EXHIBIT 13.1
Quarterly report to shareholders
First quarter 2019
Financial highlights
three months ended March 31 | ||||||||
(millions of $, except per share amounts) | 2019 | 2018 | ||||||
Income | ||||||||
Revenues | 3,487 | 3,424 | ||||||
Net income attributable to common shares | 1,004 | 734 | ||||||
per common share – basic and diluted | $1.09 | $0.83 | ||||||
Comparable EBITDA1 | 2,383 | 2,063 | ||||||
Comparable earnings1 | 987 | 864 | ||||||
per common share1 | $1.07 | $0.98 | ||||||
Cash flows | ||||||||
Net cash provided by operations | 1,949 | 1,412 | ||||||
Comparable funds generated from operations1 | 1,791 | 1,611 | ||||||
Comparable distributable cash flow1 | 1,623 | 1,439 | ||||||
per common share1 | $1.76 | $1.63 | ||||||
Capital spending2 | 2,331 | 2,096 | ||||||
Dividends declared | ||||||||
Per common share | $0.75 | $0.69 | ||||||
Basic common shares outstanding (millions) | ||||||||
– weighted average for the period | 921 | 885 | ||||||
– issued and outstanding at end of period | 924 | 891 |
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. |
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Management’s discussion and analysis
May 2, 2019
This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three months ended March 31, 2019, and should be read with the accompanying unaudited Condensed consolidated financial statements for the three months ended March 31, 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.
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 |
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• | 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 |
• | 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 |
• | our ability to effectively anticipate and assess changes to government policies and regulations. |
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 TransCanada in our Annual Information Form and other disclosure documents, which are available on SEDAR (www.sedar.com).
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. |
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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 |
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.
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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.
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Consolidated results – first quarter 2019
As of first quarter 2019, the previously disclosed Energy segment has been renamed the Power and Storage segment.
three months ended March 31 | ||||||||
(millions of $, except per share amounts) | 2019 | 2018 | ||||||
Canadian Natural Gas Pipelines | 269 | 253 | ||||||
U.S. Natural Gas Pipelines | 792 | 648 | ||||||
Mexico Natural Gas Pipelines | 116 | 137 | ||||||
Liquids Pipelines | 460 | 341 | ||||||
Power and Storage | 48 | 50 | ||||||
Corporate | (19 | ) | (81 | ) | ||||
Total segmented earnings | 1,666 | 1,348 | ||||||
Interest expense | (586 | ) | (527 | ) | ||||
Allowance for funds used during construction | 139 | 105 | ||||||
Interest income and other | 163 | 63 | ||||||
Income before income taxes | 1,382 | 989 | ||||||
Income tax expense | (236 | ) | (121 | ) | ||||
Net income | 1,146 | 868 | ||||||
Net income attributable to non-controlling interests | (101 | ) | (94 | ) | ||||
Net income attributable to controlling interests | 1,045 | 774 | ||||||
Preferred share dividends | (41 | ) | (40 | ) | ||||
Net income attributable to common shares | 1,004 | 734 | ||||||
Net income per common share – basic and diluted | $1.09 | $0.83 |
Net income attributable to common shares increased by $270 million, or $0.26 per common share, for the three months ended March 31, 2019 compared to the same period 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 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. Results included an after-tax loss of $12 million and an after-tax gain of $6 million for the three months ended March 31, 2019 and 2018, respectively, related to our U.S. Northeast power marketing contracts. These amounts have been excluded from Power and Storage's comparable earnings as we do not consider the wind-down and sales of the remaining contracts part of our underlying operations.
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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 March 31 | ||||||||
(millions of $, except per share amounts) | 2019 | 2018 | ||||||
Net income attributable to common shares | 1,004 | 734 | ||||||
Specific items (net of tax): | ||||||||
U.S. Northeast power marketing contracts | 12 | (6 | ) | |||||
Risk management activities1 | (29 | ) | 136 | |||||
Comparable earnings | 987 | 864 | ||||||
Net income per common share | $1.09 | $0.83 | ||||||
Specific items (net of tax): | ||||||||
U.S. Northeast power marketing contracts | 0.01 | — | ||||||
Risk management activities | (0.03 | ) | 0.15 | |||||
Comparable earnings per common share | $1.07 | $0.98 |
1 | Risk management activities | three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||||
Canadian Power | (1 | ) | 2 | |||||
U.S. Power | (60 | ) | (101 | ) | ||||
Liquids marketing | (15 | ) | (7 | ) | ||||
Natural Gas Storage | (3 | ) | (3 | ) | ||||
Foreign exchange | 120 | (79 | ) | |||||
Income tax attributable to risk management activities | (12 | ) | 52 | |||||
Total unrealized gains/(losses) from risk management activities | 29 | (136 | ) |
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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 March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Comparable EBITDA | ||||||
Canadian Natural Gas Pipelines | 556 | 494 | ||||
U.S. Natural Gas Pipelines | 972 | 804 | ||||
Mexico Natural Gas Pipelines | 146 | 160 | ||||
Liquids Pipelines | 563 | 431 | ||||
Power and Storage | 151 | 176 | ||||
Corporate | (5 | ) | (2 | ) | ||
Comparable EBITDA | 2,383 | 2,063 | ||||
Depreciation and amortization | (608 | ) | (535 | ) | ||
Interest expense | (586 | ) | (527 | ) | ||
Allowance for funds used during construction | 139 | 105 | ||||
Interest income and other included in comparable earnings | 29 | 63 | ||||
Income tax expense included in comparable earnings | (228 | ) | (171 | ) | ||
Net income attributable to non-controlling interests | (101 | ) | (94 | ) | ||
Preferred share dividends | (41 | ) | (40 | ) | ||
Comparable earnings | 987 | 864 |
Comparable EBITDA and comparable earnings – 2019 versus 2018
Comparable EBITDA increased by $320 million for the three months ended March 31, 2019 compared to the same period in 2018 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 |
• | higher contribution from Canadian Natural Gas Pipelines mainly due to the recovery of increased depreciation in 2019 as a result of higher rates approved in both the Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement and higher incentive earnings for the Canadian Mainline |
• | lower contribution from Power and Storage primarily due to the sale of our interests in the Cartier Wind power facilities in 2018 and costs related to Napanee's delayed in-service |
• | foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. operations. |
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Comparable earnings increased by $123 million or $0.09 per common share for the three months ended March 31, 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 depreciation reflects new projects placed in service |
• | higher interest expense primarily as a result of long-term debt issuances, net of maturities, and the foreign exchange impact on translation of U.S. dollar-denominated interest |
• | higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials |
• | 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 |
• | higher AFUDC due to increased capital expenditures for our NGTL System and Mexico projects. |
Comparable earnings per common share for the three months ended March 31, 2019 also reflects the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018.
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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 $30.3 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 $21.5 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. During first quarter 2019, we placed approximately $5.3 billion of projects in service including Mountaineer XPress, Gulf XPress, and certain NGTL System expansions.
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 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.
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Secured projects
Expected in-service date | Estimated project cost1 | Carrying value at March 31, 2019 | ||||||
(billions of $) | ||||||||
Canadian Natural Gas Pipelines | ||||||||
Canadian Mainline | 2019-2022 | 0.3 | 0.1 | |||||
NGTL System | 2019 | 2.8 | 2.0 | |||||
2020 | 1.8 | 0.3 | ||||||
2021 | 2.6 | — | ||||||
2022+ | 1.4 | — | ||||||
Coastal GasLink2,3 | 2023 | 6.2 | 0.2 | |||||
Regulated maintenance capital expenditures | 2019-2021 | 1.6 | 0.2 | |||||
U.S. Natural Gas Pipelines | ||||||||
Columbia Gas | ||||||||
Modernization II | 2019-2020 | US 1.1 | US 0.5 | |||||
Other capacity capital | 2019-2021 | US 0.5 | — | |||||
Regulated maintenance capital expenditures | 2019-2021 | US 1.8 | US 0.1 | |||||
Mexico Natural Gas Pipelines | ||||||||
Sur de Texas4 | 2019 | US 1.5 | US 1.4 | |||||
Villa de Reyes4 | 2019-2020 | US 0.8 | US 0.7 | |||||
Tula4 | 2020 | US 0.7 | US 0.6 | |||||
Liquids Pipelines | ||||||||
White Spruce | 2019 | 0.2 | 0.2 | |||||
Other capacity capital | 2020 | 0.1 | — | |||||
Recoverable maintenance capital expenditures | 2019-2021 | 0.1 | — | |||||
Power and Storage | ||||||||
Napanee | 2019 | 1.7 | 1.7 | |||||
Bruce Power – life extension5 | 2019-2023 | 2.2 | 0.7 | |||||
Other | ||||||||
Non-recoverable maintenance capital expenditures6 | 2019-2021 | 0.7 | 0.1 | |||||
28.1 | 8.8 | |||||||
Foreign exchange impact on secured projects7 | 2.2 | 1.1 | ||||||
Total secured projects (Cdn$) | 30.3 | 9.9 |
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 | The CFE has recognized force majeure events for these pipelines and approved the payment of fixed capacity charges in accordance with their respective TSAs. Payments will be recognized as revenue over the contract service term commencing once the pipelines are placed in service. |
5 | 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. |
6 | 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. |
7 | Reflects U.S./Canada foreign exchange rate of 1.34 at March 31, 2019. |
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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 March 31, 2019 | |||||
(billions of $) | ||||||
Canadian Natural Gas Pipelines | ||||||
NGTL System – Merrick | 1.9 | — | ||||
U.S. Natural Gas Pipelines | ||||||
Other capacity capital2 | US 0.7 | — | ||||
Liquids Pipelines | ||||||
Keystone XL3 | US 8.0 | US 0.7 | ||||
Heartland and TC Terminals4 | 0.9 | 0.1 | ||||
Grand Rapids Phase 24 | 0.7 | — | ||||
Keystone Hardisty Terminal4 | 0.3 | 0.1 | ||||
Power and Storage | ||||||
Bruce Power – life extension5 | 6.0 | — | ||||
18.5 | 0.9 | |||||
Foreign exchange impact on projects under development6 | 3.0 | 0.2 | ||||
Total projects under development (Cdn$) | 21.5 | 1.1 |
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 1.34 at March 31, 2019. |
Outlook
Consolidated comparable earnings
Our overall comparable earnings outlook for 2019 remains consistent with the disclosure in the 2018 Annual Report.
Consolidated capital spending
Our expected total capital expenditures as outlined in the 2018 Annual Report remain materially unchanged.
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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 March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
NGTL System | 292 | 271 | ||||
Canadian Mainline | 237 | 193 | ||||
Other Canadian pipelines1 | 27 | 30 | ||||
Comparable EBITDA | 556 | 494 | ||||
Depreciation and amortization | (287 | ) | (241 | ) | ||
Comparable EBIT and segmented earnings | 269 | 253 |
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 increased by $16 million for the three months ended March 31, 2019 compared to the same period 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 March 31 | |||||
(millions of $) | 2019 | 2018 | |||
Net Income | |||||
NGTL System | 113 | 92 | |||
Canadian Mainline | 44 | 37 | |||
Average investment base | |||||
NGTL System | 11,096 | 9,091 | |||
Canadian Mainline | 3,665 | 3,817 |
Net income for the NGTL System increased by $21 million for the three months ended March 31, 2019 compared to the same period 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.
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Net income for the Canadian Mainline increased by $7 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to higher incentive earnings. We did not record incentive earnings in first quarter 2018 pending the outcome of the 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.
COMPARABLE EBITDA
Comparable EBITDA increased by $62 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to the recovery of increased depreciation as a result of higher rates approved in both the Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher pre-tax rate base earnings for the NGTL System and higher incentive earnings and flow-through income taxes for the Canadian Mainline.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $46 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to the increase in composite depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement as well as additional NGTL System facilities that were placed in service in 2018 and first quarter 2019.
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U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).
three months ended March 31 | ||||||
(millions of US$, unless otherwise noted) | 2019 | 2018 | ||||
Columbia Gas | 308 | 231 | ||||
ANR | 153 | 141 | ||||
TC PipeLines, LP1,2 | 36 | 39 | ||||
Great Lakes3 | 30 | 35 | ||||
Midstream | 37 | 30 | ||||
Columbia Gulf | 35 | 26 | ||||
Other U.S. pipelines4 | 19 | 15 | ||||
Non-controlling interests5 | 112 | 118 | ||||
Comparable EBITDA | 730 | 635 | ||||
Depreciation and amortization | (135 | ) | (122 | ) | ||
Comparable EBIT | 595 | 513 | ||||
Foreign exchange impact | 197 | 135 | ||||
Comparable EBIT and segmented earnings (Cdn$) | 792 | 648 |
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 months ended March 31, 2019, our ownership interest in TC PipeLines, LP was 25.5 per cent, which is unchanged from the same period 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 $144 million for the three months ended March 31, 2019 compared to the same period 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 period in 2018.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$95 million for the three months ended March 31, 2019 compared to the same period 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 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$13 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to new projects placed in service.
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Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).
three months ended March 31 | ||||||
(millions of US$, unless otherwise noted) | 2019 | 2018 | ||||
Topolobampo | 40 | 44 | ||||
Tamazunchale | 31 | 31 | ||||
Mazatlán | 18 | 20 | ||||
Guadalajara | 16 | 19 | ||||
Sur de Texas1 | 5 | 9 | ||||
Other | — | 4 | ||||
Comparable EBITDA | 110 | 127 | ||||
Depreciation and amortization | (23 | ) | (19 | ) | ||
Comparable EBIT | 87 | 108 | ||||
Foreign exchange impact | 29 | 29 | ||||
Comparable EBIT and segmented earnings (Cdn$) | 116 | 137 |
1 | Represents equity income from our 60 per cent interest. |
Mexico Natural Gas Pipelines comparable EBIT and segmented earnings decreased by $21 million for the three months ended March 31, 2019 compared to the same period in 2018. Lower EBITDA as described below was partially offset by a stronger U.S. dollar in 2019 which had a positive impact on Canadian dollar equivalent earnings.
Comparable EBITDA for Mexico Natural Gas Pipelines decreased by US$17 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to the net effect of:
• | lower revenues from operations as a result of changes in timing of revenue recognition in 2018 |
• | lower equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The inter-affiliate loan amount is fully offset in Interest income and other in the Corporate segment |
• | a TransGas distribution received and recorded as income in 2018, recorded in Other above. |
DEPRECIATION AND AMORTIZATION
Depreciation and amortization was higher for the three months ended March 31, 2019 compared to the same period in 2018 reflecting new assets in service and other adjustments.
TRANSCANADA [17
FIRST 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 March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Keystone Pipeline System | 424 | 340 | ||||
Intra-Alberta pipelines | 39 | 39 | ||||
Liquids marketing and other | 100 | 52 | ||||
Comparable EBITDA | 563 | 431 | ||||
Depreciation and amortization | (88 | ) | (83 | ) | ||
Comparable EBIT | 475 | 348 | ||||
Specific item: | ||||||
Risk management activities | (15 | ) | (7 | ) | ||
Segmented earnings | 460 | 341 | ||||
Comparable EBIT denominated as follows: | ||||||
Canadian dollars | 89 | 93 | ||||
U.S. dollars | 290 | 202 | ||||
Foreign exchange impact | 96 | 53 | ||||
Comparable EBIT | 475 | 348 |
Liquids Pipelines segmented earnings increased by $119 million for the three months ended March 31, 2019 compared to the same period in 2018 and include unrealized losses 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 $132 million for the three months ended March 31, 2019 compared to the same period in 2018 and was due to:
• | higher volumes on the Keystone Pipeline System |
• | higher contribution from liquids marketing activities due to improved margins and volumes |
• | positive foreign exchange impact on the Canadian dollar equivalent earnings from our U.S. operations. |
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $5 million for the three months ended March 31, 2019 compared to the same period in 2018 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.
TRANSCANADA [18
FIRST 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 March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Western and Eastern Power1 | 77 | 119 | ||||
Bruce Power1 | 60 | 54 | ||||
Natural Gas Storage and other | 17 | 7 | ||||
Business development | (3 | ) | (4 | ) | ||
Comparable EBITDA | 151 | 176 | ||||
Depreciation and amortization | (23 | ) | (32 | ) | ||
Comparable EBIT | 128 | 144 | ||||
Specific items: | ||||||
U.S. Northeast power marketing contracts | (16 | ) | 8 | |||
Risk management activities | (64 | ) | (102 | ) | ||
Segmented earnings | 48 | 50 |
1 | Includes our share of equity income from our investments in Portlands Energy and Bruce Power. |
Power and Storage segmented earnings decreased by $2 million for the three months ended March 31, 2019 compared to the same period in 2018 and included the following specific items:
• | a loss of $16 million for the three months ended March 31, 2019 (2018 – gain of $8 million) related to our U.S. Northeast power marketing contracts. These amounts have been excluded from Power and Storage's comparable earnings as we do not consider the wind-down and sales of the remaining contracts part of our underlying operations |
• | unrealized losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, primarily related to the remaining U.S. Northeast power marketing contracts. |
Comparable EBITDA for Power and Storage decreased by $25 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the net effect of:
• | decreased Western and Eastern Power results largely due to the sale of our interests in the Cartier Wind power facilities in October 2018 and costs related to Napanee's delayed in-service. Refer to the Recent developments section for more information |
• | increased Natural Gas Storage results due to higher realized natural gas storage price spreads |
• | increased Bruce Power results primarily due to 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. |
DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by $9 million for the three months ended March 31, 2019 compared to the same period 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.
TRANSCANADA [19
FIRST QUARTER 2019
BRUCE POWER
The following reflects our proportionate share of the components of comparable EBITDA and comparable EBIT.
three months ended March 31 | ||||||||
(millions of $, unless otherwise noted) | 2019 | 2018 | ||||||
Equity income included in comparable EBITDA and EBIT comprised of: | ||||||||
Revenues1 | 361 | 371 | ||||||
Operating expenses | (227 | ) | (227 | ) | ||||
Depreciation and other | (74 | ) | (90 | ) | ||||
Comparable EBITDA and EBIT2 | 60 | 54 | ||||||
Bruce Power – other information | ||||||||
Plant availability3 | 79 | % | 85 | % | ||||
Planned outage days | 141 | 74 | ||||||
Unplanned outage days | 7 | 31 | ||||||
Sales volumes (GWh)2 | 5,260 | 5,696 | ||||||
Realized sales price per MWh4 | $68 | $67 |
1 | Net of amounts recorded to reflect operating cost efficiencies shared with the IESO. |
2 | Represents our 48.3 per cent (2018 – 48.4 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 sales prices per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues. |
Planned maintenance on Unit 3 began in fourth quarter 2018 and on Unit 7 in February 2019, with both units expected to be back in service in second quarter 2019. Planned maintenance is expected to occur on Unit 2 in second quarter 2019 and on Unit 5 in the second half of 2019. The overall average plant availability percentage in 2019 is expected to be in the mid-80 per cent range.
On April 1, 2019, Bruce Power's contract price increased from approximately $68 per MWh to approximately $75 per MWh reflecting capital to be invested under the Unit 6 Major Component Replacement program and the Asset Management program as well as normal annual inflation adjustments.
TRANSCANADA [20
FIRST QUARTER 2019
Corporate
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the most directly comparable GAAP measure).
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Comparable EBITDA and EBIT | (5 | ) | (2 | ) | ||
Specific item: | ||||||
Foreign exchange loss – inter-affiliate loan1 | (14 | ) | (79 | ) | ||
Segmented losses | (19 | ) | (81 | ) |
1 | Reported in Income from equity investments on the Condensed consolidated statement of income. |
Corporate segmented losses decreased by $62 million for the three months ended March 31, 2019 compared to the same period in 2018. Segmented losses include foreign exchange losses 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 included in Interest income and other on the inter-affiliate loan receivable. These amounts have been excluded from our calculation of comparable EBIT.
OTHER INCOME STATEMENT ITEMS
Interest Expense
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Interest on long-term debt and junior subordinated notes | ||||||
Canadian dollar-denominated | (140 | ) | (134 | ) | ||
U.S. dollar-denominated | (331 | ) | (314 | ) | ||
Foreign exchange impact | (109 | ) | (83 | ) | ||
(580 | ) | (531 | ) | |||
Other interest and amortization expense | (43 | ) | (22 | ) | ||
Capitalized interest | 37 | 26 | ||||
Interest expense | (586 | ) | (527 | ) |
Interest expense increased by $59 million for the three months ended March 31, 2019 compared to the same period in 2018 and primarily reflects 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 borrowing |
• | higher capitalized interest primarily related to Napanee and Keystone XL. |
TRANSCANADA [21
FIRST QUARTER 2019
Allowance for funds used during construction
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Canadian dollar-denominated | 43 | 20 | ||||
U.S. dollar-denominated | 72 | 67 | ||||
Foreign exchange impact | 24 | 18 | ||||
Allowance for funds used during construction | 139 | 105 |
AFUDC increased by $34 million for the three months ended March 31, 2019 compared to the same period in 2018. The increase in Canadian dollar-denominated AFUDC is primarily due to capital expenditures in our NGTL System expansion projects. The increase in U.S. dollar-denominated AFUDC is primarily due to continued investment in Mexico projects.
Interest income and other
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Interest income and other included in comparable earnings | 29 | 63 | ||||
Specific items: | ||||||
Foreign exchange gain – inter-affiliate loan | 14 | 79 | ||||
Risk management activities | 120 | (79 | ) | |||
Interest income and other | 163 | 63 |
Interest income and other increased by $100 million for the three months ended March 31, 2019 compared to the same period in 2018 and was primarily the net effect of:
• | unrealized gains on risk management activities in 2019 compared to unrealized losses in 2018. These amounts have been excluded from comparable earnings |
• | higher interest income combined with a lower foreign exchange gain related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange loss in Sur de Texas are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively, resulting in no 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. |
TRANSCANADA [22
FIRST QUARTER 2019
Income tax expense
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Income tax expense included in comparable earnings | (228 | ) | (171 | ) | ||
Specific items: | ||||||
U.S. Northeast power marketing contracts | 4 | (2 | ) | |||
Risk management activities | (12 | ) | 52 | |||
Income tax expense | (236 | ) | (121 | ) |
Income tax expense included in comparable earnings increased by $57 million for the three months ended March 31, 2019 compared to the same period in 2018. This was primarily due to higher comparable earnings before income taxes and lower foreign tax rate differentials.
Net income attributable to non-controlling interests
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Net income attributable to non-controlling interests | (101 | ) | (94 | ) |
Net income attributable to non-controlling interests increased by $7 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to higher earnings in TC PipeLines, LP and the impact of a stronger U.S. dollar in 2019 on the Canadian dollar equivalent earnings.
Preferred share dividends
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Preferred share dividends | (41 | ) | (40 | ) |
TRANSCANADA [23
FIRST QUARTER 2019
Recent developments
CANADIAN NATURAL GAS PIPELINES
Coastal GasLink Pipeline Project
Following the October 2018 positive FID by LNG Canada, pre-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.
The NEB process considering regulatory jurisdiction continues with all evidence now submitted. A final hearing is scheduled for second quarter 2019 with a decision expected in third quarter 2019.
TransCanada continues to advance funding plans for the $6.2 billion pipeline project through a combination of the sale of up to 75 per cent ownership interest and potential project financing.
NGTL System
On March 14, 2019, we filed the NGTL System Rate Design and Services Application with the NEB which includes 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. Given the complexity of the issues raised in the Application, the NEB decided to hold a public hearing. Application to participate and comments on the Application were due April 12, 2019 and reply comments were submitted by NGTL on April 18, 2019.
In first quarter 2019, we placed approximately $250 million of projects in service which included the Gordondale Lateral Loop and the Boundary Lake North projects.
Canadian Mainline 2018-2020 Toll Review
On March 13, 2019, the NEB approved Canadian Mainline tolls as filed in the January 2019 compliance filing.
U.S. NATURAL GAS PIPELINES
Mountaineer XPress and Gulf XPress
The Mountaineer XPress project, a Columbia Gas project designed to transport 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.
Grand Chenier XPress
In February 2019, we approved the Grand Chenier XPress project, an ANR Pipeline project which will connect supply directly to Gulf Coast LNG export markets through the addition of a mid-point compressor station and incremental compression capability at existing facilities. Subject to a positive customer FID, the anticipated in-service dates are in 2021 and 2022 for Phase I and II, respectively, with estimated project costs of US$0.2 billion.
MEXICO NATURAL GAS PIPELINES
Sur de Texas
The Sur de Texas project has experienced force majeure events that have delayed in-service. Some events are subject to potential dispute and we have taken measures to protect our interests under the contract. Construction and commissioning activities are progressing such that we anticipate mechanical completion in May with an expected June 2019 in-service.
TRANSCANADA [24
FIRST QUARTER 2019
Villa de Reyes and Tula
Construction of the Villa de Reyes project is ongoing with a phased in-service anticipated to commence in the second half of 2019. Commencement of 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 2020. We have negotiated separate CFE contracts that would allow certain segments of Tula and Villa de Reyes to be placed in service when facilities are complete and gas is available.
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.
On February 6, 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 on February 18, 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 second quarter 2019.
In September 2018, two U.S. Native American communities filed a lawsuit in Montana challenging the Keystone XL Presidential Permit. We, along with the U.S. Government, have filed to have the lawsuit dismissed. In December 2018, we applied to the U.S. District Court in Montana for a stay of its various decisions affecting the issuance of the 2017 Keystone XL Presidential Permit and the extensive environmental assessments made in support of its issuance. The stay application was denied by the U.S. District Court in February 2019. In February 2019, we applied to the Ninth Circuit Court of Appeals (Ninth Circuit) for a stay of the U.S. District Court decisions. On March 16, 2019, the Ninth Circuit denied our stay application and declined to further limit the scope of the preliminary injunction which prevents us from conducting certain pre-construction activities.
On March 29, 2019, U.S. President Trump issued a new Presidential Permit for the Keystone XL Project, which superseded the 2017 permit. Subsequently, we filed a motion with the Ninth Circuit requesting the court vacate the U.S. District Court decisions, dissolve the injunctions, and direct the U.S. District Court to dismiss the pending cases. A lawsuit was filed challenging the validity of the new Presidential Permit. We are not named in the lawsuit.
White Spruce
Commissioning has been completed on the White Spruce pipeline, which transports crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta to the Grand Rapids pipeline with commercial in-service achieved in May 2019.
TRANSCANADA [25
FIRST QUARTER 2019
POWER AND STORAGE (Previously ENERGY)
Napanee
In March 2019, we experienced an equipment failure while progressing commissioning activities at our 900 MW natural gas-fired power plant in Napanee, Ontario. We continue to expect that our total investment in the Napanee facility will be approximately $1.7 billion, however, commencement of commercial operations will be delayed into the second half of 2019 as we repair the damaged equipment.
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 on a sale to a third party. On March 20, 2019, we terminated the agreement with SWG after entering into an agreement with SRP to sell the Coolidge generating station for approximately US$465 million, subject to timing of the close and related adjustments. The sale will result in an estimated gain of approximately $70 million ($55 million after tax) to be recognized upon closing, which is expected to occur in mid-2019.
TRANSCANADA [26
FIRST 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 Corporate ATM program and DRP. Annually, in fourth quarter, we renew and extend our credit facilities as required.
At March 31, 2019, our current assets totaled $4.9 billion and current liabilities amounted to $13.4 billion, leaving us with a working capital deficit of $8.5 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 $11.7 billion of unutilized, unsecured credit facilities |
• | our access to capital markets, including through our DRP and Corporate ATM programs, if deemed appropriate. |
CASH PROVIDED BY OPERATING ACTIVITIES
three months ended March 31 | ||||||||
(millions of $, except per share amounts) | 2019 | 2018 | ||||||
Net cash provided by operations | 1,949 | 1,412 | ||||||
(Decrease)/increase in operating working capital | (142 | ) | 207 | |||||
Funds generated from operations | 1,807 | 1,619 | ||||||
Specific items: | ||||||||
U.S. Northeast power marketing contracts | (16 | ) | (8 | ) | ||||
Comparable funds generated from operations | 1,791 | 1,611 | ||||||
Dividends on preferred shares | (40 | ) | (39 | ) | ||||
Distributions to non-controlling interests | (56 | ) | (69 | ) | ||||
Non-recoverable maintenance capital expenditures1 | (72 | ) | (64 | ) | ||||
Comparable distributable cash flow | 1,623 | 1,439 | ||||||
Comparable distributable cash flow per common share | $1.76 | $1.63 |
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. |
NET CASH PROVIDED BY OPERATIONS
Net cash provided by operations increased by $537 million for the three months ended March 31, 2019 compared to the same period in 2018, primarily due to higher earnings, the recovery of increased depreciation on Canadian regulated pipelines as well as the amount and timing of working capital changes.
TRANSCANADA [27
FIRST QUARTER 2019
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 $180 million for the three months ended March 31, 2019 compared to the same period 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.
COMPARABLE DISTRIBUTABLE CASH FLOW
Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation.
The increase in comparable distributable cash flow for the three months ended March 31, 2019 compared to the same period in 2018 reflects higher comparable funds generated from operations as described above. Comparable distributable cash flow per common share for the three months ended March 31, 2019 also reflects 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 March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Capital spending | ||||||
Capital expenditures | (2,022 | ) | (1,702 | ) | ||
Capital projects in development | (164 | ) | (36 | ) | ||
Contributions to equity investments | (145 | ) | (358 | ) | ||
(2,331 | ) | (2,096 | ) | |||
Other distributions from equity investments | 120 | 121 | ||||
Deferred amounts and other | (26 | ) | 110 | |||
Net cash used in investing activities | (2,237 | ) | (1,865 | ) |
Capital expenditures in first quarter 2019 were incurred primarily for the expansion of the NGTL System and Columbia Gas projects along with construction of the Coastal GasLink pipeline and Napanee power generating facility.
Costs incurred on capital projects in development in 2019 and 2018 were mostly attributed 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.
Other distributions from equity investments in 2019 and 2018 reflect our proportionate share of Bruce Power financings undertaken to fund its capital program and to make distributions to its 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.
TRANSCANADA [28
FIRST QUARTER 2019
CASH PROVIDED BY FINANCING ACTIVITIES
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Notes payable issued, net | 2,852 | 1,812 | ||||
Long-term debt issued, net of issue costs1 | 24 | 93 | ||||
Long-term debt repaid1 | (1,708 | ) | (1,226 | ) | ||
Dividends and distributions paid | (515 | ) | (466 | ) | ||
Common shares issued, net of issue costs | 68 | 340 | ||||
Partnership units of TC PipeLines, LP issued, net of issue costs | — | 49 | ||||
Net cash provided by financing activities | 721 | 602 |
1 | Includes draws and repayments on an unsecured loan facility by TC PipeLines, LP. |
LONG-TERM DEBT ISSUED
The following table outlines significant debt issuances in 2019:
(millions of Canadian $, unless otherwise noted) | ||||||||||||
Company | Issue date | Type | Maturity Date | Amount | Interest rate | |||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||||
April 2019 | Medium Term Notes | October 2049 | 1,000 | 4.34 | % |
The net proceeds of the above debt issuance were used for general corporate purposes and to fund our capital program.
LONG-TERM DEBT REPAID
The following table outlines significant debt retired in 2019:
(millions of Canadian $, unless otherwise noted) | ||||||||||
Company | Retirement date | Type | Amount | Interest rate | ||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||
March 2019 | Debentures | 100 | 10.50 | % | ||||||
January 2019 | Senior Unsecured Notes | US 750 | 7.125 | % | ||||||
January 2019 | Senior Unsecured Notes | US 400 | 3.125 | % |
DIVIDEND REINVESTMENT PLAN
With respect to dividends declared on February 14, 2019, the DRP participation rate amongst common shareholders was approximately 33 per cent, resulting in $226 million reinvested in common equity under the program.
TRANSCANADA [29
FIRST QUARTER 2019
DIVIDENDS
On May 2, 2019, we declared quarterly dividends as follows:
Quarterly dividend on our common shares | |
$0.75 per share | |
Payable on July 31, 2019 to shareholders of record at the close of business on June 28, 2019. |
Quarterly dividends on our preferred shares | |
Payable on June 28, 2019 to shareholders of record at the close of business on May 31, 2019: | |
Series 1 | $0.204125 |
Series 2 | $0.22450822 |
Series 3 | $0.1345 |
Series 4 | $0.18461781 |
Payable on July 30, 2019 to shareholders of record at the close of business on July 2, 2019: | |
Series 5 | $0.14143750 |
Series 6 | $0.19895342 |
Series 7 | $0.243938 |
Series 9 | $0.265625 |
Payable on May 31, 2019 to shareholders of record at the close of business on May 15, 2019: | |
Series 11 | $0.2375 |
Series 13 | $0.34375 |
Series 15 | $0.30625 |
SHARE INFORMATION
as at April 30, 2019 | ||
Common shares | Issued and outstanding | |
927 million | ||
Preferred shares | Issued and outstanding | Convertible to |
Series 1 | 9.5 million | Series 2 preferred shares |
Series 2 | 12.5 million | Series 1 preferred shares |
Series 3 | 8.5 million | Series 4 preferred shares |
Series 4 | 5.5 million | Series 3 preferred shares |
Series 5 | 12.7 million | Series 6 preferred shares |
Series 6 | 1.3 million | Series 5 preferred shares |
Series 71 | 24 million | Series 8 preferred shares |
Series 9 | 18 million | Series 10 preferred shares |
Series 11 | 10 million | Series 12 preferred shares |
Series 13 | 20 million | Series 14 preferred shares |
Series 15 | 40 million | Series 16 preferred shares |
Options to buy common shares | Outstanding | Exercisable |
13 million | 9 million |
1 | As the total number of Series 7 preferred shares tendered for conversion did not meet the threshold for conversion, no Series 7 preferred shares were converted into Series 8 preferred shares on April 30, 2019. |
TRANSCANADA [30
FIRST QUARTER 2019
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 April 30, 2019, we had a total of $12.8 billion of committed revolving and demand credit facilities, including:
Amount | Unused capacity | Borrower | Description | Matures | ||||
Committed, syndicated, revolving, extendible senior unsecured credit facilities: | ||||||||
$3.0 billion | $3.0 billion | TCPL | Supports TCPL's Canadian dollar commercial paper program and is used for general corporate purposes | December 2023 | ||||
US$4.5 billion | US$4.5 billion | TCPL/TCPL USA/Columbia/TAIL | Supports TCPL and TCPL USA's U.S. dollar commercial paper programs and is used for general corporate purposes of the borrowers, guaranteed by TCPL | December 2019 | ||||
US$1.0 billion | US$1.0 billion | TCPL/TCPL USA/Columbia/TAIL | Used for general corporate purposes of the borrowers, guaranteed by TCPL | December 2021 | ||||
Demand senior unsecured revolving credit facilities: | ||||||||
$2.1 billion | $1.0 billion | TCPL/TCPL USA | Supports the issuance of letters of credit and provides additional liquidity, TCPL USA facility guaranteed by TCPL | Demand | ||||
MXN$5.0 billion | MXN$5.0 billion | Mexican subsidiary | Used for Mexico general corporate purposes, guaranteed by TCPL | Demand |
At April 30, 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.
CONTRACTUAL OBLIGATIONS
Our capital expenditure commitments have risen by approximately $0.2 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 decreased commitments for the NGTL System and the White Spruce pipeline.
There were no other material changes to our contractual obligations in first 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.
TRANSCANADA [31
FIRST 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.
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. 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 March 31, 2019 | 1.33 | |
three months ended March 31, 2018 | 1.27 |
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.
Significant U.S. dollar-denominated amounts
three months ended March 31 | ||||||
(millions of US$) | 2019 | 2018 | ||||
U.S. Natural Gas Pipelines comparable EBIT | 595 | 513 | ||||
Mexico Natural Gas Pipelines comparable EBIT1 | 113 | 130 | ||||
U.S. Liquids Pipelines comparable EBIT | 290 | 202 | ||||
Interest on U.S. dollar-denominated long-term debt and junior subordinated notes | (331 | ) | (314 | ) | ||
Capitalized interest on U.S. dollar-denominated capital expenditures | 6 | 3 | ||||
U.S. dollar-denominated allowance for funds used during construction | 72 | 67 | ||||
U.S. dollar comparable non-controlling interests and other | (81 | ) | (80 | ) | ||
664 | 521 |
1 | Excludes interest expense on our inter-affiliate loan with Sur de Texas which is offset in Interest income and other. |
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Net investment hedges
We hedge 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 March 31, 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.
At March 31, 2019, our Condensed consolidated balance sheet included a MXN$19.4 billion or $1.3 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 $35 million for the three months ended March 31, 2019 (2018 – $27 million) from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments.
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.
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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 $) | March 31, 2019 | December 31, 2018 | ||||
Other current assets | 313 | 737 | ||||
Intangible and other assets | 35 | 61 | ||||
Accounts payable and other | (389 | ) | (922 | ) | ||
Other long-term liabilities | (49 | ) | (42 | ) | ||
(90 | ) | (166 | ) |
Unrealized and realized (losses)/gains on derivative instruments
The following summary does not include hedges of our net investment in foreign operations.
three months ended March 31 | ||||||
(millions of $) | 2019 | 2018 | ||||
Derivative instruments held for trading1 | ||||||
Amount of unrealized (losses)/gains in the period | ||||||
Commodities2 | (88 | ) | (109 | ) | ||
Foreign exchange | 120 | (79 | ) | |||
Amount of realized gains/(losses) in the period | ||||||
Commodities | 107 | 110 | ||||
Foreign exchange | (29 | ) | 15 | |||
Derivative instruments in hedging relationships | ||||||
Amount of realized (losses)/gains in the period | ||||||
Commodities | (7 | ) | 3 | |||
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 months ended March 31, 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. |
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Effect of fair value and cash flow hedging relationships
The following table details amounts presented on 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 March 31 | ||||||||||||
Revenues (Power and Storage) | Interest Expense | |||||||||||
(millions of $) | 2019 | 2018 | 2019 | 2018 | ||||||||
Total Amount Presented in the Condensed Consolidated Statement of Income | 336 | 675 | (586 | ) | (527 | ) | ||||||
Fair Value Hedges | ||||||||||||
Interest rate contracts | ||||||||||||
Hedged items | — | — | (6 | ) | (20 | ) | ||||||
Derivatives designated as hedging instruments | — | — | (1 | ) | — | |||||||
Cash Flow Hedges | ||||||||||||
Reclassification of gains/(losses) on derivative instruments from AOCI to net income1,2 | ||||||||||||
Interest rate contracts | — | — | 4 | 5 | ||||||||
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 March 31, 2019, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $4 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 March 31, 2019, we would have been required to provide collateral of $4 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.
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Other information
CONTROLS AND PROCEDURES
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 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 first 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:
• | not to 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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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 are currently evaluating 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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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 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.
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Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
2019 | 2018 | 2017 | |||||||||||||||||||||||||||||
(millions of $, except per share amounts) | First | Fourth | Third | Second | First | Fourth | Third | Second | |||||||||||||||||||||||
Revenues | 3,487 | 3,904 | 3,156 | 3,195 | 3,424 | 3,617 | 3,195 | 3,230 | |||||||||||||||||||||||
Net income attributable to common shares | 1,004 | 1,092 | 928 | 785 | 734 | 861 | 612 | 881 | |||||||||||||||||||||||
Comparable earnings | 987 | 946 | 902 | 768 | 864 | 719 | 614 | 659 | |||||||||||||||||||||||
Share statistics | |||||||||||||||||||||||||||||||
Net income per common share – basic and diluted | $1.09 | $1.19 | $1.02 | $0.88 | $0.83 | $0.98 | $0.70 | $1.01 | |||||||||||||||||||||||
Comparable earnings per common share | $1.07 | $1.03 | $1.00 | $0.86 | $0.98 | $0.82 | $0.70 | $0.76 | |||||||||||||||||||||||
Dividends declared per common share | $0.75 | $0.69 | $0.69 | $0.69 | $0.69 | $0.625 | $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. |
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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 the 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. |
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. |
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In second quarter 2017, comparable earnings also excluded:
• | a $265 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets which included a $441 million after-tax gain on the sale of TC Hydro and a loss of $176 million after tax on the sale of the thermal and wind package |
• | an after-tax charge of $15 million for integration-related costs associated with the acquisition of Columbia |
• | an after-tax charge of $4 million related to the maintenance of Keystone XL assets. |