0.88

- diluted
 
$1.01
 
$0.52
 
$1.75
 

$0.88

Net income attributable to common shares increased by $516 million and $907 million or $0.49 and $0.88 per share for the three and six months ended June 30, 2017 compared to the same periods in 2016. Net income per common share in 2017 included the dilutive effect of issuing 161 million common shares in 2016.
The 2017 results included:
•
a $255 million after-tax net gain related to the monetization of our U.S. Northeast power business, which included a $441 million after-tax gain on the sale of TC Hydro in second quarter, an incremental loss of $176 million after tax recorded in second quarter on the sale of the thermal and wind package and $10 million year-to-date of after-tax disposition costs
•
an after-tax charge of $15 million in second quarter and $39 million year-to-date for integration-related costs associated with the acquisition of Columbia
•
an after-tax charge of $4 million in second quarter and $11 million year-to-date related to the maintenance of Keystone XL assets which is being expensed pending further advancement of the project
•
a $7 million income tax recovery in first quarter related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our 2015 impairment charge, but the related income tax recoveries could not be recorded until realized.


TRANSCANADA [7
SECOND QUARTER 2017

The 2016 results included:
•
a $176 million after-tax impairment charge in first quarter on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs
•
a charge of $113 million in second quarter and $139 million year-to-date related to costs associated with the acquisition of Columbia. In second quarter, $109 million related to the dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $10 million ($36 million year-to-date) related to acquisition costs and $6 million related to interest earned on the subscription receipt funds held in escrow
•
an after-tax charge of $9 million in second quarter and $15 million year-to-date related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project
•
an after-tax charge of $10 million in second quarter for restructuring charges mainly related to expected future losses under lease commitments. These charges formed part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs
•
an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.
Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.
Comparable earnings increased by $293 million and $497 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 as discussed below in the reconciliation of net income to comparable earnings.
RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $, except per share amounts)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Net income attributable to common shares
 
881

 
365

 
1,524

 
617

Specific items (net of tax):
 
 
 
 
 
 
 
 
Net gain on sales of U.S. Northeast power assets
 
(265
)
 
—

 
(255
)
 
—

Integration and acquisition related costs – Columbia
 
15

 
113

 
39

 
139

Keystone XL asset costs
 
4

 
9

 
11

 
15

Keystone XL income tax recoveries
 
—

 
—

 
(7
)
 
—

Alberta PPA terminations
 
—

 
—

 
—

 
176

Restructuring costs
 
—

 
10

 
—

 
10

TC Offshore loss on sale
 
—

 
—

 
—

 
3

Risk management activities1
 
24

 
(131
)
 
45

 
(100
)
Comparable earnings
 
659

 
366

 
1,357

 
860

 
 
 
 
 
 
 
 
 
Net income per common share
 
$1.01
 
$0.52
 
$1.76
 
$0.88
Specific items (net of tax):
 
 
 
 
 
 
 
 
Net gain on sales of U.S. Northeast power assets
 
(0.30
)
 
—

 
(0.29
)
 
—

Integration and acquisition related costs – Columbia
 
0.02

 
0.16

 
0.04

 
0.20

Keystone XL asset costs
 
—

 
0.01

 
0.01

 
0.02

Keystone XL income tax recoveries
 
—

 
—

 
(0.01
)
 
—

Alberta PPA terminations
 
—

 
—

 
—

 
0.25

Restructuring costs
 
—

 
0.01

 
—

 
0.01

Risk management activities
 
0.03

 
(0.18
)
 
0.05

 
(0.14
)
Comparable earnings per common share
 
$0.76
 
$0.52
 
$1.56
 
$1.22


TRANSCANADA [8
SECOND QUARTER 2017

1 
 
Risk management activities
 
three months ended
June 30
 
six months ended
June 30
 
 
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
 
 
 
 
Canadian Power
 
3

 
20

 
4

 
7

 
 
U.S. Power
 
(94
)
 
204

 
(156
)
 
89

 
 
Liquids marketing
 
4

 
4

 
4

 
2

 
 
Natural Gas Storage
 
(4
)
 
—

 
1

 
5

 
 
Foreign exchange
 
41

 
(4
)
 
56

 
49

 
 
Income tax attributable to risk management activities
 
26

 
(93
)
 
46

 
(52
)
 
 
Total unrealized (losses)/gains from risk management activities
 
(24
)
 
131

 
(45
)
 
100

Comparable earnings increased by $293 million or $0.24 per share for the three months ended June 30, 2017 compared to the same period in 2016. This was primarily the net effect of:
•
higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016
•
higher earnings from Bruce Power mainly due to higher volumes resulting from fewer planned outage days
•
higher interest expense mainly as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt issuances
•
higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016
•
higher earnings from Liquids Pipelines mainly due to higher volumes.
Comparable earnings increased by $497 million or $0.34 per share for the six months ended June 30, 2017 compared to the same period in 2016. This was primarily the net effect of:
•
higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016
•
higher interest expense as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt issuances
•
higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016
•
higher earnings from Bruce Power mainly due to higher volumes resulting from fewer planned outage days partially offset by higher interest expense
•
higher earnings from Liquids Pipelines mainly due to higher volumes
•
higher earnings from Western Power following the termination of the Alberta PPAs in March 2016.
Comparable earnings per share in 2017 included the dilutive effect of issuing 161 million common shares in 2016.



TRANSCANADA [9
SECOND QUARTER 2017

Capital Program
We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow.
Our capital program consists of approximately $24 billion of near-term projects and approximately $43 billion of medium to longer-term projects. Amounts presented exclude maintenance capital expenditures, capitalized interest and AFUDC. All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
Near-term projects
at June 30, 2017
 
Expected in-service date
 
Estimated project cost

 
Carrying value

(unaudited - billions of $)
 
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
 
 
 
 
 
Canadian Mainline
 
2017-2019
 
0.5

 
0.2

NGTL System1
 
2017
 
2.3

 
1.2

 
 
2018
 
0.3

 
—

 
 
2019
 
2.2

 
0.3

 
 
2020
 
1.9

 
0.1

 
 
2021+
 
0.4

 
—

U.S. Natural Gas Pipelines
 
 
 
 
 
 
Columbia Gas
 
 
 
 
 
 
Leach XPress
 
2017
 
US 1.5

 
US 0.9

Modernization I
 
2017
 
US 0.2

 
US 0.1

WB XPress
 
2018
 
US 0.8

 
US 0.3

Mountaineer XPress
 
2018
 
US 2.0

 
US 0.2

Modernization II
 
2018-2020
 
US 1.1

 
—

Columbia Gulf
 
 
 
 
 
 
Rayne XPress
 
2017
 
US 0.4

 
US 0.3

Cameron Access
 
2018
 
US 0.3

 
US 0.2

Gulf XPress
 
2018
 
US 0.6

 
US 0.1

Midstream – Gibraltar
 
2017
 
US 0.3

 
US 0.2

Mexico Natural Gas Pipelines
 
 
 
 
 
 
Tula
 
2018
 
US 0.6

 
US 0.4

Villa de Reyes
 
2018
 
US 0.6

 
US 0.3

Sur de Texas2
 
2018
 
US 1.3

 
US 0.4

Liquids Pipelines
 
 
 
 
 
 
Grand Rapids2
 
2017
 
0.9

 
0.8

Northern Courier
 
2017
 
1.0

 
1.0

White Spruce
 
2018
 
0.2

 
—

Energy
 
 
 
 
 
 
Napanee
 
2018
 
1.1

 
0.8

Bruce Power – life extension3
 
up to 2020+
 
1.0

 
0.2

 
 
 
 
21.5

 
8.0

Foreign exchange impact on near-term projects4
 
 
 
2.9

 
1.0

Total near-term projects (billions of Cdn$)
 
 
 
24.4

 
9.0

1 
As of June 30, 2017, near-term NGTL System capital projects are being reported by expected in-service dates.
2 
Our proportionate share.
3 
Amounts reflect our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of major refurbishment outages which are expected to begin in 2020.
4 
Reflects U.S./Canada foreign exchange rate of $1.30 at June 30, 2017.


TRANSCANADA [10
SECOND QUARTER 2017

Medium to longer-term projects
The medium to longer-term projects have greater uncertainty with respect to timing and estimated project costs. The expected in-service dates of these projects are post-2020, and costs provided in the schedule below reflect the most recent costs for each project as filed with the various regulatory authorities or otherwise determined. These projects have all been commercially secured or, in the case of Keystone XL, commercial support is expected to be achieved. All these projects are subject to approvals that include sponsor FID and/or complex regulatory processes.
at June 30, 2017
 
Segment
 
Estimated project cost

 
Carrying value

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

 
0.1

Upland
 
Liquids Pipelines
 
US 0.6

 
—

Grand Rapids Phase 21
 
Liquids Pipelines
 
0.7

 
—

Bruce Power - life extension1
 
Energy
 
5.3

 
—

Keystone projects
 
 
 
 
 
 
Keystone XL2
 
Liquids Pipelines
 
US 8.0

 
US 0.3

Keystone Hardisty Terminal2
 
Liquids Pipelines
 
0.3

 
0.1

Energy East projects
 
 
 
 
 
 
Energy East3
 
Liquids Pipelines
 
15.7

 
0.8

Eastern Mainline
 
Canadian Natural Gas Pipelines
 
2.0

 
0.1

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

 
0.4

NGTL System - Merrick
 
Canadian Natural Gas Pipelines
 
1.9

 
—

 
 
 
 
40.2

 
1.8

Foreign exchange impact on medium to longer-term projects4
 
 
 
2.6

 
0.1

Total medium to longer-term projects (billions of Cdn$)
 
 
 
42.8

 
1.9

1 
Our proportionate share.
2 
Carrying value reflects amount remaining after impairment charge recorded in fourth quarter 2015.
3 
Excludes transfer of Canadian Mainline natural gas assets.
4 
Reflects U.S./Canada foreign exchange rate of $1.30 at June 30, 2017.
Outlook
Our overall comparable earnings outlook for 2017 is expected to be higher than what was previously included in the 2016 Annual Report as a result of stronger performance across our business segments, including from the U.S. Northeast power business in first half 2017, as detailed in the MD&A.
Consolidated capital spending
Our expected total capital expenditures, projects in development and contributions to equity investments for 2017 as outlined in the 2016 Annual Report, remain unchanged.



TRANSCANADA [11
SECOND QUARTER 2017

Canadian Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
NGTL System
 
236

 
241

 
466

 
467

Canadian Mainline
 
264

 
291

 
511

 
522

Other Canadian pipelines1
 
28

 
30

 
56

 
62

Business development
 
(1
)
 
(1
)
 
(2
)
 
(2
)
Comparable EBITDA
 
527

 
561

 
1,031

 
1,049

Depreciation and amortization
 
(222
)
 
(219
)
 
(444
)
 
(435
)
Comparable EBIT and segmented earnings
 
305

 
342

 
587

 
614

1 
Includes results from Foothills, Ventures LP and our share of equity income from our investment in TQM.
Canadian Natural Gas Pipelines segmented earnings decreased by $37 million and $27 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and are equivalent to comparable EBIT.
Net income and comparable EBITDA for our rate-regulated Canadian Natural Gas Pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.
NET INCOME - NGTL SYSTEM AND CANADIAN MAINLINE
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
NGTL System
 
87

 
79

 
169

 
152

Canadian Mainline
 
48

 
52

 
100

 
102

 
Net income for the NGTL System increased by $8 million and $17 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to a higher average investment base and higher OM&A incentive earnings in 2017. The NGTL System is operating under the two-year 2016-2017 Revenue Requirement Settlement which includes an ROE of 10.1 per cent on 40 per cent deemed equity and a mechanism for sharing variances above and below a fixed annual OM&A amount with flow-through treatment of all other costs.
Net income for the Canadian Mainline decreased by $4 million and $2 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to a lower average investment base and higher carrying charges on regulatory deferrals, partially offset by higher incentive earnings. The Canadian Mainline is operating under the NEB 2014 Decision which includes an approved ROE of 10.1 per cent on a 40 per cent deemed equity with a possible range of achieved outcomes between 8.7 per cent and 11.5 per cent. The decision also includes an incentive mechanism that has both upside and downside risk and a $20 million annual after-tax contribution from us.


TRANSCANADA [12
SECOND QUARTER 2017

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $3 million and by $9 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to facilities that were placed in service for the NGTL System and Canadian Mainline.
OPERATING STATISTICS - NGTL SYSTEM AND CANADIAN MAINLINE
six months ended June 30
NGTL System1
 
Canadian Mainline2
(unaudited)
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
Average investment base (millions of $)
8,043

 
7,357

 
4,131

 
4,398

Delivery volumes (Bcf):
 

 
 

 
 

 
 

Total
2,044

 
1,994

 
903

 
849

Average per day
11.3

 
11.0

 
5.0

 
4.7

 
1 
Field receipt volumes for the NGTL System for the six months ended June 30, 2017 were 2,070 Bcf (2016 – 2,075 Bcf). Average per day was 11.4 Bcf (2016 – 11.4 Bcf).
2 
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 six months ended June 30, 2017 were 474 Bcf (2016 – 530 Bcf). Average per day was 2.6 Bcf (2016 – 2.9 Bcf).


TRANSCANADA [13
SECOND QUARTER 2017

U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of US$, unless otherwise noted)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Columbia Gas1
 
136

 
—

 
321

 
—

ANR
 
93

 
70

 
215

 
157

TC PipeLines, LP2,3
 
26

 
27

 
58

 
58

Great Lakes4
 
13

 
12

 
40

 
37

Midstream1
 
20

 
—

 
43

 
—

Columbia Gulf1
 
21

 
—

 
39

 
—

Other U.S. pipelines1,2,3,5
 
26

 
10

 
55

 
24

Non-controlling interests6
 
75

 
75

 
183

 
170

Business development
 
—

 
—

 
(1
)
 
(1
)
Comparable EBITDA 
 
410

 
194

 
953

 
445

Depreciation and amortization
 
(112
)
 
(49
)
 
(224
)
 
(100
)
Comparable EBIT
 
298

 
145

 
729

 
345

Foreign exchange impact
 
103

 
43

 
243

 
114

Comparable EBIT (Cdn$)
 
401

 
188

 
972

 
459

Specific items:
 
 
 
 
 
 
 
 
Integration and acquisition related costs – Columbia
 
—

 
—

 
(10
)
 
—

TC Offshore loss on sale
 
—

 
—

 
—

 
(4
)
Segmented earnings (Cdn$)
 
401

 
188

 
962

 
455

1 
We completed the acquisition of Columbia on July 1, 2016 and the publicly held units of Columbia Pipeline Partners LP (CPPL) on February 17, 2017.
2 
Results from Northern Border and Iroquois reflect our share of equity income from these investments. We acquired additional interests in Iroquois of 0.65 per cent on May 1, 2016 and 4.87 per cent on March 31, 2016. TC PipeLines, LP acquired TransCanada's 49.34 per cent interest in Iroquois and its remaining 11.81 per cent interest in PNGTS on June 1, 2017.
3 
TC PipeLines, LP periodically conducts at-the-market equity issuances which decrease our ownership in TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of Great Lakes and PNGTS through our ownership interest in TC PipeLines, LP for the periods presented.
 
 
Effective ownership percentage as of
 
 
June 30, 2017
 
June 30, 2016
 
 
 
 
 
TC PipeLines, LP
 
26.3
 
27.4
Effective ownership through TC PipeLines, LP:
 
 
 
 
Great Lakes
 
12.2
 
12.7
PNGTS
 
16.2
 
13.7
4 
Represents our 53.6 per cent direct interest in Great Lakes. The remaining 46.4 per cent is held by TC PipeLines, LP.
5 
Includes our effective ownership in Millennium and Hardy Storage and our direct ownership in Iroquois and PNGTS up to June 1, 2017.
6 
Comparable EBITDA for the portions of TC PipeLines, LP, PNGTS and CPPL that we do not own. Effective February 17, 2017, we acquired the remaining publicly held units of CPPL.


TRANSCANADA [14
SECOND QUARTER 2017

U.S. Natural Gas Pipelines segmented earnings increased by $213 million and $507 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to the acquisition of Columbia. Segmented earnings for the six months ended June 30, 2017 included a first quarter $10 million pre-tax charge primarily due to integration-related costs associated with the Columbia acquisition. Segmented earnings for the six months ended June 30, 2016 included a $4 million pre-tax loss ($3 million after tax) as a result of a December 2015 agreement to sell TC Offshore which closed in early 2016. These amounts have been excluded from our calculation of comparable EBIT. As well, a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. operations.
Earnings from our U.S. Natural Gas Pipelines operations, which include Columbia effective July 1, 2016, are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services. Columbia and ANR results are also affected by the contracting and pricing of their storage capacity and commodity sales. Transmission and storage revenues are generally higher in winter months due to increased seasonal demand for our services.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$216 million and US$508 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and was the net effect of:
•
US$193 million and US$443 million of EBITDA for the three and six months ended June 30, 2017 as a result of the acquisition of Columbia on July 1, 2016
•
higher ANR transportation and storage revenue resulting from a FERC-approved rate settlement, effective August 1, 2016.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$63 million and US$124 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to the acquisition of Columbia and higher depreciation rates on ANR resulting from a FERC-approved rate settlement, effective August 1, 2016.
US$5 million of first quarter 2017 depreciation related to Columbia information system assets retired as part of the Columbia integration process has been excluded from comparable EBIT and included as part of integration and acquisition related costs to arrive at segmented earnings.


TRANSCANADA [15
SECOND QUARTER 2017

Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of US$, unless otherwise noted)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Topolobampo
 
40

 
—

 
80

 
(1
)
Tamazunchale
 
27

 
28

 
56

 
55

Guadalajara
 
17

 
15

 
34

 
32

Mazatlán
 
17

 
—

 
33

 
—

Sur de Texas1
 
7

 
—

 
11

 
—

Other
 
—

 
1

 
—

 
—

Business development
 
—

 
(2
)
 
—

 
(5
)
Comparable EBITDA
 
108

 
42

 
214

 
81

Depreciation and amortization
 
(19
)
 
(7
)
 
(36
)
 
(13
)
Comparable EBIT
 
89

 
35

 
178

 
68

Foreign exchange impact
 
31

 
6

 
60

 
18

Comparable EBIT and segmented earnings (Cdn$)
 
120

 
41

 
238

 
86

1 
Represents our 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline.
Mexico Natural Gas Pipelines segmented earnings increased by $79 million and $152 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and are equivalent to comparable EBIT. A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent segmented earnings from our Mexico operations.
Earnings from our Mexico operations are underpinned by long-term, stable, primarily U.S. dollar-denominated revenue contracts, and are affected by the cost of providing service.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$66 million and US$133 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and was the net effect of:
•
incremental earnings from Topolobampo. The Topolobampo project has experienced a delay in construction which, under the terms of our Transportation Service Agreement (TSA) with the CFE, constitutes a force majeure event with provisions allowing for the collection and recognition of revenue as per the original TSA service commencement date of July 2016
•
incremental earnings from Mazatlán. Construction is complete and the collection and recognition of revenue began per the terms of the TSA in December 2016
•
equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$12 million and US$23 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to the commencement of depreciation on Topolobampo and Mazatlán.


TRANSCANADA [16
SECOND QUARTER 2017

Liquids Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Keystone Pipeline System
 
329

 
274

 
635

 
576

Business development and other
 
3

 
2

 
9

 
(4
)
Comparable EBITDA
 
332

 
276

 
644

 
572

Depreciation and amortization
 
(80
)
 
(69
)
 
(157
)
 
(141
)
Comparable EBIT
 
252

 
207

 
487

 
431

Specific items:
 
 
 
 
 
 
 
 
Keystone XL asset costs
 
(5
)
 
(13
)
 
(13
)
 
(23
)
Risk management activities
 
4

 
4

 
4

 
2

Segmented earnings
 
251

 
198

 
478

 
410

 
 
 
 
 
 
 
 
 
Comparable EBIT denominated as follows:
 
 
 
 

 
 

 
 

Canadian dollars
 
57

 
56

 
112

 
109

U.S. dollars
 
146

 
116

 
281

 
243

Foreign exchange impact
 
49

 
35

 
94

 
79

 
 
252

 
207

 
487

 
431

Liquids Pipelines segmented earnings increased by $53 million and $68 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and included pre-tax charges related to Keystone XL costs for the maintenance of project assets which are being expensed pending further advancement of the project as well as unrealized gains from changes in the fair value of derivatives related to our liquids marketing business.
Keystone Pipeline System earnings are 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 Liquids Pipelines increased by $56 million and $72 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and was the net effect of:
•
higher volumes on Keystone pipeline
•
higher contribution from liquids marketing activities
•
increased business development activities, including advancement of Keystone XL
•
a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $11 million and $16 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.


TRANSCANADA [17
SECOND QUARTER 2017

Energy
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Canadian Power
 
 
 
 
 
 
 
 
Western Power1
 
23

 
18

 
53

 
22

Eastern Power
 
83

 
84

 
177

 
186

Bruce Power
 
132

 
20

 
223

 
134

Canadian Power - comparable EBITDA1,2
 
238

 
122

 
453

 
342

Depreciation and amortization
 
(36
)
 
(36
)
 
(73
)
 
(83
)
Canadian Power - comparable EBIT1,2
 
202

 
86

 
380

 
259

U.S. Power (US$)
 
 
 
 
 
 

 
 

U.S. Power - comparable EBITDA
 
32

 
82

 
86

 
157

Depreciation and amortization3
 
—

 
(33
)
 
—

 
(64
)
U.S. Power - comparable EBIT
 
32

 
49

 
86

 
93

Foreign exchange impact
 
9

 
11

 
27

 
28

U.S. Power - comparable EBIT (Cdn$)
 
41

 
60

 
113

 
121

 
 
 
 
 
 
 

 
 

Natural Gas Storage and other - comparable EBITDA
 
11

 
9

 
32

 
18

Depreciation and amortization
 
(3
)
 
(3
)
 
(6
)
 
(6
)
Natural Gas Storage and other - comparable EBIT
 
8

 
6

 
26

 
12

 
 
 
 
 
 
 
 
 
Business Development comparable EBITDA and EBIT
 
(3
)
 
(5
)
 
(6
)
 
(8
)
Energy - comparable EBIT1,2
 
248

 
147

 
513

 
384

Specific items:
 
 
 
 
 
 
 
 
Net gain on sales of U.S. Northeast power assets
 
492

 
—

 
481

 
—

Alberta PPA terminations
 
—

 
—

 
—

 
(240
)
Risk management activities
 
(95
)
 
224

 
(151
)
 
101

Segmented earnings1,2
 
645

 
371

 
843

 
245

1 
Included losses from the Alberta PPAs up to March 7, 2016 when the PPAs were terminated.
2 
Includes our share of equity income from our investments in Portlands Energy and Bruce Power.
3 
U.S. Northeast power assets no longer depreciated effective November 2016 when classified as held for sale.


TRANSCANADA [18
SECOND QUARTER 2017

Energy segmented earnings increased by $274 million and $598 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and included the following specific items:
•
in 2017, a net gain of $481 million before tax related to the monetization of our U.S. Northeast power business which included a $717 million gain on the sale of TC Hydro, a loss of $219 million on the sale of the thermal and wind package and $17 million of pre-tax disposition costs. See Recent developments section for more details
•
in 2016, a $240 million pre-tax charge, which included a $29 million impairment of our equity investment in ASTC Power Partnership, on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs
•
unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks as follows:
Risk management activities
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $, pre-tax)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Canadian Power
 
3

 
20

 
4

 
7

U.S. Power
 
(94
)
 
204

 
(156
)
 
89

Natural Gas Storage
 
(4
)
 
—

 
1

 
5

Total unrealized (losses)/gains from risk management activities
 
(95
)
 
224

 
(151
)
 
101

The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time, however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impacts of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.
The remainder of the Energy segmented earnings are equivalent to comparable EBIT and are discussed in the following sections.


TRANSCANADA [19
SECOND QUARTER 2017

CANADIAN POWER
Western and Eastern Power
The following are the components of comparable EBITDA and comparable EBIT.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Revenues1
 
 
 
 
 
 
 
 
Western Power
 
43

 
36

 
89

 
124

Eastern Power
 
93

 
108

 
198

 
203

Other2
 
5

 
—

 
20

 
29

 
 
141

 
144

 
307

 
356

Income from equity investments
 
7

 
7

 
15

 
7

Commodity purchases resold
 
(1
)
 
—

 
(2
)
 
(59
)
Plant operating costs and other
 
(41
)
 
(49
)
 
(90
)
 
(96
)
Comparable EBITDA3
 
106

 
102

 
230

 
208

Depreciation and amortization
 
(36
)
 
(36
)
 
(73
)
 
(83
)
Comparable EBIT3
 
70

 
66

 
157

 
125

 
 
 
 
 
 
 
 
 
Breakdown of comparable EBITDA
 
 
 
 
 
 
 
 
Western Power3
 
23

 
18

 
53

 
22

Eastern Power
 
83

 
84

 
177

 
186

Comparable EBITDA3
 
106

 
102

 
230

 
208

 
 
 
 
 
 
 
 
 
Plant availability4
 
 
 
 
 
 
 
 
Western Power5
 
95
%
 
83
%
 
97
%
 
91
%
Eastern Power
 
93
%
 
97
%
 
96
%
 
92
%
1 
Includes the realized gains and losses from financial derivatives used to manage Canadian Power’s assets which are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives have been excluded to arrive at comparable EBITDA.
2 
Includes revenues from the sale of unused natural gas transportation and sale of excess natural gas purchased for generation.
3 
Included Alberta PPAs up to March 7, 2016 when the PPAs were terminated.
4 
The percentage of time the plant was available to generate power, regardless of whether it was running.
5 
Plant availability was higher in the three and six months ended June 30, 2017 than the same periods in 2016 due to an unplanned outage at the Mackay River facility as a result of the Northern Alberta wildfires in 2016.
Western Power
Comparable EBITDA for Western Power increased by $5 million and $31 million for the three and six months ended June 30, 2017 compared to the same periods in 2016. Results from the Alberta PPAs are included up to March 7, 2016 when we terminated the PPAs for the Sundance A, Sundance B and Sheerness facilities.
Depreciation and amortization decreased by $10 million for the six months ended June 30, 2017 compared to the same period in 2016 following the termination of the Alberta PPAs.
Eastern Power
Comparable EBITDA for Eastern Power decreased by $9 million for the six months ended June 30, 2017 compared to the same period in 2016 mainly due to lower earnings on the sale of unused natural gas transportation.


TRANSCANADA [20
SECOND QUARTER 2017

Bruce Power
Bruce Power results reflect our proportionate share. The following is our proportionate share of the components of comparable EBITDA and comparable EBIT.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $, unless noted otherwise)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Equity income included in comparable EBITDA and EBIT comprised of:
 
 
 
 
 
 
 
 
Revenues
 
428

 
325

 
829

 
752

Operating expenses
 
(209
)
 
(225
)
 
(433
)
 
(462
)
Depreciation and other
 
(87
)
 
(80
)
 
(173
)
 
(156
)
Comparable EBITDA and EBIT1
 
132

 
20

 
223

 
134

 
 
 
 
 
 
 
 
 
Bruce Power – other information
 
 

 
 
 
 

 
 
Plant availability2
 
92
%
 
71
%
 
91
%
 
80
%
Planned outage days
 
41

 
209

 
97

 
285

Unplanned outage days
 
3

 
4

 
20

 
12

Sales volumes (GWh)1
 
6,309

 
4,700

 
12,292

 
10,534

Realized sales price per MWh3
 

$68

 

$69

 

$67

 

$67

1 
Represents our 48.4 per cent (2016 - 48.5 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation.
2 
The percentage of time the plant was available to generate power, regardless of whether it was running.
3 
Calculation based on actual and deemed generation. Realized sales prices per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues.
Comparable EBITDA from Bruce Power increased by $112 million and $89 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to higher volumes resulting from fewer planned outage days, partially offset by higher interest expense.
Planned outage work, which commenced on Unit 5 in February 2017, was completed in May 2017. Planned outages for Units 3 and 6 are scheduled to occur in second half of 2017. The overall average plant availability percentage in 2017 is expected to be approximately 90 per cent.
NATURAL GAS STORAGE AND OTHER
Comparable EBITDA for Natural Gas Storage and Other increased by $2 million and $14 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to increased third party storage revenues as a result of higher realized natural gas storage price spreads.


TRANSCANADA [21
SECOND QUARTER 2017

U.S. POWER
In second quarter 2017, we sold our U.S. Power generation assets and initiated the wind down of our TransCanada Power Marketing Ltd. (TCPM) operations. We expect to realize the value of the remaining TCPM marketing contracts and working capital over time. See Recent developments section for more details.
The following are the components of comparable EBITDA and comparable EBIT.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of US$)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
Power1
 
480

 
411

 
1,010

 
829

Capacity
 
41

 
77

 
83

 
139

 
 
521

 
488

 
1,093

 
968

Commodity purchases resold
 
(407
)
 
(289
)
 
(816
)
 
(594
)
Plant operating costs and other2
 
(82
)
 
(117
)
 
(191
)
 
(217
)
Comparable EBITDA3
 
32

 
82

 
86

 
157

Depreciation and amortization4
 
—

 
(33
)
 
—

 
(64
)
Comparable EBIT
 
32

 
49

 
86

 
93

1 
Includes the realized gains and losses from financial derivatives used to manage U.S. Power’s business which are presented on a net basis in Power revenues. The unrealized gains and losses from financial derivatives are excluded to arrive at comparable EBITDA.
2 
Includes the cost of fuel consumed in generation.
3 
TC Hydro earnings included up to April 19, 2017 sale date; Ravenswood, Ironwood, Ocean State Power and Kibby Wind earnings included up to June 2, 2017 sale date.
4 
U.S. Northeast power assets no longer depreciated effective November 2016 when classified as held for sale.
Comparable EBITDA for U.S. Power decreased by US$50 million and US$71 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to the sale of our generation assets in the second quarter 2017, partially offset by higher sales to customers in the PJM and New England wholesale markets.


TRANSCANADA [22
SECOND QUARTER 2017

Corporate
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
 
 
three months ended
June 30
 
six months ended
June 30
(unaudited - millions of $)
 
2017