TransCanada Reports First Quarter 2017 Financial Results; Strong Results Build Upon Transformational 2016
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 05/05/17 -- TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada) today announced net income attributable to common shares for first quarter 2017 of $643 million or $0.74 per share compared to net income of $252 million or $0.36 per share for the same period in 2016. Comparable earnings for first quarter 2017 were $698 million or $0.81 per share compared to $494 million or $0.70 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 June 30, 2017, equivalent to $2.50 per common share on an annualized basis.
"We generated record first quarter financial results, excluding specific items," said Russ Girling, TransCanada''s president and chief executive officer. "Comparable earnings per share increased 16 per cent compared to first quarter 2016 primarily due to strong performance across our Natural Gas Pipelines business, including Columbia which was acquired in mid-2016, while net cash provided by operations reached $1.3 billion."
"Today we are advancing a $23 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 $7.5 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 purchase of Columbia Pipeline Partners LP which results in 100 per cent ownership in the core Columbia assets and further simplifies our corporate structure."
"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. Those include Keystone XL and the Bruce Power life extension agreement. During the first quarter, we were very pleased to receive a U.S. Presidential Permit for Keystone XL and are now in the process of seeking regulatory approval in Nebraska while progressing commercial discussions with our customers. Success in advancing these or other growth initiatives could augment or extend the Company''s dividend growth outlook through 2020 and beyond," concluded Girling.
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Net income attributable to common shares increased by $391 million to $643 million or $0.74 per share for the three months ended March 31, 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. First quarter 2017 included a charge of $24 million after-tax for integration-related costs associated with the acquisition of Columbia, a $10 million after-tax charge for costs related to the monetization of our U.S. Northeast power business, a $7 million after-tax charge related to the maintenance of Keystone XL assets and a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets. First quarter 2016 results included a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs, a $26 million after-tax charge relating to costs associated with the acquisition of Columbia, a $6 million after-tax charge related to Keystone XL costs for the maintenance and liquidation of project assets and a $3 million after-tax loss on the sale of TC Offshore which closed in March 2016. All of these specific items plus risk management activities are excluded from comparable earnings.
Comparable earnings for first quarter 2017 were $698 million or $0.81 per share compared to $494 million or $0.70 per share for the same period in 2016, an increase of $204 million or $0.11 per share and includes the dilutive effect of issuing 161 million common shares in 2016. The 2017 increase in comparable earnings was primarily due to the net effect of higher contributions from U.S. Natural Gas Pipelines primarily due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from higher rates effective August 1, 2016, a higher contribution from Mexican Natural Gas Pipelines due to incremental earnings from the Mazatlan and Topolobampo pipelines, higher earnings primarily from U.S. Power due to depreciation no longer being recorded effective November 1, 2016 on these assets along with higher realized power prices and higher earnings from Western Power following the termination of the Alberta PPAs in 2016. These increases were partially offset by higher interest expense as a result of debt assumed in the Columbia acquisition and long-term debt issuances and 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.
Notable recent developments include:
Natural Gas Pipelines:
Liquids Pipelines:
Energy:
Corporate:
We will hold a teleconference and webcast on Friday, May 5, 2017 to discuss our first 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 12:30 p.m. (MT) / 2:30 p.m. (ET).
Members of the investment community and other interested parties are invited to participate by calling 800.408.3053 or 905.694.9451 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast 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 May 12, 2017. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 8663009.
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 over 10,100 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 May 4, 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 May 4, 2017.
Management''s discussion and analysis
May 4, 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 months ended March 31, 2017, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months ended March 31, 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
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
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 - first 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 $391 million or $0.38 per share for the three months ended March 31, 2017 compared to the same period 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 $204 million for the three months ended March 31, 2017 compared to the same period in 2016 as discussed below in the reconciliation of net income to comparable earnings.
Comparable earnings increased by $204 million or $0.11 per share for the three months ended March 31, 2017 compared to the same period in 2016. Comparable earnings per share in 2017 included the dilutive effect of issuing 161 million common shares in 2016.
The year-over-year increase in comparable earnings was primarily the net effect of:
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 $23 billion of near-term projects and approximately $48 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.
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 remains consistent with what was previously included in the 2016 Annual Report.
Consolidated acquisition, equity investments and capital spending
Our expected total capital expenditures 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 increased by $10 million for the three months ended March 31, 2017 compared to the same period 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 for the NGTL System increased by $9 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to a higher average investment base and OM&A incentive earnings recorded 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 increased by $2 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to higher incentive earnings, partially offset by a lower average investment base. 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 $6 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to the NGTL System facilities that were placed in service.
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 $294 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the acquisition of Columbia and included a $10 million pre-tax charge, primarily due to integration-related costs associated with the Columbia acquisition. Segmented earnings for the three months ended March 31, 2016 included a $4 million pre-tax loss provision ($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.
Earnings for 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$292 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of:
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$61 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to the acquisition of Columbia.
US$5 million of 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-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 $73 million for the three months ended March 31, 2017 compared to the same period in 2016 and are equivalent to comparable EBIT.
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$67 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of:
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$11 million for the three months ended March 31, 2017 compared to the same period 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 $15 million for the three months ended March 31, 2017 compared to the same period in 2016 and included pre-tax charges related to Keystone XL costs for the maintenance of project assets which are being expensed pending further advancement of the project as well as unrealized losses from changes in the fair value of derivatives related to our liquids marketing business in 2016.
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 $16 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of:
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $5 million for the three months ended March 31, 2017 compared to the same period in 2016 as a result of new facilities being placed in service.
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 $324 million for the three months ended March 31, 2017 compared to the same period 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 $26 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to the termination of the Alberta PPAs. 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 three months ended March 31, 2017 compared to the same period in 2016 following the termination of the Alberta PPAs.
Eastern Power
Comparable EBITDA for Eastern Power decreased by $8 million for the three months ended March 31, 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 decreased by $23 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to lower gains from contracting activities and higher interest expense, partially offset by higher volumes resulting from fewer outage days.
Planned outage work which commenced on Unit 5 in February 2017 is scheduled to be completed in second quarter 2017. Planned outages for Units 3 and 6 are scheduled to occur in the 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 $12 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to increased third party storage revenues as a result of higher realized natural gas storage price spreads.
U.S. POWER (monetization expected to close in the first half of 2017)
The following are the components of comparable EBITDA and comparable EBIT.
Comparable EBITDA for U.S. Power decreased by US$21 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of:
Average New York Zone J spot capacity prices were approximately 41 per cent lower for the three months ended March 31, 2017 compared to the same period in 2016. The decrease in spot capacity prices and the offsetting impact of hedging activities resulted in lower realized capacity prices in New York. This was primarily due to an increase in demonstrated capability from existing resources in the New York City''s Zone J market.
Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three months ended March 31, 2017 than the same period in 2016 as we have expanded our customer base in the PJM and New England 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 $6 million for the three months ended March 31, 2017 compared to the same period in 2016. Comparable EBIT in 2017 and 2016 excluded acquisition and integration costs associated with the acquisition of Columbia.
OTHER INCOME STATEMENT ITEMS
Interest expense increased by $80 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt issuances, partially offset by Canadian and U.S. dollar-denominated debt maturities.
AFUDC was consistent for the three months ended March 31, 2017 compared to the same period in 2016. The increase in Canadian dollar-denominated AFUDC is primarily due to increased investment in our NGTL System expansions, while the decrease in our U.S. dollar-denominated AFUDC is primarily due to the completed construction of Topolobampo and Mazatlan pipelines, partially offset by our increased investment in projects acquired as part of the Columbia acquisition on July 1, 2016.
Interest income and other decreased by $80 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of:
Income tax expense included in comparable earnings increased by $64 million for the three months ended March 31, 2017 compared to the same period 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 increased by $10 million for the three months ended March 31, 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 outstanding publicly held common units of CPPL.
Preferred share dividends increased by $19 million for the three months ended March 31, 2017 compared to the same period 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
The NGTL System currently has a $5.1 billion near-term capital program for completion to 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 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, but still accommodates, 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 and included the request to implement the service starting November 1, 2017.
U.S. NATURAL GAS PIPELINES
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 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 US$765 million. The transaction is comprised of US$597 million in cash and the assumption of US$168 million in proportionate debt at Iroquois and PNGTS. The transaction is expected to close mid-2017.
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$1.4 billion Leach XPress project and the US$0.4 billion Rayne XPress project are expected to be in service in November 2017.
WB XPress
We received our Environmental Assessment on March 24, 2017 for the WB XPress project and expect to receive our FERC order later this summer after additional FERC Commissioners are appointed and a quorum is re-established. 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.
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 Pipeline
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, however, 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, however, a hearing date has not yet been announced by the NEB.
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.
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.
ENERGY
U.S. Power
Ravenswood
In late March 2017, the 972 MW Unit 30 at the Ravenswood Generating Station experienced an unplanned outage as a result of a problem on the generator associated with the low pressure turbine. Repairs to the unit are underway and the unit is expected to be returned to service in second quarter 2017. The incident is not expected to materially affect the sale process for Ravenswood.
Monetization of U.S. Northeast power business
The sale of TC Hydro to Great River Hydro, LLC closed on April 19, 2017 for proceeds of US$1.065 billion resulting in a gain of approximately $710 million ($440 million after tax) before post-closing adjustments which will be recorded in second quarter 2017. The proceeds received were used to reduce the Columbia acquisition bridge credit facility.
The sale of Ravenswood, Ironwood, Ocean State Power and Kibby to Helix Generation, LLC is expected to close in second quarter 2017.
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 the establishment of an at-the-market equity issuance program, if applicable), our DRP, portfolio management including proceeds from the anticipated drop down of natural gas pipeline assets to TC PipeLines, LP, cash on hand and substantial committed credit facilities.
At March 31, 2017, our current assets were $8.0 billion and current liabilities were $9.1 billion, leaving us with a working capital deficit of $1.1 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:
COMPARABLE FUNDS GENERATED FROM OPERATIONS
Comparable funds generated from operations increased $259 million for the three months ended March 31, 2017 compared to the same period 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 first quarter 2016 to 2017 was driven by an increase in comparable funds generated from operations and lower maintenance capital expenditures, primarily at Bruce Power, partially offset by higher dividends on preferred shares and distributions paid to non-controlling interests. Comparable distributable cash flow per share in 2017 included 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:
Capital expenditures in 2017 were primarily related to:
Costs incurred on capital projects under 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.
The increase in other distributions from equity investments is primarily due to distributions from Bruce Power. In first quarter 2017, Bruce Power issued bonds to fund its capital program and make distributions to its partners which resulted in $362 million being received by us.
On February 17, 2017, we acquired all outstanding common units of CPPL for US$921 million.
JUNIOR SUBORDINATED NOTES ISSUED
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. In the most recent quarter, approximately 40 per cent of common share dividends declared were designated to be reinvested by shareholders in TransCanada common shares under the DRP.
TC PIPELINES, LP AT-THE-MARKET (ATM) EQUITY ISSUANCE PROGRAM
During first quarter 2017, 1.2 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$69 million. At March 31, 2017, our ownership interest in TC PipeLines, LP was 26.4 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. In March 2017, rescission rights on 0.4 million common units expired. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit.
DIVIDENDS
On May 4, 2017, we declared quarterly dividends as follows:
CREDIT FACILITIES
We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for general corporate purposes as well as acquisition bridge facilities to support the interim financing of the Columbia acquisition. 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 May 4, 2017, we had a total of $11.1 billion of committed revolving and demand credit facilities and $2.8 million of acquisition bridge facilities including:
At May 4, 2017, our operated affiliates had an additional $0.7 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 $0.5 billion since December 31, 2016 primarily as a result of decreased commitments for the NGTL System and Sur de Texas natural gas pipelines due to the progression of construction. Transportation by others commitments have increased by approximately $0.7 billion since December 31, 2016, primarily related to Canadian Mainline contracts.
Our commitments at March 31, 2017 include operating leases and other purchase obligations related to our U.S. Northeast power business. At the close of the sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power, our commitments are expected to decrease by $42 million in 2017, $97 million in 2018, $79 million in 2019, $29 million in 2020, $23 million in 2021 and $259 million in 2022 and beyond.
There were no other material changes to our contractual obligations in first 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.
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 March 31, 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.
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.
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.
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:
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 fr om 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 consolidated statement of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests is as follows:
Credit risk related contingent features of derivative instruments
Derivatives often contain financial assurance provisions that may require us to provide collateral if a credit risk related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits.
Based on contracts in place and market prices at March 31, 2017, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $20 million (December 31, 2016 - $19 million), with collateral provided in the normal course of business of nil (December 31, 2016 - nil). If the credit-risk-related contingent features in these agreements were triggered on March 31, 2017, we would have been required to provide additional collateral of $20 million (December 31, 2016 - $19 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
Other information
CONTROLS AND PROCEDURES
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2017, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
There were no changes in first quarter 2017 that had or are likely to have a material impact on our internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES
When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2016 Annual Report.
Our significant accounting policies have remained unchanged since December 31, 2016 other than described below. You can find a summary of our significant accounting policies in our 2016 Annual Report.
Changes in accounting policies for 2017
Inventory
In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on our consolidated balance sheet.
Derivatives and hedging
In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance was effective January 1, 2017, was applied prospectively and did not result in any impact on our consolidated financial statements.
Equity method investments
In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. In these situations, when an increase in ownership interest in an investment qualifies it for equity method accounting, the new guidance eliminates the requirement to retroactively apply the equity method of accounting. This new guidance was effective January 1, 2017, was applied prospectively and did not result in any impact on our consolidated financial statements.
Employee share-based payments
In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. We have elected to account for forfeitures when they occur. This new guidance was effective, on a prospective basis, January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to 2017 opening retained earnings and the recognition of a deferred tax asset related to employee share-based payments made prior to the adoption of this standard.
Consolidation
In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entity (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions.
Future accounting changes
Revenue from contracts with customers
In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a five-step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. We will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. We are evaluating both methods of adoption as we work through our analysis.
We have identified all existing customer contracts that are within the scope of the new guidance and we are in the process of analyzing individual contracts or groups of contracts on a segmented basis to identify any significant changes in how revenues are recognized as a result of implementing the new standard. As we continue our contract analysis, we will also quantify the impact, if any, on prior period revenues. We will address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard. We are currently evaluating the impact on our consolidated financial statements as well as the development of disclosures required under the new standard.
Financial instruments
In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires us to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and specifies the method of adoption for each component of the guidance. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.
Leases
In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. L
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