TransCanada Reports Strong Second Quarter 2017 Financial Results; Performance Highlights Diversified, Low Risk Business Strategy
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 07/28/17 -- TransCanada Corporation (TSX: TRP)(NYSE: TRP) (TransCanada or the Company) today announced net income attributable to common shares for second quarter 2017 of $881 million or $1.01 per share compared to net income of $365 million or $0.52 per share for the same period in 2016. Comparable earnings for second quarter 2017 were $659 million or $0.76 per share compared to $366 million or $0.52 per share for the same period in 2016. TransCanada''s Board of Directors also declared a quarterly dividend of $0.625 per common share for the quarter ending September 30, 2017, equivalent to $2.50 per common share on an annualized basis.
"Our diversified portfolio of high-quality, low risk energy infrastructure assets continued to perform very well in the second quarter of 2017," said Russ Girling, TransCanada''s president and chief executive officer. "Comparable earnings per share increased 46 per cent compared to second quarter 2016 primarily due to the Columbia acquisition in July 2016 and the realization of associated synergies, strong performance across our Natural Gas and Liquids Pipelines businesses and higher earnings from Bruce Power following a major planned outage in second quarter 2016. The growth in earnings was accompanied by a significant increase in net cash provided by operations which rose to $1.4 billion from $1.1 billion in the same period last year."
"In the quarter, we added $2 billion of additional expansion projects on the NGTL System and today announced a $0.2 billion expansion on the Canadian Mainline, highlighting the organic growth opportunities that continue to emanate from our broad, strategically located asset base. We are now advancing a $24 billion near-term capital program that is expected to generate significant growth in earnings and cash flow and support an expected annual dividend growth rate at the upper end of an eight to 10 per cent range through 2020," added Girling. "To date we have invested $9.0 billion in these projects and are well positioned to both execute and fund the remainder of the program over the next few years. In addition, we concluded the sale of our U.S. Northeast merchant generation facilities, with proceeds used to fully retire the Columbia acquisition bridge facilities. With those sales complete, over 95 per cent of our future EBITDA is expected to be derived from regulated or long-term contracted assets."
"We also continue to progress a number of additional medium to longer-term organic growth opportunities in our three core businesses of natural gas pipelines, liquids pipelines and energy in Canada, the United States and Mexico. Success in advancing Keystone XL or other growth initiatives, including the Bruce Power life extension, could further augment or extend the Company''s dividend growth outlook," concluded Girling.
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Net income attributable to common shares increased by $516 million to $881 million or $1.01 per share for the three months ended June 30, 2017 compared to the same period last year. Net income per common share in 2017 includes the dilutive effect of issuing 161 million common shares in 2016. Second quarter 2017 results included a $265 million after-tax net gain on the monetization of the U.S. Northeast power assets which was comprised of a $441 million after-tax gain on the sale of TC Hydro and an incremental loss of $176 million after-tax on the sale of the thermal and wind package, an after-tax charge of $15 million for integration-related costs associated with the acquisition of Columbia and a $4 million after-tax charge related to the maintenance of Keystone XL assets. Second quarter 2016 included a charge of $113 million related to costs associated with the Columbia acquisition which were primarily related to the dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, an after-tax $10 million restructuring charge related to expected future losses under lease commitments and $9 million after-tax related to Keystone XL maintenance and liquidation costs. All of these specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings.
Comparable earnings for second quarter 2017 were $659 million or $0.76 per share compared to $366 million or $0.52 per share for the same period in 2016, an increase of $293 million or $0.24 per share and includes the dilutive effect of issuing 161 million common shares in 2016. The increase in second quarter comparable earnings was primarily due to higher contributions from U.S. Natural Gas Pipelines reflecting incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from higher rates effective August 1, 2016, higher earnings from Bruce Power mainly due to higher volumes resulting from fewer planned outage days, a higher contribution from Mexican Natural Gas Pipelines due to earnings from the Mazatlan and Topolobampo pipelines and higher earnings from Liquids Pipelines mainly due to higher volumes. These increases were partially offset by higher interest expense mainly as a result of debt assumed in the acquisition of Columbia and long-term debt issuances.
Notable recent developments include:
Natural Gas Pipelines:
Liquids Pipelines:
Energy:
Corporate:
Teleconference and Webcast:
We will hold a teleconference and webcast on Friday, July 28, 2017 to discuss our second quarter 2017 financial results. Russ Girling, TransCanada President and Chief Executive Officer, and Don Marchand, Executive Vice-President and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 9 a.m. (MT) / 11 a.m. (ET).
Members of the investment community and other interested parties are invited to participate by calling 800.377.0758 or 416.340.2218 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live of the teleconference will be available at .
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on August 4, 2017. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 9154252.
The unaudited interim condensed Consolidated Financial Statements and Management''s Discussion and Analysis (MD&A) are available under TransCanada''s profile on SEDAR at , with the U.S. Securities and Exchange Commission on EDGAR at and on the TransCanada website at .
With more than 65 years'' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 91,500 kilometres (56,900 miles), tapping into virtually all major gas supply basins in North America. TransCanada is the continent''s largest provider of gas storage and related services with 653 billion cubic feet of storage capacity. A large independent power producer, TransCanada owns or has interests in approximately 6,200 megawatts of power generation in Canada and the United States. TransCanada is also the developer and operator of one of North America''s leading liquids pipeline systems that extends over 4,300 kilometres (2,700 miles) connecting growing continental oil supplies to key markets and refineries. TransCanada''s common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com and our blog to learn more, or connect with us on social media and 3BL Media.
Forward Looking Information
This release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "believe", "may", "will", "should", "estimate", "intend" or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management''s assessment of TransCanada''s and its subsidiaries'' future plans and financial outlook. All forward-looking statements reflect TransCanada''s beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to the Quarterly Report to Shareholders dated July 27, 2017 and 2016 Annual Report filed under TransCanada''s profile on SEDAR at and with the U.S. Securities and Exchange Commission at .
Non-GAAP Measures
This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, comparable distributable cash flow, comparable funds generated from operations, comparable earnings per share and comparable distributable cash flow per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada''s Quarterly Report to Shareholders dated July 27, 2017.
Quarterly report to shareholders
Second quarter 2017
Financial highlights
Management''s discussion and analysis
July 27, 2017
This management''s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and six months ended June 30, 2017, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2017 which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2016 audited consolidated financial statements and notes and the MD&A in our 2016 Annual Report.
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management''s assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A include information about the following, among other things:
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.
Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:
Assumptions
Risks and uncertainties
You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2016 Annual Report.
As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.
FOR MORE INFORMATION
You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR ().
NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be similar to measures presented by other entities.
Comparable measures
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:
We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.
The following table identifies our non-GAAP measures against their equivalent GAAP measures.
Comparable earnings and comparable earnings per share
Comparable earnings represent earnings or loss attributable to common shareholders on a consolidated basis adjusted for specific items. Comparable earnings is comprised of segmented earnings, interest expense, AFUDC, interest income and other, income taxes and non-controlling interests adjusted for the specific items. See the Consolidated results section for a reconciliation to net income attributable to common shares.
Comparable EBIT and comparable EBITDA
Comparable EBIT represents segmented earnings adjusted for the specific items described above. We use comparable EBIT as a measure of our earnings from ongoing operations as it is a useful measure of our performance and an effective tool for evaluating trends in each segment. Comparable EBITDA is calculated the same way as comparable EBIT but excludes the non-cash charges for depreciation and amortization. See the Reconciliation of non-GAAP measures section for a reconciliation to segmented earnings.
Funds generated from operations and comparable funds generated from operations
Funds generated from operations reflects net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. Comparable funds generated from operations is adjusted for the cash impact of specific items noted above. See the Financial condition section for a reconciliation to net cash provided by operations.
Comparable distributable cash flow and comparable distributable cash flow per share
We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. Comparable distributable cash flow is defined as comparable funds generated from operations less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability, and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, in certain of our rate-regulated businesses, maintenance capital expenditures are included in their respective rate bases, on which we earn a regulated return and recover depreciation through future tolls. See the Financial condition section for a reconciliation to net cash provided by operations.
Consolidated results - second quarter 2017
Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
Net income attributable to common shares increased by $516 million and $907 million or $0.49 and $0.88 per share for the three and six months ended June 30, 2017 compared to the same periods in 2016. Net income per common share in 2017 included the dilutive effect of issuing 161 million common shares in 2016.
The 2017 results included:
The 2016 results included:
Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.
Comparable earnings increased by $293 million and $497 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 as discussed below in the reconciliation of net income to comparable earnings.
RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
Comparable earnings increased by $293 million or $0.24 per share for the three months ended June 30, 2017 compared to the same period in 2016. This was primarily the net effect of:
Comparable earnings increased by $497 million or $0.34 per share for the six months ended June 30, 2017 compared to the same period in 2016. This was primarily the net effect of:
Comparable earnings per share in 2017 included the dilutive effect of issuing 161 million common shares in 2016.
Capital Program
We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow.
Our capital program consists of approximately $24 billion of near-term projects and approximately $43 billion of medium to longer-term projects. Amounts presented exclude maintenance capital expenditures, capitalized interest and AFUDC. All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
Near-term projects
Medium to longer-term projects
The medium to longer-term projects have greater uncertainty with respect to timing and estimated project costs. The expected in-service dates of these projects are post-2020, and costs provided in the schedule below reflect the most recent costs for each project as filed with the various regulatory authorities or otherwise determined. These projects have all been commercially secured or, in the case of Keystone XL, commercial support is expected to be achieved. All these projects are subject to approvals that include sponsor FID and/or complex regulatory processes.
Outlook
Our overall comparable earnings outlook for 2017 is expected to be higher than what was previously included in the 2016 Annual Report as a result of stronger performance across our business segments, including from the U.S. Northeast power business in first half 2017, as detailed in the MD&A.
Consolidated capital spending
Our expected total capital expenditures, projects in development and contributions to equity investments for 2017 as outlined in the 2016 Annual Report, remain unchanged.
Canadian Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
Canadian Natural Gas Pipelines segmented earnings decreased by $37 million and $27 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and are equivalent to comparable EBIT.
Net income and comparable EBITDA for our rate-regulated Canadian Natural Gas Pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.
NET INCOME - NGTL SYSTEM AND CANADIAN MAINLINE
Net income for the NGTL System increased by $8 million and $17 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to a higher average investment base and higher OM&A incentive earnings in 2017. The NGTL System is operating under the two-year 2016-2017 Revenue Requirement Settlement which includes an ROE of 10.1 per cent on 40 per cent deemed equity and a mechanism for sharing variances above and below a fixed annual OM&A amount with flow-through treatment of all other costs.
Net income for the Canadian Mainline decreased by $4 million and $2 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to a lower average investment base and higher carrying charges on regulatory deferrals, partially offset by higher incentive earnings. The Canadian Mainline is operating under the NEB 2014 Decision which includes an approved ROE of 10.1 per cent on a 40 per cent deemed equity with a possible range of achieved outcomes between 8.7 per cent and 11.5 per cent. The decision also includes an incentive mechanism that has both upside and downside risk and a $20 million annual after-tax contribution from us.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $3 million and by $9 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to facilities that were placed in service for the NGTL System and Canadian Mainline.
OPERATING STATISTICS - NGTL SYSTEM AND CANADIAN MAINLINE
U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
U.S. Natural Gas Pipelines segmented earnings increased by $213 million and $507 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to the acquisition of Columbia. Segmented earnings for the six months ended June 30, 2017 included a first quarter $10 million pre-tax charge primarily due to integration-related costs associated with the Columbia acquisition. Segmented earnings for the six months ended June 30, 2016 included a $4 million pre-tax loss ($3 million after tax) as a result of a December 2015 agreement to sell TC Offshore which closed in early 2016. These amounts have been excluded from our calculation of comparable EBIT. As well, a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. operations.
Earnings from our U.S. Natural Gas Pipelines operations, which include Columbia effective July 1, 2016, are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services. Columbia and ANR results are also affected by the contracting and pricing of their storage capacity and commodity sales. Transmission and storage revenues are generally higher in winter months due to increased seasonal demand for our services.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$216 million and US$508 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and was the net effect of:
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$63 million and US$124 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to the acquisition of Columbia and higher depreciation rates on ANR resulting from a FERC-approved rate settlement, effective August 1, 2016.
US$5 million of first quarter 2017 depreciation related to Columbia information system assets retired as part of the Columbia integration process has been excluded from comparable EBIT and included as part of integration and acquisition related costs to arrive at segmented earnings.
Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
Mexico Natural Gas Pipelines segmented earnings increased by $79 million and $152 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and are equivalent to comparable EBIT. A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent segmented earnings from our Mexico operations.
Earnings from our Mexico operations are underpinned by long-term, stable, primarily U.S. dollar-denominated revenue contracts, and are affected by the cost of providing service.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$66 million and US$133 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and was the net effect of:
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$12 million and US$23 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to the commencement of depreciation on Topolobampo and Mazatlan.
Liquids Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
Liquids Pipelines segmented earnings increased by $53 million and $68 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and included pre-tax charges related to Keystone XL costs for the maintenance of project assets which are being expensed pending further advancement of the project as well as unrealized gains from changes in the fair value of derivatives related to our liquids marketing business.
Keystone Pipeline System earnings are generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings.
Comparable EBITDA for Liquids Pipelines increased by $56 million and $72 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and was the net effect of:
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $11 million and $16 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.
Energy
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
Energy segmented earnings increased by $274 million and $598 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and included the following specific items:
The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time, however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impacts of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.
The remainder of the Energy segmented earnings are equivalent to comparable EBIT and are discussed in the following sections.
CANADIAN POWER
Western and Eastern Power
The following are the components of comparable EBITDA and comparable EBIT.
Western Power
Comparable EBITDA for Western Power increased by $5 million and $31 million for the three and six months ended June 30, 2017 compared to the same periods in 2016. Results from the Alberta PPAs are included up to March 7, 2016 when we terminated the PPAs for the Sundance A, Sundance B and Sheerness facilities.
Depreciation and amortization decreased by $10 million for the six months ended June 30, 2017 compared to the same period in 2016 following the termination of the Alberta PPAs.
Eastern Power
Comparable EBITDA for Eastern Power decreased by $9 million for the six months ended June 30, 2017 compared to the same period in 2016 mainly due to lower earnings on the sale of unused natural gas transportation.
Bruce Power
Bruce Power results reflect our proportionate share. The following is our proportionate share of the components of comparable EBITDA and comparable EBIT.
Comparable EBITDA from Bruce Power increased by $112 million and $89 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to higher volumes resulting from fewer planned outage days, partially offset by higher interest expense.
Planned outage work, which commenced on Unit 5 in February 2017, was completed in May 2017. Planned outages for Units 3 and 6 are scheduled to occur in second half of 2017. The overall average plant availability percentage in 2017 is expected to be approximately 90 per cent.
NATURAL GAS STORAGE AND OTHER
Comparable EBITDA for Natural Gas Storage and Other increased by $2 million and $14 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to increased third party storage revenues as a result of higher realized natural gas storage price spreads.
U.S. POWER
In second quarter 2017, we sold our U.S. Power generation assets and initiated the wind down of our TransCanada Power Marketing Ltd. (TCPM) operations. We expect to realize the value of the remaining TCPM marketing contracts and working capital over time. See Recent developments section for more details.
The following are the components of comparable EBITDA and comparable EBIT.
Comparable EBITDA for U.S. Power decreased by US$50 million and US$71 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly due to the sale of our generation assets in the second quarter 2017, partially offset by higher sales to customers in the PJM and New England wholesale markets.
Corporate
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
Corporate segmented losses increased by $16 million and $22 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and included the following specific items that have been excluded from comparable EBIT:
OTHER INCOME STATEMENT ITEMS
Interest expense
Interest expense increased by $10 million and $90 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and primarily reflects the net effect of:
Allowance for funds used during construction
AFUDC increased $10 million for both the three and six months ended June 30, 2017 compared to the same periods in 2016. The increase in Canadian dollar-denominated AFUDC is primarily due to increased investment in our NGTL System expansions, while the year-to-date decrease in U.S. dollar-denominated AFUDC is primarily due to the completed construction of the Topolobampo and Mazatlan pipelines, partially offset by increased investment in projects acquired as part of the Columbia acquisition on July 1, 2016.
Interest income and other
Interest income and other increased by $83 million and $3 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 and was primarily the net effect of:
Income tax expense
Income tax expense included in comparable earnings increased by $9 million and $73 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 mainly as a result of higher pre-tax earnings in 2017 compared to 2016 and changes in the proportion of income earned between Canadian and foreign jurisdictions.
Net income attributable to non-controlling interests
Net income attributable to non-controlling interests increased by $13 million for the six months ended June 30, 2017 compared to the same period in 2016 primarily due to the acquisition of Columbia which included a non-controlling interest in CPPL. On February 17, 2017, we acquired all of the outstanding publicly held common units of CPPL.
Preferred share dividends
Preferred share dividends increased by $11 million and $30 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to the issuance of Series 13 and Series 15 preferred shares in April 2016 and November 2016, respectively.
Recent developments
CANADIAN NATURAL GAS PIPELINES
NGTL System
On June 14, 2017, we announced an additional $2 billion expansion program on our NGTL System based on new contracted customer demand for approximately 3 Bcf/d of incremental firm receipt and delivery services. We also successfully concluded a recent expansion open season for incremental service at the Alberta/British Columbia export delivery point, which connects Canadian supply through our downstream pipelines to Pacific Northwest, California and Nevada markets. The open season was over-subscribed and all 381 MMcf/d of available expansion service was awarded under long-term contracts.
This additional expansion program increases our overall near-term capital program for completion to 2021 on the NGTL System to $7.1 billion.
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 that the project could only proceed once a positive FID is made for the Pacific Northwest LNG project. North Montney is now underpinned by restructured, 20-year commercial contracts with shippers and is not dependent on the LNG project proceeding. On April 19, 2017, the NEB granted an interim extension of the sunset clause that was due to expire June 10, 2017 to March 31, 2018. In-service dates are planned for April 2019 and April 2020, subject to regulatory approval.
Towerbirch Expansion
On March 10, 2017, the Government of Canada approved the $0.4 billion Towerbirch Expansion project. The project consists of 55 km (34 miles) of 36-inch loop to the Groundbirch Mainline plus 32 km (20 miles) of new 30-inch pipe and four new meter stations. 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 the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The open season resulted in binding, long-term contracts from WCSB gas producers to transport 1.5 PJ/d of natural gas at a simplified toll of $0.77/GJ. The term of each contract is 10 years and includes 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. The NEB is following a modified Streamlined Application Process with adjudication expected to follow after oral arguments are presented on September 11, 2017. The new service is requested to begin November 1, 2017.
Canadian Mainline Maple Compressor Expansion Project
The Canadian Mainline has received requests for expansion capacity to the southern Ontario market plus delivery to Atlantic Canada via the TQM and PNGTS systems. The requests for approximately 80 MMcf/d of firm service underpin the need for new compression at the existing Maple compressor site. Customers have executed 15-year precedent agreements to proceed with the estimated $160 million project. Once we have completed our tariff process for this capacity addition, an application to the NEB for approval to proceed with the project is planned for early 2018 to meet a November 1, 2019 in-service date.
Coastal GasLink
The continuing delay in the FID for the LNG Canada project has triggered a restructuring of provisions in the Coastal GasLink project agreement with LNG Canada that will result in the payment of certain amounts to TransCanada with respect to carrying charges on costs incurred since inception of the project. An approximate $80 million payment will be received in September 2017, followed by quarterly payments of approximately $7 million until further notice. We continue to work with LNG Canada under the agreement towards a FID.
Prince Rupert Gas Transmission
On July 25, 2017, we were notified that PNW LNG would not be proceeding with their proposed LNG project. As part of our PRGT agreement, following receipt of a termination notice, we would be reimbursed for the full costs and carrying charges incurred to advance the PRGT project. We expect to receive this payment later in 2017.
U.S. NATURAL GAS PIPELINES
Sale of Iroquois and PNGTS to TC PipeLines, LP
On June 1, 2017, we closed the sale of a 49.34 per cent interest in Iroquois Gas Transmission System, LP (Iroquois) and our remaining 11.81 per cent interest in Portland Natural Gas Transmission System (PNGTS) to TC PipeLines, LP valued at US$765 million. Proceeds were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and PNGTS debt.
Leach XPress and Rayne XPress
FERC approvals and Notices to Proceed were received in first quarter 2017 for both the Leach XPress and Rayne XPress projects allowing construction activities to begin. The US$1.5 billion Leach XPress project and the US$0.4 billion Rayne XPress project are expected to be in service in November 2017.
Great Lakes Rate Case
Great Lakes is required to file a new Section 4 rate case with rates effective no later than January 1, 2018 as part of the settlement agreement with shippers approved November 2013. 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 be effective on October 1, 2017, subject to refund, if alternate resolution to the proceeding is not reached prior to that date. Great Lakes has initiated customer discussions regarding the details of the filing and will seek to achieve a mutually beneficial resolution through settlement with its customers.
Columbia Pipeline Partners LP
On February 17, 2017, we completed the acquisition, for cash, of all outstanding publicly held common units of CPPL at a price of US$17.00 and a stub period distribution payment of US$0.10 per common unit for an aggregate transaction value of US$921 million.
LIQUIDS PIPELINES
Energy East
In January 2017, the NEB appointed three new panel members to undertake the review of the Energy East and Eastern Mainline projects. The new NEB panel members voided all decisions made by the previous hearing panel and will decide how to move forward with the hearing. We are not required to refile the application and parties will not be required to reapply for intervener status. All other proceedings and associated deadlines are no longer applicable. If the new panel members determine that the project application is complete, the 21-month NEB review period will commence.
On March 29, 2017, the NEB issued its decision to hear the Energy East and Eastern Mainline projects together. A hearing date has not yet been announced by the NEB.
On May 10, 2017, the NEB solicited comments on a draft list of issues for the Energy East and Eastern Mainline projects with comments due from the general public on May 31, 2017. Energy East and Eastern Mainline projects provided their comments on the draft list of issues on June 21, 2017. At the same time, we provided our response to the comments received by the NEB from the general public. We are awaiting the NEB''s decision on the final list of issues. In addition, we are awaiting further direction from the NEB regarding the regulatory review process.
Keystone XL
In February 2017, we filed an application with the Nebraska Public Service Commission (PSC) 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 on the proposed route is expected by the end of November 2017.
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 discontinued our claim under Chapter 11 of the North American Free Trade Agreement and have also withdrawn the U.S. Constitutional challenge. With the receipt of the U.S. Presidential Permit, we will continue to work through the Nebraska PSC process to obtain route approval through that state and with other U.S. federal agencies to obtain ancillary permits.
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 anticipate commercial support for the project to be substantially similar to that which existed when we first applied for Keystone XL.
On July 27, 2017, we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on the Keystone Pipeline and Keystone XL Pipeline project from Hardisty, Alberta to markets in Cushing, Oklahoma and the U.S. Gulf Coast. The open season will close on September 28, 2017.
Grand Rapids
On June 1, 2017, the Grand Rapids pipeline, which will connect producing areas northwest of Fort McMurray, Alberta to terminals in the Edmonton/Heartland region, commenced line fill activities with anticipated in-service in third quarter 2017.
ENERGY
U.S. Power
Monetization of U.S. Northeast power business
On April 19, 2017, we closed the sale of TC Hydro to Great River Hydro, LLC for US$1.07 billion resulting in a gain of $717 million ($441 million after tax) recorded in second quarter 2017.
On June 2, 2017, we closed the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC for US$2.029 billion. An additional loss on sale of approximately $219 million ($176 million after tax) was recorded in second quarter 2017, primarily related to an adjustment to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close. Insurance recoveries for a portion of the repair costs are expected to be received by the end of 2017 and will partially reduce this loss.
Proceeds from the sale transactions were used to fully retire the remaining bridge facilities that partially funded the acquisition of Columbia.
After assessing our options, we initiated the wind down of our TCPM operations and will realize the value of the remaining marketing contracts and working capital over time.
Financial condition
We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.
We believe we have the financial capacity to fund our existing capital program through our predictable and growing cash flow from operations, access to capital markets (including through our At-The-Market (ATM) equity issuance program), our Dividend Reinvestment Plan (DRP), portfolio management including proceeds from potential drop downs of additional natural gas pipeline assets to TC PipeLines, LP, cash on hand and substantial committed credit facilities.
At June 30, 2017, our current assets were $4.9 billion and current liabilities were $10.1 billion, leaving us with a working capital deficit of $5.2 billion compared to a surplus of $0.4 billion at December 31, 2016. Our working capital deficiency is considered to be in the normal course of business and is managed through:
CASH PROVIDED BY OPERATING ACTIVITIES
COMPARABLE FUNDS GENERATED FROM OPERATIONS
Comparable funds generated from operations increased $352 million and $611 million for the three and six months ended June 30, 2017 compared to the same periods in 2016 primarily due to the increase in comparable earnings.
COMPARABLE DISTRIBUTABLE CASH FLOW
Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation. The increase from second quarter 2016 to 2017 was driven by an increase in comparable funds generated from operations partially offset by higher maintenance capital expenditures, distributions paid to non-controlling interests and dividends on preferred shares. Comparable distributable cash flow per share in 2017 includes the dilutive effect of issuing 161 million common shares in 2016.
Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, in certain of our rate-regulated businesses maintenance capital expenditures are included in their respective rate bases on which we earn a regulated return and recover depreciation through future tolls.
The following provides a breakdown of maintenance capital expenditures:
CASH PROVIDED BY/(USED IN) INVESTING ACTIVITIES
Capital expenditures in 2017 were primarily related to:
Costs incurred on Capital projects in development primarily relate to the Energy East and LNG pipeline projects.
Contributions to equity investments have increased in 2017 compared to 2016 primarily due to our investments in Sur de Texas and Bruce Power and includes our proportionate share of Sur de Texas debt financing requirements.
Restricted cash in 2016 represented the amount held in escrow at June 30, 2016 for the purchase of Columbia on July 1, 2016 and included the proceeds from the sale of subscription receipts, net of dividend equivalent payments, and draws on the committed bridge loan credit facilities.
In second quarter 2017, we closed the sale of the our U.S. Northeast power assets for net proceeds of $4,147 million.
The decrease in Other distributions from equity investments is primarily due to Bruce Power financings undertaken to fund its capital program and make distributions to its partners. In second quarter 2016, Bruce Power issued senior notes in the capital markets and borrowed under a bank credit facility which resulted in $725 million being received by us. In first quarter 2017, Bruce Power issued additional senior notes in the capital markets which resulted in $362 million being received by us.
CASH (USED IN)/PROVIDED BY FINANCING ACTIVITIES
LONG-TERM DEBT ISSUED
LONG-TERM DEBT RETIRED
The acquisition bridge facilities were put into place to finance a portion of the Columbia acquisition. Proceeds from the sales of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in second quarter 2017.
JUNIOR SUBORDINATED NOTES ISSUED
In May 2017, the Trust issued $1.5 billion of Trust Notes - Series 2017-B (Trust Notes) to third party investors with a fixed interest rate of 4.65 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for $1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 4.90 per cent, including a 0.25 per cent administration charge. The rate will reset commencing May 2027 until May 2047 to the three month Bankers'' Acceptance rate plus 3.33 per cent per annum; from May 2047 until May 2077, the interest rate will reset to the three month Bankers'' Acceptance rate plus 4.08 per cent per annum. The junior subordinated notes are callable at TCPL''s option at any time on or after May 18, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.
In March 2017, the Trust issued US$1.5 billion of Trust Notes - Series 2017-A (Trust 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. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.55 per cent, including a 0.25 per cent administration charge. The rate will reset commencing March 2027 until March 2047 to the three month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the three month LIBOR plus 4.208 per cent per annum. The junior subordinated notes are callable at TCPL''s option at any time on or after March 15, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.
Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL.
DIVIDEND REINVESTMENT PLAN
Under our DRP, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. Common shares are issued from treasury at a discount of two per cent. For the dividends declared on May 5, 2017, approximately 35 per cent of common share dividends declared were designated to be reinvested by shareholders in TransCanada common shares under the DRP. Since issuance under the DRP from treasury at a discount began in July 2016, the cumulative participation rate has been approximately 38 per cent of common shares, resulting in $773 million of common equity issued.
TRANSCANADA CORPORATION ATM EQUITY ISSUANCE PROGRAM
In June 2017, we established an ATM program that allows us to issue common shares from treasury having an aggregate gross sales price of up to $1.0 billion or their U.S. dollar equivalent, from time to time, at our discretion, at the prevailing market price when sold through the Toronto Stock Exchange or the New York Stock Exchange. The ATM program, which is effective for a 25-month period, will be activated at our discretion, if and as required, based on the spend profile of TransCanada''s capital program and relative cost of other funding options. At June 30, 2017, no common shares were issued under the program.
TC PIPELINES, LP ATM EQUITY ISSUANCE PROGRAM
During first and second quarter 2017, 1.6 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$90 million. At June 30, 2017, our ownership interest in TC PipeLines, LP was 26.3 per cent as a result of issuances under the ATM program and resulting dilution.
In connection with the late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon the filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the ATM program may have a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP. All rescission rights have expired and no unitholder claimed or attempted to exercise any rescission rights prior to the expiration date.
DIVIDENDS
On July 27, 2017, we declared quarterly dividends as follows:
SHARE INFORMATION
CREDIT FACILITIES
We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for general corporate purposes. In addition, we have demand credit facilities that are also used for general corporate purposes, including issuing letters of credit and providing additional liquidity.
At July 27, 2017, we had a total of $10.9 billion of committed revolving and demand credit facilities, including:
At July 27, 2017, our operated affiliates had an additional $0.6 billion of undrawn capacity on committed credit facilities.
See Financial risks and financial instruments for more information about liquidity, market and other risks.
CONTRACTUAL OBLIGATIONS
Our capital commitments have decreased by approximately $0.8 billion since December 31, 2016 primarily as a result of decreased commitments for the Sur de Texas and NGTL System natural gas pipelines due to the progression of construction. Transportation by others commitments have increased by approximately $0.6 billion since December 31, 2016 primarily related to Canadian Mainline contracts. Other Energy commitments have decreased by approximately $0.4 billion since December 31, 2016 as a result of the sale of our U.S. Northeast power assets.
Our operating lease commitments at December 31, 2016 included future payments related to our U.S. Northeast power business. As a result of the completion of the thermal sale on June 2, 2017, the remaining future obligations included at December 31, 2016 have decreased by: $2 million in 2017, $52 million in 2018, $34 million in 2019 and $102 million in 2022 and beyond.
There were no other material changes to our contractual obligations in second quarter 2017 or to payments due in the next five years or after. See the MD&A in our 2016 Annual Report for more information about our contractual obligations.
Financial risks and financial instruments
We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.
See our 2016 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2016, other than described below.
In second quarter 2017, we sold our U.S. Northeast merchant power generation assets and initiated the wind down of our TCPM operations. We expect to realize the value of the remaining marketing contracts and working capital over time. As a result, our exposure to commodity risk has been reduced.
LIQUIDITY RISK
We manage our liquidity risk by continuously forecasting our cash flow for a 12 month period to ensure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.
COUNTERPARTY CREDIT RISK
We have exposure to counterparty credit risk in the following areas:
We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At June 30, 2017, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired.
We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
LOAN RECEIVABLE FROM AFFILIATE
We hold a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline for which we account as an equity investment. On April 21, 2017, we issued a peso-denominated unsecured revolving credit facility to the joint venture. This $1 billion facility bears interest at a floating interest rate per annum. As at June 30, 2017, Intangible and other assets on our condensed consolidated balance sheet included a $341 million loan receivable from the Sur de Texas joint venture (December 31, 2016 - nil). This loan receivable represents our proportionate share of our affiliate''s debt financing requirements and is included in Contributions to equity investments on our condensed consolidated statement of cash flow. Interest income and other included $3 million in the three and six months ended June 30, 2017 as a result of inter-affiliate lending to the Sur de Texas joint venture (2016 - nil and nil).
FOREIGN EXCHANGE AND INTEREST RATE RISK
We generate revenues and incur expenses that are denominated in currencies other than Canadian dollars. As a result, our earnings and cash flows are exposed to currency fluctuations.
A portion of our businesses generate earnings in U.S. dollars, but since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.
We have floating interest rate debt which subjects us to interest rate cash flow risk. We manage this using a combination of interest rate swaps and options.
Average exchange rate - U.S. to Canadian dollars
The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly offset by interest on U.S. dollar-denominated long-term debt, as set out in the table below. Comparable EBIT is a non-GAAP measure. See our Reconciliation of non-GAAP measures section for more information.
Significant U.S. dollar-denominated amounts
Derivatives designated as a net investment hedge
We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options.
The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:
U.S. dollar-denominated debt designated as a net investment hedge
FINANCIAL INSTRUMENTS
All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.
Derivative instruments
We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify and are designated for hedge accounting treatment.
The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.
Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of derivative instruments is as follows:
Unrealized and realized (losses)/gains of derivative instruments
The following summary does not include hedges of our net investment in foreign operations.
Derivatives in cash flow hedging relationships
The components of the condensed c
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Datum: 28.07.2017 - 05:30 Uhr
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