EX-13.1 2 trp-06302019xmda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS Exhibit
EXHIBIT 13.1

Quarterly report to shareholders
Second quarter 2019
Financial highlights
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $, except per share amounts)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Income
 
 
 
 
 
 
 
 
Revenues
 
3,372

 
3,195

 
6,859

 
6,619

Net income attributable to common shares
 
1,125

 
785

 
2,129

 
1,519

per common share – basic and diluted
 

$1.21

 

$0.88

 

$2.30

 

$1.70

Comparable EBITDA1
 
2,324

 
1,991

 
4,707

 
4,054

Comparable earnings1
 
924

 
768

 
1,911

 
1,632

per common share1
 

$1.00

 

$0.86

 

$2.07

 

$1.83

 
 
 
 
 
 
 
 
 
Cash flows
 
 

 
 

 
 

 
 

Net cash provided by operations
 
1,722

 
1,805

 
3,671

 
3,217

Comparable funds generated from operations1
 
1,667

 
1,459

 
3,490

 
3,070

Comparable distributable cash flow1
 
1,518

 
1,306

 
3,173

 
2,745

per common share1
 

$1.64

 

$1.46

 

$3.43

 

$3.08

Capital spending2
 
1,963

 
2,597

 
4,294

 
4,693

 
 
 
 
 
 
 
 
 
Dividends declared
 
 

 
 
 
 

 
 
Per common share
 

$0.75

 

$0.69

 

$1.50

 

$1.38

Basic common shares outstanding (millions)
 
 

 
 

 
 

 
 
– weighted average for the period
 
927

 
896

 
924

 
892

– issued and outstanding at end of period
 
929

 
904

 
929

 
904

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. Refer to the Non-GAAP measures section for more information.
2
Includes capital expenditures, capital projects in development and contributions to equity investments.


TC ENERGY [2
SECOND QUARTER 2019

Management’s discussion and analysis
July 31, 2019
On May 3, 2019, TransCanada Corporation changed its name to TC Energy Corporation (TC Energy).
This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TC Energy. It discusses our business, operations, financial position, risks and other factors for the three and six months ended June 30, 2019, and should be read with the accompanying unaudited Condensed consolidated financial statements for the three and six months ended June 30, 2019, which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2018 audited Consolidated financial statements and notes and the MD&A in our 2018 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in our 2018 Annual Report. Certain comparative figures have been adjusted to reflect the current period’s presentation.
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:
•
our financial and operational performance, including the performance of our subsidiaries
•
expectations about strategies and goals for growth and expansion
•
expected cash flows and future financing options available, including portfolio management
•
expected dividend growth
•
expected access to and cost of capital
•
expected costs and schedules for planned projects, including projects under construction and in development
•
expected capital expenditures and contractual obligations
•
expected regulatory processes and outcomes
•
expected outcomes with respect to legal proceedings, including arbitration and insurance claims
•
expected impact of future tax and 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.


TC ENERGY [3
SECOND QUARTER 2019

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:
Assumptions
•
regulatory decisions and outcomes
•
planned and unplanned outages and the use of our pipeline, power and storage assets
•
integrity and reliability of our assets
•
anticipated construction costs, schedules and completion dates
•
access to capital markets, including portfolio management
•
expected industry, market and economic conditions
•
inflation rates and commodity prices
•
interest, tax and foreign exchange rates
•
nature and scope of hedging.
Risks and uncertainties
•
our ability to successfully implement our strategic priorities and whether they will yield the expected benefits
•
our ability to implement a capital allocation strategy aligned with maximizing shareholder value
•
the operating performance of our pipeline, power and storage assets
•
amount of capacity sold and rates achieved in our pipeline businesses
•
the amount of capacity payments and revenues from our power generation assets due to plant availability
•
production levels within supply basins
•
construction and completion of capital projects
•
costs for labour, equipment and materials
•
the availability and market prices of commodities
•
access to capital markets on competitive terms
•
interest, tax and foreign exchange rates
•
performance and credit risk of our counterparties
•
regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims
•
changes in environmental and other laws and regulations
•
our ability to effectively anticipate and assess changes to government policies and regulations
•
competition in the pipeline, power and storage sectors
•
unexpected or unusual weather
•
acts of civil disobedience
•
cyber security and technological developments
•
economic conditions in North America as well as globally.
You can read more about these factors and others in this MD&A and in other reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2018 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 TC Energy in our Annual Information Form and other disclosure documents, which are available on SEDAR (www.sedar.com).


TC ENERGY [4
SECOND QUARTER 2019

NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
•
comparable EBITDA
•
comparable EBIT
•
comparable earnings
•
comparable earnings per common share
•
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 GAAP and therefore may not be comparable to similar measures presented by other entities.
Comparable measures
We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, 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 to enacted tax rates
•
gains or losses on sales of assets or assets held for sale
•
legal, contractual and bankruptcy settlements
•
impact of regulatory or arbitration decisions relating to prior year earnings
•
restructuring costs
•
impairment of goodwill, investments and other assets
•
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 most directly comparable GAAP measures.
Comparable measure
GAAP measure
 
 
comparable EBITDA
segmented earnings
comparable EBIT
segmented earnings
comparable earnings
net income attributable to common shares
comparable earnings per common share
net income per common share
comparable funds generated from operations
net cash provided by operations
comparable distributable cash flow
net cash provided by operations


TC ENERGY [5
SECOND QUARTER 2019

Comparable EBITDA and comparable EBIT
Comparable EBITDA represents segmented earnings adjusted for certain specific items, excluding non-cash charges for depreciation and amortization. We use comparable EBITDA as a measure of our earnings from ongoing operations as it is a useful indicator of our performance and is also presented on a consolidated basis. Comparable EBIT represents segmented earnings adjusted for specific items. Comparable EBIT is an effective tool for evaluating trends in each segment.
Comparable earnings and comparable earnings per common share
Comparable earnings represents earnings or loss attributable to common shareholders on a consolidated basis, adjusted for specific items. Comparable earnings is comprised of segmented earnings, Interest expense, AFUDC, Interest income and other, Income taxes, Non-controlling interests and Preferred share dividends, adjusted for specific items. Refer to the Consolidated results section for reconciliations to net income attributable to common shares and net income per common share.
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. Refer to the Financial condition section for a reconciliation to net cash provided by operations.
Comparable distributable cash flow and comparable distributable cash flow per common 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 non-recoverable 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. We have the opportunity to recover effectively all of our pipeline maintenance capital expenditures in Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines through tolls. As such, our presentation of comparable distributable cash flow and comparable distributable cash flow per common share only includes a reduction for non-recoverable maintenance capital expenditures in their respective calculations.
Refer to the Financial condition section for a reconciliation to net cash provided by operations.


TC ENERGY [6
SECOND QUARTER 2019

Consolidated results – second quarter 2019
As of first quarter 2019, the previously disclosed Energy segment has been renamed the Power and Storage segment.
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $, except per share amounts)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
242

 
280

 
511

 
533

U.S. Natural Gas Pipelines
 
663

 
541

 
1,455

 
1,189

Mexico Natural Gas Pipelines
 
113

 
118

 
229

 
255

Liquids Pipelines
 
542

 
390

 
1,002

 
731

Power and Storage
 
278

 
191

 
326

 
241

Corporate
 
(15
)
 
72

 
(34
)
 
(9
)
Total segmented earnings
 
1,823

 
1,592

 
3,489


2,940

Interest expense
 
(588
)
 
(558
)
 
(1,174
)
 
(1,085
)
Allowance for funds used during construction
 
99

 
113

 
238

 
218

Interest income and other
 
106

 
(92
)
 
269

 
(29
)
Income before income taxes
 
1,440

 
1,055

 
2,822

 
2,044

Income tax expense
 
(217
)
 
(153
)
 
(453
)
 
(274
)
Net income
 
1,223

 
902

 
2,369

 
1,770

Net income attributable to non-controlling interests
 
(57
)
 
(76
)
 
(158
)
 
(170
)
Net income attributable to controlling interests
 
1,166

 
826

 
2,211

 
1,600

Preferred share dividends
 
(41
)
 
(41
)
 
(82
)
 
(81
)
Net income attributable to common shares
 
1,125

 
785

 
2,129

 
1,519

Net income per common share – basic and diluted
 

$1.21

 

$0.88

 

$2.30

 

$1.70

Net income attributable to common shares increased by $340 million and $610 million, or $0.33 and $0.60 per common share, for the three and six months ended June 30, 2019 compared to the same periods in 2018. Net income per common share reflects the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018.
Net income in both periods included unrealized gains and losses from changes in risk management activities which we exclude along with other specific items as noted below to arrive at comparable earnings.
2019 results included:
•
an after-tax gain of $54 million related to the sale of our Coolidge generating station in May 2019
•
a deferred tax benefit of $32 million related to the impact of an Alberta corporate income tax rate reduction on our Canadian businesses not subject to rate-regulated accounting
•
an after-tax gain of $6 million and an after-tax loss of $6 million for the three and six months ended June 30, 2019 related to our U.S. Northeast power marketing contracts.
2018 results included:
•
after-tax losses of $11 million and $5 million for the three and six months ended June 30, 2018 related to our U.S. Northeast power marketing contracts.
These amounts have been excluded from comparable earnings as we do not consider these transactions or adjustments to be a part of our underlying operations.



TC ENERGY [7
SECOND QUARTER 2019

A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.
RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $, except per share amounts)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Net income attributable to common shares
 
1,125

 
785

 
2,129

 
1,519

Specific items (net of tax):
 
 
 
 
 
 
 
 
Gain on sale of Coolidge generating station
 
(54
)
 
—

 
(54
)
 
—

Alberta corporate income tax rate reduction
 
(32
)
 
—

 
(32
)
 
—

U.S. Northeast power marketing contracts
 
(6
)
 
11

 
6

 
5

Risk management activities1
 
(109
)
 
(28
)
 
(138
)
 
108

Comparable earnings
 
924

 
768

 
1,911

 
1,632

Net income per common share
 

$1.21

 

$0.88

 

$2.30

 

$1.70

Specific items (net of tax):
 
 
 
 
 
 
 
 
Gain on sale of Coolidge generating station
 
(0.06
)
 
—

 
(0.06
)
 
—

Alberta corporate income tax rate reduction
 
(0.03
)
 
—

 
(0.03
)
 
—

U.S. Northeast power marketing contracts
 
(0.01
)
 
0.01

 
0.01

 
0.01

Risk management activities
 
(0.11
)
 
(0.03
)
 
(0.15
)
 
0.12

Comparable earnings per common share
 

$1.00

 

$0.86

 

$2.07

 

$1.83

1
 
Risk management activities
 
three months ended
June 30
 
six months ended
June 30
 
 
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
 
 
 
 
Canadian Power
 
1

 
1

 
—

 
3

 
 
U.S. Power
 
8

 
39

 
(52
)
 
(62
)
 
 
Liquids marketing
 
49

 
62

 
34

 
55

 
 
Natural Gas Storage
 
(2
)
 
(3
)
 
(5
)
 
(6
)
 
 
Foreign exchange
 
87

 
(60
)
 
207

 
(139
)
 
 
Income tax attributable to risk management activities
 
(34
)
 
(11
)
 
(46
)
 
41

 
 
Total unrealized gains/(losses) from risk management activities
 
109

 
28

 
138

 
(108
)


TC ENERGY [8
SECOND QUARTER 2019

COMPARABLE EBITDA TO COMPARABLE EARNINGS
Comparable EBITDA represents segmented earnings adjusted for certain aspects of the specific items described above and excludes non-cash charges for depreciation and amortization.
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Comparable EBITDA
 
 
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
528

 
545

 
1,084

 
1,039

U.S. Natural Gas Pipelines
 
857

 
704

 
1,829

 
1,508

Mexico Natural Gas Pipelines
 
141

 
142

 
287

 
302

Liquids Pipelines
 
582

 
413

 
1,145

 
844

Power and Storage
 
219

 
202

 
370

 
378

Corporate
 
(3
)
 
(15
)
 
(8
)
 
(17
)
Comparable EBITDA
 
2,324

 
1,991

 
4,707

 
4,054

Depreciation and amortization
 
(621
)
 
(570
)
 
(1,229
)
 
(1,105
)
Interest expense
 
(588
)
 
(558
)
 
(1,174
)
 
(1,085
)
Allowance for funds used during construction
 
99

 
113

 
238

 
218

Interest income and other included in comparable earnings
 
7

 
55

 
36

 
118

Income tax expense included in comparable earnings
 
(199
)
 
(146
)
 
(427
)
 
(317
)
Net income attributable to non-controlling interests
 
(57
)
 
(76
)
 
(158
)
 
(170
)
Preferred share dividends
 
(41
)
 
(41
)
 
(82
)
 
(81
)
Comparable earnings
 
924

 
768

 
1,911

 
1,632

Comparable EBITDA – 2019 versus 2018
Comparable EBITDA increased by $333 million for the three months ended June 30, 2019 compared to the same period in 2018 primarily due to the net effect of the following:
•
higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities
•
higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service
•
higher contribution from Power and Storage primarily due to increased Bruce Power results from a higher realized power price, partially offset by the sale of our interests in the Cartier Wind power facilities in 2018
•
lower flow-through income taxes on the NGTL System and the Canadian Mainline as a result of accelerated tax depreciation enacted in June 2019, partially offset by increased depreciation and higher incentive earnings for the Canadian Mainline in 2019
•
foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. and Mexico operations.
Comparable EBITDA increased by $653 million for the six months ended June 30, 2019 compared to the same period in 2018 and was primarily due to the net effect of the following:
•
higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service
•
higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities


TC ENERGY [9
SECOND QUARTER 2019

•
higher contribution from Canadian Natural Gas Pipelines mainly due to the Canadian Mainline recovery of increased depreciation and higher incentive earnings in 2019, partially offset by lower flow-through income taxes on the NGTL System and the Canadian Mainline as a result of accelerated tax depreciation
•
lower contribution from Power and Storage primarily due to the sale of our interests in the Cartier Wind power facilities in 2018, partially offset by increased Bruce Power results from a higher realized power price and higher income on funds invested for future retirement benefits
•
foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. and Mexico operations.
Due to the flow-through treatment of income taxes on our Canadian rate-regulated pipelines, the beneficial income tax change on these assets related to accelerated tax depreciation reduces our comparable EBITDA despite having no impact on net income.
Comparable earnings – 2019 versus 2018
Comparable earnings increased by $156 million or $0.14 per common share for the three months ended June 30, 2019 compared to the same period in 2018 and was primarily the net effect of:
•
changes in comparable EBITDA described above
•
higher depreciation largely in Canadian Natural Gas Pipelines, which is fully recovered in tolls as reflected in the comparable EBITDA discussion above, therefore having no impact on comparable earnings. In addition, higher consolidated depreciation reflects new projects placed in service
•
lower interest income and other due to realized losses in 2019 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
•
higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow-through income taxes in our Canadian rate-regulated pipelines
•
higher interest expense primarily as a result of higher levels of short-term borrowings, long-term debt issuances, net of maturities, and the foreign exchange impact on translation of U.S. dollar-denominated interest.
Comparable earnings increased by $279 million or $0.24 per common share for the six months ended June 30, 2019 compared to the same period in 2018 and was primarily the net effect of:
•
changes in comparable EBITDA described above
•
higher depreciation largely in Canadian Natural Gas Pipelines, which is fully recovered in tolls as reflected in the increase in comparable EBITDA described above, therefore having no impact on comparable earnings. In addition, higher consolidated depreciation reflects new projects placed in service
•
higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow-through income taxes in our Canadian rate-regulated pipelines
•
higher interest expense primarily as a result of long-term debt issuances, net of maturities, higher levels of short-term borrowings, and the foreign exchange impact on translation of U.S. dollar-denominated interest
•
lower interest income and other due to realized losses in 2019 compared to realized gains in 2018 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.
Comparable earnings per common share for the three and six months ended June 30, 2019 also reflects the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018.


TC ENERGY [10
SECOND QUARTER 2019

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 flows.
Our capital program consists of approximately $32 billion of secured projects which include commercially supported, committed projects that are either under construction or are in or preparing to commence the permitting stage but are not yet fully approved. An additional $21 billion of projects under development are commercially supported (except where noted) but have greater uncertainty with respect to timing and estimated project costs and are subject to certain approvals. In the first half of 2019, we have placed approximately $5.6 billion of projects in service including Mountaineer XPress, Gulf XPress, various NGTL System expansions and the White Spruce pipeline.
Three years of maintenance capital expenditures for our businesses are included in the secured projects table. Maintenance capital expenditures on our regulated Canadian and U.S. natural gas pipelines businesses are added to rate base on which we have the opportunity to earn a return and recover these expenditures through current or future tolls, which is similar to our capacity capital projects on these pipelines. Tolling arrangements in our liquids pipelines business provide for the recovery of maintenance capital expenditures.
All projects are subject to cost and timing adjustments due to weather, market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits, among other factors. Amounts presented in the following tables exclude capitalized interest and AFUDC.


TC ENERGY [11
SECOND QUARTER 2019

Secured projects
 
 
Expected in-service date
 
Estimated project cost1

 
Carrying value at June 30, 2019

(billions of $)
 
 
 
 
 
 
 
Canadian Natural Gas Pipelines
 
 
 
 
 
 
Canadian Mainline
 
2019-2022
 
0.4

 
0.1

NGTL System
 
2019
 
2.6

 
2.2

 
 
2020
 
2.1

 
0.4

 
 
2021
 
2.6

 
0.1

 
 
2022+
 
1.5

 
—

Coastal GasLink2,3
 
2023
 
6.2

 
0.3

Regulated maintenance capital expenditures
 
2019-2021
 
1.8

 
0.3

U.S. Natural Gas Pipelines
 
 
 
 
 
 
Columbia Gas
 
 
 
 
 
 
Modernization II
 
2019-2020
 
US 1.1

 
US 0.6

Other capacity capital
 
2019-2021
 
US 1.1

 
US 0.1

Regulated maintenance capital expenditures
 
2019-2021
 
US 2.0

 
US 0.2

Mexico Natural Gas Pipelines
 
 
 
 
 
 
Sur de Texas
 
2019
 
US 1.6

 
US 1.6

Villa de Reyes
 
2019-2020
 
US 0.9

 
US 0.7

Tula
 
2021
 
US 0.7

 
US 0.6

Liquids Pipelines
 
 
 
 
 
 
Other capacity capital
 
2020
 
0.1

 
—

Recoverable maintenance capital expenditures
 
2019-2021
 
0.1

 
—

Power and Storage
 
 
 
 
 
 
Napanee
 
2019
 
1.8

 
1.7

Bruce Power – life extension4
 
2019-2023
 
2.2

 
0.8

Other
 
 
 
 
 
 
Non-recoverable maintenance capital expenditures5
 
2019-2021
 
0.7

 
0.1

 
 
 
 
29.5

 
9.8

Foreign exchange impact on secured projects6
 
 
 
2.3

 
1.2

Total secured projects (Cdn$)
 
 
 
31.8

 
11.0

1
Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP.
2
Represents 100 per cent of required capital prior to potential joint venture partners or project financing.
3
Carrying value is net of the fourth quarter 2018 receipts from the LNG Canada participants for the reimbursement of approximately $0.5 billion of pre-FID costs pursuant to project agreements.
4
Reflects our proportionate share of the Unit 6 Major Component Replacement program costs, expected to be in service in 2023, and amounts to be invested under the Asset Management program through 2023.
5
Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of our proportionate share of maintenance capital expenditures for Bruce Power and other Power and Storage assets.
6
Reflects U.S./Canada foreign exchange rate of 1.31 at June 30, 2019.


TC ENERGY [12
SECOND QUARTER 2019

Projects under development
The costs provided in the table below reflect the most recent estimates for each project as filed with the various regulatory authorities or otherwise determined by management.
 
 
Estimated project cost1

 
Carrying value
at June 30, 2019

(billions of $)
 
 
 
 
 
Canadian Natural Gas Pipelines
 
 
 
 
NGTL System – Merrick
 
1.9

 
—

U.S. Natural Gas Pipelines
 
 
 
 
Other capacity capital2
 
US 0.4

 
—

Liquids Pipelines
 
 
 
 
Keystone XL3
 
US 8.0

 
US 0.9

Heartland and TC Terminals4
 
0.9

 
0.1

Grand Rapids Phase 24
 
0.7

 
—

Keystone Hardisty Terminal4
 
0.3

 
0.1

Power and Storage
 
 
 
 
Bruce Power – life extension5
 
6.0

 
—

 
 
18.2

 
1.1

Foreign exchange impact on projects under development6
 
2.6

 
0.3

Total projects under development (Cdn$)
 
20.8

 
1.4

1
Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP.
2
Includes projects subject to a positive customer FID.
3
Carrying value reflects amount remaining after impairment charge recorded in 2015 along with additional amounts capitalized from January 1, 2018. A portion of these costs are recoverable from shippers under certain conditions.
4
Regulatory approvals have been obtained and additional commercial support is being pursued.
5
Reflects our proportionate share of Major Component Replacement program costs for Units 3, 4, 5, 7 and 8, and the remaining Asset Management program costs beyond 2023.
6
Reflects U.S./Canada foreign exchange rate of 1.31 at June 30, 2019.

Outlook
Consolidated comparable earnings
Our overall comparable earnings outlook for 2019 remains consistent with the 2018 Annual Report taking into consideration the net effect of:
•
higher expected volumes on the Keystone Pipeline System as well as higher contribution from liquids marketing activities
•
delays in the commencement of operations on the Napanee power plant and Sur de Texas pipeline
•
uncertainty regarding the impact of final U.S. Tax Reform regulations, expected in late 2019, on the cost of financing certain of our U.S. operations
•
asset sales and use of proceeds.
Consolidated capital spending
Our expected total capital expenditures for 2019 as outlined in the 2018 Annual Report remain materially unchanged.



TC ENERGY [13
SECOND QUARTER 2019

Canadian Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
NGTL System
 
268

 
311

 
560

 
582

Canadian Mainline
 
233

 
204

 
470

 
397

Other Canadian pipelines1
 
27

 
30

 
54

 
60

Comparable EBITDA
 
528

 
545

 
1,084

 
1,039

Depreciation and amortization
 
(286
)
 
(265
)
 
(573
)
 
(506
)
Comparable EBIT and segmented earnings
 
242

 
280

 
511

 
533

1
Includes results from Foothills, Ventures LP, Great Lakes Canada and our share of equity income from our investment in TQM as well as general and administrative and business development costs related to our Canadian Natural Gas Pipelines.
Canadian Natural Gas Pipelines comparable EBIT and segmented earnings decreased by $38 million and $22 million for the three and six months ended June 30, 2019 compared to the same periods in 2018.
Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are primarily affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenue on a flow-through basis.
NET INCOME AND AVERAGE INVESTMENT BASE
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
Net Income
 
 
 
 
 
 
 
NGTL System
118

 
96

 
231

 
188

Canadian Mainline
42

 
44

 
86

 
81

Average investment base
 
 
 
 
 
 
 
NGTL System
 
 
 
 
11,376

 
9,250

Canadian Mainline
 
 
 
 
3,666

 
3,829

Net income for the NGTL System increased by $22 million and $43 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 mainly due to a higher average investment base resulting from continued system expansions. The NGTL System is operating under the 2018-2019 Settlement which includes an ROE of 10.1 per cent on 40 per cent deemed common equity, a mechanism for sharing variances above and below a fixed annual OM&A amount and flow-through treatment of all other costs.
 


TC ENERGY [14
SECOND QUARTER 2019

Net income for the Canadian Mainline decreased by $2 million and increased by $5 million for the three and six months ended June 30, 2019 compared to the same periods in 2018. The increase in the six months ended June 30, 2019 is mainly due to higher incentive earnings. We did not record incentive earnings in the first half of 2018 pending the outcome of the Canadian Mainline 2018-2020 toll review. The NEB 2018 Decision, received in December 2018, preserved the incentive arrangement from the NEB 2014 Decision along with an approved ROE of 10.1 per cent on 40 per cent deemed equity. As a result, we recorded the 2018 incentive earnings in fourth quarter 2018.
COMPARABLE EBITDA
Comparable EBITDA for the Canadian Natural Gas Pipelines decreased by $17 million and increased by $45 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 due to the net effect of:
•
lower flow-through income taxes on the NGTL System and the Canadian Mainline as a result of the Canadian federal government’s accelerated tax depreciation, enacted in June 2019, to allow businesses in Canada to deduct the cost of their investments more quickly. Due to the flow-through treatment of income taxes on our Canadian rate-regulated pipelines, this beneficial income tax change reduces our comparable EBITDA despite having no impact on net income
•
increased depreciation on the Canadian Mainline due to higher rates approved in the NEB 2018 Decision
•
increased incentive earnings on the Canadian Mainline
•
increased rate base earnings on the NGTL System.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $21 million and $67 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 mainly due to the increase in composite depreciation rates approved in the Mainline NEB 2018 Decision as well as additional NGTL System facilities that were placed in service.


TC ENERGY [15
SECOND QUARTER 2019

U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).
 
 
three months ended
June 30
 
six months ended
June 30
(millions of US$, unless otherwise noted)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Columbia Gas
 
307

 
202

 
615

 
433

ANR
 
113

 
118

 
266

 
259

TC PipeLines, LP1,2
 
26

 
33

 
62

 
72

Great Lakes3
 
17

 
21

 
47

 
56

Midstream
 
32

 
29

 
69

 
59

Columbia Gulf
 
49

 
30

 
84

 
56

Other U.S. pipelines4
 
18

 
16

 
37

 
31

Non-controlling interests5
 
79

 
97

 
191

 
215

Comparable EBITDA 
 
641

 
546

 
1,371

 
1,181

Depreciation and amortization
 
(145
)
 
(128
)
 
(280
)
 
(250
)
Comparable EBIT
 
496

 
418

 
1,091

 
931

Foreign exchange impact
 
167

 
123

 
364

 
258

Comparable EBIT and segmented earnings (Cdn$)
 
663

 
541

 
1,455

 
1,189

1
Reflects our earnings from TC PipeLines, LP’s ownership interests in eight natural gas pipelines as well as general and administrative costs related to TC PipeLines, LP.
2
For the three and six months ended June 30, 2019, our ownership interest in TC PipeLines, LP was 25.5 per cent which is unchanged from the same periods in 2018.
3
Reflects our 53.55 per cent direct interest in Great Lakes. The remaining 46.45 per cent is held by TC PipeLines, LP.
4
Reflects earnings from our effective ownership in Millennium and Hardy Storage as well as general and administrative and business development costs related to our U.S. natural gas pipelines.
5
Reflects earnings attributable to portions of TC PipeLines, LP that we do not own.
U.S. Natural Gas Pipelines comparable EBIT and segmented earnings increased by $122 million and $266 million for the three and six months ended June 30, 2019 compared to the same periods in 2018. In addition to the net increases in comparable EBITDA noted below, a stronger U.S. dollar in 2019 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same periods in 2018.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$95 million and US$190 million for the three and six months ended June 30, 2019 compared to the same periods in 2018. This was primarily the net effect of:
•
increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service
•
decreased earnings from Bison (wholly-owned by TC PipeLines, LP) due to 2018 customer agreements to pay out their future contracted revenues and terminate their contracts.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$17 million and US$30 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 mainly due to new projects placed in service, partially offset by lower depreciation as a result of the Bison (wholly-owned by TC PipeLines, LP) asset impairment in 2018.


TC ENERGY [16
SECOND QUARTER 2019

Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).
 
 
three months ended
June 30
 
six months ended
June 30
(millions of US$, unless otherwise noted)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Topolobampo
 
40

 
42

 
80

 
86

Tamazunchale
 
31

 
32

 
62

 
63

Mazatlán
 
17

 
19

 
35

 
39

Guadalajara
 
16

 
16

 
32

 
35

Sur de Texas1
 
3

 
1

 
8

 
10

Other
 
—

 
—

 
—

 
4

Comparable EBITDA
 
107

 
110

 
217

 
237

Depreciation and amortization
 
(21
)
 
(18
)
 
(44
)
 
(37
)
Comparable EBIT
 
86

 
92

 
173

 
200

Foreign exchange impact
 
27

 
26

 
56

 
55

Comparable EBIT and segmented earnings (Cdn$)
 
113

 
118

 
229

 
255

1
Represents equity income from our 60 per cent interest. Sur de Texas results include AFUDC during construction, net of interest expense on an inter-affiliate loan from TC Energy. This interest expense is fully offset in Interest income and other in the Corporate segment.
Mexico Natural Gas Pipelines comparable EBIT and segmented earnings decreased by $5 million and $26 million for the three and six months ended June 30, 2019 compared to the same periods in 2018. Lower EBITDA as described below was partially offset by a stronger U.S. dollar in 2019 which had a positive impact on the Canadian dollar equivalent earnings.
Comparable EBITDA for Mexico Natural Gas Pipelines decreased by US$3 million and US$20 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 largely due to lower revenues from operations primarily as a result of changes in timing of revenue recognition in 2018.
Although the Sur de Texas pipeline was mechanically complete and ready for commercial service in the latter part of June 2019, we have not yet recorded any equity income from operating earnings. Refer to the Recent developments section for more information.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$3 million and US$7 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 reflecting new assets in service and other adjustments.


TC ENERGY [17
SECOND QUARTER 2019

Liquids Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Keystone Pipeline System
 
444

 
352

 
868

 
692

Intra-Alberta pipelines
 
41

 
37

 
80

 
76

Liquids marketing and other
 
97

 
24

 
197

 
76

Comparable EBITDA
 
582

 
413

 
1,145

 
844

Depreciation and amortization
 
(89
)
 
(85
)
 
(177
)
 
(168
)
Comparable EBIT
 
493

 
328

 
968

 
676

Specific item:
 
 
 
 
 
 
 
 
Risk management activities
 
49

 
62

 
34

 
55

Segmented earnings
 
542

 
390

 
1,002

 
731

 
 
 
 
 
 
 
 
 
Comparable EBIT denominated as follows:
 
 
 
 

 
 

 
 

Canadian dollars
 
95

 
89

 
184

 
182

U.S. dollars
 
298

 
185

 
588

 
387

Foreign exchange impact
 
100

 
54

 
196

 
107

Comparable EBIT
 
493

 
328

 
968

 
676

Liquids Pipelines segmented earnings increased by $152 million and $271 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 and include unrealized gains from changes in the fair value of derivatives related to our liquids marketing business which have been excluded from our calculation of comparable EBIT.
Comparable EBITDA for Liquids Pipelines increased by $169 million and $301 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to:
•
higher volumes on the Keystone Pipeline System
•
higher contribution from liquids marketing activities due to improved margins and volumes
•
contribution from the White Spruce pipeline, which went into service in May 2019
•
positive foreign exchange impact on the Canadian dollar equivalent earnings from our U.S. operations.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $4 million and $9 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.


TC ENERGY [18
SECOND QUARTER 2019

Power and Storage
As of first quarter 2019, the previously disclosed Energy segment has been renamed the Power and Storage segment.
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Western and Eastern Power1
 
90

 
104

 
167

 
223

Bruce Power1
 
125

 
91

 
185

 
145

Natural Gas Storage and other
 
6

 
10

 
23

 
17

Business development
 
(2
)
 
(3
)
 
(5
)
 
(7
)
Comparable EBITDA
 
219

 
202

 
370

 
378

Depreciation and amortization
 
(24
)

(33
)
 
(47
)
 
(65
)
Comparable EBIT
 
195


169

 
323

 
313

Specific items:
 
 
 
 
 
 
 
 
Gain on sale of Coolidge generating station
 
68

 
—

 
68

 
—

U.S. Northeast power marketing contracts
 
8

 
(15
)
 
(8
)
 
(7
)
Risk management activities
 
7

 
37

 
(57
)
 
(65
)
Segmented earnings
 
278

 
191

 
326

 
241

1
Includes our share of equity income from our investments in Portlands Energy and Bruce Power.
Power and Storage segmented earnings increased by $87 million and $85 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 and included the following specific items which have been excluded from comparable EBIT:
•
a pre-tax gain of $68 million related to the sale of our Coolidge generating station in May 2019. Refer to the Recent developments section for more information
•
a pre-tax gain of $8 million and pre-tax loss of $8 million for the three and six months ended June 30, 2019, (2018 – pre-tax losses of $15 million and $7 million, respectively) related to our U.S. Northeast power marketing contracts, the remainder of which were sold in May 2019
•
unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, largely related to the remaining U.S. Northeast power marketing contracts.
Comparable EBITDA for Power and Storage increased by $17 million and decreased by $8 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to the net effect of:
•
increased Bruce Power results primarily due to a higher realized power price and higher income on funds invested for future retirement benefits, partially offset by lower volumes resulting from higher outage days. Additional financial and operating information on Bruce Power is provided below
•
decreased Western and Eastern Power results largely due to the sale of our interests in the Cartier Wind power facilities in October 2018 and the sale of our Coolidge generating facility in May 2019
•
decreased Natural Gas Storage results for the three months ended June 30, 2019, mainly due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities, versus increased results for the six months ended June 30, 2019 on account of higher realized natural gas storage price spreads, primarily in first quarter 2019.


TC ENERGY [19
SECOND QUARTER 2019

DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by $9 million and $18 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to the sale of our interests in the Cartier Wind power facilities in October 2018 and the cessation of depreciation on our Coolidge generating station upon classification as held for sale at December 31, 2018.
BRUCE POWER
The following reflects our proportionate share of the components of comparable EBITDA and comparable EBIT.
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $, unless otherwise noted)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Equity income included in comparable EBITDA and EBIT comprised of:
 
 
 
 
 
 
 
 
Revenues1
 
424

 
385

 
785

 
756

Operating expenses
 
(216
)
 
(209
)
 
(443
)
 
(436
)
Depreciation and other
 
(83
)
 
(85
)
 
(157
)
 
(175
)
Comparable EBITDA and EBIT2
 
125

 
91

 
185

 
145

Bruce Power – other information
 
 

 
 
 
 

 
 
Plant availability3
 
78
%
 
89
%
 
79
%
 
87
%
Planned outage days
 
105

 
76

 
246

 
150

Unplanned outage days
 
47

 
3

 
54

 
34

Sales volumes (GWh)2
 
5,236

 
6,027

 
10,496

 
11,723

Realized power price per MWh4
 

$79

 

$67

 

$74

 

$67

1
Net of amounts recorded to reflect operating cost efficiencies shared with the IESO.
2
Represents our 48.4 per cent (2018 – 48.3 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation.
3
The percentage of time the plant was available to generate power, regardless of whether it was running.
4
Calculation based on actual and deemed generation. Realized power price 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.
Planned outage work on Unit 3 and Unit 7 was completed in second quarter 2019. Planned maintenance is expected to occur on Unit 2 and Unit 5 in the second half of 2019. The overall average plant availability percentage in 2019 is expected to be in the low-80 per cent range.
On April 1, 2019, Bruce Power's contract price increased from approximately $68 per MWh to a final adjusted contract price of approximately $78 per MWh including flow-through items, reflecting capital to be invested under the Unit 6 Major Component Replacement program and the Asset Management program as well as annual inflation adjustments.


TC ENERGY [20
SECOND QUARTER 2019

Corporate
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented (losses)/earnings (the most directly comparable GAAP measure).
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Comparable EBITDA and EBIT
 
(3
)
 
(15
)
 
(8
)
 
(17
)
Specific item:
 
 
 
 
 
 
 
 
Foreign exchange (loss)/gain – inter-affiliate loan1
 
(12
)
 
87

 
(26
)
 
8

Segmented (losses)/earnings
 
(15
)
 
72

 
(34
)
 
(9
)
1
Reported in Income from equity investments on the Condensed consolidated statement of income.
Corporate segmented losses increased by $87 million and $25 million for the three and six months ended June 30, 2019 compared to the same periods in 2018. Segmented (losses)/earnings include foreign exchange losses and gains on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing which are fully offset by corresponding foreign exchange gains and losses included in Interest income and other on the inter-affiliate loan receivable. These amounts have been excluded from our calculation of comparable EBIT.
Comparable EBITDA improved by $12 million and $9 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to U.S. capital tax adjustments recorded in second quarter 2018.
OTHER INCOME STATEMENT ITEMS
Interest expense
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Interest on long-term debt and junior subordinated notes
 
 
 
 
 
 
 
 
Canadian dollar-denominated
 
(148
)
 
(131
)
 
(288
)
 
(265
)
U.S. dollar-denominated
 
(328
)
 
(332
)
 
(659
)
 
(646
)
Foreign exchange impact
 
(111
)
 
(97
)
 
(220
)
 
(180
)
 
 
(587
)
 
(560
)
 
(1,167
)
 
(1,091
)
Other interest and amortization expense
 
(45
)
 
(28
)
 
(88
)
 
(50
)
Capitalized interest
 
44

 
30

 
81

 
56

Interest expense
 
(588
)
 
(558
)
 
(1,174
)
 
(1,085
)
Interest expense increased by $30 million and $89 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to the net effect of:
•
long-term debt issuances, net of maturities
•
foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest
•
higher levels of short-term borrowings
•
higher capitalized interest primarily related to Napanee and Keystone XL.


TC ENERGY [21
SECOND QUARTER 2019

Allowance for funds used during construction
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Canadian dollar-denominated
 
51

 
21

 
94

 
41

U.S. dollar-denominated
 
36

 
72

 
108

 
139

Foreign exchange impact
 
12

 
20

 
36

 
38

Allowance for funds used during construction
 
99

 
113

 
238

 
218

AFUDC decreased by $14 million and increased by $20 million for the three and six months ended June 30, 2019 compared to the same periods in 2018. The increase in Canadian dollar-denominated AFUDC is primarily due to capital expenditures on our NGTL System expansion projects. The decrease in U.S. dollar-denominated AFUDC is primarily due to Columbia Gas and Columbia Gulf growth projects placed in service, partially offset by continued investment in our Mexico projects.
Interest income and other
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Interest income and other included in comparable earnings
 
7

 
55

 
36

 
118

Specific items:
 
 
 
 
 
 
 
 
Foreign exchange gain/(loss) – inter-affiliate loan
 
12

 
(87
)
 
26

 
(8
)
Risk management activities
 
87

 
(60
)
 
207

 
(139
)
Interest income and other
 
106

 
(92
)
 
269

 
(29
)
Interest income and other increased by $198 million and $298 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 and was primarily the net effect of:
•
unrealized gains in 2019 compared to unrealized losses in 2018 from foreign exchange risk management activities. These amounts have been excluded from comparable earnings
•
foreign exchange gains in 2019 compared to foreign exchange losses in 2018 related to a peso-denominated inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding foreign exchange losses and gains in Sur de Texas are reflected in Income from equity investments, resulting in no net impact on net income. The offsetting currency-related gain and loss amounts are excluded from comparable earnings
•
realized losses in 2019 compared to realized gains in 2018 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.


TC ENERGY [22
SECOND QUARTER 2019

Income tax expense
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Income tax expense included in comparable earnings
 
(199
)
 
(146
)
 
(427
)
 
(317
)
Specific items:
 
 
 
 
 
 
 
 
Alberta corporate income tax rate reduction
 
32

 
—

 
32

 
—

Gain on sale of Coolidge generating station
 
(14
)
 
—

 
(14
)
 
—

U.S. Northeast power marketing contracts
 
(2
)
 
4

 
2

 
2

Risk management activities
 
(34
)
 
(11
)
 
(46
)
 
41

Income tax expense
 
(217
)
 
(153
)
 
(453
)
 
(274
)
Income tax expense included in comparable earnings increased by $53 million and $110 million for the three and six months ended June 30, 2019 compared to the same periods in 2018. This was primarily due to higher comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow-through income taxes in Canadian rate-regulated pipelines.
We recorded a $32 million income tax recovery on deferred income tax balances attributable to our Canadian businesses not subject to rate-regulated accounting due to the Alberta corporate income tax rate reduction enacted in June 2019. This has been excluded from comparable earnings.
Net income attributable to non-controlling interests
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Net income attributable to non-controlling interests
 
(57
)
 
(76
)
 
(158
)
 
(170
)
Net income attributable to non-controlling interests decreased by $19 million and $12 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to lower earnings in TC PipeLines, LP, partially offset by the impact of a stronger U.S. dollar in 2019 on the Canadian dollar equivalent earnings.
Preferred share dividends
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Preferred share dividends
 
(41
)
 
(41
)
 
(82
)
 
(81
)



TC ENERGY [23
SECOND QUARTER 2019

Recent developments
CANADIAN NATURAL GAS PIPELINES
Coastal GasLink Pipeline Project
Following the October 2018 positive FID by LNG Canada, construction activities continue at many locations along the pipeline route including the area south of Houston, B.C. which required a B.C. Supreme Court injunction for access. We expect a further decision in third quarter 2019 from the B.C. Supreme Court to extend the injunction to project completion.
On July 26, 2019, the NEB issued its decision affirming provincial jurisdiction for Coastal GasLink. Accordingly, construction will continue to proceed as planned under the permits granted to Coastal GasLink by the B.C. Oil and Gas Commission.
TC Energy continues to advance funding plans for this $6.2 billion pipeline project through a combination of the sale of up to 75 per cent ownership interest and project financing, which are proceeding as planned. Both transactions are expected to be completed in fourth quarter 2019.
NGTL System
On March 14, 2019, the NGTL System Rate Design and Services Application was filed with the NEB which included a settlement agreement negotiated between NGTL and members of its Tolls, Tariff, Facilities and Procedures (TTFP) committee which represents stakeholders. The settlement is supported by a majority of members of the TTFP committee. The Application addresses rate design, terms and conditions of service for the NGTL System and a tolling methodology for the North Montney Mainline (NMML). Given the complexity of the issues raised in the Application, the NEB decided to hold a public hearing which is expected to conclude in fourth quarter 2019.
On May 16, 2019, the NEB approved the proposed NMML tolling methodology including the surcharge, as filed, on an interim basis, pending the outcome of the above Rate Design and Services Application.
In the first half of 2019, the NGTL System placed approximately $0.3 billion of capacity projects in service.
Canadian Mainline
In March 2019, the NEB approved Canadian Mainline tolls as filed in the January 2019 compliance filing related to the 2018-2020 Toll Review.
On May 9, 2019, we received NEB approval of the North Bay Junction Long Term Fixed Price service, as filed.
U.S. NATURAL GAS PIPELINES
Sale of Columbia Midstream Assets
On July 2, 2019, we entered into an agreement to sell certain Columbia Midstream assets to UGI Energy Services, LLC, a subsidiary of UGI Corporation, for proceeds of approximately US$1.3 billion. The transaction is expected to close in third quarter 2019 subject to post-closing adjustments and customary regulatory approvals. The sale is expected to result in a pre-tax gain of $20 million ($130 million after-tax loss), which includes the release of an estimated $589 million of Columbia's goodwill allocated to these assets that is not deductible for tax purposes. The gain and related tax impact will be recognized upon closing of the transaction. This sale does not include any interest in Columbia Energy Ventures Company, which is our minerals business in the Appalachian basin.
East Lateral XPress
In second quarter 2019, we approved the East Lateral XPress project, an expansion project on the Columbia Gulf system that will connect supply to Gulf Coast LNG export markets. Subject to a positive customer FID, the anticipated in-service is 2022 with estimated project costs of US$0.3 billion.


TC ENERGY [24
SECOND QUARTER 2019

Louisiana XPress and Grand Chenier XPress
Combined, the Louisiana XPress and Grand Chenier XPress projects will connect nearly 2 Bcf/d of supply to Gulf Coast LNG export facilities. Both projects have now obtained necessary customer approvals or waivers of conditions allowing the projects to move to the execution phase. The anticipated in-service date of Louisiana XPress is in 2022 and estimated project costs are US$0.4 billion. The anticipated in-service dates for Grand Chenier are in 2021 and 2022 for Phase I and II, respectively, with total estimated project costs of US$0.2 billion.
Mountaineer XPress and Gulf XPress
The Mountaineer XPress project, a Columbia Gas project transporting supply from the Marcellus and Utica shale plays to points along the system and the Leach interconnect with Columbia Gulf, was phased into service over first quarter 2019 along with Gulf XPress, a Columbia Gulf project.
MEXICO NATURAL GAS PIPELINES
Sur de Texas
In June 2019, we completed construction and commissioning activities for the 775 km (482 mile) Sur de Texas pipeline, which has the capacity to provide up to 2.6 Bcf/d of natural gas supply to Mexico directly from the United States. We communicated the pipeline’s readiness for operation to both the regulator, CRE, and our customer, CFE, as required under our service contract. We require CFE's acknowledgment of readiness prior to commencing transportation service to CFE. To date, CFE has not provided this acknowledgment and, as a result, we have not been able to commence transportation services under their contract.
Villa de Reyes
Construction of the Villa de Reyes project is ongoing, but the project has experienced force majeure events that have delayed the schedule. We anticipate a phased in-service sequence to commence late 2019.
Tula
Construction for the central segment of the Tula project has been delayed due to a lack of progress by the Secretary of Energy, the governmental department responsible for Indigenous consultations. Project completion has been revised to the end of 2021.
CFE Arbitration
In June 2019, CFE filed requests for arbitration under the Sur de Texas, Villa de Reyes and Tula contracts, seeking nullification of clauses that govern the parties’ responsibilities in instances of force majeure and require reimbursement of fixed capacity payments. We are analyzing the content of the arbitration requests and preparing our response. In our view, the contracts were properly established in accordance with all original bid and regulatory requirements and remain valid and enforceable. We will defend them as necessary through the arbitration proceedings.
We have received certain capacity payments under force majeure provisions in the contracts governing the Sur de Texas, Villa de Reyes and Tula projects but we have not commenced recording revenues under these contracts.
The President of Mexico and the CEO of CFE have also made public statements questioning various provisions of the Sur de Texas, Villa de Reyes and Tula contracts. The parties have invited us to participate in negotiations to address these perceived issues and we have commenced discussions.


TC ENERGY [25
SECOND QUARTER 2019

LIQUIDS PIPELINES
Keystone Pipeline System
In January 2019, we entered into an agreement with Motiva Enterprises LLC (Motiva) to construct a pipeline    connection between the Keystone Pipeline system and Motiva’s 630,000 Bbl/d refinery in Port Arthur, Texas. The connection is targeted to be operational in second quarter 2020.
In early February 2019, the Keystone Pipeline system was temporarily shut down after a leak was detected near St. Charles, Missouri. The pipeline system was restarted the same day while the segment between Steele City, Nebraska to Patoka, Illinois was restarted in mid-February 2019. This shutdown is not expected to have a significant impact on our 2019 earnings.
Keystone XL
A decision from the Nebraska Supreme Court on the appeal of the Nebraska Public Service Commission route approval remains pending. We expect the decision to be issued in third quarter 2019.
In March 2019, U.S. President Trump issued a new Presidential Permit for the Keystone XL project, which superseded the 2017 Permit.
On June 6, 2019, the U.S. Court of Appeals (Appellate Court) for the Ninth Circuit granted TC Energy’s and the U.S. Government’s motions to dismiss the appeals from the various rulings of the District Court in Montana affecting the 2017 Keystone XL Presidential Permit and the associated injunction barring certain pre-construction activities and construction of the project. The Appellate Court found that issuance of the new Presidential Permit negates the challenges to the 2017 Permit. The Appellate Court overturned the District Court’s injunction orders and, on July 29, 2019, the injunction was dissolved.
On June 27, 2019, the U.S. Government and TC Energy filed motions to dismiss the lawsuit brought by two U.S. Native American communities, that have been expanded to challenge both the 2017 and 2019 Presidential Permits. The District Court in Montana has scheduled argument on motions to dismiss the complaints on September 12, 2019.
On June 27, 2019, the U.S. Government filed a motion to dismiss the challenge to the 2019 Presidential Permit brought by the Indigenous Environmental Network. TC Energy has intervened and will move to dismiss this lawsuit.
We continue to actively manage legal and regulatory challenges as the project advances.
White Spruce
The White Spruce pipeline, which transports crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta to the Grand Rapids pipeline, was placed in service in May 2019.
Northern Courier
On July 17, 2019, we completed the sale of an 85 per cent equity interest in the Northern Courier pipeline to Alberta Investment Management Corporation for gross proceeds of $144 million before post-closing adjustments, resulting in an expected pre-tax gain of $70 million after recording our remaining 15 per cent interest at fair value. On an after-tax basis, the gain of approximately $115 million reflects the utilization of previously unrecognized tax loss benefits. Preceding the equity sale, Northern Courier pipeline issued $1.0 billion of long-term, non-recourse debt, the proceeds from which were paid to TC Energy, resulting in aggregate gross proceeds to TC Energy of approximately $1.15 billion from this asset monetization.
We will remain the operator of the Northern Courier pipeline and will use the equity method to account for our remaining 15 per cent interest in our Consolidated financial statements.


TC ENERGY [26
SECOND QUARTER 2019

POWER AND STORAGE (PREVIOUSLY ENERGY)
Ontario Natural Gas-Fired Power Plants
On July 30, 2019, we entered into an agreement to sell our Halton Hills and Napanee power plants as well as our 50 per cent interest in Portlands Energy Centre to a subsidiary of Ontario Power Generation Inc. for proceeds of approximately $2.87 billion, subject to timing of the close and related adjustments. The sale is expected to close in late 2019 subject to conditions which include regulatory approvals and Napanee reaching commercial operations as outlined in the agreement. We expect this sale to result in a total pre-tax loss of approximately $230 million ($150 million after tax), with $125 million of the pre-tax loss recorded at July 30, 2019 upon classifying the net assets as held for sale. The remaining loss will be recorded on or before closing of the transaction.
In March 2019, Napanee experienced an equipment failure while progressing commissioning activities. Steps are being taken to address the situation and commercial operations are expected to commence by the end of 2019.
Coolidge Generating Station
In December 2018, we entered into an agreement to sell our Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC (SWG). Salt River Project Agriculture Improvement and Power District (SRP), the PPA counterparty, subsequently exercised its contractual right of first refusal (ROFR) on a sale to a third party and we terminated the agreement with SWG. On May 21, 2019, we completed the sale to SRP for proceeds of US$448 million before post-closing adjustments, as per the terms of their ROFR, resulting in a pre-tax gain of $68 million ($54 million after tax).
Monetization of U.S. Northeast power business
In May 2019, we sold our remaining U.S. Northeast power marketing contracts. This transaction concludes the wind-down of our U.S. Northeast power marketing business.


TC ENERGY [27
SECOND QUARTER 2019

Financial condition
We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets and engage in portfolio management to meet our financing needs, manage our capital structure and to preserve our credit ratings.
We believe we have the financial capacity to fund our existing capital program through predictable and growing cash flow from operations, access to capital markets, portfolio management, cash on hand, substantial committed credit facilities and, if deemed appropriate, our DRP. Annually, in fourth quarter, we renew and extend our credit facilities as required.
At June 30, 2019, our current assets totaled $5.7 billion and current liabilities amounted to $13.0 billion, leaving us with a working capital deficit of $7.3 billion compared to $7.8 billion at December 31, 2018. Our working capital deficiency is considered to be in the normal course of business and is managed through:
•
our ability to generate predictable and growing cash flow from operations
•
approximately $11.5 billion of unutilized, unsecured credit facilities
•
our access to capital markets.
CASH PROVIDED BY OPERATING ACTIVITIES
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $, except per share amounts)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Net cash provided by operations
 
1,722

 
1,805

 
3,671

 
3,217

Decrease in operating working capital
 
(47
)
 
(361
)
 
(189
)
 
(154
)
Funds generated from operations
 
1,675

 
1,444

 
3,482

 
3,063

Specific items:
 
 
 
 
 
 
 
 
U.S. Northeast power marketing contracts
 
(8
)
 
15

 
8

 
7

Comparable funds generated from operations
 
1,667

 
1,459

 
3,490

 
3,070

Dividends on preferred shares
 
(40
)
 
(39
)
 
(80
)
 
(78
)
Distributions to non-controlling interests
 
(58
)
 
(48
)
 
(114
)
 
(117
)
Non-recoverable maintenance capital expenditures1
 
(51
)
 
(66
)
 
(123
)
 
(130
)
Comparable distributable cash flow
 
1,518

 
1,306

 
3,173

 
2,745

Comparable distributable cash flow per common share
 

$1.64

 

$1.46

 

$3.43

 

$3.08

1
Includes non-recoverable maintenance capital expenditures from all segments including cash contributions to fund our proportionate share of maintenance capital expenditures for our equity investments which are primarily related to contributions to Bruce Power.
COMPARABLE FUNDS GENERATED FROM OPERATIONS
Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our operations by excluding the timing effects of working capital changes as well as the cash impact of our specific items.
Comparable funds generated from operations increased by $208 million and $420 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to higher comparable earnings adjusted for non-cash items and the cash impact of specific items as well as the recovery of higher depreciation for both the Canadian Mainline and the NGTL System.


TC ENERGY [28
SECOND QUARTER 2019

NET CASH PROVIDED BY OPERATIONS
Net cash provided by operations decreased by $83 million and increased by $454 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to higher funds generated from operations as well as the amount and timing of working capital changes.
COMPARABLE DISTRIBUTABLE CASH FLOW
Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation.
Comparable distributable cash flow increased by $212 million and $428 million for the three and six months ended June 30, 2019 compared to the same periods in 2018 and reflects higher comparable funds generated from operations as described above. Comparable distributable cash flow per common share of $1.64 and $3.43 for the three and six months ended June 30, 2019 also incorporates the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018.
CASH USED IN INVESTING ACTIVITIES
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Capital spending
 
 
 
 
 
 
 
 
Capital expenditures
 
(1,571
)

(2,337
)

(3,593
)

(4,039
)
Capital projects in development
 
(217
)

(76
)

(381
)

(112
)
Contributions to equity investments
 
(175
)

(184
)

(320
)

(542
)
 
 
(1,963
)
 
(2,597
)
 
(4,294
)
 
(4,693
)
Proceeds from sale of assets, net of transaction costs
 
591

 
—

 
591

 
—

Other distributions from equity investments
 
66


—


186


121

Deferred amounts and other
 
(55
)

(16
)

(81
)

94

Net cash used in investing activities
 
(1,361
)

(2,613
)

(3,598
)

(4,478
)
Capital expenditures in 2019 were incurred primarily for the expansion of the NGTL System and Columbia Gas projects along with construction of the Coastal GasLink pipeline, Napanee power generating facility and maintenance capital expenditures. Lower spending in 2019 reflects Columbia Gas and Columbia Gulf growth projects being completed and placed in service, partially offset by increased spending on the NGTL System.
Costs incurred on capital projects in development in 2019 and 2018 were mostly attributable to spending on Keystone XL.
Contributions to equity investments decreased in 2019 compared to 2018 mainly due to lower contributions to Sur de Texas which include our proportionate share of debt financing requirements.
In second quarter 2019, we closed the sale of our Coolidge generating station for net proceeds of $591 million.
Other distributions from equity investments reflect our proportionate share of Bruce Power and Northern Border financings undertaken to fund their respective capital programs and to make distributions to their partners. In first quarter 2019, we received distributions of $120 million (2018 – $121 million) from Bruce Power in connection with their issuance of senior notes in capital markets. In second quarter 2019, we received distributions of $66 million (2018 – nil) from Northern Border originating from a draw on its revolving credit facility to manage capitalization levels.


TC ENERGY [29
SECOND QUARTER 2019

CASH (USED IN)/PROVIDED BY FINANCING ACTIVITIES
 
 
three months ended
June 30
 
six months ended
June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Notes payable (repaid)/issued, net
 
(956
)
 
(1,327
)
 
1,896

 
485

Long-term debt issued, net of issue costs1
 
997

 
3,240

 
1,021

 
3,333

Long-term debt repaid1
 
(126
)
 
(808
)
 
(1,834
)
 
(2,034
)
Dividends and distributions paid
 
(564
)
 
(467
)
 
(1,079
)
 
(933
)
Common shares issued, net of issue costs
 
91

 
445

 
159

 
785

Partnership units of TC PipeLines, LP issued, net of issue costs
 
—

 
—

 
—

 
49

Net cash (used in)/provided by financing activities
 
(558
)
 
1,083

 
163

 
1,685

1
Includes draws and repayments on an unsecured loan facility by TC PipeLines, LP.
We maintain access to debt capital markets to partially fund our growth programs and for other financing requirements. Further details related to our long-term debt as at and for the three and six months ended June 30, 2019 are discussed in Note 8, Long-term debt, of our Condensed consolidated financial statements.
DIVIDEND REINVESTMENT PLAN
With respect to the common share dividend declared on May 3, 2019, the DRP participation rate amongst common shareholders was approximately 34 per cent resulting in $238 million reinvested in common equity under the program. Year-to-date in 2019, the participation rate amongst common shareholders has been approximately 33 per cent resulting in $464 million of dividends reinvested.
DIVIDENDS
On July 31, 2019, we declared quarterly dividends on our common shares of $0.75 per share payable on October 31, 2019 to shareholders of record at the close of business on September 30, 2019.
SHARE INFORMATION
At July 29, 2019, we had 929 million issued and outstanding common shares and 11 million outstanding options to buy common shares of which 7 million were exercisable.
CREDIT FACILITIES
We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for general corporate purposes. In addition, we have demand credit facilities that are also used for general corporate purposes, including issuing letters of credit and providing additional liquidity.
At July 29, 2019, we had a total of $12.7 billion of committed revolving and demand credit facilities of which $11.5 billion remains available.
At July 29, 2019, our operated affiliates had an additional $0.8 billion of undrawn capacity on committed credit facilities.
Refer to Financial risks and financial instruments for more information about liquidity, market and other risks.


TC ENERGY [30
SECOND QUARTER 2019

CONTRACTUAL OBLIGATIONS
Our capital expenditure commitments have risen by approximately $0.6 billion since December 31, 2018. This increase is primarily due to increased commitments related to the construction of Coastal GasLink, Columbia growth projects, and advancement of Keystone XL, partially offset by the fulfillment of commitments for the NGTL System and the White Spruce pipeline.
There were no other material changes to our contractual obligations in second quarter 2019 or to payments due in the next five years or after. Refer to the MD&A in our 2018 Annual Report for more information about our contractual obligations.


TC ENERGY [31
SECOND QUARTER 2019

Financial risks and financial instruments
We are exposed to market risk and counterparty credit risk and have strategies, policies and limits in place to manage the impact of these risks on our earnings, cash flow and, ultimately, shareholder value. Risk management strategies, policies and limits are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.
Refer to our 2018 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2018.
In May 2019, we sold our remaining U.S. Northeast power marketing contracts. This transaction concludes the wind-down of our U.S. Northeast power marketing business, reducing our commodity price risk.
INTEREST RATE RISK
We utilize short-term and long-term debt to finance our operations which exposes us to interest rate risk. We typically pay fixed rates of interest on our long-term debt and floating rates on our commercial paper programs and amounts drawn on our credit facilities and receive floating rates on cash and cash equivalents held. A small portion of our long-term debt is at floating interest rates. In addition, we are exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. We manage our interest rate risk using a combination of interest rate swaps and option derivatives.
FOREIGN EXCHANGE RISK
We generate revenues and incur expenses that are denominated in currencies other than Canadian dollars. As a result, our earnings and cash flows are exposed to currency fluctuations.
A portion of our businesses generate earnings in U.S. dollars, but since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of this risk is offset by interest expense on U.S. dollar-denominated debt. The balance of the exposure is actively managed on a rolling one-year basis using foreign exchange derivatives, however, the natural exposure beyond that period remains.
Average exchange rate – U.S. to Canadian dollars
The average exchange rate for one U.S. dollar converted into Canadian dollars was as follows:
three months ended June 30, 2019
1.34

three months ended June 30, 2018
1.29

six months ended June 30, 2019
1.33

six months ended June 30, 2018
1.28

The impact of changes in the value of the U.S. dollar on our U.S. and Mexico operations is partially offset by interest on U.S. dollar-denominated debt as set out in the table below. Comparable EBIT is a non-GAAP measure.


TC ENERGY [32
SECOND QUARTER 2019

Significant U.S. dollar-denominated amounts
 
 
three months ended
June 30
 
six months ended
June 30
(millions of US$)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
U.S. Natural Gas Pipelines comparable EBIT
 
496

 
418

 
1,091

 
931

Mexico Natural Gas Pipelines comparable EBIT1
 
114

 
114

 
227

 
244

U.S. Liquids Pipelines comparable EBIT
 
298

 
185

 
588

 
387

Interest on U.S. dollar-denominated long-term debt and junior subordinated notes
 
(328
)
 
(332
)
 
(659
)
 
(646
)
Capitalized interest on U.S. dollar-denominated capital expenditures
 
9

 
3

 
15

 
6

U.S. dollar-denominated allowance for funds used during construction
 
36

 
72

 
108

 
139

U.S. dollar comparable non-controlling interests and other
 
(47
)
 
(65
)
 
(128
)
 
(145
)
 
 
578

 
395

 
1,242

 
916

1
Excludes interest expense on our inter-affiliate loan with Sur de Texas which is offset in Interest income and other.
Net investment hedges
We hedge a portion of our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency swaps and foreign exchange options.
COUNTERPARTY CREDIT RISK
We have exposure to counterparty credit risk in the following areas:
•
cash and cash equivalents
•
accounts receivable
•
available-for-sale assets
•
the fair value of derivative assets
•
a loan receivable.
We monitor counterparties and review our accounts receivable regularly. We record allowances for doubtful accounts using the specific identification method. At June 30, 2019, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired.
We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
LIQUIDITY RISK
We manage our liquidity risk by continuously forecasting our cash flow and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.
LOAN RECEIVABLE FROM AFFILIATE
We hold a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. We account for our interest in the joint venture as an equity investment. In 2017, we entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022.


TC ENERGY [33
SECOND QUARTER 2019

At June 30, 2019, our Condensed consolidated balance sheet included a MXN$20.3 billion or $1.4 billion (December 31, 2018 – MXN$18.9 billion or $1.3 billion) loan receivable from the Sur de Texas joint venture which represents our proportionate share of long-term debt financing requirements related to the joint venture. Interest income and other included interest income of $37 million and $72 million for the three and six months ended June 30, 2019 (2018 – $29 million and $56 million) from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments in our Mexico Natural Gas Pipelines segment.
FINANCIAL INSTRUMENTS
With the exception of Long-term debt and Junior subordinated notes, our derivative and non-derivative financial
instruments are recorded on the balance sheet at fair value unless they were entered into and continue to be held for
the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as
such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting
exemptions.
Derivative instruments
We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. Derivative instruments, including those that qualify and are designated for hedge accounting treatment, are recorded at fair value. 
The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk and are classified as held for trading. Changes in the fair value of held-for-trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held-for-trading derivative instruments can fluctuate significantly from period to period.
Balance sheet presentation of derivative instruments
The balance sheet presentation of the fair value of derivative instruments is as follows:
(millions of $)
 
June 30, 2019

 
December 31, 2018

 
 
 
 
 
Other current assets
 
313

 
737

Intangible and other assets
 
41

 
61

Accounts payable and other
 
(232
)
 
(922
)
Other long-term liabilities
 
(97
)
 
(42
)
 
 
25

 
(166
)
 


TC ENERGY [34
SECOND QUARTER 2019

Unrealized and realized gains/(losses) on derivative instruments
The following summary does not include hedges of our net investment in foreign operations:
 
 
three months ended June 30
 
six months ended June 30
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Derivative instruments held for trading1
 
 
 
 
 
 
 
 
Amount of unrealized gains/(losses) in the period
 
 
 
 
 
 
 
 
Commodities2
 
59

 
99

 
(29
)
 
(10
)
Foreign exchange
 
87

 
(60
)
 
207

 
(139
)
Amount of realized gains/(losses) in the period
 
 
 
 
 
 
 
 
Commodities
 
80

 
19

 
187

 
129

Foreign exchange
 
(30
)
 
4

 
(59
)
 
19

Derivative instruments in hedging relationships
 
 
 
 
 
 
 
 
Amount of realized (losses)/gains in the period
 
 
 
 
 
 
 
 
Commodities
 
(2
)
 
(4
)
 
(9
)
 
(1
)
Interest rate
 
—

 
—

 
—

 
1

1
Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively.
2
In the three and six months ended June 30, 2019 and 2018, there were no gains or losses included in Net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.
Effect of fair value and cash flow hedging relationships
The following tables detail amounts presented in the Condensed consolidated statement of income and in which accounts the effects of fair value or cash flow hedging relationships are recorded:
 
 
three months ended June 30
 
 
Revenues (Power and Storage)
 
Interest Expense
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Total Amount Presented in the Condensed Consolidated Statement of Income
 
242

 
514

 
(588
)
 
(558
)
Fair Value Hedges
 
 
 
 
 
 
 
 
Interest rate contracts
 
 
 
 
 
 
 
 
Hedged items
 
—

 
—

 
(5
)
 
(22
)
Derivatives designated as hedging instruments
 
—

 
—

 
—

 
(2
)
Cash Flow Hedges
 
 
 
 
 
 
 
 
Reclassification of gains on derivative instruments from AOCI to net income1,2
 
 
 
 
 
 
 
 
Interest rate contracts
 
—

 
—

 
4

 
7

Commodity contracts
 
—

 
2

 
—

 
—

1
Refer to our Condensed consolidated financial statements for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.
2
There are no amounts recognized in earnings that were excluded from effectiveness testing.



TC ENERGY [35
SECOND QUARTER 2019

 
 
six months ended June 30
 
 
Revenues (Power and Storage)
 
Interest Expense
(millions of $)
 
2019

 
2018

 
2019

 
2018

 
 
 
 
 
 
 
 
 
Total Amount Presented in the Condensed Consolidated Statement of Income
 
578

 
1,189

 
(1,174
)
 
(1,085
)
Fair Value Hedges
 
 
 
 
 
 
 
 
Interest rate contracts
 
 
 
 
 
 
 
 
Hedged items
 
—

 
—

 
(11
)
 
(42
)
Derivatives designated as hedging instruments
 
—

 
—

 
(1
)
 
(2
)
Cash Flow Hedges
 
 
 
 
 
 
 
 
Reclassification of gains on derivative instruments from AOCI to net income1,2
 
 
 
 
 
 
 
 
Interest rate contracts
 
—

 
—

 
8

 
12

Commodity contracts
 
—

 
1

 
—

 
—

1
Refer to our Condensed consolidated financial statements for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.
2
There are no amounts recognized in earnings that were excluded from effectiveness testing.
Credit-risk-related contingent features of derivative instruments
Derivatives often contain financial assurance provisions that may require us to provide collateral if a credit-risk-related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits.
Based on contracts in place and market prices at June 30, 2019, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $6 million (December 31, 2018 – $6 million), with no collateral provided in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on June 30, 2019, we would have been required to provide collateral of $6 million (December 31, 2018 – $6 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.


TC ENERGY [36
SECOND QUARTER 2019

Other information
CONTROLS AND PROCEDURES
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at June 30, 2019, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
There were no changes in second quarter 2019 that had or are likely to have a material impact on our internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES
When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amounts we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. A summary of our critical accounting estimates is included in our 2018 Annual Report.
Our significant accounting policies have remained unchanged since December 31, 2018 other than described below. A summary of our significant accounting policies is included in our 2018 Annual Report.
Changes in accounting policies for 2019
Leases
In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statement of income. The new guidance does not make extensive changes to lessor accounting.
The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This transition option allowed us to not apply the new guidance, including disclosure requirements, to the comparative periods presented.
We elected available practical expedients and exemptions upon adoption which allowed us:
•
to not reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard
•
to carry forward the historical lease classification and our accounting treatment for land easements on existing agreements
•
to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption
•
to not separate lease and non-lease components for all leases for which we are the lessee and for facility and liquids tank terminals for which we are the lessor
•
to use hindsight in determining the lease term and assessing ROU assets for impairment.


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SECOND QUARTER 2019

The new guidance had a significant impact on our Condensed consolidated balance sheet, but did not have an impact on our Condensed consolidated statements of income and cash flows. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases and providing significant new disclosures about our leasing activities. Refer to our Condensed consolidated financial statements for further information related to the impact of adopting the new guidance and our updated accounting policies related to leases.
In the application of the new guidance, significant assumptions and judgments are used to determine the following:
•
whether a contract contains a lease
•
the duration of the lease term including exercising lease renewal options. The lease term for all of our leases includes the noncancellable period of the lease plus any additional periods covered by either our option to extend (or not to terminate) the lease that we are reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor
•
the discount rate for the lease.
Fair value measurement
In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. We elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material impact on our consolidated financial statements.
Future accounting changes
Measurement of credit losses on financial instruments
In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments, basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write-down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We have determined which of our assets are in scope for the new standard and have started to compile historical credit loss information. Current processes are being assessed to determine if any changes are required as a result. We continue to evaluate the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.
Defined benefit plans
In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to defined benefit pension and other post-retirement benefit plans. This new guidance is effective January 1, 2021 and will be applied on a retrospective basis, however, early adoption is permitted. We are currently evaluating the timing and impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.
Implementation costs of cloud computing arrangements
In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance is effective January 1, 2020, however, early adoption is permitted. This guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We are currently evaluating the timing and impact of adoption of this guidance and have not yet determined the effect on our consolidated financial statements.


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SECOND QUARTER 2019

Consolidation
In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020 and will be applied on a retrospective basis, however, early adoption is permitted. We do not expect the adoption of this new guidance to have a material impact on our consolidated financial statements.


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SECOND QUARTER 2019

Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
 
2019
 
2018
 
2017
(millions of $, except
per share amounts)
Second

 
First

 
Fourth

 
Third

 
Second

 
First

 
Fourth

 
Third

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
3,372

 
3,487

 
3,904

 
3,156

 
3,195

 
3,424

 
3,617

 
3,195

Net income attributable to common shares
1,125

 
1,004

 
1,092

 
928

 
785

 
734

 
861

 
612

Comparable earnings
924

 
987

 
946

 
902

 
768

 
864

 
719

 
614

Share statistics
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income per common share – basic and diluted

$1.21

 

$1.09

 

$1.19

 

$1.02

 

$0.88

 

$0.83

 

$0.98

 

$0.70

Comparable earnings per common share

$1.00

 

$1.07

 

$1.03

 

$1.00

 

$0.86

 

$0.98

 

$0.82

 

$0.70

Dividends declared per common share

$0.75

 

$0.75

 

$0.69

 

$0.69

 

$0.69

 

$0.69

 

$0.625

 

$0.625

 
FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT
Quarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments.
In our Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines segments, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
•
regulators' decisions
•
negotiated settlements with shippers
•
newly constructed assets being placed in service
•
acquisitions and divestitures
•
developments outside of the normal course of operations.
In Liquids Pipelines, annual revenues and net income are based on contracted and uncommitted spot transportation and liquids marketing activities. Quarter-over-quarter revenues and net income are affected by:
•
regulatory decisions
•
newly constructed assets being placed in service
•
acquisitions and divestitures
•
demand for uncontracted transportation services
•
liquids marketing activities
•
developments outside of the normal course of operations
•
certain fair value adjustments.
In Power and Storage, quarter-over-quarter revenues and net income are affected by:
•
weather
•
customer demand
•
newly constructed assets being placed in service
•
acquisitions and divestitures
•
market prices for natural gas and power
•
capacity prices and payments
•
planned and unplanned plant outages
•
developments outside of the normal course of operations
•
certain fair value adjustments.



TC ENERGY [40
SECOND QUARTER 2019

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.
Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives 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 part of our underlying operations.
In second quarter 2019, comparable earnings also excluded:
•
an after-tax gain of $54 million related to the sale of our Coolidge generating station
•
a deferred tax benefit of $32 million related to the impact of an Alberta corporate income tax rate reduction on our Canadian businesses not subject to rate-regulated accounting
•
an after-tax gain of $6 million related to our U.S. Northeast power marketing contracts.
In first quarter 2019, comparable earnings also excluded:
•
an after-tax loss of $12 million related to our U.S. Northeast power marketing contracts.
In fourth quarter 2018, comparable earnings also excluded:
•
a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities
•
a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions
•
a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform
•
a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets
•
$25 million of after-tax income recognized on the Bison contract terminations
•
a $140 million after-tax impairment charge on Bison
•
a $15 million after-tax goodwill impairment charge on Tuscarora
•
an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts.
In third quarter 2018, comparable earnings also excluded:
•
after-tax gain of $8 million related to our U.S. Northeast power marketing contracts.
In second quarter 2018, comparable earnings also excluded:
•
an after-tax loss of $11 million related to our U.S. Northeast power marketing contracts.
In the first quarter 2018, comparable earnings also excluded:
•
after-tax gain of $6 million related to our U.S. Northeast power marketing contracts, primarily due to income recognized on the sale of our retail contracts.
In fourth quarter 2017, comparable earnings also excluded:
•
an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform
•
a $136 million after-tax gain related to the sale of our Ontario solar assets
•
a $64 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets
•
a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications
•
a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets.


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SECOND QUARTER 2019

In third quarter 2017, comparable earnings also excluded:
•
an incremental net loss of $12 million related to the monetization of our U.S. Northeast power generation assets
•
an after-tax charge of $30 million for integration-related costs associated with the acquisition of Columbia
•
an after-tax charge of $8 million related to the maintenance of Keystone XL assets.