EX-13.1 2 tcpl-09302017xmda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS Exhibit
EXHIBIT 13.1

Quarterly report to shareholders
Third quarter 2017
Financial highlights
 
 
three months ended
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Income
 
 
 
 
 
 
 
 
Revenues
 
3,242

 
3,632

 
9,850

 
8,886

Net income/(loss) attributable to controlling interests and to common shares
 
636

 
(118
)
 
2,217

 
655

Comparable EBITDA1
 
1,667

 
1,886

 
5,474

 
4,757

Comparable earnings1
 
638

 
639

 
2,052

 
1,552

 
 
 
 
 
 
 
 
 
Cash flows
 
 

 
 

 
 

 
 

Net cash provided by operations
 
1,168

 
1,305

 
3,789

 
3,590

Comparable funds generated from operations1
 
1,296

 
1,430

 
4,139

 
3,739

Comparable distributable cash flow1
 
788

 
1,011

 
2,936

 
2,680

Capital spending - capital expenditures
 
2,031

 
1,444

 
5,383

 
3,262

- projects in development
 
37

 
62

 
135

 
219

- contributions to equity investments
 
475

 
286

 
1,140

 
570

Acquisitions, net of cash acquired
 

 
12,609

 

 
13,608

Proceeds from sales of assets, net of transaction costs
 

 

 
4,147

 
6

 
 
 
 
 
 
 
 
 
Basic common shares outstanding (millions)
 
 

 
 

 
 

 
 
Average for the period
 
867

 
823

 
864

 
790

End of period
 
868

 
823

 
868

 
823

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




TRANSCANADA PIPELINES LIMITED [2
THIRD QUARTER 2017

Management’s discussion and analysis
November 8, 2017
This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada PipeLines Limited (TCPL). It discusses our business, operations, financial position, risks and other factors for the three and nine months ended September 30, 2017, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 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. These statements generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A include information about the following, among other things:
planned changes in our business including the divestiture of assets
our financial and operational performance, including the performance of our subsidiaries
expectations or projections about strategies and goals for growth and expansion
expected cash flows and future financing options available to us
expected dividend growth
expected costs for planned projects, including projects under construction, permitting and in development
expected schedules for planned projects (including anticipated construction and completion dates)
expected regulatory processes and outcomes
expected impact of regulatory outcomes
expected outcomes with respect to legal proceedings, including arbitration and insurance claims
expected capital expenditures and contractual obligations
expected operating and financial results
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 is 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



TRANSCANADA PIPELINES LIMITED [3
THIRD QUARTER 2017

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.
Risks and uncertainties
our ability to successfully implement our strategic priorities and whether they 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 regulatory environment
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 TCPL in our Annual Information Form and other disclosure documents, which are available on SEDAR (www.sedar.com).



TRANSCANADA PIPELINES LIMITED [4
THIRD QUARTER 2017

NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
comparable earnings
comparable EBITDA
comparable EBIT
funds generated from operations
comparable funds generated from operations
comparable distributable cash flow.
These measures do not have any standardized meaning as prescribed by 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 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 and integration 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 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 PIPELINES LIMITED [5
THIRD QUARTER 2017

Comparable earnings
Comparable earnings represent earnings or loss attributable to controlling interests and 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 controlling interests and 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
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 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 PIPELINES LIMITED [6
THIRD QUARTER 2017

Consolidated results - third 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
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
316

 
329

 
903

 
943

U.S. Natural Gas Pipelines
 
337

 
332

 
1,299

 
787

Mexico Natural Gas Pipelines
 
95

 
98

 
333

 
184

Liquids Pipelines
 
203

 
183

 
681

 
593

Energy
 
237

 
(828
)
 
1,080

 
(583
)
Corporate
 
(29
)
 
(36
)
 
(102
)
 
(87
)
Total segmented earnings
 
1,159

 
78

 
4,194

 
1,837

Interest expense
 
(522
)
 
(538
)
 
(1,578
)
 
(1,369
)
Allowance for funds used during construction
 
145

 
110

 
367

 
322

Interest income and other
 
83

 
18

 
192

 
128

Income/(loss) before income taxes
 
865

 
(332
)
 
3,175

 
918

Income tax (expense)/recovery
 
(185
)
 
266

 
(769
)
 
(79
)
Net income/(loss)
 
680

 
(66
)
 
2,406

 
839

Net income attributable to non-controlling interests
 
(44
)
 
(52
)
 
(189
)
 
(184
)
Net income/(loss) attributable to controlling interests and to common shares
 
636

 
(118
)
 
2,217

 
655

Net income attributable to controlling interests and to common shares increased by $754 million and $1,562 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016.
The 2017 results included:
a $243 million after-tax net gain related to the monetization of our U.S. Northeast power business, which included a $440 million after-tax gain on the sale of TC Hydro, an incremental loss of $183 million after tax recorded on the sale of the thermal and wind package and $14 million year-to-date of after-tax disposition costs and income tax adjustments
an after-tax charge of $30 million in third quarter and $69 million year-to-date for integration-related costs associated with the acquisition of Columbia
an after-tax charge of $8 million in third quarter and $19 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 PIPELINES LIMITED [7
THIRD QUARTER 2017

The 2016 results included:
a $656 million after-tax impairment on Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value
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
costs associated with the acquisition of Columbia including an after-tax charge of $67 million in third quarter, primarily relating to retention, severance and integration expenses, and $103 million year-to-date which included $36 million related to acquisition costs
$28 million of income tax recoveries in third quarter related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected loss on these assets was included in our fourth quarter 2015 impairment charge, but the related income tax recoveries could not be recorded until realized
an after-tax charge of $9 million in third quarter and $24 million year-to-date related to Keystone XL costs for the maintenance and liquidation of project assets which are expensed pending further advancement of the project
an after-tax charge of $10 million year-to-date 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
$3 million of after-tax costs related to the monetization of our U.S. Northeast Power business
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 decreased by $1 million and increased by $500 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 as discussed below in the reconciliation of net income to comparable earnings.



TRANSCANADA PIPELINES LIMITED [8
THIRD QUARTER 2017

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
 
 
three months ended
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Net income/(loss) attributable to controlling interests and to common shares
 
636

 
(118
)
 
2,217

 
655

Specific items (net of tax):
 
 
 
 
 
 
 
 
Net loss/(gain) on sales of U.S. Northeast power assets
 
12

 
3

 
(243
)
 
3

Integration and acquisition related costs – Columbia
 
30

 
67

 
69

 
103

Keystone XL asset costs
 
8

 
9

 
19

 
24

Keystone XL income tax recoveries
 

 
(28
)
 
(7
)
 
(28
)
Ravenswood goodwill impairment
 

 
656

 

 
656

Alberta PPA terminations
 

 

 

 
176

Restructuring costs
 

 

 

 
10

TC Offshore loss on sale
 

 

 

 
3

Risk management activities1
 
(48
)
 
50

 
(3
)
 
(50
)
Comparable earnings
 
638

 
639

 
2,052

 
1,552

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

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
 
 
 
 
Canadian Power
 
1

 
(4
)
 
5

 
3

 
 
U.S. Power
 
59

 
(73
)
 
(97
)
 
16

 
 
Liquids marketing
 
(19
)
 
(8
)
 
(15
)
 
(6
)
 
 
Natural Gas Storage
 
4

 
4

 
5

 
9

 
 
Interest rate
 
(1
)
 

 
(1
)
 

 
 
Foreign exchange
 
33

 

 
89

 
49

 
 
Income tax attributable to risk management activities
 
(29
)
 
31

 
17

 
(21
)
 
 
Total unrealized gains/(losses) from risk management activities
 
48

 
(50
)
 
3

 
50




TRANSCANADA PIPELINES LIMITED [9
THIRD QUARTER 2017

Comparable earnings decreased by $1 million for the three months ended September 30, 2017 compared to the same period in 2016. This decrease was primarily the net effect of:
lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017
lower contribution from U.S. Natural Gas Pipelines primarily due to the timing of funding contributions to the Columbia Gas defined benefit pension plan, partially offset by higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016
higher AFUDC on our rate-regulated U.S. natural gas pipelines
lower interest expense mainly due to the repayment of the remaining bridge facilities that partially funded the acquisition of Columbia
higher interest income and other primarily due to realized gains in 2017 compared to realized losses in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and income recognized on the termination of the PRGT project
higher contribution from Liquids Pipelines primarily due to higher volumes on Keystone and the commencement of operations on Grand Rapids
higher earnings from Bruce Power mainly due to improved results from contracting activities
higher contribution from Mexico Natural Gas Pipelines primarily due to earnings from Mazatlán beginning in December 2016, partially offset by the impairment of our equity investment in TransGas.
Comparable earnings increased by $500 million for the nine months ended September 30, 2017 compared to the same period in 2016. This increase was primarily the net effect of:
higher contribution from U.S. Natural Gas Pipelines due to incremental earnings resulting from the Columbia acquisition on July 1, 2016, higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016, partially offset by the timing of funding contributions to the Columbia Gas defined benefit pension plan
increased earnings from Bruce Power mainly due to higher volumes resulting from fewer planned outage days
higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016, partially offset by the impairment of our equity investment in TransGas
higher earnings from Liquids Pipelines primarily due to higher volumes on Keystone and the commencement of operations on Grand Rapids
higher AFUDC on our rate-regulated U.S. natural gas pipelines, as well as the NGTL System, partially offset by the commercial in-service of Topolobampo and completion of Mazatlán construction
higher interest income and other due to income related to Coastal GasLink project costs and the termination of the PRGT project
higher earnings from Western Power following the termination of the Alberta PPAs in March 2016
lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017
higher interest expense as a result of debt assumed in the acquisition of Columbia on July 1, 2016, and long-term debt and junior subordinated note issuances.



TRANSCANADA PIPELINES LIMITED [10
THIRD 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 $24 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 September 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

 
1.5

 
 
2018
 
0.3

 
0.1

 
 
2019
 
2.2

 
0.3

 
 
2020
 
1.9

 
0.1

 
 
2021+
 
0.4

 

U.S. Natural Gas Pipelines
 
 
 
 
 
 
Columbia Gas
 
 
 
 
 
 
Leach XPress
 
2018
 
US 1.6

 
US 1.3

Modernization I
 
2017
 
US 0.2

 
US 0.2

WB XPress
 
2018
 
US 0.8

 
US 0.3

Mountaineer XPress
 
2018
 
US 2.6

 
US 0.4

Modernization II
 
2018-2020
 
US 1.1

 
US 0.1

Columbia Gulf
 
 
 
 
 
 
Rayne XPress
 
2017
 
US 0.4

 
US 0.4

Cameron Access
 
2018
 
US 0.3

 
US 0.2

Gulf XPress
 
2018
 
US 0.6

 
US 0.2

Midstream – Gibraltar
 
2017
 
US 0.3

 
US 0.2

Mexico Natural Gas Pipelines
 
 
 
 
 
 
Tula
 
2018
 
US 0.6

 
US 0.5

Villa de Reyes
 
2018
 
US 0.6

 
US 0.4

Sur de Texas2
 
2018
 
US 1.3

 
US 0.7

Liquids Pipelines
 
 
 
 
 
 
Northern Courier
 
2017
 
1.0

 
1.0

White Spruce
 
2018
 
0.2

 

Energy
 
 
 
 
 
 
Napanee
 
2018
 
1.1

 
0.9

Bruce Power – life extension3
 
up to 2020+
 
1.0

 
0.2

 
 
 
 
21.3

 
9.2

Foreign exchange impact on near-term projects4
 
 
 
2.6

 
1.2

Total near-term projects (billions of Cdn$)
 
 
 
23.9

 
10.4

1 
Beginning in second quarter 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 1.25 at September 30, 2017.



TRANSCANADA PIPELINES LIMITED [11
THIRD 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 FID and/or complex regulatory processes.
at September 30, 2017
 
Segment
 
Estimated project cost

 
Carrying value

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

 
0.1

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

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

 

 
 
 
 
21.9

 
0.9

Foreign exchange impact on medium to longer-term projects3
 
 
 
2.0

 
0.1

Total medium to longer-term projects (billions of Cdn$)
 
 
 
23.9

 
1.0

1 
Our proportionate share.
2 
Carrying value reflects amount remaining after impairment charge recorded in fourth quarter 2015.
3 
Reflects U.S./Canada foreign exchange rate of 1.25 at September 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 as reported in our 2017 year-to-date results in this 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 remains unchanged.




TRANSCANADA PIPELINES LIMITED [12
THIRD 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
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
NGTL System
 
256

 
246

 
722

 
713

Canadian Mainline
 
263

 
278

 
774

 
800

Other Canadian pipelines1
 
25

 
27

 
81

 
89

Business development
 

 
(2
)
 
(2
)
 
(4
)
Comparable EBITDA
 
544

 
549

 
1,575

 
1,598

Depreciation and amortization
 
(228
)
 
(220
)
 
(672
)
 
(655
)
Comparable EBIT and segmented earnings
 
316

 
329

 
903

 
943

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 $13 million and $40 million for the three and nine months ended September 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
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
NGTL System
 
92

 
81

 
261

 
233

Canadian Mainline
 
49

 
52

 
149

 
154

 
Net income for the NGTL System increased by $11 million and $28 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 mainly due to a higher average investment base and higher OM&A incentive earnings, partially offset by higher carrying charges on regulatory deferrals 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 $3 million for the three months ended September 30, 2017 compared to the same period in 2016 primarily due to a lower average investment base and lower incentive earnings. Net income decreased by $5 million for the nine months ended September 30, 2017 compared to the same period 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 TCPL.



TRANSCANADA PIPELINES LIMITED [13
THIRD QUARTER 2017

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $8 million and $17 million for the three and nine months ended September 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
nine months ended September 30
NGTL System1
 
Canadian Mainline2
(unaudited)
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
Average investment base (millions of $)
8,210

 
7,401

 
4,165

 
4,423

Delivery volumes (Bcf):
 

 
 

 
 

 
 

Total
3,015

 
2,978

 
1,244

 
1,217

Average per day
11.0

 
10.9

 
4.6

 
4.4

 
1 
Field receipt volumes for the NGTL System for the nine months ended September 30, 2017 were 3,111 Bcf (20163,080 Bcf). Average per day was 11.4 Bcf (201611.2 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 nine months ended September 30, 2017 were 716 Bcf (2016802 Bcf). Average per day was 2.6 Bcf (20162.9 Bcf).



TRANSCANADA PIPELINES LIMITED [14
THIRD 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
September 30
 
nine months ended
September 30
(unaudited - millions of US$, unless otherwise noted)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Columbia Gas1
 
125

 
123

 
446

 
123

ANR
 
86

 
76

 
301

 
233

TC PipeLines, LP2,3
 
25

 
32

 
83

 
90

Great Lakes4
 
9

 
11

 
49

 
48

Midstream1
 
27

 
26

 
70

 
26

Columbia Gulf1
 
16

 
11

 
55

 
11

Other U.S. pipelines1,2,3,5
 
23

 
22

 
78

 
46

Non-controlling interests6
 
74

 
94

 
257

 
264

Business development
 

 
(1
)
 
(1
)
 
(2
)
Comparable EBITDA 
 
385

 
394

 
1,338

 
839

Depreciation and amortization
 
(116
)
 
(104
)
 
(340
)
 
(204
)
Comparable EBIT
 
269

 
290

 
998

 
635

Foreign exchange impact
 
68

 
94

 
311

 
208

Comparable EBIT (Cdn$)
 
337

 
384

 
1,309

 
843

Specific items:
 
 
 
 
 
 
 
 
Integration and acquisition related costs – Columbia
 

 
(52
)
 
(10
)
 
(52
)
TC Offshore loss on sale
 

 

 

 
(4
)
Segmented earnings (Cdn$)
 
337

 
332

 
1,299

 
787

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 TCPL'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
 
 
September 30, 2017
 
September 30, 2016
 
 
 
 
 
TC PipeLines, LP
 
26.0
 
27.1
Effective ownership through TC PipeLines, LP:
 
 
 
 
Great Lakes
 
12.1
 
12.6
PNGTS
 
16.1
 
13.5
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 PIPELINES LIMITED [15
THIRD QUARTER 2017

U.S. Natural Gas Pipelines segmented earnings increased by $5 million and $512 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 primarily due to the acquisition of Columbia.
Segmented earnings for the nine months ended September 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 nine months ended September 30, 2016 included a $52 million pre-tax charge primarily due to integration and acquisition-related costs associated with the Columbia acquisition and a $4 million pre-tax loss 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 weaker U.S. dollar had a negative 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 decreased by US$9 million for the three months ended September 30, 2017 compared to the same period in 2016. This was primarily the net effect of:
the timing of funding contributions to the Columbia Gas defined benefit pension plan. Under the current rate settlement for Columbia Gas, pension costs are reflected in expense as funding occurs and the full 2017 pension funding for this plan was recorded in third quarter 2017
increased revenue from Columbia Gas growth projects
higher ANR transportation and storage revenue resulting from a FERC-approved rate settlement effective August 1, 2016.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$499 million for the nine months ended September 30, 2017 compared to the same period in 2016.  This was primarily the net effect of:
the earnings contribution resulting from the Columbia acquisition for nine months in 2017 compared to only three months in 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$12 million and US$136 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 mainly due to the acquisition of Columbia and higher depreciation rates on ANR following the 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 PIPELINES LIMITED [16
THIRD 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
September 30
 
nine months ended
September 30
(unaudited - millions of US$, unless otherwise noted)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Topolobampo
 
39

 
41

 
119

 
40

Tamazunchale
 
29

 
24

 
85

 
79

Guadalajara
 
17

 
17

 
51

 
49

Mazatlán
 
16

 

 
49

 

Sur de Texas1
 
3

 

 
14

 

Other2
 
(10
)
 

 
(10
)
 

Business development
 

 
1

 

 
(4
)
Comparable EBITDA
 
94

 
83

 
308

 
164

Depreciation and amortization
 
(18
)
 
(10
)
 
(54
)
 
(23
)
Comparable EBIT
 
76

 
73

 
254

 
141

Foreign exchange impact
 
19

 
25

 
79

 
43

Comparable EBIT and segmented earnings (Cdn$)
 
95

 
98

 
333

 
184

1 
Represents our 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline.
2 
Reflects results from our 46.5 per cent equity investment in TransGas. On August 25, 2017, TransGas transferred all of its pipeline assets to Transportadora de Gas Internacional S.A..
Mexico Natural Gas Pipelines segmented earnings decreased by $3 million and increased $149 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 and are equivalent to comparable EBIT. Aside from commercial factors outlined below, a weaker U.S. dollar had a negative 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$11 million and US$144 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 and was the net effect of:
incremental earnings from Topolobampo on a year-to-date basis. 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 as 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, net of interest expense on an inter-affiliate loan from TCPL
the impairment of our equity investment in TransGas. See Recent developments section for further detail.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$8 million and US$31 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 primarily due to the commencement of depreciation on Topolobampo and Mazatlán.



TRANSCANADA PIPELINES LIMITED [17
THIRD 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
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Keystone Pipeline System
 
302

 
280

 
937

 
856

Business development and other
 
1

 
(2
)
 
10

 
(6
)
Comparable EBITDA
 
303

 
278

 
947

 
850

Depreciation and amortization
 
(71
)
 
(73
)
 
(228
)
 
(214
)
Comparable EBIT
 
232

 
205

 
719

 
636

Specific items:
 
 
 
 
 
 
 
 
Keystone XL asset costs
 
(10
)
 
(14
)
 
(23
)
 
(37
)
Risk management activities
 
(19
)
 
(8
)
 
(15
)
 
(6
)
Segmented earnings
 
203

 
183

 
681

 
593

 
 
 
 
 
 
 
 
 
Comparable EBIT denominated as follows:
 
 
 
 

 
 

 
 

Canadian dollars
 
63

 
51

 
175

 
160

U.S. dollars
 
135

 
117

 
416

 
360

Foreign exchange impact
 
34

 
37

 
128

 
116

 
 
232

 
205

 
719

 
636

Liquids Pipelines segmented earnings increased by $20 million and $88 million for the three and nine months ended September 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 losses 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 $25 million and $97 million for the three and nine months ended September 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
contribution from Grand Rapids pipeline, which was placed in service in late-August 2017
increased business development activities, including advancement of Keystone XL
a weaker U.S. dollar which had a negative impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $14 million for the nine months ended September 30, 2017 compared to the same period in 2016 as a result of the timing of new facilities being placed in service, partially offset by the effect of a weaker U.S. dollar.



TRANSCANADA PIPELINES LIMITED [18
THIRD 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
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Canadian Power
 
 
 
 
 
 
 
 
Western Power1
 
24

 
26

 
77

 
48

Eastern Power
 
75

 
81

 
252

 
267

Bruce Power
 
91

 
76

 
314

 
210

Canadian Power - comparable EBITDA1,2
 
190

 
183

 
643

 
525

Depreciation and amortization
 
(35
)
 
(36
)
 
(108
)
 
(119
)
Canadian Power - comparable EBIT1,2
 
155

 
147

 
535

 
406

U.S. Power (US$)
 
 
 
 
 
 

 
 

U.S. Power - comparable EBITDA3
 
22

 
164

 
108

 
321

Depreciation and amortization4
 

 
(34
)
 

 
(98
)
U.S. Power - comparable EBIT
 
22

 
130

 
108

 
223

Foreign exchange impact
 
7

 
44

 
34

 
72

U.S. Power - comparable EBIT (Cdn$)
 
29

 
174

 
142

 
295

 
 
 
 
 
 
 

 
 

Natural Gas Storage and other - comparable EBITDA
 
8

 
20

 
40

 
38

Depreciation and amortization
 
(4
)
 
(3
)
 
(10
)
 
(9
)
Natural Gas Storage and other - comparable EBIT
 
4

 
17

 
30

 
29

 
 
 
 
 
 
 
 
 
Business Development comparable EBITDA and EBIT
 
(3
)
 
(3
)
 
(9
)
 
(11
)
Energy - comparable EBIT1,2,3
 
185

 
335

 
698

 
719

Specific items:
 
 
 
 
 
 
 
 
Net (loss)/gain on sales of U.S. Northeast power assets
 
(12
)
 
(5
)
 
469

 
(5
)
Ravenswood goodwill impairment
 

 
(1,085
)
 

 
(1,085
)
Alberta PPA terminations
 

 

 

 
(240
)
Risk management activities
 
64

 
(73
)
 
(87
)
 
28

Segmented earnings/(losses)1,2,3
 
237

 
(828
)
 
1,080

 
(583
)
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 
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 
Depreciation of U.S. Northeast power assets ceased effective November 2016 when classified as held for sale.



TRANSCANADA PIPELINES LIMITED [19
THIRD QUARTER 2017

Energy segmented earnings increased by $1,065 million and $1,663 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 and included the following specific items:
in 2017, a net gain of $469 million before tax related to the monetization of our U.S. Northeast power business which included a $715 million gain on the sale of TC Hydro, a loss of $226 million on the sale of the thermal and wind package and $20 million (2016 - $5 million) of pre-tax disposition costs. See Recent developments section for more details
in 2016, a $1,085 million pre-tax impairment charge on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast Power business, it was determined that the fair value of Ravenswood no longer exceeded its carrying value
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
September 30
 
nine months ended
September 30
(unaudited - millions of $, pre-tax)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Canadian Power
 
1

 
(4
)
 
5

 
3

U.S. Power
 
59

 
(73
)
 
(97
)
 
16

Natural Gas Storage
 
4

 
4

 
5

 
9

Total unrealized gains/(losses) from risk management activities
 
64

 
(73
)
 
(87
)
 
28

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 PIPELINES LIMITED [20
THIRD QUARTER 2017

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

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Revenues1
 
 
 
 
 
 
 
 
Western Power
 
39

 
43

 
128

 
167

Eastern Power
 
103

 
112

 
301

 
315

Other2
 
4

 
2

 
24

 
31

 
 
146

 
157

 
453

 
513

Income from equity investments
 
8

 
9

 
23

 
16

Commodity purchases resold
 

 
(1
)
 
(2
)
 
(60
)
Plant operating costs and other
 
(55
)
 
(58
)
 
(145
)
 
(154
)
Comparable EBITDA3
 
99

 
107

 
329

 
315

Depreciation and amortization
 
(35
)
 
(36
)
 
(108
)
 
(119
)
Comparable EBIT3
 
64

 
71

 
221

 
196

 
 
 
 
 
 
 
 
 
Breakdown of comparable EBITDA
 
 
 
 
 
 
 
 
Western Power3
 
24

 
26

 
77

 
48

Eastern Power
 
75

 
81

 
252

 
267

Comparable EBITDA3
 
99

 
107

 
329

 
315

 
 
 
 
 
 
 
 
 
Plant availability4
 
 
 
 
 
 
 
 
Western Power
 
94
%
 
94
%
 
96
%
 
92
%
Eastern Power
 
97
%
 
96
%
 
96
%
 
93
%
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.
Western Power
Comparable EBITDA for Western Power increased by $29 million for the nine months ended September 30, 2017 compared to the same period 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.
Eastern Power
Comparable EBITDA for Eastern Power decreased by $6 million and $15 million for the three and nine months ended September 30, 2017 compared to the same periods in 2016 mainly due to lower earnings from our renewable assets and from the Ontario gas-fired plants due to reduced ancillary revenue opportunities. Lower earnings from the sale of unused natural gas transportation also contributed to the decreased earnings for the nine months ended September 30, 2017 compared to the same period in 2016.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by $11 million for the nine months ended September 30, 2017 compared to the same period in 2016 following the termination of the Alberta PPAs.



TRANSCANADA PIPELINES LIMITED [21
THIRD 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
September 30
 
nine months ended
September 30
(unaudited - millions of $, unless noted otherwise)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Equity income included in comparable EBITDA and EBIT comprised of:
 
 
 
 
 
 
 
 
Revenues
 
383

 
369

 
1,212

 
1,109

Operating expenses
 
(205
)
 
(208
)
 
(638
)
 
(658
)
Depreciation and other
 
(87
)
 
(85
)
 
(260
)
 
(241
)
Comparable EBITDA and EBIT1
 
91

 
76

 
314

 
210

 
 
 
 
 
 
 
 
 
Bruce Power  other information
 
 

 
 
 
 

 
 
Plant availability2
 
86
%
 
88
%
 
89
%
 
82
%
Planned outage days
 
81

 
50

 
178

 
335

Unplanned outage days
 
19

 
37

 
39

 
49

Sales volumes (GWh)1
 
5,801

 
5,886

 
18,093

 
16,420

Realized sales price per MWh3
 

$67

 

$67

 

$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 $15 million for the three months ended September 30, 2017 compared to the same period in 2016 due to improved results from contracting activities partially offset by lower volumes resulting from increased planned outage days.
Comparable EBITDA from Bruce Power increased by $104 million for the nine months ended September 30, 2017 compared to the same period in 2016 due to higher volumes resulting from fewer planned outage days and higher gains from contracting activities, partially offset by higher interest expense.
Planned outage work, which commenced on Unit 3 in August 2017, was completed in September 2017. Planned maintenance on Unit 6 began in September 2017 and is scheduled to be completed in fourth quarter 2017. The overall average plant availability percentage in 2017 is expected to be approximately 90 per cent.
U.S. POWER
In second quarter 2017, we completed the sale of our U.S. Power generation assets and initiated the wind down of our U.S. power marketing operations. See Recent developments section for more details.
NATURAL GAS STORAGE AND OTHER
Comparable EBITDA for Natural Gas Storage and other decreased by $12 million for the three months ended September 30, 2017 compared to the same period in 2016 mainly due to lower realized natural gas storage price spreads.



TRANSCANADA PIPELINES LIMITED [22
THIRD 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
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Comparable EBITDA and EBIT
 
(4
)
 
8

 
(20
)
 
7

Specific items:
 
 
 
 
 
 
 
 
Integration and acquisition related costs – Columbia
 
(32
)
 
(44
)
 
(81
)
 
(80
)
Foreign exchange gain/(loss) – inter-affiliate loan1
 
7

 

 
(1
)
 

Restructuring costs
 

 

 

 
(14
)
Segmented losses
 
(29
)
 
(36
)
 
(102
)
 
(87
)
1 
Reported in Income from equity investments on the condensed consolidated statement of income.
Corporate segmented losses decreased by $7 million for the three months ended September 30, 2017, and increased by $15 million for the nine months ended September 30, 2017 compared to the same periods in 2016 and included the following specific items that have been excluded from comparable EBIT:
integration and acquisition costs associated with the acquisition of Columbia
foreign exchange on an inter-affiliate loan, which is offset in Interest income and other. This peso-denominated loan to the Sur de Texas project represents our proportionate share of its financing
in 2016, restructuring costs related to expected future losses under lease commitments.
Comparable EBITDA decreased by $12 million and $27 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016 primarily due to increased legal and other general and administrative costs recorded in 2017.
OTHER INCOME STATEMENT ITEMS
Interest expense
 
 
three months ended
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Interest on long-term debt and junior subordinated notes
 
 
 
 
 
 
 
 
Canadian dollar-denominated
 
(130
)
 
(122
)
 
(356
)
 
(343
)
U.S. dollar-denominated
 
(314
)
 
(315
)
 
(954
)
 
(811
)
Foreign exchange impact
 
(79
)
 
(102
)
 
(293
)
 
(260
)
 
 
(523
)
 
(539
)
 
(1,603
)
 
(1,414
)
Other interest and amortization expense
 
(47
)
 
(39
)
 
(124
)
 
(82
)
Capitalized interest
 
49

 
46

 
150

 
133

Interest expense included in comparable earnings
 
(521
)
 
(532
)
 
(1,577
)
 
(1,363
)
Specific items:
 
 
 
 
 
 
 
 
Integration and acquisition related costs – Columbia
 

 
(6
)
 

 
(6
)
Risk management activities
 
(1
)
 

 
(1
)
 

Interest expense
 
(522
)
 
(538
)
 
(1,578
)
 
(1,369
)



TRANSCANADA PIPELINES LIMITED [23
THIRD QUARTER 2017

Interest expense decreased by $16 million in the three months ended September 30, 2017 compared to the same period in 2016 and primarily reflects the net effect of:
final repayment of the Columbia acquisition bridge facilities in June 2017
long-term debt and junior subordinated notes issuances, net of maturities
the impact of a weaker U.S. dollar in translating U.S. dollar denominated interest.
Interest expense increased by $209 million for the nine months ended September 30, 2017 compared to the same period in 2016 and primarily reflects the net effect of:
long-term debt and junior subordinated notes issuances, partially offset by Canadian and U.S. dollar-denominated debt maturities
debt assumed in the acquisition of Columbia on July 1, 2016
higher capitalized interest on the Napanee power generating facility and LNG projects
higher related-party debt financing
the impact of a weaker U.S. dollar in translating U.S. dollar denominated interest.
Allowance for funds used during construction
 
 
three months ended
September 30
 
nine months ended
September 30
(unaudited - millions of $)
 
2017

 
2016

 
2017

 
2016

 
 
 
 
 
 
 
 
 
Canadian dollar-denominated
 
44

 
44

 
149

 
133

U.S. dollar-denominated
 
81

 
55

 
168

 
149

Foreign exchange impact