Date: May 5, 2017 | TRANSCANADA CORPORATION | |
By: | /s/ Donald R. Marchand | |
Donald R. Marchand | ||
Executive Vice-President and | ||
Chief Financial Officer | ||
By: | /s/ G. Glenn Menuz | |
G. Glenn Menuz | ||
Vice-President and Controller |
13.1 | Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended March 31, 2017. |
13.2 | Consolidated comparative interim unaudited financial statements of the registrant for the period ended March 31, 2017 (included in the registrant's First Quarter 2017 Quarterly Report to Shareholders). |
31.1 | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.1 | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
99.1 | A copy of the registrant’s news release of May 5, 2017. |
three months ended March 31 | ||||||||
(unaudited - millions of $, except per share amounts) | 2017 | 2016 | ||||||
Income | ||||||||
Revenues | 3,391 | 2,503 | ||||||
Net income attributable to common shares | 643 | 252 | ||||||
per common share - basic and diluted | $0.74 | $0.36 | ||||||
Comparable EBITDA1 | 1,977 | 1,502 | ||||||
Comparable earnings1 | 698 | 494 | ||||||
per common share1 | $0.81 | $0.70 | ||||||
Cash flows | ||||||||
Net cash provided by operations | 1,302 | 1,081 | ||||||
Comparable funds generated from operations1 | 1,508 | 1,249 | ||||||
Comparable distributable cash flow1 | 1,222 | 974 | ||||||
per common share1 | $1.41 | $1.39 | ||||||
Capital spending - capital expenditures | 1,560 | 836 | ||||||
- projects in development | 42 | 67 | ||||||
Contributions to equity investments | 192 | 170 | ||||||
Acquisitions, net of cash acquired | — | 995 | ||||||
Proceeds from sale of assets, net of transaction costs | — | 6 | ||||||
Dividends declared | ||||||||
Per common share | $0.625 | $0.565 | ||||||
Basic common shares outstanding (millions) | ||||||||
Average for the period | 866 | 702 | ||||||
End of period | 867 | 702 |
1 | Comparable EBITDA, comparable earnings, comparable earnings per common share, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share are all non-GAAP measures. See the non-GAAP measures section for more information. |
• | planned changes in our business including the divestiture of certain assets |
• | our financial and operational performance, including the performance of our subsidiaries |
• | expectations or projections about strategies and goals for growth and expansion |
• | expected cash flows and future financing options available to us |
• | expected dividend growth |
• | expected costs for planned projects, including projects under construction, permitting and in development |
• | expected schedules for planned projects (including anticipated construction and completion dates) |
• | expected regulatory processes and outcomes |
• | expected impact of regulatory outcomes |
• | expected outcomes with respect to legal proceedings, including arbitration and insurance claims |
• | expected capital expenditures and contractual obligations |
• | expected operating and financial results |
• | expected impact of future accounting changes, commitments and contingent liabilities |
• | expected industry, market and economic conditions. |
• | planned monetization of our U.S. Northeast power business |
• | inflation rates, commodity prices and capacity prices |
• | nature and scope of hedging |
• | regulatory decisions and outcomes |
• | the Canadian dollar to U.S. dollar exchange rate remains at or near current levels |
• | interest rates |
• | tax rates |
• | planned and unplanned outages and the use of our pipeline and energy assets |
• | integrity and reliability of our assets |
• | access to capital markets |
• | anticipated construction costs, schedules and completion dates. |
• | our ability to realize the anticipated benefits from the acquisition of Columbia |
• | timing and execution of our planned asset sales |
• | our ability to successfully implement our strategic initiatives |
• | whether our strategic initiatives will yield the expected benefits |
• | the operating performance of our pipeline and energy assets |
• | amount of capacity sold and rates achieved in our pipeline businesses |
• | the availability and price of energy commodities |
• | the amount of capacity payments and revenues we receive from our energy business |
• | regulatory decisions and outcomes |
• | outcomes of legal proceedings, including arbitration and insurance claims |
• | performance and credit risk of our counterparties |
• | changes in market commodity prices |
• | changes in the political environment |
• | changes in environmental and other laws and regulations |
• | competitive factors in the pipeline and energy sectors |
• | construction and completion of capital projects |
• | costs for labour, equipment and materials |
• | access to capital markets |
• | interest, tax and foreign exchange rates |
• | weather |
• | cyber security |
• | technological developments |
• | economic conditions in North America as well as globally. |
• | comparable earnings |
• | comparable earnings per common share |
• | comparable EBITDA |
• | comparable EBIT |
• | funds generated from operations |
• | comparable funds generated from operations |
• | comparable distributable cash flow |
• | comparable distributable cash flow per common share. |
• | certain fair value adjustments relating to risk management activities |
• | income tax refunds and adjustments and changes to enacted tax rates |
• | gains or losses on sales of assets 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 including certain ongoing maintenance and liquidation costs |
• | acquisition costs. |
Comparable measure | Original measure |
comparable earnings | net income attributable to common shares |
comparable earnings per common share | net income per common share |
comparable EBITDA | segmented earnings |
comparable EBIT | segmented earnings |
comparable funds generated from operations | net cash provided by operations |
comparable distributable cash flow | net cash provided by operations |
three months ended March 31 | |||||||
(unaudited - millions of $, except per share amounts) | 2017 | 2016 | |||||
Canadian Natural Gas Pipelines | 282 | 272 | |||||
U.S. Natural Gas Pipelines | 561 | 267 | |||||
Mexico Natural Gas Pipelines | 118 | 45 | |||||
Liquids Pipelines | 227 | 212 | |||||
Energy | 198 | (126 | ) | ||||
Corporate | (33 | ) | (27 | ) | |||
Total segmented earnings | 1,353 | 643 | |||||
Interest expense | (500 | ) | (420 | ) | |||
Allowance for funds used during construction | 101 | 101 | |||||
Interest income and other | 20 | 100 | |||||
Income before income taxes | 974 | 424 | |||||
Income tax expense | (200 | ) | (70 | ) | |||
Net income | 774 | 354 | |||||
Net income attributable to non-controlling interests | (90 | ) | (80 | ) | |||
Net income attributable to controlling interests | 684 | 274 | |||||
Preferred share dividends | (41 | ) | (22 | ) | |||
Net income attributable to common shares | 643 | 252 | |||||
Net income per common share - basic and diluted | $0.74 | $0.36 |
• | a charge of $24 million after tax for integration-related costs associated with the acquisition of Columbia |
• | a charge of $10 million after tax for costs related to the monetization of our U.S. Northeast power business |
• | a charge of $7 million after tax related to the maintenance of Keystone XL assets which are being expensed pending further advancement of the project |
• | a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our 2015 impairment charge, but the related income tax recoveries could not be recorded until realized. |
• | a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs |
• | a charge of $26 million after tax relating to costs associated with the acquisition of Columbia |
• | a charge of $6 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project |
• | an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016. |
three months ended March 31 | ||||||
(unaudited - millions of $, except per share amounts) | 2017 | 2016 | ||||
Net income attributable to common shares | 643 | 252 | ||||
Specific items (net of tax): | ||||||
Acquisition related costs - Columbia | 24 | 26 | ||||
U.S. Northeast power monetization | 10 | — | ||||
Keystone XL asset costs | 7 | 6 | ||||
Keystone XL income tax recoveries | (7 | ) | — | |||
Alberta PPA terminations | — | 176 | ||||
TC Offshore loss on sale | — | 3 | ||||
Risk management activities1 | 21 | 31 | ||||
Comparable earnings | 698 | 494 | ||||
Net income per common share | $0.74 | $0.36 | ||||
Specific items (net of tax): | ||||||
Acquisition related costs - Columbia | 0.03 | 0.04 | ||||
U.S. Northeast power monetization | 0.01 | — | ||||
Keystone XL asset costs | 0.01 | 0.01 | ||||
Keystone XL income tax recoveries | (0.01 | ) | — | |||
Alberta PPA terminations | — | 0.25 | ||||
Risk management activities | 0.03 | 0.04 | ||||
Comparable earnings per share | $0.81 | $0.70 |
1 | Risk management activities | three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||||
Canadian Power | 1 | (13 | ) | |||||
U.S. Power | (62 | ) | (115 | ) | ||||
Liquids marketing | — | (2 | ) | |||||
Natural Gas Storage | 5 | 5 | ||||||
Foreign exchange | 15 | 53 | ||||||
Income tax attributable to risk management activities | 20 | 41 | ||||||
Total unrealized losses from risk management activities | (21 | ) | (31 | ) |
• | higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016 |
• | higher interest expense as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt issuances |
• | higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016 |
• | lower interest income and other due to realized losses in 2017 compared to realized gains in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income |
• | lower earnings from Bruce Power mainly due to lower gains from contracting activities and higher interest expense, partially offset by higher volumes resulting from fewer outage days |
• | higher earnings from Western Power mainly due to termination of the Alberta PPAs in 2016 |
• | higher earnings from Liquids Pipelines due to higher volumes |
• | higher earnings from Natural Gas Storage due to higher realized natural gas storage price spreads |
• | higher earnings from U.S. Power due to depreciation no longer being recorded effective November 1, 2016 on the assets classified as held for sale and higher realized power prices, partially offset by lower capacity revenues in New York and higher fuel costs and lower generation volumes at our New York and New England facilities. |
at March 31, 2017 | Segment | Expected in-service date | Estimated project cost | Carrying value | ||||||
(unaudited - billions of $) | ||||||||||
Canadian Mainline | Canadian Natural Gas Pipelines | 2017-2018 | 0.3 | 0.1 | ||||||
NGTL System – North Montney | Canadian Natural Gas Pipelines | 2019-2020 | 1.4 | 0.3 | ||||||
– Saddle West | Canadian Natural Gas Pipelines | 2019 | 0.6 | — | ||||||
– 2016/17 Facilities | Canadian Natural Gas Pipelines | 2017-2020 | 2.2 | 0.9 | ||||||
– 2018 Facilities | Canadian Natural Gas Pipelines | 2018-2020 | 0.6 | — | ||||||
– Other | Canadian Natural Gas Pipelines | 2017-2020 | 0.3 | — | ||||||
Columbia Gas – Leach XPress | U.S. Natural Gas Pipelines | 2017 | US 1.4 | US 0.5 | ||||||
– Modernization I | U.S. Natural Gas Pipelines | 2017 | US 0.2 | US 0.1 | ||||||
– WB XPress | U.S. Natural Gas Pipelines | 2018 | US 0.8 | US 0.3 | ||||||
– Mountaineer XPress | U.S. Natural Gas Pipelines | 2018 | US 2.0 | US 0.2 | ||||||
– Modernization II | U.S. Natural Gas Pipelines | 2018-2020 | US 1.1 | — | ||||||
Columbia Gulf – Rayne XPress | U.S. Natural Gas Pipelines | 2017 | US 0.4 | US 0.3 | ||||||
– Cameron Access | U.S. Natural Gas Pipelines | 2018 | US 0.3 | US 0.2 | ||||||
– Gulf XPress | U.S. Natural Gas Pipelines | 2018 | US 0.6 | US 0.1 | ||||||
Midstream – Gibraltar | U.S. Natural Gas Pipelines | 2017 | US 0.3 | US 0.2 | ||||||
Tula | Mexico Natural Gas Pipelines | 2018 | US 0.6 | US 0.4 | ||||||
Villa de Reyes | Mexico Natural Gas Pipelines | 2018 | US 0.6 | US 0.3 | ||||||
Sur de Texas1 | Mexico Natural Gas Pipelines | 2018 | US 1.3 | US 0.2 | ||||||
Grand Rapids1 | Liquids Pipelines | 2017 | 0.9 | 0.8 | ||||||
Northern Courier | Liquids Pipelines | 2017 | 1.0 | 0.9 | ||||||
White Spruce | Liquids Pipelines | 2018 | 0.2 | — | ||||||
Napanee | Energy | 2018 | 1.1 | 0.7 | ||||||
Bruce Power – life extension2 | Energy | up to 2020+ | 1.1 | 0.1 | ||||||
19.3 | 6.6 | |||||||||
Foreign exchange impact on near-term projects3 | 3.2 | 0.9 | ||||||||
Total near-term projects (billions of Cdn$) | 22.5 | 7.5 |
1 | Our proportionate share. |
2 | Amounts reflect our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of major refurbishment outages which are expected to begin in 2020. |
3 | Reflects U.S./Canada foreign exchange rate of $1.33 at March 31, 2017. |
at March 31, 2017 | Segment | Estimated project cost | Carrying value | |||||
(unaudited - billions of $) | ||||||||
Heartland and TC Terminals | Liquids Pipelines | 0.9 | 0.1 | |||||
Upland | Liquids Pipelines | US 0.6 | — | |||||
Grand Rapids Phase 21 | Liquids Pipelines | 0.7 | — | |||||
Bruce Power - life extension1 | Energy | 5.3 | — | |||||
Keystone projects | ||||||||
Keystone XL2 | Liquids Pipelines | US 8.0 | US 0.3 | |||||
Keystone Hardisty Terminal2 | Liquids Pipelines | 0.3 | 0.1 | |||||
Energy East projects | ||||||||
Energy East3 | Liquids Pipelines | 15.7 | 0.8 | |||||
Eastern Mainline | Canadian Natural Gas Pipelines | 2.0 | 0.1 | |||||
BC west coast LNG-related projects | ||||||||
Coastal GasLink | Canadian Natural Gas Pipelines | 4.8 | 0.4 | |||||
Prince Rupert Gas Transmission | Canadian Natural Gas Pipelines | 5.0 | 0.5 | |||||
NGTL System - Merrick | Canadian Natural Gas Pipelines | 1.9 | — | |||||
45.2 | 2.3 | |||||||
Foreign exchange impact on medium to longer-term projects4 | 2.8 | 0.1 | ||||||
Total medium to longer-term projects (billions of Cdn$) | 48.0 | 2.4 |
1 | Our proportionate share. |
2 | Carrying value reflects amount remaining after impairment charge recorded in fourth quarter 2015. |
3 | Excludes transfer of Canadian Mainline natural gas assets. |
4 | Reflects U.S./Canada foreign exchange rate of $1.33 at March 31, 2017. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
NGTL System | 230 | 226 | ||||
Canadian Mainline | 247 | 231 | ||||
Other Canadian pipelines1 | 28 | 32 | ||||
Business development | (1 | ) | (1 | ) | ||
Comparable EBITDA | 504 | 488 | ||||
Depreciation and amortization | (222 | ) | (216 | ) | ||
Comparable EBIT and segmented earnings | 282 | 272 |
1 | Includes results from Foothills, Ventures LP and our share of equity income from our investment in TQM. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
NGTL System | 82 | 73 | ||||
Canadian Mainline | 52 | 50 |
three months ended March 31 | NGTL System1 | Canadian Mainline2 | |||||||||
(unaudited) | 2017 | 2016 | 2017 | 2016 | |||||||
Average investment base (millions of $) | 7,853 | 7,257 | 4,103 | 4,384 | |||||||
Delivery volumes (Bcf): | |||||||||||
Total | 1,090 | 1,063 | 521 | 481 | |||||||
Average per day | 12.1 | 11.7 | 5.8 | 5.3 |
1 | Field receipt volumes for the NGTL System for the three months ended March 31, 2017 were 1,037 Bcf (2016 – 1,074 Bcf). Average per day was 11.5 Bcf (2016 – 11.8 Bcf). |
2 | Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2017 were 235 Bcf (2016 – 274 Bcf). Average per day was 2.6 Bcf (2016 – 3.0 Bcf). |
three months ended March 31 | ||||||
(unaudited - millions of US$, unless otherwise noted) | 2017 | 2016 | ||||
Columbia Gas1 | 185 | — | ||||
ANR | 122 | 87 | ||||
TC PipeLines, LP2,3 | 32 | 31 | ||||
Great Lakes3,4 | 27 | 25 | ||||
Midstream1 | 23 | — | ||||
Columbia Gulf1 | 18 | — | ||||
Other U.S. pipelines1,2,3,5 | 29 | 14 | ||||
Non-controlling interests6 | 108 | 95 | ||||
Business development | (1 | ) | (1 | ) | ||
Comparable EBITDA | 543 | 251 | ||||
Depreciation and amortization | (112 | ) | (51 | ) | ||
Comparable EBIT | 431 | 200 | ||||
Foreign exchange impact | 140 | 71 | ||||
Comparable EBIT (Cdn$) | 571 | 271 | ||||
Specific items: | ||||||
Acquisition related costs - Columbia | (10 | ) | — | |||
TC Offshore loss on sale | — | (4 | ) | |||
Segmented earnings (Cdn$) | 561 | 267 |
1 | We completed the acquisition of Columbia on July 1, 2016 and the remaining publicly held units of Columbia Pipeline Partners LP (CPPL) on February 17, 2017. |
2 | Results from Northern Border and Iroquois reflect our share of equity income from these investments. We acquired additional interests in Iroquois of 0.65 per cent on May 1, 2016 and 4.87 per cent on March 31, 2016. |
3 | TC PipeLines, LP periodically conducts at-the-market equity issuances which decrease our ownership in TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Great Lakes and PNGTS through our ownership interest in TC PipeLines, LP for the periods presented. |
Effective ownership percentage as of | ||||
March 31, 2017 | March 31, 2016 | |||
TC PipeLines, LP | 26.4 | 27.9 | ||
Effective ownership through TC PipeLines, LP: | ||||
Great Lakes | 12.3 | 13.0 | ||
PNGTS | 13.2 | 13.9 |
4 | Represents our 53.6 per cent direct interest in Great Lakes. The remaining 46.4 per cent is held by TC PipeLines, LP. |
5 | Includes our direct ownership in Iroquois and PNGTS and our effective ownership in Millennium and Hardy Storage. |
6 | Comparable EBITDA for the portions of TC PipeLines, LP, PNGTS and CPPL that we do not own. Effective February 17, 2017, we acquired the remaining publicly held units of CPPL. |
• | US$250 million of earnings as a result of the acquisition of Columbia on July 1, 2016 and the remaining publicly held common units of CPPL on February 17, 2017 |
• | higher ANR transportation revenue resulting from a FERC-approved rate settlement, effective August 1, 2016, and higher storage results. |
three months ended March 31 | ||||||
(unaudited - millions of US$, unless otherwise noted) | 2017 | 2016 | ||||
Topolobampo | 40 | (1 | ) | |||
Tamazunchale | 29 | 27 | ||||
Guadalajara | 17 | 17 | ||||
Mazatlán | 16 | — | ||||
Sur de Texas1 | 4 | — | ||||
Other | — | (1 | ) | |||
Business development | — | (3 | ) | |||
Comparable EBITDA | 106 | 39 | ||||
Depreciation and amortization | (17 | ) | (6 | ) | ||
Comparable EBIT | 89 | 33 | ||||
Foreign exchange impact | 29 | 12 | ||||
Comparable EBIT and segmented earnings (Cdn$) | 118 | 45 |
1 | Represents our 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. |
• | US$41 million of incremental earnings from Topolobampo. The Topolobampo project has experienced a delay in construction which, under the terms of our Transportation Service Agreement (TSA) with the CFE, constitutes a force majeure event with provisions allowing for the collection and recognition of revenue as per the original TSA service commencement date of July 2016 |
• | US$16 million of incremental earnings from Mazatlán. Construction is complete and the collection and recognition of revenue began per the terms of the TSA in December 2016 |
• | US$4 million of equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Keystone Pipeline System | 306 | 302 | ||||
Business development and other | 6 | (6 | ) | |||
Comparable EBITDA | 312 | 296 | ||||
Depreciation and amortization | (77 | ) | (72 | ) | ||
Comparable EBIT | 235 | 224 | ||||
Specific items: | ||||||
Keystone XL asset costs | (8 | ) | (10 | ) | ||
Risk management activities | — | (2 | ) | |||
Segmented earnings | 227 | 212 | ||||
Comparable EBIT denominated as follows: | ||||||
Canadian dollars | 55 | 53 | ||||
U.S. dollars | 135 | 127 | ||||
Foreign exchange impact | 45 | 44 | ||||
235 | 224 |
• | higher volumes on Keystone pipeline |
• | higher contribution from liquids marketing |
• | higher business development activities, including advancement of Keystone XL. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Canadian Power | ||||||
Western Power1 | 30 | 4 | ||||
Eastern Power | 94 | 102 | ||||
Bruce Power | 91 | 114 | ||||
Canadian Power - comparable EBITDA1,2 | 215 | 220 | ||||
Depreciation and amortization | (37 | ) | (47 | ) | ||
Canadian Power - comparable EBIT1,2 | 178 | 173 | ||||
U.S. Power (US$) | ||||||
U.S. Power - comparable EBITDA | 54 | 75 | ||||
Depreciation and amortization3 | — | (31 | ) | |||
U.S. Power - comparable EBIT | 54 | 44 | ||||
Foreign exchange impact | 18 | 17 | ||||
U.S. Power - comparable EBIT (Cdn$) | 72 | 61 | ||||
Natural Gas Storage and other - comparable EBITDA | 21 | 9 | ||||
Depreciation and amortization | (3 | ) | (3 | ) | ||
Natural Gas Storage and other - comparable EBIT | 18 | 6 | ||||
Business Development comparable EBITDA and EBIT | (3 | ) | (3 | ) | ||
Energy - comparable EBIT1,2 | 265 | 237 | ||||
Specific items: | ||||||
U.S. Northeast power monetization | (11 | ) | — | |||
Alberta PPA terminations | — | (240 | ) | |||
Risk management activities | (56 | ) | (123 | ) | ||
Segmented earnings/(losses)1,2 | 198 | (126 | ) |
1 | Included losses from the Alberta PPAs up to March 7, 2016 when the PPAs were terminated. |
2 | Includes our share of equity income from our investments in Portlands Energy and Bruce Power. |
3 | Depreciation no longer being recorded effective November 1, 2016 on assets held for sale. |
• | in 2017, $11 million of pre-tax costs related to the monetization of our U.S. Northeast power business. See Recent developments section for more details |
• | in 2016, a $240 million pre-tax charge, which included a $29 million impairment of our equity investment in ASTC Power Partnership, on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs |
• | unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks as follows: |
Risk management activities | three months ended March 31 | |||||
(unaudited - millions of $, pre-tax) | 2017 | 2016 | ||||
Canadian Power | 1 | (13 | ) | |||
U.S. Power | (62 | ) | (115 | ) | ||
Natural Gas Storage | 5 | 5 | ||||
Total unrealized losses from risk management activities | (56 | ) | (123 | ) |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Revenue1 | ||||||
Western Power | 46 | 88 | ||||
Eastern Power | 105 | 95 | ||||
Other2 | 15 | 29 | ||||
166 | 212 | |||||
Income from equity investments3 | 8 | — | ||||
Commodity purchases resold | (1 | ) | (59 | ) | ||
Plant operating costs and other | (49 | ) | (47 | ) | ||
Comparable EBITDA4 | 124 | 106 | ||||
Depreciation and amortization | (37 | ) | (47 | ) | ||
Comparable EBIT4 | 87 | 59 | ||||
Breakdown of comparable EBITDA | ||||||
Western Power4 | 30 | 4 | ||||
Eastern Power | 94 | 102 | ||||
Comparable EBITDA4 | 124 | 106 | ||||
Plant availability5 | ||||||
Western Power | 99 | % | 99 | % | ||
Eastern Power6,7 | 99 | % | 86 | % |
1 | Includes the realized gains and losses from financial derivatives used to manage Canadian Power’s assets which are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives have been excluded to arrive at comparable EBITDA. |
2 | Includes revenues from the sale of unused natural gas transportation and sale of excess natural gas purchased for generation. |
3 | Includes our share of equity income in Portlands Energy, and ASTC Power Partnership up to March 7, 2016. |
4 | Included Alberta PPAs up to March 7, 2016 when the PPAs were terminated. |
5 | The percentage of time the plant was available to generate power, regardless of whether it was running. |
6 | Does not include Bécancour because power generation has been suspended since 2008. |
7 | Plant availability was higher in the three months ended March 31, 2017 than the same period in 2016 due to an unplanned outage at the Halton Hills facility in 2016. |
three months ended March 31 | ||||||||
(unaudited - millions of $, unless noted otherwise) | 2017 | 2016 | ||||||
Equity income included in comparable EBITDA and EBIT comprised of: | ||||||||
Revenues | 401 | 415 | ||||||
Operating expenses | (224 | ) | (225 | ) | ||||
Depreciation and other | (86 | ) | (76 | ) | ||||
Comparable EBITDA and EBIT1 | 91 | 114 | ||||||
Bruce Power - other information | ||||||||
Plant availability2 | 89 | % | 88 | % | ||||
Planned outage days | 56 | 76 | ||||||
Unplanned outage days | 17 | 8 | ||||||
Sales volumes (GWh)1 | 5,983 | 5,834 | ||||||
Realized sales price per MWh3 | $67 | $66 |
1 | Represents our 48.4 per cent (2016 - 48.5 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation. |
2 | The percentage of time the plant was available to generate power, regardless of whether it was running. |
3 | Calculation based on actual and deemed generation. Realized sales prices per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues. |
three months ended March 31 | ||||||
(unaudited - millions of US$) | 2017 | 2016 | ||||
Revenue1 | ||||||
Power2 | 530 | 418 | ||||
Capacity | 42 | 62 | ||||
572 | 480 | |||||
Commodity purchases resold | (409 | ) | (305 | ) | ||
Plant operating costs and other3 | (109 | ) | (100 | ) | ||
Comparable EBITDA1 | 54 | 75 | ||||
Depreciation and amortization4 | — | (31 | ) | |||
Comparable EBIT1 | 54 | 44 |
1 | Includes Ironwood commencing February 1, 2016. |
2 | Includes the realized gains and losses from financial derivatives used to manage U.S. Power’s assets which are presented on a net basis in Power revenues. The unrealized gains and losses from financial derivatives are excluded to arrive at comparable EBITDA. |
3 | Includes the cost of fuel consumed in generation. |
4 | U.S. Power assets held for sale are no longer being depreciated effective November 2016. |
three months ended March 31 | ||||||
(unaudited) | 2017 | 2016 | ||||
Physical sales volumes (GWh) | ||||||
Supply | ||||||
Generation | 2,007 | 2,280 | ||||
Purchased | 6,356 | 4,748 | ||||
8,363 | 7,028 | |||||
Plant availability1 | 71 | % | 71 | % |
1 | The percentage of time the plant was available to generate power, regardless of whether it was running. |
three months ended March 31 | ||||||
(unaudited) | 2017 | 2016 | ||||
Average Spot Power Prices (US$ per MWh) | ||||||
New England¹ | 36 | 30 | ||||
New York² | 36 | 28 | ||||
PJM3 | 29 | 21 | ||||
Average New York² Spot Capacity Prices (US$ per KW-M) | 3.43 | 5.83 |
1 | New England ISO all hours Mass Hub price. |
2 | Zone J market in New York City where the Ravenswood plant operates. |
3 | The METED Zone price in Pennsylvania where the Ironwood plant operates. Average price for 2016 is from the Ironwood acquisition date of February 1, 2016. |
• | lower realized capacity prices in New York |
• | higher realized power prices at our facilities in New York and New England, partially offset by higher fuel costs and lower generation volumes |
• | higher sales to customers in the PJM and New England wholesale utility markets offset by lower realized margins. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Comparable EBITDA and EBIT | (4 | ) | (1 | ) | ||
Specific items: | ||||||
Acquisition related costs - Columbia | (29 | ) | (26 | ) | ||
Segmented losses | (33 | ) | (27 | ) |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Interest on long-term debt and junior subordinated notes | ||||||
Canadian dollar-denominated | (108 | ) | (111 | ) | ||
U.S. dollar-denominated | (317 | ) | (246 | ) | ||
Foreign exchange impact | (103 | ) | (85 | ) | ||
(528 | ) | (442 | ) | |||
Other interest and amortization expense | (17 | ) | (19 | ) | ||
Capitalized interest | 45 | 41 | ||||
Interest expense | (500 | ) | (420 | ) |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Canadian dollar-denominated | 50 | 41 | ||||
U.S. dollar-denominated | 38 | 45 | ||||
Foreign exchange impact | 13 | 15 | ||||
Allowance for funds used during construction | 101 | 101 |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Interest income and other included in comparable earnings | 5 | 47 | ||||
Specific item: | ||||||
Risk management activities | 15 | 53 | ||||
Interest income and other | 20 | 100 |
• | realized losses in 2017 compared to realized gains in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income |
• | lower unrealized gains on risk management activities in 2017 compared to 2016. These amounts have been excluded from comparable earnings |
• | the impact of a fluctuating U.S. dollar on the translation of foreign currency denominated working capital. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Income tax expense included in comparable earnings | (244 | ) | (180 | ) | ||
Specific items: | ||||||
Acquisition related costs - Columbia | 15 | — | ||||
U.S. Northeast power monetization | 1 | — | ||||
Keystone XL income tax recoveries | 7 | — | ||||
Keystone XL asset costs | 1 | 4 | ||||
Alberta PPA terminations | — | 64 | ||||
TC Offshore loss on sale | — | 1 | ||||
Risk management activities | 20 | 41 | ||||
Income tax expense | (200 | ) | (70 | ) |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Net income attributable to non-controlling interests | (90 | ) | (80 | ) |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Preferred share dividends | (41 | ) | (22 | ) |
• | our ability to generate cash flow from operations |
• | our access to capital markets |
• | approximately $9.1 billion of unutilized, unsecured committed credit facilities. |
three months ended March 31 | ||||||||
(unaudited - millions of $, except per share amounts) | 2017 | 2016 | ||||||
Net cash provided by operations | 1,302 | 1,081 | ||||||
Increase in operating working capital | 155 | 132 | ||||||
Funds generated from operations1 | 1,457 | 1,213 | ||||||
Specific items: | ||||||||
Acquisition related costs - Columbia | 32 | 26 | ||||||
Keystone XL asset costs | 8 | 10 | ||||||
U.S. Northeast power monetization | 11 | — | ||||||
Comparable funds generated from operations1 | 1,508 | 1,249 | ||||||
Dividends on preferred shares | (39 | ) | (23 | ) | ||||
Distributions paid to non-controlling interests | (80 | ) | (62 | ) | ||||
Maintenance capital expenditures including equity investments | (167 | ) | (190 | ) | ||||
Comparable distributable cash flow1 | 1,222 | 974 | ||||||
Comparable distributable cash flow per common share | $1.41 | $1.39 |
1 | See the non-GAAP measures section in this MD&A for further discussion of funds generated from operations, comparable funds generated from operations and comparable distributable cash flow. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Canadian Natural Gas Pipelines | 49 | 55 | ||||
U.S. Natural Gas Pipelines | 70 | 71 | ||||
Other | 48 | 64 | ||||
Maintenance capital expenditures including equity investments | 167 | 190 |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Capital spending | ||||||
Capital expenditures | (1,560 | ) | (836 | ) | ||
Capital projects in development | (42 | ) | (67 | ) | ||
(1,602 | ) | (903 | ) | |||
Contributions to equity investments | (192 | ) | (170 | ) | ||
Acquisitions, net of cash acquired | — | (995 | ) | |||
Proceeds from sale of assets, net of transaction costs | — | 6 | ||||
Other distributions from equity investments | 363 | — | ||||
Deferred amounts and other | (85 | ) | 52 | |||
Net cash used in investing activities | (1,516 | ) | (2,010 | ) |
• | expansion of Columbia pipelines |
• | expansion of the NGTL System |
• | construction of Mexico pipelines |
• | expansion of the Canadian Mainline |
• | expansion of the ANR pipeline |
• | construction of the Napanee power generating facility. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Notes payable issued, net | 670 | 1,176 | ||||
Long-term debt issued, net of issue costs | — | 1,992 | ||||
Long-term debt repaid | (1,051 | ) | (1,357 | ) | ||
Junior subordinated notes issued, net of issue costs | 1,982 | — | ||||
Dividends and distributions paid | (419 | ) | (450 | ) | ||
Common shares issued, net of issue costs | 18 | 3 | ||||
Common shares repurchased | — | (14 | ) | |||
Partnership units of TC PipeLines, LP issued, net of issue costs | 92 | 24 | ||||
Common units of Columbia Pipeline Partners LP acquired | (1,205 | ) | — | |||
Net cash provided by financing activities | 87 | 1,374 |
(unaudited - millions of $) Company | Retirement/Repayment date | Type | Amount | Interest rate | |||||||
TRANSCANADA PIPELINES LIMITED | |||||||||||
February 2017 | Acquisition Bridge Facility1 | US $500 | Floating | ||||||||
January 2017 | Medium Term Notes | $300 | 5.10 | % | |||||||
TRANSCANADA PIPELINE USA LTD | |||||||||||
April 2017 | Acquisition Bridge Facility1,2 | US $1,070 | Floating |
1 | This facility was put into place to finance a portion of the Columbia acquisition and bears interest at LIBOR plus an applicable margin. |
2 | Proceeds from the April 19, 2017 sale of TC Hydro were used to partially repay the acquisition bridge facility. |
(unaudited - millions of $) Company | Issue date | Type | Maturity date | Amount | Interest rate | |||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||||
March 2017 | Junior Subordinated Notes1,2 | March 2077 | US $1,500 | 5.55 | % |
1 | The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. |
2 | The Junior subordinated notes were issued to TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. |
Quarterly dividend on our common shares | |
$0.625 per share | |
Payable on July 31, 2017 to shareholders of record at the close of business on June 30, 2017 |
Quarterly dividends on our preferred shares | |
Series 1 | $0.204125 |
Series 2 | $0.14958904 |
Series 3 | $0.1345 |
Series 4 | $0.10969863 |
Payable on June 30, 2017 to shareholders of record at the close of business on May 31, 2017 | |
Series 5 | $0.14143750 |
Series 6 | $0.12796096 |
Series 7 | $0.25 |
Series 9 | $0.265625 |
Payable on July 31, 2017 to shareholders of record at the close of business on June 30, 2017 | |
Series 11 | $0.2375 |
Series 13 | $0.34375 |
Series 15 | $0.30625 |
Payable on May 31, 2017 to shareholders of record at the close of business on May 16, 2017 |
as at May 1, 2017 | ||
Common shares | Issued and outstanding | |
871 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 7 | 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 |
12 million | 8 million |
Amount | Unused capacity | Borrower | Description | Matures | |
$3.0 billion | $3.0 billion | TCPL | Committed, syndicated, revolving, extendible credit facility that supports TCPL's Canadian commercial paper program and for general corporate purposes | December 2021 | |
US$1.5 billion | — | TCPL | Committed, syndicated, senior asset bridge term loan commitment that supports the acquisition of Columbia | June 2018 | |
US$2.0 billion | US$2.0 billion | TCPL | Committed, syndicated, revolving, extendible credit facility that supports TCPL's U.S. commercial paper program | December 2017 | |
US$0.6 billion | — | TCPL USA | Committed, syndicated, senior asset bridge term loan commitment that supports the acquisition of Columbia | June 2018 | |
US$1.0 billion | US$1.0 billion | TCPL USA | Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes, guaranteed by TCPL | December 2017 | |
US$1.0 billion | US$0.5 billion | Columbia | Committed, syndicated, revolving, extendible credit facility that is used for Columbia's general corporate purposes, guaranteed by TCPL | December 2017 | |
US$0.5 billion | US$0.5 billion | TAIL | Committed, syndicated, revolving, extendible credit facility that supports TAIL's commercial paper program, guaranteed by TCPL | December 2017 | |
$2.1 billion | $0.8 billion | TCPL/TCPL USA | Supports the issuance of letters of credit and provides additional liquidity | Demand |
• | accounts receivable |
• | the fair value of derivative assets |
• | cash and cash equivalents |
• | notes receivable. |
three months ended March 31, 2017 | 1.32 | |
three months ended March 31, 2016 | 1.35 |
three months ended March 31 | ||||||
(unaudited - millions of US$) | 2017 | 2016 | ||||
U.S. Natural Gas Pipelines comparable EBIT | 431 | 200 | ||||
Mexico Natural Gas Pipelines comparable EBIT | 89 | 33 | ||||
U.S. Liquids Pipelines comparable EBIT | 135 | 127 | ||||
U.S. Power comparable EBIT | 54 | 44 | ||||
AFUDC on U.S. dollar-denominated projects | 38 | 45 | ||||
Interest on U.S. dollar-denominated long-term debt | (317 | ) | (246 | ) | ||
Capitalized interest on U.S. dollar-denominated capital expenditures | — | 7 | ||||
U.S. dollar non-controlling interests | (68 | ) | (60 | ) | ||
362 | 150 |
March 31, 2017 | December 31, 2016 | |||||||||
(unaudited - millions of Canadian $, unless noted otherwise) | Fair value1 | Notional or principal amount | Fair value1 | Notional or principal amount | ||||||
U.S. dollar cross-currency interest rate swaps (maturing 2017 to 2019)2 | (337 | ) | US 2,000 | (425 | ) | US 2,350 | ||||
U.S. dollar foreign exchange forward contracts | — | — | (7 | ) | US 150 | |||||
(337 | ) | US 2,000 | (432 | ) | US 2,500 |
1 | Fair values equal carrying values. |
2 | In the three months ended March 31, 2017, net realized gains of $1 million (2016 - gains of $2 million) related to the interest component of cross-currency swaps settlements are included in interest expense. |
(unaudited - millions of Canadian $, unless noted otherwise) | March 31, 2017 | December 31, 2016 | ||
Notional amount | 28,400 (US 21,400) | 26,600 (US 19,800) | ||
Fair value | 31,500 (US 23,600) | 29,400 (US 21,900) |
(unaudited - millions of $) | March 31, 2017 | December 31, 2016 | ||||
Other current assets | 413 | 376 | ||||
Intangible and other assets | 153 | 133 | ||||
Accounts payable and other | (607 | ) | (607 | ) | ||
Other long-term liabilities | (334 | ) | (330 | ) | ||
(375 | ) | (428 | ) |
three months ended March 31 | ||||||
(unaudited - millions of $, pre-tax) | 2017 | 2016 | ||||
Derivative instruments held for trading1 | ||||||
Amount of unrealized (losses)/gains in the period | ||||||
Commodities2 | (56 | ) | (67 | ) | ||
Foreign exchange | 15 | 27 | ||||
Interest rate | 1 | — | ||||
Amount of realized (losses)/gains in the period | ||||||
Commodities | (48 | ) | (95 | ) | ||
Foreign exchange | (4 | ) | 44 | |||
Derivative instruments in hedging relationships | ||||||
Amount of realized gains/(losses) in the period | ||||||
Commodities | 6 | (73 | ) | |||
Foreign exchange | 5 | (63 | ) | |||
Interest rate | 1 | 2 |
1 | Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included net in interest expense and interest income and other, respectively. |
2 | Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast power business, a loss of $49 million and a gain of $7 million were recorded in net income in the three months ended March 31, 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale. |
three months ended March 31 | ||||||
(unaudited - millions of $, pre-tax) | 2017 | 2016 | ||||
Change in fair value of derivative instruments recognized in OCI (effective portion)1 | ||||||
Commodities | 5 | (16 | ) | |||
Foreign exchange | — | (35 | ) | |||
Interest rate | 1 | (3 | ) | |||
6 | (54 | ) | ||||
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)1 | ||||||
Commodities2 | (4 | ) | 82 | |||
Foreign exchange3 | — | 34 | ||||
Interest rate4 | 4 | 4 | ||||
— | 120 | |||||
Losses on derivative instruments recognized in net income (ineffective portion) | ||||||
Commodities2 | — | (58 | ) | |||
— | (58 | ) |
1 | No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI. |
2 | Reported within revenues on the condensed consolidated statement of income. |
3 | Reported within interest income and other on the condensed consolidated statement of income. |
4 | Reported within interest expense on the condensed consolidated statement of income. |
three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||
Comparable EBITDA | ||||||
Canadian Natural Gas Pipelines | 504 | 488 | ||||
U.S. Natural Gas Pipelines | 720 | 338 | ||||
Mexico Natural Gas Pipelines | 140 | 53 | ||||
Liquids Pipelines | 312 | 296 | ||||
Energy | 305 | 328 | ||||
Corporate | (4 | ) | (1 | ) | ||
Comparable EBITDA | 1,977 | 1,502 | ||||
Depreciation and amortization | (510 | ) | (454 | ) | ||
Comparable EBIT | 1,467 | 1,048 | ||||
Specific items: | ||||||
Acquisition related costs - Columbia | (39 | ) | (26 | ) | ||
U.S. Northeast power monetization | (11 | ) | — | |||
Keystone XL asset costs | (8 | ) | (10 | ) | ||
Alberta PPA terminations | — | (240 | ) | |||
TC Offshore loss on sale | — | (4 | ) | |||
Risk management activities1 | (56 | ) | (125 | ) | ||
Segmented earnings | 1,353 | 643 |
1 | Risk management activities | three months ended March 31 | ||||||
(unaudited - millions of $) | 2017 | 2016 | ||||||
Canadian Power | 1 | (13 | ) | |||||
U.S. Power | (62 | ) | (115 | ) | ||||
Natural Gas Storage | 5 | 5 | ||||||
Liquids marketing | — | (2 | ) | |||||
Total unrealized losses from risk management activities | (56 | ) | (125 | ) |
2017 | 2016 | 2015 | ||||||||||||||||||||||||||||||
(unaudited - millions of $, except per share amounts) | First | Fourth | Third | Second | First | Fourth | Third | Second | ||||||||||||||||||||||||
Revenues | 3,391 | 3,619 | 3,632 | 2,751 | 2,503 | 2,851 | 2,944 | 2,631 | ||||||||||||||||||||||||
Net income/(loss) attributable to common shares | 643 | (358 | ) | (135 | ) | 365 | 252 | (2,458 | ) | 402 | 429 | |||||||||||||||||||||
Comparable earnings | 698 | 626 | 622 | 366 | 494 | 453 | 440 | 397 | ||||||||||||||||||||||||
Per share statistics | ||||||||||||||||||||||||||||||||
Net income/(loss) per common share - basic and diluted | $0.74 | ($0.43 | ) | ($0.17 | ) | $0.52 | $0.36 | ($3.47 | ) | $0.57 | $0.60 | |||||||||||||||||||||
Comparable earnings per share | $0.81 | $0.75 | $0.78 | $0.52 | $0.70 | $0.64 | $0.62 | $0.56 | ||||||||||||||||||||||||
Dividends declared per common share | $0.625 | $0.565 | $0.565 | $0.565 | $0.565 | $0.52 | $0.52 | $0.52 |
• | regulatory decisions |
• | negotiated settlements with shippers |
• | acquisitions and divestitures |
• | developments outside of the normal course of operations |
• | newly constructed assets being placed in service. |
• | developments outside of the normal course of operations |
• | newly constructed assets being placed in service |
• | regulatory decisions. |
• | weather |
• | customer demand |
• | market prices for natural gas and power |
• | capacity prices and payments |
• | planned and unplanned plant outages |
• | acquisitions and divestitures |
• | certain fair value adjustments |
• | developments outside of the normal course of operations |
• | newly constructed assets being placed in service. |
• | a charge of $24 million after tax for integration-related costs associated with the acquisition of Columbia |
• | a charge of $10 million after tax for costs related to the monetization of our U.S. Northeast power business |
• | a charge of $7 million after tax related to the maintenance of Keystone XL assets which are being expensed pending further advancement of the project |
• | a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our 2015 impairment charge, but the related income tax recoveries could not be recorded until realized |
• | an $870 million after-tax charge related to the loss on U.S. Northeast power assets held for sale which included an $863 million after-tax loss on the thermal and wind package held for sale and $7 million of after-tax costs related to the monetization |
• | an additional $68 million after-tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the Alberta PPA terminations |
• | an after-tax charge of $67 million for costs associated with the acquisition of Columbia which included a $44 million deferred tax adjustment upon acquisition and $23 million of retention, severance and integration costs |
• | an after-tax charge of $18 million related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project |
• | an after-tax restructuring charge of $6 million for additional expected future losses under lease commitments. These charges form part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs. |
• | a $656 million after-tax impairment on Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value |
• | costs associated with the acquisition of Columbia including a charge of $67 million after tax primarily related to retention, severance and integration expenses |
• | $28 million of income tax recoveries related to the realized loss on a third party sale of Keystone XL plant and equipment. A provision for the expected loss on these assets was included in our fourth quarter 2015 impairment charge but the related tax recoveries could not be recorded until realized |
• | a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project |
• | a $3 million after-tax charge related to the monetization of our U.S. Northeast Power business. |
• | a charge of $113 million related to costs associated with the acquisition of Columbia |
• | a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project |
• | a charge of $10 million after tax for restructuring charges mainly related to expected future losses under lease commitments. |
• | a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs |
• | a charge of $26 million related to costs associated with the acquisition of Columbia |
• | a charge of $6 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project |
• | an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016. |
• | a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects |
• | an $86 million after-tax loss provision related to the sale of TC Offshore expected to close in early 2016 |
• | a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges form part of a restructuring initiative which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs |
• | a $43 million after-tax charge related to an impairment in value of turbine equipment held for future use in our Energy business |
• | a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships |
• | a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes. |
three months ended March 31 | ||||||||
(unaudited - millions of Canadian $, except per share amounts) | 2017 | 2016 | ||||||
Revenues | ||||||||
Canadian Natural Gas Pipelines | 882 | 818 | ||||||
U.S. Natural Gas Pipelines | 994 | 429 | ||||||
Mexico Natural Gas Pipelines | 143 | 66 | ||||||
Liquids Pipelines | 472 | 436 | ||||||
Energy | 900 | 754 | ||||||
3,391 | 2,503 | |||||||
Income from Equity Investments | 174 | 135 | ||||||
Operating and Other Expenses | ||||||||
Plant operating costs and other | 990 | 715 | ||||||
Commodity purchases resold | 543 | 470 | ||||||
Property taxes | 162 | 141 | ||||||
Depreciation and amortization | 517 | 454 | ||||||
Asset impairment charges | — | 211 | ||||||
2,212 | 1,991 | |||||||
Loss on sale of assets | — | (4 | ) | |||||
Financial Charges | ||||||||
Interest expense | 500 | 420 | ||||||
Allowance for funds used during construction | (101 | ) | (101 | ) | ||||
Interest income and other | (20 | ) | (100 | ) | ||||
379 | 219 | |||||||
Income before Income Taxes | 974 | 424 | ||||||
Income Tax Expense | ||||||||
Current | 67 | 34 | ||||||
Deferred | 133 | 36 | ||||||
200 | 70 | |||||||
Net Income | 774 | 354 | ||||||
Net income attributable to non-controlling interests | 90 | 80 | ||||||
Net Income Attributable to Controlling Interests | 684 | 274 | ||||||
Preferred share dividends | 41 | 22 | ||||||
Net Income Attributable to Common Shares | 643 | 252 | ||||||
Net Income per Common Share | ||||||||
Basic and diluted | $0.74 | $0.36 | ||||||
Dividends Declared per Common Share | $0.625 | $0.565 | ||||||
Weighted Average Number of Common Shares (millions) | ||||||||
Basic | 866 | 702 | ||||||
Diluted | 868 | 703 |
three months ended March 31 | ||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | ||||
Net Income | 774 | 354 | ||||
Other Comprehensive Loss, Net of Income Taxes | ||||||
Foreign currency translation losses on net investment in foreign operations | (82 | ) | (212 | ) | ||
Change in fair value of net investment hedges | (1 | ) | (2 | ) | ||
Change in fair value of cash flow hedges | 5 | (39 | ) | |||
Reclassification to net income of gains on cash flow hedges | — | 80 | ||||
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 3 | 4 | ||||
Other comprehensive income on equity investments | 3 | 3 | ||||
Other comprehensive loss (Note 9) | (72 | ) | (166 | ) | ||
Comprehensive Income | 702 | 188 | ||||
Comprehensive income/(loss) attributable to non-controlling interests | 50 | (26 | ) | |||
Comprehensive Income Attributable to Controlling Interests | 652 | 214 | ||||
Preferred share dividends | 41 | 22 | ||||
Comprehensive Income Attributable to Common Shares | 611 | 192 |
three months ended March 31 | ||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | ||||
Cash Generated from Operations | ||||||
Net income | 774 | 354 | ||||
Depreciation and amortization | 517 | 454 | ||||
Asset impairment charges | — | 211 | ||||
Deferred income taxes | 133 | 36 | ||||
Income from equity investments | (174 | ) | (135 | ) | ||
Distributions received from operating activities of equity investments | 219 | 259 | ||||
Employee post-retirement benefits expense, net of funding | 3 | 11 | ||||
Loss on sale of assets | — | 4 | ||||
Equity allowance for funds used during construction | (64 | ) | (57 | ) | ||
Unrealized losses on financial instruments | 41 | 71 | ||||
Other | 8 | 5 | ||||
Increase in operating working capital | (155 | ) | (132 | ) | ||
Net cash provided by operations | 1,302 | 1,081 | ||||
Investing Activities | ||||||
Capital expenditures | (1,560 | ) | (836 | ) | ||
Capital projects in development | (42 | ) | (67 | ) | ||
Contributions to equity investments | (192 | ) | (170 | ) | ||
Acquisitions, net of cash acquired | — | (995 | ) | |||
Proceeds from sale of assets, net of transaction costs | — | 6 | ||||
Other distributions from equity investments | 363 | — | ||||
Deferred amounts and other | (85 | ) | 52 | |||
Net cash used in investing activities | (1,516 | ) | (2,010 | ) | ||
Financing Activities | ||||||
Notes payable issued, net | 670 | 1,176 | ||||
Long-term debt issued, net of issue costs | — | 1,992 | ||||
Long-term debt repaid | (1,051 | ) | (1,357 | ) | ||
Junior subordinated notes issued, net of issue costs | 1,982 | — | ||||
Dividends on common shares | (300 | ) | (365 | ) | ||
Dividends on preferred shares | (39 | ) | (23 | ) | ||
Distributions paid to non-controlling interests | (80 | ) | (62 | ) | ||
Common shares issued, net of issue costs | 18 | 3 | ||||
Common shares repurchased | — | (14 | ) | |||
Partnership units of TC PipeLines, LP issued, net of issue costs | 92 | 24 | ||||
Common units of Columbia Pipeline Partners LP acquired | (1,205 | ) | — | |||
Net cash provided by financing activities | 87 | 1,374 | ||||
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents | 5 | (57 | ) | |||
(Decrease)/increase in Cash and Cash Equivalents | (122 | ) | 388 | |||
Cash and Cash Equivalents | ||||||
Beginning of period | 1,016 | 850 | ||||
Cash and Cash Equivalents | ||||||
End of period | 894 | 1,238 |
March 31, | December 31, | ||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | |||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | 894 | 1,016 | |||||
Accounts receivable | 2,120 | 2,075 | |||||
Inventories | 384 | 368 | |||||
Assets held for sale | 3,687 | 3,717 | |||||
Other | 918 | 908 | |||||
8,003 | 8,084 | ||||||
Plant, Property and Equipment | net of accumulated depreciation of $22,696 and $22,263, respectively | 55,353 | 54,475 | ||||
Equity Investments | 6,262 | 6,544 | |||||
Regulatory Assets | 1,325 | 1,322 | |||||
Goodwill | 13,849 | 13,958 | |||||
Intangible and Other Assets | 3,148 | 3,026 | |||||
Restricted Investments | 699 | 642 | |||||
88,639 | 88,051 | ||||||
LIABILITIES | |||||||
Current Liabilities | |||||||
Notes payable | 1,493 | 774 | |||||
Accounts payable and other | 3,806 | 3,861 | |||||
Dividends payable | 557 | 526 | |||||
Accrued interest | 549 | 595 | |||||
Liabilities related to assets held for sale | 60 | 86 | |||||
Current portion of long-term debt | 2,669 | 1,838 | |||||
9,134 | 7,680 | ||||||
Regulatory Liabilities | 2,259 | 2,121 | |||||
Other Long-Term Liabilities | 1,134 | 1,183 | |||||
Deferred Income Tax Liabilities | 7,749 | 7,662 | |||||
Long-Term Debt | 36,163 | 38,312 | |||||
Junior Subordinated Notes | 5,879 | 3,931 | |||||
62,318 | 60,889 | ||||||
Common Units Subject to Rescission or Redemption | 82 | 1,179 | |||||
EQUITY | |||||||
Common shares, no par value | 20,308 | 20,099 | |||||
Issued and outstanding: | March 31, 2017 - 867 million shares | ||||||
December 31, 2016 - 864 million shares | |||||||
Preferred shares | 3,980 | 3,980 | |||||
Additional paid-in capital | — | — | |||||
Retained earnings | 1,115 | 1,138 | |||||
Accumulated other comprehensive loss | (992 | ) | (960 | ) | |||
Controlling Interests | 24,411 | 24,257 | |||||
Non-controlling interests | 1,828 | 1,726 | |||||
26,239 | 25,983 | ||||||
88,639 | 88,051 |
three months ended March 31 | |||||
(unaudited - millions of Canadian $) | 2017 | 2016 | |||
Common Shares | |||||
Balance at beginning of period | 20,099 | 12,102 | |||
Shares issued on exercise of stock options | 19 | 3 | |||
Shares repurchased | — | (6 | ) | ||
Shares issued under dividend reinvestment and share purchase plan | 190 | — | |||
Balance at end of period | 20,308 | 12,099 | |||
Preferred Shares | |||||
Balance at beginning and end of period | 3,980 | 2,499 | |||
Additional Paid-In Capital | |||||
Balance at beginning of period | — | 7 | |||
Issuance of stock options, net of exercises | 2 | 5 | |||
Dilution impact from TC PipeLines, LP units issued | 10 | 3 | |||
Impact of common shares repurchased | — | (8 | ) | ||
Impact of asset drop down to TC PipeLines, LP | — | (38 | ) | ||
Impact of Columbia Pipeline Partners LP acquisition | (171 | ) | — | ||
Reclassification of Additional Paid-In Capital deficit to Retained Earnings | 159 | 31 | |||
Balance at end of period | — | — | |||
Retained Earnings | |||||
Balance at beginning of period | 1,138 | 2,769 | |||
Net income attributable to controlling interests | 684 | 274 | |||
Common share dividends | (542 | ) | (397 | ) | |
Preferred share dividends | (18 | ) | (21 | ) | |
Adjustment related to employee share-based payments (Note 2) | 12 | — | |||
Reclassification of Additional Paid-In Capital deficit to Retained Earnings | (159 | ) | (31 | ) | |
Balance at end of period | 1,115 | 2,594 | |||
Accumulated Other Comprehensive Loss | |||||
Balance at beginning of period | (960 | ) | (939 | ) | |
Other comprehensive loss | (32 | ) | (60 | ) | |
Balance at end of period | (992 | ) | (999 | ) | |
Equity Attributable to Controlling Interests | 24,411 | 16,193 | |||
Equity Attributable to Non-Controlling Interests | |||||
Balance at beginning of period | 1,726 | 1,717 | |||
Net income attributable to non-controlling interests | |||||
TC PipeLines, LP | 73 | 71 | |||
Portland Natural Gas Transmission System | 8 | 9 | |||
Columbia Pipeline Partners LP | 9 | — | |||
Other comprehensive loss attributable to non-controlling interests | (40 | ) | (106 | ) | |
Issuance of TC PipeLines, LP units | |||||
Proceeds, net of issue costs | 92 | 24 | |||
Decrease in TransCanada's ownership of TC PipeLines, LP | (17 | ) | (4 | ) | |
Reclassification from common units subject to rescission | 24 | — | |||
Distributions declared to non-controlling interests | (80 | ) | (68 | ) | |
Impact of Columbia Pipeline Partners LP acquisition | 33 | — | |||
Balance at end of period | 1,828 | 1,643 | |||
Total Equity | 26,239 | 17,836 |
three months ended March 31, 2017 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | |||||||||||||||||
(unaudited - millions of Canadian $) | Energy | Corporate | Total | ||||||||||||||||||
Revenues | 882 | 994 | 143 | 472 | 900 | — | 3,391 | ||||||||||||||
Income from equity investments | 3 | 65 | 6 | — | 100 | — | 174 | ||||||||||||||
Plant operating costs and other | (312 | ) | (295 | ) | (9 | ) | (145 | ) | (196 | ) | (33 | ) | (990 | ) | |||||||
Commodity purchases resold | — | — | — | — | (543 | ) | — | (543 | ) | ||||||||||||
Property taxes | (69 | ) | (47 | ) | — | (23 | ) | (23 | ) | — | (162 | ) | |||||||||
Depreciation and amortization | (222 | ) | (156 | ) | (22 | ) | (77 | ) | (40 | ) | — | (517 | ) | ||||||||
Segmented earnings/(losses) | 282 | 561 | 118 | 227 | 198 | (33 | ) | 1,353 | |||||||||||||
Interest expense | (500 | ) | |||||||||||||||||||
Allowance for funds used during construction | 101 | ||||||||||||||||||||
Interest income and other | 20 | ||||||||||||||||||||
Income before income taxes | 974 | ||||||||||||||||||||
Income tax expense | (200 | ) | |||||||||||||||||||
Net income | 774 | ||||||||||||||||||||
Net income attributable to non-controlling interests | (90 | ) | |||||||||||||||||||
Net income attributable to controlling interests | 684 | ||||||||||||||||||||
Preferred share dividends | (41 | ) | |||||||||||||||||||
Net income attributable to common shares | 643 |
three months ended March 31, 2016 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | |||||||||||||||||
(unaudited - millions of Canadian $) | Energy | Corporate | Total | ||||||||||||||||||
Revenues | 818 | 429 | 66 | 436 | 754 | — | 2,503 | ||||||||||||||
Income from equity investments | 3 | 48 | — | — | 84 | — | 135 | ||||||||||||||
Plant operating costs and other | (260 | ) | (118 | ) | (13 | ) | (129 | ) | (168 | ) | (27 | ) | (715 | ) | |||||||
Commodity purchases resold | — | — | — | — | (470 | ) | — | (470 | ) | ||||||||||||
Property taxes | (73 | ) | (21 | ) | — | (23 | ) | (24 | ) | — | (141 | ) | |||||||||
Depreciation and amortization | (216 | ) | (67 | ) | (8 | ) | (72 | ) | (91 | ) | — | (454 | ) | ||||||||
Asset impairment charges | — | — | — | — | (211 | ) | — | (211 | ) | ||||||||||||
Loss on assets held for sale | — | (4 | ) | — | — | — | — | (4 | ) | ||||||||||||
Segmented earnings/(losses) | 272 | 267 | 45 | 212 | (126 | ) | (27 | ) | 643 | ||||||||||||
Interest expense | (420 | ) | |||||||||||||||||||
Allowance for funds used during construction | 101 | ||||||||||||||||||||
Interest income and other | 100 | ||||||||||||||||||||
Income before income taxes | 424 | ||||||||||||||||||||
Income tax expense | (70 | ) | |||||||||||||||||||
Net Income | 354 | ||||||||||||||||||||
Net income attributable to non-controlling interests | (80 | ) | |||||||||||||||||||
Net Income attributable to controlling interests | 274 | ||||||||||||||||||||
Preferred share dividends | (22 | ) | |||||||||||||||||||
Net Income attributable to common shares | 252 |
(unaudited - millions of Canadian $) | March 31, 2017 | December 31, 2016 | ||||
Canadian Natural Gas Pipelines | 16,255 | 15,816 | ||||
U.S. Natural Gas Pipelines | 34,934 | 34,422 | ||||
Mexico Natural Gas Pipelines | 5,230 | 5,013 | ||||
Liquids Pipelines | 16,995 | 16,896 | ||||
Energy | 12,832 | 13,169 | ||||
Corporate | 2,393 | 2,735 | ||||
88,639 | 88,051 |
(millions of $) | U.S. | Canadian1 | |||||
Assets held for sale | |||||||
Accounts receivable | 10 | 13 | |||||
Inventories | 56 | 74 | |||||
Other current assets | 73 | 97 | |||||
Plant, property and equipment | 2,242 | 2,986 | 2 | ||||
Intangible and other assets | 335 | 447 | |||||
Foreign currency translation gains | — | 70 | 3 | ||||
Total assets held for sale | 2,716 | 3,687 | |||||
Liabilities related to assets held for sale | |||||||
Accounts payable and other | 21 | 28 | |||||
Other long-term liabilities | 24 | 32 | |||||
Total liabilities related to assets held for sale | 45 | 60 |
1 | At March 31, 2017 exchange rate of $1.33. |
2 | Includes $17 million (US$13 million) for a gas plant held for sale in the U.S. Natural Gas Pipelines segment. |
3 | Foreign currency translation gains related to the investments in Ravenswood, Ironwood, Kibby Wind and Ocean State Power will be reclassified from AOCI to Net Income on close of the sales. |
(unaudited - millions of Canadian $, unless noted otherwise) Company | Retirement/Repayment date | Type | Amount | Interest rate | ||||||
TRANSCANADA PIPELINES LIMITED | ||||||||||
February 2017 | Acquisition Bridge Facility1 | US$500 | Floating | |||||||
January 2017 | Medium Term Notes | $300 | 5.10 | % |
1 | This facility was put into place to finance a portion of the Columbia acquisition and bears interest at LIBOR plus an applicable margin. |
(unaudited - millions of Canadian $, unless noted otherwise) Company | Issue date | Type | Maturity date | Amount | Interest rate | |||||||
TRANSCANADA PIPELINES LIMITED | March 2017 | Junior Subordinated Notes1,2 | March 2077 | US $1,500 | 5.55 | % |
1 | The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. |
2 | The Junior subordinated notes were issued to TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. |
three months ended March 31, 2017 | Income Tax | ||||||||
(unaudited - millions of Canadian $) | Before Tax Amount | Recovery/Expense | Net of Tax Amount | ||||||
Foreign currency translation losses on net investment in foreign operations | (88 | ) | 6 | (82 | ) | ||||
Change in fair value of net investment hedges | (2 | ) | 1 | (1 | ) | ||||
Change in fair value of cash flow hedges | 6 | (1 | ) | 5 | |||||
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 5 | (2 | ) | 3 | |||||
Other comprehensive income on equity investments | 4 | (1 | ) | 3 | |||||
Other comprehensive loss | (75 | ) | 3 | (72 | ) |
three months ended March 31, 2016 | Income Tax | ||||||||
(unaudited - millions of Canadian $) | Before Tax Amount | Recovery/Expense | Net of Tax Amount | ||||||
Foreign currency translation losses on net investment in foreign operations | (210 | ) | (2 | ) | (212 | ) | |||
Change in fair value of net investment hedges | (3 | ) | 1 | (2 | ) | ||||
Change in fair value of cash flow hedges | (54 | ) | 15 | (39 | ) | ||||
Reclassification to net income of gains on cash flow hedges | 120 | (40 | ) | 80 | |||||
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans | 5 | (1 | ) | 4 | |||||
Other comprehensive income on equity investments | 4 | (1 | ) | 3 | |||||
Other comprehensive loss | (138 | ) | (28 | ) | (166 | ) |
three months ended March 31, 2017 | Currency | Pension and | |||||||||||||
(unaudited - millions of Canadian $) | Translation Adjustments | Cash Flow Hedges | OPEB Plan Adjustments | Equity Investments | Total1 | ||||||||||
AOCI balance at January 1, 2017 | (376 | ) | (28 | ) | (208 | ) | (348 | ) | (960 | ) | |||||
Other comprehensive (loss)/income before reclassifications2 | (42 | ) | 4 | — | — | (38 | ) | ||||||||
Amounts reclassified from accumulated other comprehensive loss | — | — | 3 | 3 | 6 | ||||||||||
Net current period other comprehensive (loss)/income3 | (42 | ) | 4 | 3 | 3 | (32 | ) | ||||||||
AOCI balance at March 31, 2017 | (418 | ) | (24 | ) | (205 | ) | (345 | ) | (992 | ) |
1 | All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. |
2 | Other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $41 million and gains of $1 million. |
3 | Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $2 million ($1 million, net of tax) at March 31, 2017. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. |
Amounts reclassified from accumulated other comprehensive loss1 | Affected line item in the condensed consolidated statement of income | ||||||
three months ended March 31 | |||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | |||||
Cash flow hedges | |||||||
Commodities | 4 | (82 | ) | Revenue (Energy) | |||
Foreign exchange | — | (34 | ) | Interest income and other | |||
Interest rate | (4 | ) | (4 | ) | Interest expense | ||
— | (120 | ) | Total before tax | ||||
— | 40 | Income tax expense | |||||
— | (80 | ) | Net of tax | ||||
Pension and other post-retirement benefit plan adjustments | |||||||
Amortization of actuarial loss | (4 | ) | (5 | ) | Plant operating costs 2 | ||
2 | 1 | Income tax expense | |||||
(2 | ) | (4 | ) | Net of tax | |||
Equity investments | |||||||
Equity income | (4 | ) | (4 | ) | Income from equity investments | ||
1 | 1 | Income tax expense | |||||
(3 | ) | (3 | ) | Net of tax |
1 | All amounts in parentheses indicate expenses to the condensed consolidated statement of income. |
2 | These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 10 for additional detail. |
three months ended March 31 | ||||||||||||
Pension benefit plans | Other post-retirement benefit plans | |||||||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | 2017 | 2016 | ||||||||
Service cost | 29 | 26 | 1 | 1 | ||||||||
Interest cost | 34 | 30 | 4 | 2 | ||||||||
Expected return on plan assets | (50 | ) | (40 | ) | (5 | ) | — | |||||
Amortization of actuarial loss | 4 | 4 | — | 1 | ||||||||
Amortization of regulatory asset | 6 | 4 | — | — | ||||||||
Net benefit cost recognized | 23 | 24 | — | 4 |
(unaudited - millions of Canadian $, unless noted otherwise) | March 31, 2017 | December 31, 2016 | ||
Notional amount | 28,400 (US 21,400) | 26,600 (US 19,800) | ||
Fair value | 31,500 (US 23,600) | 29,400 (US 21,900) |
March 31, 2017 | December 31, 2016 | |||||||||
(unaudited - millions of Canadian $, unless noted otherwise) | Fair value1 | Notional or principal amount | Fair value1 | Notional or principal amount | ||||||
U.S. dollar cross-currency interest rate swaps (maturing 2017 to 2019)2 | (337 | ) | US 2,000 | (425 | ) | US 2,350 | ||||
U.S. dollar foreign exchange forward contracts | — | — | (7 | ) | US 150 | |||||
(337 | ) | US 2,000 | (432 | ) | US 2,500 |
1 | Fair values equal carrying values. |
2 | In the three months ended March 31, 2017, net realized gains of $1 million (2016 - gains of $2 million) related to the interest component of cross-currency swap settlements are included in interest expense. |
March 31, 2017 | December 31, 2016 | |||||||||||
(unaudited - millions of Canadian $) | Carrying amount | Fair value | Carrying amount | Fair value | ||||||||
Notes receivable1 | 115 | 158 | 165 | 211 | ||||||||
Current and long-term debt2,3 | (38,832 | ) | (43,770 | ) | (40,150 | ) | (45,047 | ) | ||||
Junior subordinated notes | (5,879 | ) | (6,021 | ) | (3,931 | ) | (3,825 | ) | ||||
(44,596 | ) | (49,633 | ) | (43,916 | ) | (48,661 | ) |
1 | Notes receivable are included in Assets held for sale on the condensed consolidated balance sheet. The fair value is calculated based on the original contract terms. |
2 | Long-term debt is recorded at amortized cost except for US$850 million (December 31, 2016 - US$850 million) that is attributed to hedged risk and recorded at fair value. |
3 | Consolidated net income for the three months ended March 31, 2017 included unrealized gains of $2 million (2016 - losses of $12 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of long-term debt at March 31, 2017 (December 31, 2016 - US$850 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. |
March 31, 2017 | December 31, 2016 | ||||||||||
(unaudited - millions of Canadian $) | LMCI restricted investments | Other restricted investments2 | LMCI restricted investments | Other restricted investments2 | |||||||
Fair Values1 | |||||||||||
Fixed income securities (maturing within 1 year) | — | 27 | — | 19 | |||||||
Fixed income securities (maturing within 1-5 years) | — | 106 | — | 117 | |||||||
Fixed income securities (maturing within 5-10 years) | 13 | — | 9 | — | |||||||
Fixed income securities (maturing after 10 years) | 572 | — | 513 | — | |||||||
585 | 133 | 522 | 136 |
1 | Available for sale assets are recorded at fair value and included in other current assets and restricted investments on the condensed consolidated balance sheet. |
2 | Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. |
March 31, 2017 | March 31, 2016 | |||||||||||
(unaudited - millions of Canadian $) | LMCI restricted investments1 | Other restricted investments2 | LMCI restricted investments1 | Other restricted investments2 | ||||||||
Net unrealized gains in the period | ||||||||||||
three months ended | 2 | — | 5 | 1 |
1 | Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. |
2 | Unrealized gains and losses on other restricted investments are included in OCI. |
at March 31, 2017 | Cash Flow Hedges | Fair Value Hedges | Net Investment Hedges | Held for Trading | Total Fair Value of Derivative Instruments1 | |||||||||
(unaudited - millions of Canadian $) | ||||||||||||||
Other current assets | ||||||||||||||
Commodities2 | 9 | — | — | 387 | 396 | |||||||||
Foreign exchange | — | — | 4 | 9 | 13 | |||||||||
Interest rate | 2 | — | — | 2 | 4 | |||||||||
11 | — | 4 | 398 | 413 | ||||||||||
Intangible and other assets | ||||||||||||||
Commodities2 | 3 | — | — | 141 | 144 | |||||||||
Foreign exchange | — | — | 8 | — | 8 | |||||||||
Interest rate | 1 | — | — | — | 1 | |||||||||
4 | — | 8 | 141 | 153 | ||||||||||
Total Derivative Assets | 15 | — | 12 | 539 | 566 | |||||||||
Accounts payable and other | ||||||||||||||
Commodities2 | — | — | — | (373 | ) | (373 | ) | |||||||
Foreign exchange | — | — | (209 | ) | (22 | ) | (231 | ) | ||||||
Interest rate | (1 | ) | (2 | ) | — | — | (3 | ) | ||||||
(1 | ) | (2 | ) | (209 | ) | (395 | ) | (607 | ) | |||||
Other long-term liabilities | ||||||||||||||
Commodities2 | (1 | ) | — | — | (192 | ) | (193 | ) | ||||||
Foreign exchange | — | — | (140 | ) | — | (140 | ) | |||||||
Interest rate | — | (1 | ) | — | — | (1 | ) | |||||||
(1 | ) | (1 | ) | (140 | ) | (192 | ) | (334 | ) | |||||
Total Derivative Liabilities | (2 | ) | (3 | ) | (349 | ) | (587 | ) | (941 | ) | ||||
Total Derivatives | 13 | (3 | ) | (337 | ) | (48 | ) | (375 | ) |
1 | Fair value equals carrying value. |
2 | Includes purchases and sales of power, natural gas and liquids. |
at December 31, 2016 | Cash Flow Hedges | Fair Value Hedges | Net Investment Hedges | Held for Trading | Total Fair Value of Derivative Instruments1 | |||||||||
(unaudited - millions of Canadian $) | ||||||||||||||
Other current assets | ||||||||||||||
Commodities2 | 6 | — | — | 351 | 357 | |||||||||
Foreign exchange | — | — | 6 | 10 | 16 | |||||||||
Interest rate | 1 | 1 | — | 1 | 3 | |||||||||
7 | 1 | 6 | 362 | 376 | ||||||||||
Intangible and other assets | ||||||||||||||
Commodities2 | 4 | — | — | 118 | 122 | |||||||||
Foreign exchange | — | — | 10 | — | 10 | |||||||||
Interest rate | 1 | — | — | — | 1 | |||||||||
5 | — | 10 | 118 | 133 | ||||||||||
Total Derivative Assets | 12 | 1 | 16 | 480 | 509 | |||||||||
Accounts payable and other | ||||||||||||||
Commodities2 | — | — | — | (330 | ) | (330 | ) | |||||||
Foreign exchange | — | — | (237 | ) | (38 | ) | (275 | ) | ||||||
Interest rate | (1 | ) | (1 | ) | — | — | (2 | ) | ||||||
(1 | ) | (1 | ) | (237 | ) | (368 | ) | (607 | ) | |||||
Other long-term liabilities | ||||||||||||||
Commodities2 | — | — | — | (118 | ) | (118 | ) | |||||||
Foreign exchange | — | — | (211 | ) | — | (211 | ) | |||||||
Interest rate | — | (1 | ) | — | — | (1 | ) | |||||||
— | (1 | ) | (211 | ) | (118 | ) | (330 | ) | ||||||
Total Derivative Liabilities | (1 | ) | (2 | ) | (448 | ) | (486 | ) | (937 | ) | ||||
Total Derivatives | 11 | (1 | ) | (432 | ) | (6 | ) | (428 | ) |
1 | Fair value equals carrying value. |
2 | Includes purchases and sales of power, natural gas and liquids. |
at March 31, 2017 | Power | Natural Gas | Liquids | Foreign Exchange | Interest | |||||||||
(unaudited) | ||||||||||||||
Purchases1 | 104,858 | 222 | 12 | — | — | |||||||||
Sales1 | 66,420 | 202 | 14 | — | — | |||||||||
Millions of U.S. dollars | — | — | — | US 2,513 | US 2,600 | |||||||||
Millions of Mexican pesos | — | — | — | MXN 500 | — | |||||||||
Maturity dates | 2017-2021 | 2017-2020 | 2017 | 2017-2018 | 2017-2019 |
1 | Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively. |
at December 31, 2016 | Power | Natural Gas | Liquids | Foreign Exchange | Interest | |||||||||
(unaudited) | ||||||||||||||
Purchases1 | 86,887 | 182 | 6 | — | — | |||||||||
Sales1 | 58,561 | 147 | 6 | — | — | |||||||||
Millions of U.S. dollars | — | — | — | US 2,394 | US 1,550 | |||||||||
Maturity dates | 2017-2021 | 2017-2020 | 2017 | 2017 | 2017-2019 |
1 | Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively. |
three months ended March 31 | ||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | ||||
Derivative instruments held for trading1 | ||||||
Amount of unrealized (losses)/gains in the period | ||||||
Commodities2 | (56 | ) | (67 | ) | ||
Foreign exchange | 15 | 27 | ||||
Interest rate | 1 | — | ||||
Amount of realized (losses)/gains in the period | ||||||
Commodities | (48 | ) | (95 | ) | ||
Foreign exchange | (4 | ) | 44 | |||
Derivative instruments in hedging relationships | ||||||
Amount of realized gains/(losses) in the period | ||||||
Commodities | 6 | (73 | ) | |||
Foreign exchange | 5 | (63 | ) | |||
Interest rate | 1 | 2 |
1 | Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively. |
2 | Following the March 17, 2016 announcement of the Company's intention to sell the U.S. Northeast power assets, a loss of $49 million and a gain of $7 million were recorded in net income in the three months ended March 31, 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale. |
three months ended March 31 | ||||||
(unaudited - millions of Canadian $, pre-tax) | 2017 | 2016 | ||||
Change in fair value of derivative instruments recognized in OCI (effective portion)1 | ||||||
Commodities | 5 | (16 | ) | |||
Foreign exchange | — | (35 | ) | |||
Interest rate | 1 | (3 | ) | |||
6 | (54 | ) | ||||
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)1 | ||||||
Commodities2 | (4 | ) | 82 | |||
Foreign exchange3 | — | 34 | ||||
Interest rate4 | 4 | 4 | ||||
— | 120 | |||||
Losses on derivative instruments recognized in net income (ineffective portion) | ||||||
Commodities2 | — | (58 | ) | |||
— | (58 | ) |
1 | No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI. |
2 | Reported within revenues on the condensed consolidated statement of income. |
3 | Reported within interest income and other on the condensed consolidated statement of income. |
4 | Reported within interest expense on the condensed consolidated statement of income. |
at March 31, 2017 | Gross derivative instruments presented on the balance sheet | Amounts available for offset1 | Net amounts | ||||||
(unaudited - millions of Canadian $) | |||||||||
Derivative - Asset | |||||||||
Commodities | 540 | (333 | ) | 207 | |||||
Foreign exchange | 21 | (20 | ) | 1 | |||||
Interest rate | 5 | (2 | ) | 3 | |||||
Total | 566 | (355 | ) | 211 | |||||
Derivative - Liability | |||||||||
Commodities | (566 | ) | 333 | (233 | ) | ||||
Foreign exchange | (371 | ) | 20 | (351 | ) | ||||
Interest rate | (4 | ) | 2 | (2 | ) | ||||
Total | (941 | ) | 355 | (586 | ) |
1 | Amounts available for offset do not include cash collateral pledged or received. |
at December 31, 2016 | Gross derivative instruments presented on the balance sheet | Amounts available for offset1 | Net amounts | ||||||
(unaudited - millions of Canadian $) | |||||||||
Derivative - Asset | |||||||||
Commodities | 479 | (362 | ) | 117 | |||||
Foreign exchange | 26 | (26 | ) | — | |||||
Interest rate | 4 | (1 | ) | 3 | |||||
Total | 509 | (389 | ) | 120 | |||||
Derivative - Liability | |||||||||
Commodities | (448 | ) | 362 | (86 | ) | ||||
Foreign exchange | (486 | ) | 26 | (460 | ) | ||||
Interest rate | (3 | ) | 1 | (2 | ) | ||||
Total | (937 | ) | 389 | (548 | ) |
1 | Amounts available for offset do not include cash collateral pledged or received. |
Levels | How fair value has been determined |
Level I | Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. |
Level II | Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances. |
Level III | Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category mainly includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. Valuation of options is based on the Black-Scholes pricing model. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data become available, they are transferred out of Level III and into Level II. |
at March 31, 2017 | Quoted prices in active markets | Significant other observable inputs | Significant unobservable inputs | |||||||||
(unaudited - millions of Canadian $) | (Level I)1 | (Level II)1 | (Level III)1 | Total | ||||||||
Derivative instrument assets: | ||||||||||||
Commodities | 82 | 433 | 25 | 540 | ||||||||
Foreign exchange | — | 21 | — | 21 | ||||||||
Interest rate | — | 5 | — | 5 | ||||||||
Derivative instrument liabilities: | ||||||||||||
Commodities | (64 | ) | (487 | ) | (15 | ) | (566 | ) | ||||
Foreign exchange | — | (371 | ) | — | (371 | ) | ||||||
Interest rate | — | (4 | ) | — | (4 | ) | ||||||
18 | (403 | ) | 10 | (375 | ) |
1 | There were no transfers from Level I to Level II or from Level II to Level III for the three months ended March 31, 2017. |
at December 31, 2016 | Quoted prices in active markets (Level I)1 | Significant other observable inputs (Level II)1 | Significant unobservable inputs (Level III)1 | |||||||||
(unaudited - millions of Canadian $) | Total | |||||||||||
Derivative instrument assets: | ||||||||||||
Commodities | 134 | 326 | 19 | 479 | ||||||||
Foreign exchange | — | 26 | — | 26 | ||||||||
Interest rate | — | 4 | — | 4 | ||||||||
Derivative instrument liabilities: | ||||||||||||
Commodities | (102 | ) | (343 | ) | (3 | ) | (448 | ) | ||||
Foreign exchange | — | (486 | ) | — | (486 | ) | ||||||
Interest rate | — | (3 | ) | — | (3 | ) | ||||||
32 | (476 | ) | 16 | (428 | ) |
1 | There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016. |
three months ended March 31 | ||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | ||||
Balance at beginning of period | 16 | 9 | ||||
Transfers out of Level III | (4 | ) | (3 | ) | ||
Sales | (2 | ) | (1 | ) | ||
Settlements | — | 1 | ||||
Total gains included in net income | — | 3 | ||||
Balance at end of period1 | 10 | 9 |
1 | For the three months ended March 31, 2017, revenues include unrealized losses of less than $1 million attributed to derivatives in the Level III category that were still held at March 31, 2017 (2016 - gains of $2 million). |
at March 31, 2017 | at December 31, 2016 | |||||||||||||
(unaudited - millions of Canadian $) | Term | Potential exposure1 | Carrying value | Potential exposure1 | Carrying value | |||||||||
Sur de Texas | ranging to 2020 | 758 | 10 | 805 | 53 | |||||||||
Bruce Power | ranging to 2018 | 88 | 1 | 88 | 1 | |||||||||
Other jointly owned entities | ranging to 2059 | 111 | 16 | 87 | 28 | |||||||||
957 | 27 | 980 | 82 |
1 | TransCanada’s share of the potential estimated current or contingent exposure. |
March 31, | December 31, | ||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | |||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | 92 | 77 | |||||
Accounts receivable | 62 | 71 | |||||
Inventories | 24 | 25 | |||||
Other | 7 | 10 | |||||
185 | 183 | ||||||
Plant, Property and Equipment | 3,627 | 3,685 | |||||
Equity Investments | 595 | 606 | |||||
Goodwill | 521 | 525 | |||||
Intangible and Other Assets | 1 | 1 | |||||
4,929 | 5,000 | ||||||
LIABILITIES | |||||||
Current Liabilities | |||||||
Accounts payable and other | 94 | 80 | |||||
Accrued interest | 22 | 21 | |||||
Current portion of long-term debt | 72 | 76 | |||||
188 | 177 | ||||||
Regulatory Liabilities | 34 | 34 | |||||
Other Long-Term Liabilities | 4 | 4 | |||||
Deferred Income Tax Liabilities | 7 | 7 | |||||
Long-Term Debt | 2,723 | 2,827 | |||||
2,956 | 3,049 |
March 31, | December 31, | ||||||
(unaudited - millions of Canadian $) | 2017 | 2016 | |||||
Balance sheet | |||||||
Equity investments | 4,642 | 4,964 | |||||
Off-balance sheet | |||||||
Potential exposure to guarantees | 176 | 163 | |||||
Maximum exposure to loss | 4,818 | 5,127 |
1. | I have reviewed this quarterly report on Form 6-K of TransCanada Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and |
5. | The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting. |
Dated: May 5, 2017 | /s/ Russell K. Girling |
Russell K. Girling | |
President and Chief Executive Officer |
1. | I have reviewed this quarterly report on Form 6-K of TransCanada Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and |
5. | The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting. |
Dated: May 5, 2017 | /s/ Donald R. Marchand |
Donald R. Marchand | |
Executive Vice-President and Chief Financial Officer |
1. | the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Russell K. Girling | |
Russell K. Girling | |
Chief Executive Officer | |
May 5, 2017 |
1. | the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Donald R. Marchand | |
Donald R. Marchand | |
Chief Financial Officer | |
May 5, 2017 |
QuarterlyReport to Shareholders | ![]() | |
• | First quarter 2017 financial results |
• | Declared a quarterly dividend of $0.625 per common share for the quarter ending June 30, 2017 |
• | Acquired all outstanding publicly held units of Columbia Pipeline Partners LP (CPPL) for a total of US$921 million |
• | Filed a variance application with the National Energy Board (NEB) for the $1.4 billion North Montney project to remove the condition requiring a positive Final Investment Decision (FID) for the Pacific Northwest LNG project. The amended project is supported by 20-year contracts with 11 shippers |
• | Successfully concluded an open season on the Canadian Mainline for 1.5 petajoules per day (PJ/d) of 10 year transportation service from Empress, Alberta to the Dawn hub in Southern Ontario |
• | Received Federal Energy Regulatory Commission (FERC) approvals and began construction on the Leach XPress and Rayne XPress projects. Also received an Environmental Assessment on WB XPress |
• | Received a U.S. Presidential Permit authorizing construction of the U.S./Canada border crossing facilities of the Keystone XL pipeline. We also filed an application with the Nebraska Public Service Commission seeking approval for the Keystone XL pipeline route through that state |
• | Raised US$1.5 billion in gross proceeds through an offering of Junior Subordinated Notes maturing in 2077 |
• | In April, closed the sale of a portion of our U.S. Northeast power business for US$1.065 billion; the proceeds were used to repay a portion of the acquisition bridge facilities which partially financed the Columbia acquisition |
• | In May, announced agreements to sell a 49.3 per cent interest in Iroquois Gas Transmission System, LP (Iroquois), together with our remaining 11.8 per cent interest in Portland Natural Gas Transmission System (PNGTS), to our master limited partnership, TC PipeLines, LP for a total of US$765 million |
• | NGTL System: NGTL currently has a $5.1 billion near-term capital program targeted for completion by 2020. This includes the recently filed application to amend approvals for the North Montney project with a revised $1.4 billion capital cost estimate and the recently approved Towerbirch Expansion project. |
• | North Montney: On March 20, 2017, we filed an application with the NEB for a variance to the existing approvals for North Montney, to remove the condition it can only proceed once a positive FID is made for the Pacific Northwest LNG project. North Montney is now underpinned by restructured, 20-year commercial |
• | Towerbirch Expansion: On March 10, 2017, the Government of Canada approved the $0.4 billion Towerbirch Expansion project. In February 2017, the B.C. Government approved the environmental assessment with conditions that have since been met. |
• | Canadian Mainline Tolling Option Open Season: On March 13, 2017, we announced the successful conclusion of the long-term fixed-price open season on the Canadian Mainline for service from Empress, Alberta to the Dawn hub in Southern Ontario. The open season resulted in binding, long-term contracts to transport 1.5 PJ/d of natural gas at a toll of $0.77/GJ. The 10 year contracts have early termination rights that can be exercised following the initial five years of service and upon payment of an increased toll for the final two years of the contract. The application to the NEB for approval of the service was filed on April 26, 2017 and included the request to implement the service starting November 1, 2017. |
• | Sale of Iroquois and PNGTS to TC PipeLines, LP: On May 4, 2017, we announced agreements to sell a 49.3 per cent interest in Iroquois, together with our remaining 11.8 per cent interest in PNGTS, to our master limited partnership, TC PipeLines, LP for US$765 million. The transaction is expected to close mid-2017. |
• | Columbia Projects: Leach XPress and Rayne XPress both received FERC approvals and Notices to Proceed in the first quarter of 2017. Construction is now underway. The US$1.4 billion Leach XPress project and the US$0.4 billion Rayne XPress project are expected to be in-service in November 2017. WB XPress received an Environmental Assessment on March 24, 2017 and expects to receive its FERC order later this summer. The US$0.8 billion project remains on schedule with Phase I expected to be in-service in June 2018 and Phase II in November 2018. |
• | Columbia Pipeline Partners LP: On February 17, 2017, we acquired, for cash, all of the outstanding publicly held common units of CPPL for an aggregate transaction value of US$921 million. |
• | Great Lakes Rate Filing: Consistent with its 2013 settlement, on March 31, 2017, Great Lakes submitted a General Section 4 Rate Filing and Tariff Changes with the FERC. The rates proposed in the filing will become effective on October 1, 2017, subject to refund, if alternate resolution to the proceeding is not reached prior to that date. We have initiated customer discussions and will seek to achieve a mutually beneficial settlement resolution. |
• | Keystone XL: In March 2017, the U.S. Department of State issued a U.S. Presidential Permit authorizing construction of the U.S./Canada border crossing facilities of the Keystone XL pipeline. We have discontinued our claim under Chapter 11 of the North American Free Trade Agreement and have withdrawn the U.S. Constitutional challenge. In February 2017, we filed an application with the Nebraska Public Service Commission seeking approval for the Keystone XL pipeline route through that state. A hearing on the application is scheduled in August 2017 and a final decision is expected by the end of November 2017. Given the passage of time since the Keystone XL Presidential Permit application was previously denied in November 2015, we are updating the shipping contracts and anticipate the core contract shipper group will be modified with the introduction of new shippers and reductions in volume commitments by other shippers. We expect this transition to be complete within a few months and would anticipate commercial support for the project to be substantially similar to that which existed when we first applied for Keystone XL. |
• | Monetization of U.S. Northeast power business: On April 19, 2017, we announced the closing of the previously announced sale of TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC, for US$1.065 billion. In second quarter 2017 we expect to book an approximate $440 million after-tax gain on the sale of the hydro assets. The proceeds received were used to reduce the acquisition bridge facilities which |
• | Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.625 per share for the quarter ending June 30, 2017 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.50 per common share on an annualized basis. |
• | Junior Subordinated Debt Issuance: In March 2017, TransCanada Trust issued US$1.5 billion of 60-year Junior Subordinated Notes to third party investors with a fixed interest rate of 5.30 per cent for the first ten years converting to a floating rate thereafter. The notes are callable at par beginning ten years following their issuance. All of the proceeds of the issuance by the Trust were loaned to TCPL in US$1.5 billion of subordinated notes at a rate of 5.55 per cent which includes a 0.25 per cent administration charge. |
• | Dividend Reinvestment Plan: Currently, approximately 40 per cent of the common and preferred share dividends declared are being reinvested in TransCanada common shares through our Dividend Reinvestment Plan (DRP). |
• | Management Changes: Alex Pourbaix, Chief Operating Officer announced his retirement from the company, effective May 31, 2017. There is no current intention to replace this role. Effective April 28, 2017, Stan Chapman, previously Senior Vice-President of U.S. Natural Gas Pipelines, was promoted to Executive Vice-President and President, U.S. Natural Gas Pipelines. On April 21, 2017, Bill Taylor, Executive Vice-President and President, Energy left the company to pursue other opportunities and Karl Johannson will take over the responsibility of the Energy business unit along with his revised role as President of Canada and Mexico Natural Gas Pipelines. |