TransCanada Reports First Quarter 2017 Financial Results; Strong Results Build Upon Transformational 2016
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)
-- First quarter 2017 financial results
-- Net income attributable to common shares of $643 million or $0.74
per share
-- Comparable earnings of $698 million or $0.81 per share
-- Comparable earnings before interest, taxes, depreciation and
amortization (EBITDA) of $2.0 billion
-- Net cash provided by operations of $1.3 billion
-- Comparable funds generated from operations of $1.5 billion
-- Comparable distributable cash flow of $1.2 billion or $1.41 per
common share
-- Declared a quarterly dividend of $0.625 per common share for the quarter
ending June 30, 2017
-- Acquired all outstanding publicly held units of Columbia Pipeline
Partners LP (CPPL) for a total of US$921 million
-- Filed a variance application with the National Energy Board (NEB) for
the $1.4 billion North Montney project to remove the condition requiring
a positive Final Investment Decision (FID) for the Pacific Northwest LNG
project. The amended project is supported by 20-year contracts with 11
shippers
-- Successfully concluded an open season on the Canadian Mainline for 1.5
petajoules per day (PJ/d) of 10 year transportation service from
Empress, Alberta to the Dawn hub in Southern Ontario
-- Received Federal Energy Regulatory Commission (FERC) approvals and began
construction on the Leach XPress and Rayne XPress projects. Also
received an Environmental Assessment on WB XPress
-- Received a U.S. Presidential Permit authorizing construction of the
U.S./Canada border crossing facilities of the Keystone XL pipeline. We
also filed an application with the Nebraska Public Service Commission
seeking approval for the Keystone XL pipeline route through that state
-- Raised US$1.5 billion in gross proceeds through an offering of Junior
Subordinated Notes maturing in 2077
-- In April, closed the sale of a portion of our U.S. Northeast power
business for US$1.065 billion; the proceeds were used to repay a portion
of the acquisition bridge facilities which partially financed the
Columbia acquisition
-- In May, announced agreements to sell a 49.3 per cent interest in
Iroquois Gas Transmission System, LP (Iroquois), together with our
remaining 11.8 per cent interest in Portland Natural Gas Transmission
System (PNGTS), to our master limited partnership, TC PipeLines, LP for
a total of US$765 million
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:
-- NGTL System: NGTL currently has a $5.1 billion near-term capital program
targeted for completion by 2020. This includes the recently filed
application to amend approvals for the North Montney project with a
revised $1.4 billion capital cost estimate and the recently approved
Towerbirch Expansion project.
-- North Montney: On March 20, 2017, we filed an application with the NEB
for a variance to the existing approvals for North Montney, to remove
the condition it can only proceed once a positive FID is made for the
Pacific Northwest LNG project. North Montney is now underpinned by
restructured, 20-year commercial contracts with a group of shippers and
is not dependent on, but still accommodates, the LNG project proceeding.
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. In February
2017, the B.C. Government approved the environmental assessment with
conditions that have since been met.
-- Canadian Mainline Tolling Option Open Season: On March 13, 2017, we
announced the successful conclusion of the long-term fixed-price open
season on the Canadian Mainline for service from Empress, Alberta to the
Dawn hub in Southern Ontario. The open season resulted in binding, long-
term contracts to transport 1.5 PJ/d of natural gas at a toll of
$0.77/GJ. The 10 year contracts have early termination rights that can
be exercised following the initial five years of service and upon
payment of an increased toll for the final two years of the contract.
The application to the NEB for approval of the service was filed on
April 26, 2017 and included the request to implement the service
starting November 1, 2017.
-- Sale of Iroquois and PNGTS to TC PipeLines, LP: On May 4, 2017, we
announced agreements to sell a 49.3 per cent interest in Iroquois,
together with our remaining 11.8 per cent interest in PNGTS, to our
master limited partnership, TC PipeLines, LP for US$765 million. The
transaction is expected to close mid-2017.
-- Columbia Projects: Leach XPress and Rayne XPress both received FERC
approvals and Notices to Proceed in the first quarter of 2017.
Construction is now underway. The US$1.4 billion Leach XPress project
and the US$0.4 billion Rayne XPress project are expected to be in-
service in November 2017. WB XPress received an Environmental Assessment
on March 24, 2017 and expects to receive its FERC order later this
summer. The US$0.8 billion project remains on schedule with Phase I
expected to be in-service in June 2018 and Phase II in November 2018.
-- Columbia Pipeline Partners LP: On February 17, 2017, we acquired, for
cash, all of the outstanding publicly held common units of CPPL for an
aggregate transaction value of US$921 million.
-- Great Lakes Rate Filing: Consistent with its 2013 settlement, on March
31, 2017, Great Lakes submitted a General Section 4 Rate Filing and
Tariff Changes with the FERC. The rates proposed in the filing will
become effective on October 1, 2017, subject to refund, if alternate
resolution to the proceeding is not reached prior to that date. We have
initiated customer discussions and will seek to achieve a mutually
beneficial settlement resolution.
Liquids Pipelines:
-- Keystone XL: In March 2017, the U.S. Department of State issued a U.S.
Presidential Permit authorizing construction of the U.S./Canada border
crossing facilities of the Keystone XL pipeline. We have discontinued
our claim under Chapter 11 of the North American Free Trade Agreement
and have withdrawn the U.S. Constitutional challenge. In February 2017,
we filed an application with the Nebraska Public Service Commission
seeking approval for the Keystone XL pipeline route through that state.
A hearing on the application is scheduled in August 2017 and a final
decision is expected by the end of November 2017. Given the passage of
time since the Keystone XL Presidential Permit application was
previously denied in November 2015, we are updating the shipping
contracts and anticipate the core contract shipper group will be
modified with the introduction of new shippers and reductions in volume
commitments by other shippers. We expect this transition to be complete
within a few months and would anticipate commercial support for the
project to be substantially similar to that which existed when we first
applied for Keystone XL.
Energy:
-- Monetization of U.S. Northeast power business: On April 19, 2017, we
announced the closing of the previously announced sale of TC Hydro to
Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC,
for US$1.065 billion. In second quarter 2017 we expect to book an
approximate $440 million after-tax gain on the sale of the hydro assets.
The proceeds received were used to reduce the acquisition bridge
facilities which partially financed the Columbia acquisition. The
previously announced sale of Ravenswood, Ironwood, Ocean State Power and
Kibby to Helix Generation, LLC is expected to close in second quarter
2017.
Corporate:
-- Common Share Dividend: Our Board of Directors declared a quarterly
dividend of $0.625 per share for the quarter ending June 30, 2017 on
TransCanada's outstanding common shares. The quarterly amount is
equivalent to $2.50 per common share on an annualized basis.
-- Junior Subordinated Debt Issuance: In March 2017, TransCanada Trust
issued US$1.5 billion of 60-year Junior Subordinated Notes to third
party investors with a fixed interest rate of 5.30 per cent for the
first ten years converting to a floating rate thereafter. The notes are
callable at par beginning ten years following their issuance. All of the
proceeds of the issuance by the Trust were loaned to TCPL in US$1.5
billion of subordinated notes at a rate of 5.55 per cent which includes
a 0.25 per cent administration charge.
-- Dividend Reinvestment Plan: Currently, approximately 40 per cent of the
common and preferred share dividends declared are being reinvested in
TransCanada common shares through our Dividend Reinvestment Plan (DRP).
-- Management Changes: Alex Pourbaix, Chief Operating Officer announced his
retirement from the company, effective May 31, 2017. There is no current
intention to replace this role. Effective April 28, 2017, Stan Chapman,
previously Senior Vice-President of U.S. Natural Gas Pipelines, was
promoted to Executive Vice-President and President, U.S. Natural Gas
Pipelines. On April 21, 2017, Bill Taylor, Executive Vice-President and
President, Energy left the company to pursue other opportunities and
Karl Johannson will take over the responsibility of the Energy business
unit along with his revised role as President of Canada and Mexico
Natural Gas Pipelines.
-- Teleconference and Webcast:
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 www.transcanada.com.
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 www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com.
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 www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov.
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.
First quarter 2017 financial highlights
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three months ended March 31
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(unaudited - millions of $, except per share
amounts) 2017 2016
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Income
Revenues 3,391 2,503
Net income attributable to common shares 643 252
per common share - basic and diluted $0.74 $0.36
Comparable EBITDA(1) 1,977 1,502
Comparable earnings(1) 698 494
per common share(1) $0.81 $0.70
Cash flows
Net cash provided by operations 1,302 1,081
Comparable funds generated from operations(1) 1,508 1,249
Comparable distributable cash flow(1) 1,222 974
per common share(1) $1.41 $1.39
Capital spending
- capital expenditures 1,560 836
- projects in development 42 67
Contributions to equity investments 192 170
Acquisitions, net of cash acquired - 995
Proceeds from sale of assets, net of
transaction costs - 6
Dividends declared
Per common share $0.625 $0.565
Basic common shares outstanding (millions)
Average for the period 866 702
End of period 867 702
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(1) Comparable EBITDA, comparable earnings, comparable earnings per common
share, comparable funds generated from operations, comparable
distributable cash flow and comparable distributable cash flow per
common share are all non-GAAP measures. See the non-GAAP measures
section for more information.
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:
-- planned changes in our business including the divestiture of certain
assets
-- our financial and operational performance, including the performance of
our subsidiaries
-- expectations or projections about strategies and goals for growth and
expansion
-- expected cash flows and future financing options available to us
-- expected dividend growth
-- expected costs for planned projects, including projects under
construction, permitting and in development
-- expected schedules for planned projects (including anticipated
construction and completion dates)
-- expected regulatory processes and outcomes
-- expected impact of regulatory outcomes
-- expected outcomes with respect to legal proceedings, including
arbitration and insurance claims
-- expected capital expenditures and contractual obligations
-- expected operating and financial results
-- expected impact of future accounting changes, commitments and contingent
liabilities
-- expected industry, market and economic conditions.
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
-- planned monetization of our U.S. Northeast power business
-- inflation rates, commodity prices and capacity prices
-- nature and scope of hedging
-- regulatory decisions and outcomes
-- the Canadian dollar to U.S. dollar exchange rate remains at or near
current levels
-- interest rates
-- tax rates
-- planned and unplanned outages and the use of our pipeline and energy
assets
-- integrity and reliability of our assets
-- access to capital markets
-- anticipated construction costs, schedules and completion dates.
Risks and uncertainties
-- our ability to realize the anticipated benefits from the acquisition of
Columbia
-- timing and execution of our planned asset sales
-- our ability to successfully implement our strategic initiatives
-- whether our strategic initiatives will yield the expected benefits
-- the operating performance of our pipeline and energy assets
-- amount of capacity sold and rates achieved in our pipeline businesses
-- the availability and price of energy commodities
-- the amount of capacity payments and revenues we receive from our energy
business
-- regulatory decisions and outcomes
-- outcomes of legal proceedings, including arbitration and insurance
claims
-- performance and credit risk of our counterparties
-- changes in market commodity prices
-- changes in the political environment
-- changes in environmental and other laws and regulations
-- competitive factors in the pipeline and energy sectors
-- construction and completion of capital projects
-- costs for labour, equipment and materials
-- access to capital markets
-- interest, tax and foreign exchange rates
-- weather
-- cyber security
-- technological developments
-- economic conditions in North America as well as globally.
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 (www.sedar.com).
NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
-- comparable earnings -- comparable earnings per common share -- comparable EBITDA -- comparable EBIT -- funds generated from operations -- comparable funds generated from operations -- comparable distributable cash flow -- comparable distributable cash flow per common share.
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:
-- certain fair value adjustments relating to risk management activities
-- income tax refunds and adjustments and changes to enacted tax rates
-- gains or losses on sales of assets or assets held for sale
-- legal, contractual and bankruptcy settlements
-- impact of regulatory or arbitration decisions relating to prior year
earnings
-- restructuring costs
-- impairment of goodwill, investments and other assets including certain
ongoing maintenance and liquidation costs
-- acquisition costs.
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.
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Comparable measure Original measure
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comparable earnings net income attributable to common
shares
comparable earnings per common share net income per common share
comparable EBITDA segmented earnings
comparable EBIT segmented earnings
comparable funds generated from net cash provided by operations
operations
comparable distributable cash flow net cash provided by operations
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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.
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three months ended March 31
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(unaudited - millions of $, except per share
amounts) 2017 2016
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Canadian Natural Gas Pipelines 282 272
U.S. Natural Gas Pipelines 561 267
Mexico Natural Gas Pipelines 118 45
Liquids Pipelines 227 212
Energy 198 (126)
Corporate (33) (27)
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Total segmented earnings 1,353 643
Interest expense (500) (420)
Allowance for funds used during construction 101 101
Interest income and other 20 100
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Income before income taxes 974 424
Income tax expense (200) (70)
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Net income 774 354
Net income attributable to non-controlling
interests (90) (80)
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Net income attributable to controlling
interests 684 274
Preferred share dividends (41) (22)
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Net income attributable to common shares 643 252
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Net income per common share - basic and
diluted $0.74 $0.36
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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:
-- a charge of $24 million after tax for integration-related costs
associated with the acquisition of Columbia
-- a charge of $10 million after tax for costs related to the monetization
of our U.S. Northeast power business
-- a charge of $7 million after tax related to the maintenance of Keystone
XL assets which are being expensed pending further advancement of the
project
-- a $7 million income tax recovery related to the realized loss on a third
party sale of Keystone XL project assets. A provision for the expected
pre-tax loss on these assets was included in our 2015 impairment charge,
but the related income tax recoveries could not be recorded until
realized.
The 2016 results included:
-- a $176 million after-tax impairment charge on the carrying value of our
Alberta PPAs as a result of our decision to terminate the PPAs
-- a charge of $26 million after tax relating to costs associated with the
acquisition of Columbia
-- a charge of $6 million after tax related to Keystone XL costs for the
maintenance and liquidation of project assets which are being expensed
pending further advancement of the project
-- an additional $3 million after-tax loss on the sale of TC Offshore which
closed on March 31, 2016.
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.
RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
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three months ended March 31
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(unaudited - millions of $, except per share
amounts) 2017 2016
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Net income attributable to common shares 643 252
Specific items (net of tax):
Acquisition related costs - Columbia 24 26
U.S. Northeast power monetization 10 -
Keystone XL asset costs 7 6
Keystone XL income tax recoveries (7) -
Alberta PPA terminations - 176
TC Offshore loss on sale - 3
Risk management activities(1) 21 31
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Comparable earnings 698 494
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Net income per common share $0.74 $0.36
Specific items (net of tax):
Acquisition related costs - Columbia 0.03 0.04
U.S. Northeast power monetization 0.01 -
Keystone XL asset costs 0.01 0.01
Keystone XL income tax recoveries (0.01) -
Alberta PPA terminations - 0.25
Risk management activities 0.03 0.04
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Comparable earnings per share $0.81 $0.70
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(1) three months ended
Risk management activities March 31
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(unaudited - millions of $) 2017 2016
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Canadian Power 1 (13)
U.S. Power (62) (115)
Liquids marketing - (2)
Natural Gas Storage 5 5
Foreign exchange 15 53
Income tax attributable to risk management
activities 20 41
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Total unrealized losses from risk
management activities (21) (31)
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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:
-- higher contribution from U.S. Natural Gas Pipelines due to incremental
earnings from Columbia following the July 1, 2016 acquisition and higher
ANR transportation revenues resulting from a FERC-approved rate
settlement effective August 1, 2016
-- higher interest expense as a result of debt assumed in the acquisition
of Columbia on July 1, 2016 and long-term debt issuances
-- higher contribution from Mexico Natural Gas Pipelines due to earnings
from Topolobampo beginning in July 2016 and Mazatlan beginning in
December 2016
-- lower interest income and other due to realized losses in 2017 compared
to realized gains in 2016 on derivatives used to manage our net exposure
to foreign exchange rate fluctuations on U.S. dollar-denominated income
-- lower earnings from Bruce Power mainly due to lower gains from
contracting activities and higher interest expense, partially offset by
higher volumes resulting from fewer outage days
-- higher earnings from Western Power mainly due to termination of the
Alberta PPAs in 2016
-- higher earnings from Liquids Pipelines due to higher volumes
-- higher earnings from Natural Gas Storage due to higher realized natural
gas storage price spreads
-- higher earnings from U.S. Power due to depreciation no longer being
recorded effective November 1, 2016 on the assets classified as held for
sale and higher realized power prices, partially offset by lower
capacity revenues in New York and higher fuel costs and lower generation
volumes at our New York and New England facilities.
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.
Near-term projects
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at March 31,
2017 Expected Estimated
in-service project Carrying
(unaudited -
billions of $) Segment date cost value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian
Mainline Canadian Natural Gas Pipelines 2017-2018 0.3 0.1
NGTL System
- North
Montney Canadian Natural Gas Pipelines 2019-2020 1.4 0.3
- Saddle West Canadian Natural Gas Pipelines 2019 0.6 -
- 2016/17
Facilities Canadian Natural Gas Pipelines 2017-2020 2.2 0.9
- 2018
Facilities Canadian Natural Gas Pipelines 2018-2020 0.6 -
- Other Canadian Natural Gas Pipelines 2017-2020 0.3 -
Columbia Gas
- Leach XPress U.S. Natural Gas Pipelines 2017 US 1.4 US 0.5
-
Modernization
I U.S. Natural Gas Pipelines 2017 US 0.2 US 0.1
- WB XPress U.S. Natural Gas Pipelines 2018 US 0.8 US 0.3
- Mountaineer
XPress U.S. Natural Gas Pipelines 2018 US 2.0 US 0.2
-
Modernization
II U.S. Natural Gas Pipelines 2018-2020 US 1.1 -
Columbia Gulf
- Rayne XPress U.S. Natural Gas Pipelines 2017 US 0.4 US 0.3
- Cameron
Access U.S. Natural Gas Pipelines 2018 US 0.3 US 0.2
- Gulf XPress U.S. Natural Gas Pipelines 2018 US 0.6 US 0.1
Midstream -
Gibraltar U.S. Natural Gas Pipelines 2017 US 0.3 US 0.2
Tula Mexico Natural Gas Pipelines 2018 US 0.6 US 0.4
Villa de Reyes Mexico Natural Gas Pipelines 2018 US 0.6 US 0.3
Sur de Texas(1) Mexico Natural Gas Pipelines 2018 US 1.3 US 0.2
Grand Rapids(1) Liquids Pipelines 2017 0.9 0.8
Northern Courier Liquids Pipelines 2017 1.0 0.9
White Spruce Liquids Pipelines 2018 0.2 -
Napanee Energy 2018 1.1 0.7
Bruce Power -
life up to
extension(2) Energy 2020+ 1.1 0.1
----------------------------------------------------------------------------
19.3 6.6
Foreign exchange impact on near-term
projects(3) 3.2 0.9
----------------------------------------------------------------------------
Total near-term projects (billions of Cdn$) 22.5 7.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Our proportionate share.
(2) Amounts reflect our proportionate share of the remaining capital costs
that Bruce Power expects to incur on its life extension investment
programs in advance of major refurbishment outages which are expected to
begin in 2020.
(3) Reflects U.S./Canada foreign exchange rate of $1.33 at March 31, 2017.
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at March 31, 2017 Estimated
project Carrying
(unaudited - billions of $) Segment cost value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Heartland and TC Terminals Liquids Pipelines 0.9 0.1
Upland Liquids Pipelines US 0.6 -
Grand Rapids Phase 2(1) Liquids Pipelines 0.7 -
Bruce Power - life extension(1) Energy 5.3 -
Keystone projects
Keystone XL(2) Liquids Pipelines US 8.0 US 0.3
Keystone Hardisty Terminal(2) Liquids Pipelines 0.3 0.1
Energy East projects
Energy East(3) Liquids Pipelines 15.7 0.8
Eastern Mainline Canadian Natural Gas
Pipelines 2.0 0.1
BC west coast LNG-related
projects
Coastal GasLink Canadian Natural Gas
Pipelines 4.8 0.4
Prince Rupert Gas Transmission Canadian Natural Gas
Pipelines 5.0 0.5
NGTL System - Merrick Canadian Natural Gas
Pipelines 1.9 -
----------------------------------------------------------------------------
45.2 2.3
Foreign exchange impact on medium
to longer-term projects(4) 2.8 0.1
----------------------------------------------------------------------------
Total medium to longer-term
projects (billions of Cdn$) 48.0 2.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Our proportionate share.
(2) Carrying value reflects amount remaining after impairment charge
recorded in fourth quarter 2015.
(3) Excludes transfer of Canadian Mainline natural gas assets.
(4) Reflects U.S./Canada foreign exchange rate of $1.33 at March 31, 2017.
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NGTL System 230 226
Canadian Mainline 247 231
Other Canadian pipelines(1) 28 32
Business development (1) (1)
----------------------------------------------------------------------------
Comparable EBITDA 504 488
Depreciation and amortization (222) (216)
----------------------------------------------------------------------------
Comparable EBIT and segmented earnings 282 272
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes results from Foothills, Ventures LP and our share of equity
income from our investment in TQM.
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 - NGTL SYSTEM AND CANADIAN MAINLINE
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NGTL System 82 73
Canadian Mainline 52 50
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31 NGTL System(1) Canadian Mainline(2)
-------------------- --------------------
(unaudited) 2017 2016 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average investment base (millions
of $) 7,853 7,257 4,103 4,384
Delivery volumes (Bcf):
Total 1,090 1,063 521 481
Average per day 12.1 11.7 5.8 5.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Field receipt volumes for the NGTL System for the three months ended
March 31, 2017 were 1,037 Bcf (2016 - 1,074 Bcf). Average per day was
11.5 Bcf (2016 - 11.8 Bcf).
(2) Canadian Mainline's throughput volumes represent physical deliveries to
domestic and export markets. Physical receipts originating at the
Alberta border and in Saskatchewan for the three months ended March 31,
2017 were 235 Bcf (2016 - 274 Bcf). Average per day was 2.6 Bcf (2016 -
3.0 Bcf).
U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of US$, unless otherwise
noted) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Columbia Gas(1) 185 -
ANR 122 87
TC PipeLines, LP(2,3) 32 31
Great Lakes(3,4) 27 25
Midstream(1) 23 -
Columbia Gulf(1) 18 -
Other U.S. pipelines(1,2,3,5) 29 14
Non-controlling interests(6) 108 95
Business development (1) (1)
----------------------------------------------------------------------------
Comparable EBITDA 543 251
Depreciation and amortization (112) (51)
----------------------------------------------------------------------------
Comparable EBIT 431 200
Foreign exchange impact 140 71
----------------------------------------------------------------------------
Comparable EBIT (Cdn$) 571 271
Specific items:
Acquisition related costs - Columbia (10) -
TC Offshore loss on sale - (4)
----------------------------------------------------------------------------
Segmented earnings (Cdn$) 561 267
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) We completed the acquisition of Columbia on July 1, 2016 and the
remaining publicly held units of Columbia Pipeline Partners LP (CPPL) on
February 17, 2017.
(2) Results from Northern Border and Iroquois reflect our share of equity
income from these investments. We acquired additional interests in
Iroquois of 0.65 per cent on May 1, 2016 and 4.87 per cent on March 31,
2016.
(3) TC PipeLines, LP periodically conducts at-the-market equity issuances
which decrease our ownership in TC PipeLines, LP. The following shows
our ownership interest in TC PipeLines, LP and our effective ownership
interest of GTN, Great Lakes and PNGTS through our ownership interest in
TC PipeLines, LP for the periods presented.
------------------------------------------------------------------------
------------------------------------------------------------------------
Effective ownership percentage
as of
------------------------------
March 31, 2017 March 31, 2016
------------------------------------------------------------------------
------------------------------------------------------------------------
TC PipeLines, LP 26.4 27.9
Effective ownership through TC PipeLines,
LP:
Great Lakes 12.3 13.0
PNGTS 13.2 13.9
------------------------------------------------------------------------
------------------------------------------------------------------------
(4) Represents our 53.6 per cent direct interest in Great Lakes. The
remaining 46.4 per cent is held by TC PipeLines, LP.
(5) Includes our direct ownership in Iroquois and PNGTS and our effective
ownership in Millennium and Hardy Storage.
(6) Comparable EBITDA for the portions of TC PipeLines, LP, PNGTS and CPPL
that we do not own. Effective February 17, 2017, we acquired the
remaining publicly held units of CPPL.
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:
-- US$250 million of earnings as a result of the acquisition of Columbia on
July 1, 2016 and the remaining publicly held common units of CPPL on
February 17, 2017
-- higher ANR transportation revenue resulting from a FERC-approved rate
settlement, effective August 1, 2016, and higher storage results.
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$5 million of depreciation related to Columbia information system assets retired as part of the Columbia integration process has been excluded from comparable EBIT and included as part of integration-related costs to arrive at segmented earnings.
Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of US$, unless otherwise
noted) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Topolobampo 40 (1)
Tamazunchale 29 27
Guadalajara 17 17
Mazatlan 16 -
Sur de Texas(1) 4 -
Other - (1)
Business development - (3)
----------------------------------------------------------------------------
Comparable EBITDA 106 39
Depreciation and amortization (17) (6)
----------------------------------------------------------------------------
Comparable EBIT 89 33
Foreign exchange impact 29 12
----------------------------------------------------------------------------
Comparable EBITand segmented earnings (Cdn$) 118 45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents our 60 per cent equity interest in a joint venture with
IEnova to build, own and operate the Sur de Texas pipeline.
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:
-- US$41 million of incremental earnings from Topolobampo. The Topolobampo
project has experienced a delay in construction which, under the terms
of our Transportation Service Agreement (TSA) with the CFE, constitutes
a force majeure event with provisions allowing for the collection and
recognition of revenue as per the original TSA service commencement date
of July 2016
-- US$16 million of incremental earnings from Mazatlan. Construction is
complete and the collection and recognition of revenue began per the
terms of the TSA in December 2016
-- US$4 million of equity earnings from our investment in the Sur de Texas
pipeline which records AFUDC during construction.
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Keystone Pipeline System 306 302
Business development and other 6 (6)
----------------------------------------------------------------------------
Comparable EBITDA 312 296
Depreciation and amortization (77) (72)
----------------------------------------------------------------------------
Comparable EBIT 235 224
Specific items:
Keystone XL asset costs (8) (10)
Risk management activities - (2)
----------------------------------------------------------------------------
Segmented earnings 227 212
----------------------------------------------------------------------------
Comparable EBIT denominated as follows:
Canadian dollars 55 53
U.S. dollars 135 127
Foreign exchange impact 45 44
----------------------------------------------------------------------------
235 224
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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:
-- higher volumes on Keystone pipeline
-- higher contribution from liquids marketing
-- higher business development activities, including advancement of
Keystone XL.
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Power
Western Power(1) 30 4
Eastern Power 94 102
Bruce Power 91 114
----------------------------------------------------------------------------
Canadian Power - comparable EBITDA(1,2) 215 220
Depreciation and amortization (37) (47)
----------------------------------------------------------------------------
Canadian Power-comparable EBIT(1,2) 178 173
----------------------------------------------------------------------------
U.S. Power (US$)
U.S. Power - comparable EBITDA 54 75
Depreciation and amortization(3) - (31)
----------------------------------------------------------------------------
U.S. Power - comparable EBIT 54 44
Foreign exchange impact 18 17
----------------------------------------------------------------------------
U.S. Power-comparable EBIT (Cdn$) 72 61
----------------------------------------------------------------------------
Natural Gas Storage and other - comparable
EBITDA 21 9
Depreciation and amortization (3) (3)
----------------------------------------------------------------------------
Natural Gas Storage and other - comparable
EBIT 18 6
----------------------------------------------------------------------------
Business Development comparable EBITDA and
EBIT (3) (3)
----------------------------------------------------------------------------
Energy-comparable EBIT(1,2) 265 237
Specific items:
U.S. Northeast power monetization (11) -
Alberta PPA terminations - (240)
Risk management activities (56) (123)
----------------------------------------------------------------------------
Segmented earnings/(losses)(1,2) 198 (126)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included losses from the Alberta PPAs up to March 7, 2016 when the PPAs
were terminated.
(2) Includes our share of equity income from our investments in Portlands
Energy and Bruce Power.
(3) Depreciation no longer being recorded effective November 1, 2016 on
assets held for sale.
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:
-- in 2017, $11 million of pre-tax costs related to the monetization of our
U.S. Northeast power business. See Recent developments section for more
details
-- in 2016, a $240 million pre-tax charge, which included a $29 million
impairment of our equity investment in ASTC Power Partnership, on the
carrying value of our Alberta PPAs as a result of our decision to
terminate the PPAs
-- unrealized gains and losses from changes in the fair value of
derivatives used to reduce our exposure to certain commodity price risks
as follows:
------------------------------------------------------------------
------------------------------------------------------------------
three months ended
Risk management activities March 31
--------------------
(unaudited - millions of $, pre-tax) 2017 2016
------------------------------------------------------------------
------------------------------------------------------------------
Canadian Power 1 (13)
U.S. Power (62) (115)
Natural Gas Storage 5 5
------------------------------------------------------------------
Total unrealized losses from risk management
activities (56) (123)
------------------------------------------------------------------
------------------------------------------------------------------
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue(1)
Western Power 46 88
Eastern Power 105 95
Other(2) 15 29
----------------------------------------------------------------------------
166 212
Income from equity investments(3) 8 -
Commodity purchases resold (1) (59)
Plant operating costs and other (49) (47)
----------------------------------------------------------------------------
Comparable EBITDA(4) 124 106
Depreciation and amortization (37) (47)
----------------------------------------------------------------------------
Comparable EBIT(4) 87 59
----------------------------------------------------------------------------
Breakdown of comparable EBITDA
Western Power(4) 30 4
Eastern Power 94 102
----------------------------------------------------------------------------
Comparable EBITDA(4) 124 106
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Plant availability(5)
Western Power 99% 99%
Eastern Power(6,7) 99% 86%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the realized gains and losses from financial derivatives used
to manage Canadian Power's assets which are presented on a net basis in
Western and Eastern Power revenues. The unrealized gains and losses from
financial derivatives have been excluded to arrive at comparable EBITDA.
(2) Includes revenues from the sale of unused natural gas transportation and
sale of excess natural gas purchased for generation.
(3) Includes our share of equity income in Portlands Energy, and ASTC Power
Partnership up to March 7, 2016.
(4) Included Alberta PPAs up to March 7, 2016 when the PPAs were terminated.
(5) The percentage of time the plant was available to generate power,
regardless of whether it was running.
(6) Does not include Becancour because power generation has been suspended
since 2008.
(7) Plant availability was higher in the three months ended March 31, 2017
than the same period in 2016 due to an unplanned outage at the Halton
Hills facility in 2016.
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
-----------------------------
(unaudited - millions of $, unless noted
otherwise) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Equity income included in comparable EBITDA and
EBIT comprised of:
Revenues 401 415
Operating expenses (224) (225)
Depreciation and other (86) (76)
----------------------------------------------------------------------------
Comparable EBITDA and EBIT(1) 91 114
----------------------------------------------------------------------------
Bruce Power - other information
Plant availability(2) 89% 88%
Planned outage days 56 76
Unplanned outage days 17 8
Sales volumes (GWh)(1) 5,983 5,834
Realized sales price per MWh(3) $67 $66
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents our 48.4 per cent (2016 - 48.5 per cent) ownership interest
in Bruce Power. Sales volumes include deemed generation.
(2) The percentage of time the plant was available to generate power,
regardless of whether it was running.
(3) Calculation based on actual and deemed generation. Realized sales prices
per MWh includes realized gains and losses from contracting activities
and cost flow-through items. Excludes unrealized gains and losses on
contracting activities and non-electricity revenues.
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 $12 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to increased third party storage revenues as a result of higher realized natural gas storage price spreads.
U.S. POWER (monetization expected to close in the first half of 2017)
The following are the components of comparable EBITDA and comparable EBIT.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of US$) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue(1)
Power(2) 530 418
Capacity 42 62
----------------------------------------------------------------------------
572 480
Commodity purchases resold (409) (305)
Plant operating costs and other(3) (109) (100)
----------------------------------------------------------------------------
Comparable EBITDA(1) 54 75
Depreciation and amortization(4) - (31)
----------------------------------------------------------------------------
Comparable EBIT(1) 54 44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Ironwood commencing February 1, 2016.
(2) Includes the realized gains and losses from financial derivatives used
to manage U.S. Power's assets which are presented on a net basis in
Power revenues. The unrealized gains and losses from financial
derivatives are excluded to arrive at comparable EBITDA.
(3) Includes the cost of fuel consumed in generation.
(4) U.S. Power assets held for sale are no longer being depreciated
effective November 2016.
Sales volumes and plant availability
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Physical sales volumes (GWh)
Supply
Generation 2,007 2,280
Purchased 6,356 4,748
----------------------------------------------------------------------------
8,363 7,028
Plant availability(1) 71% 71%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The percentage of time the plant was available to generate power,
regardless of whether it was running.
U.S. Power - other information
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average Spot Power Prices (US$ per MWh)
New England(1) 36 30
New York2 36 28
PJM(3) 29 21
Average New York2 Spot Capacity Prices (US$
per KW-M) 3.43 5.83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) New England ISO all hours Mass Hub price.
(2) Zone J market in New York City where the Ravenswood plant operates.
(3) The METED Zone price in Pennsylvania where the Ironwood plant operates.
Average price for 2016 is from the Ironwood acquisition date of February
1, 2016.
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:
-- lower realized capacity prices in New York
-- higher realized power prices at our facilities in New York and New
England, partially offset by higher fuel costs and lower generation
volumes
-- higher sales to customers in the PJM and New England wholesale utility
markets offset by lower realized margins.
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBITDA and EBIT (4) (1)
Specific items:
Acquisition related costs - Columbia (29) (26)
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Segmented losses (33) (27)
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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
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----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest on long-term debt and junior
subordinated notes
Canadian dollar-denominated (108) (111)
U.S. dollar-denominated (317) (246)
Foreign exchange impact (103) (85)
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(528) (442)
Other interest and amortization expense (17) (19)
Capitalized interest 45 41
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Interest expense (500) (420)
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----------------------------------------------------------------------------
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.
Allowance for funds used during construction
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
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Canadian dollar-denominated 50 41
U.S. dollar-denominated 38 45
Foreign exchange impact 13 15
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Allowance for funds used during construction 101 101
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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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest income and other included in
comparable earnings 5 47
Specific item:
Risk management activities 15 53
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Interest income and other 20 100
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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:
-- realized losses in 2017 compared to realized gains in 2016 on
derivatives used to manage our net exposure to foreign exchange rate
fluctuations on U.S. dollar-denominated income
-- lower unrealized gains on risk management activities in 2017 compared to
2016. These amounts have been excluded from comparable earnings
-- the impact of a fluctuating U.S. dollar on the translation of foreign
currency denominated working capital.
Income tax expense
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----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
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Income tax expense included in comparable
earnings (244) (180)
Specific items:
Acquisition related costs - Columbia 15 -
U.S. Northeast power monetization 1 -
Keystone XL income tax recoveries 7 -
Keystone XL asset costs 1 4
Alberta PPA terminations - 64
TC Offshore loss on sale - 1
Risk management activities 20 41
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Income tax expense (200) (70)
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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
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----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income attributable to non-controlling
interests (90) (80)
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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
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----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Preferred share dividends (41) (22)
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----------------------------------------------------------------------------
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:
-- our ability to generate cash flow from operations
-- our access to capital markets
-- approximately $9.1 billion of unutilized, unsecured committed credit
facilities.
CASH PROVIDED BY OPERATING ACTIVITIES
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----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $, except per share
amounts) 2017 2016
----------------------------------------------------------------------------
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Net cash provided by operations 1,302 1,081
Increase in operating working capital 155 132
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Funds generated from operations(1) 1,457 1,213
Specific items:
Acquisition related costs - Columbia 32 26
Keystone XL asset costs 8 10
U.S. Northeast power monetization 11 -
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Comparable funds generated from operations(1) 1,508 1,249
Dividends on preferred shares (39) (23)
Distributions paid to non-controlling
interests (80) (62)
Maintenance capital expenditures including
equity investments (167) (190)
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Comparable distributable cash flow(1) 1,222 974
----------------------------------------------------------------------------
Comparable distributable cash flow per common
share $1.41 $1.39
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(1) See the non-GAAP measures section in this MD&A for further discussion of
funds generated from operations, comparable funds generated from
operations and comparable distributable cash flow.
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:
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three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
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Canadian Natural Gas Pipelines 49 55
U.S. Natural Gas Pipelines 70 71
Other 48 64
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Maintenance capital expenditures including
equity investments 167 190
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CASH USED IN INVESTING ACTIVITIES
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
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Capital spending
Capital expenditures (1,560) (836)
Capital projects in development (42) (67)
----------------------------------------------------------------------------
(1,602) (903)
Contributions to equity investments (192) (170)
Acquisitions, net of cash acquired - (995)
Proceeds from sale of assets, net of
transaction costs - 6
Other distributions from equity investments 363 -
Deferred amounts and other (85) 52
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Net cash used in investing activities (1,516) (2,010)
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Capital expenditures in 2017 were primarily related to:
-- expansion of Columbia pipelines -- expansion of the NGTL System -- construction of Mexico pipelines -- expansion of the Canadian Mainline -- expansion of the ANR pipeline -- construction of the Napanee power generating facility.
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.
CASH PROVIDED BY FINANCING ACTIVITIES
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----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes payable issued, net 670 1,176
Long-term debt issued, net of issue costs - 1,992
Long-term debt repaid (1,051) (1,357)
Junior subordinated notes issued, net of issue
costs 1,982 -
Dividends and distributions paid (419) (450)
Common shares issued, net of issue costs 18 3
Common shares repurchased - (14)
Partnership units of TC PipeLines, LP issued,
net of issue costs 92 24
Common units of Columbia Pipeline Partners LP
acquired (1,205) -
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Net cash provided by financing activities 87 1,374
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On February 17, 2017, we acquired all outstanding common units of CPPL for US$921 million.
LONG-TERM DEBT RETIRED/REPAID
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited -
millions of $) Retirement/Repayment Interest
Company date Type Amount rate
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TRANSCANADA PIPELINES LIMITED
February 2017 Acquisition
Bridge
Facility(1) US $500 Floating
January 2017 Medium Term
Notes $300 5.10 %
TRANSCANADA PIPELINE USA LTD
April 2017 Acquisition
Bridge
Facility(1,2) US $1,070 Floating
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(1) This facility was put into place to finance a portion of the Columbia
acquisition and bears interest at LIBOR plus an applicable margin.
(2) Proceeds from the April 19, 2017 sale of TC Hydro were used to partially
repay the acquisition bridge facility.
JUNIOR SUBORDINATED NOTES ISSUED
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----------------------------------------------------------------------------
(unaudited -
millions of $) Maturity Interest
Company Issue date Type date Amount rate
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TRANSCANADA PIPELINES
LIMITED
March 2017 Junior Subordinated
Notes(1,2) March 2077 US $1,500 5.55 %
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(1) The Junior subordinated notes are subordinated in right of payment to
existing and future senior indebtedness or other obligations of TCPL.
(2) The Junior subordinated notes were issued to TransCanada Trust (the
Trust), a financing trust subsidiary wholly-owned by TCPL. While the
obligations of the Trust are fully and unconditionally guaranteed by
TCPL on a subordinated basis, the Trust is not consolidated in
TransCanada's financial statements because TCPL does not have a variable
interest in the Trust and the only substantive assets of the Trust are
junior subordinated notes of TCPL.
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:
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----------------------------------------------------------------------------
Quarterly dividend on our common shares
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----------------------------------------------------------------------------
$0.625 per share
Payable on July 31, 2017 to shareholders of record at the close of business
on June 30, 2017
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Quarterly dividends on our preferred shares
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Series 1 $0.204125
Series 2 $0.14958904
Series 3 $0.1345
Series 4 $0.10969863
Payable on June 30, 2017 to shareholders of record at the close of business
on May 31, 2017
Series 5 $0.14143750
Series 6 $0.12796096
Series 7 $0.25
Series 9 $0.265625
Payable on July 31, 2017 to shareholders of record at the close of business
on June 30, 2017
Series 11 $0.2375
Series 13 $0.34375
Series 15 $0.30625
Payable on May 31, 2017 to shareholders of record at the close of business
on May 16, 2017
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SHARE INFORMATION
----------------------------------------------------------------------------
----------------------------------------------------------------------------
as at May 1, 2017
----------------------------------------------------------------------------
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Common shares Issued and outstanding
871 million
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Preferred shares Issued and outstanding Convertible to
Series 1 9.5 million Series 2 preferred shares
Series 2 12.5 million Series 1 preferred shares
Series 3 8.5 million Series 4 preferred shares
Series 4 5.5 million Series 3 preferred shares
Series 5 12.7 million Series 6 preferred shares
Series 6 1.3 million Series 5 preferred shares
Series 7 24 million Series 8 preferred shares
Series 9 18 million Series 10 preferred shares
Series 11 10 million Series 12 preferred shares
Series 13 20 million Series 14 preferred shares
Series 15 40 million Series 16 preferred shares
Options to buy common Outstanding Exercisable
shares
12 million 8 million
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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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Unused
Amount capacity Borrower Description Matures
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$3.0 billion $3.0 TCPL Committed, syndicated, December
billion revolving, extendible credit 2021
facility that supports TCPL's
Canadian commercial paper
program and for general
corporate purposes
US$1.5 - TCPL Committed, syndicated, senior June 2018
billion asset bridge term loan
commitment that supports the
acquisition of Columbia
US$2.0 US$2.0 TCPL Committed, syndicated, December
billion billion revolving, extendible credit 2017
facility that supports TCPL's
U.S. commercial paper program
US$0.6 - TCPL USA Committed, syndicated, senior June 2018
billion asset bridge term loan
commitment that supports the
acquisition of Columbia
US$1.0 US$1.0 TCPL USA Committed, syndicated, December
billion billion revolving, extendible credit 2017
facility that is used for TCPL
USA general corporate
purposes, guaranteed by TCPL
US$1.0 US$0.5 Columbia Committed, syndicated, December
billion billion revolving, extendible credit 2017
facility that is used for
Columbia's general corporate
purposes, guaranteed by TCPL
US$0.5 US$0.5 TAIL Committed, syndicated, December
billion billion revolving, extendible credit 2017
facility that supports TAIL's
commercial paper program,
guaranteed by TCPL
$2.1 billion $0.8 TCPL/TCPL Supports the issuance of Demand
billion USA letters of credit and provides
additional liquidity
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----------------------------------------------------------------------------
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:
-- accounts receivable -- the fair value of derivative assets -- cash and cash equivalents -- notes receivable.
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.
Average exchange rate - U.S. to Canadian dollars ------------------------------------------------------------------ ------------------------------------------------------------------ three months ended March 31, 2017 1.32 three months ended March 31, 2016 1.35 ------------------------------------------------------------------ ------------------------------------------------------------------
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
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----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of US$) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S. Natural Gas Pipelines comparable EBIT 431 200
Mexico Natural Gas Pipelines comparable EBIT 89 33
U.S. Liquids Pipelines comparable EBIT 135 127
U.S. Power comparable EBIT 54 44
AFUDC on U.S. dollar-denominated projects 38 45
Interest on U.S. dollar-denominated long-term
debt (317) (246)
Capitalized interest on U.S. dollar-
denominated capital expenditures - 7
U.S. dollar non-controlling interests (68) (60)
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362 150
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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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, 2017 December 31, 2016
---------------------- ----------------------
(unaudited - millions of Notional or Notional or
Canadian $, unless noted Fair principal Fair principal
otherwise) value(1) amount value(1) amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S. dollar cross-currency
interest rate swaps (maturing
2017 to 2019)(2) (337) US 2,000 (425) US 2,350
U.S. dollar foreign exchange
forward contracts - - (7) US 150
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(337) US 2,000 (432) US 2,500
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(1) Fair values equal carrying values.
(2) In the three months ended March 31, 2017, net realized gains of $1
million (2016 - gains of $2 million) related to the interest component
of cross-currency swaps settlements are included in interest expense.
U.S. dollar-denominated debt designated as a net investment hedge
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(unaudited - millions of Canadian $,
unless noted otherwise) March 31, 2017 December 31, 2016
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Notional amount 28,400 (US 21,400) 26,600 (US 19,800)
Fair value 31,500 (US 23,600) 29,400 (US 21,900)
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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:
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(unaudited - millions of $) March 31, 2017 December 31, 2016
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Other current assets 413 376
Intangible and other assets 153 133
Accounts payable and other (607) (607)
Other long-term liabilities (334) (330)
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(375) (428)
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Unrealized and realized (losses)/gains of derivative instruments
The following summary does not include hedges of our net investment in foreign operations.
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three months ended March 31
------------------------------
(unaudited - millions of $, pre-tax) 2017 2016
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Derivative instruments held for trading(1)
Amount of unrealized (losses)/gains in the
period
Commodities(2) (56) (67)
Foreign exchange 15 27
Interest rate 1 -
Amount of realized (losses)/gains in the
period
Commodities (48) (95)
Foreign exchange (4) 44
Derivative instruments in hedging
relationships
Amount of realized gains/(losses) in the
period
Commodities 6 (73)
Foreign exchange 5 (63)
Interest rate 1 2
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(1) Realized and unrealized gains and losses on held for trading derivative
instruments used to purchase and sell commodities are included net in
revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange held for trading derivative instruments are included
net in interest expense and interest income and other, respectively.
(2) Following the March 17, 2016 announcement of our intention to sell the
U.S. Northeast power business, a loss of $49 million and a gain of $7
million were recorded in net income in the three months ended March 31,
2016 relating to discontinued cash flow hedges where it was probable
that the anticipated underlying transaction would not occur as a result
of a future sale.
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:
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three months ended March 31
------------------------------
(unaudited - millions of $, pre-tax) 2017 2016
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Change in fair value of derivative instruments
recognized in OCI (effective portion)(1)
Commodities 5 (16)
Foreign exchange - (35)
Interest rate 1 (3)
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6 (54)
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Reclassification of (losses)/gains on
derivative instruments from AOCI to net
income (effective portion)(1)
Commodities(2) (4) 82
Foreign exchange(3) - 34
Interest rate(4) 4 4
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- 120
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Losses on derivative instruments recognized in
net income (ineffective portion)
Commodities(2) - (58)
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- (58)
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(1) No amounts have been excluded from the assessment of hedge
effectiveness. Amounts in parentheses indicate losses recorded to OCI.
(2) Reported within revenues on the condensed consolidated statement of
income.
(3) Reported within interest income and other on the condensed consolidated
statement of income.
(3) Reported within interest expense on the condensed consolidated statement
of income.
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. Lessees may also be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019. We are currently identifying existing lease agreements that may have an impact on our consolidated financial statements as a result of adopting this new guidance.
Measurement of credit losses on financial instruments
In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.
Income taxes
In October 2016, the FASB issued new guidance on income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied on a modified retrospective basis. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.
Restricted cash
In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The amounts of restricted cash and cash equivalents will be included in Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively, however, early adoption is permitted.
Goodwill impairment
In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, with early adoption permitted.
Employee post-retirement benefits
In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of the net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of the net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. We are currently evaluating the impact of the adoption of this guidance on our consolidated financial statements.
Amortization on purchased callable debt securities
In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.
Reconciliation of non-GAAP measures
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three months ended March 31
------------------------------
(unaudited - millions of $) 2017 2016
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Comparable EBITDA
Canadian Natural Gas Pipelines 504 488
U.S. Natural Gas Pipelines 720 338
Mexico Natural Gas Pipelines 140 53
Liquids Pipelines 312 296
Energy 305 328
Corporate (4) (1)
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Comparable EBITDA 1,977 1,502
Depreciation and amortization (510) (454)
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Comparable EBIT 1,467 1,048
Specific items:
Acquisition related costs - Columbia (39) (26)
U.S. Northeast power monetization (11) -
Keystone XL asset costs (8) (10)
Alberta PPA terminations - (240)
TC Offshore loss on sale - (4)
Risk management activities(1) (56) (125)
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Segmented earnings 1,353 643
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(1) three months ended
Risk management activities March 31
--------------------
(unaudited - millions of $) 2017 2016
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Canadian Power 1 (13)
U.S. Power (62) (115)
Natural Gas Storage 5 5
Liquids marketing - (2)
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Total unrealized losses from risk
management activities (56) (125)
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Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
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2017 2016 2015
------ ---------------------------- --------------------
(unaudited -
millions of $,
except per share
amounts) First Fourth Third Second First Fourth Third Second
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Revenues 3,391 3,619 3,632 2,751 2,503 2,851 2,944 2,631
Net income/(loss)
attributable to
common shares 643 (358) (135) 365 252 (2,458) 402 429
Comparable earnings 698 626 622 366 494 453 440 397
Per share statistics
Net income/(loss)
per common share
- basic and
diluted $0.74 ($0.43)($0.17) $0.52 $0.36 ($3.47) $0.57 $0.60
Comparable
earnings per
share $0.81 $0.75 $0.78 $0.52 $0.70 $0.64 $0.62 $0.56
Dividends declared
per common share $0.625 $0.565 $0.565 $0.565 $0.565 $0.52 $0.52 $0.52
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FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT
Quarter-over-quarter revenues and net income sometimes fluctuate, the causes of which vary across our business segments.
In our Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines segments, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
-- regulatory decisions -- negotiated settlements with shippers -- acquisitions and divestitures -- developments outside of the normal course of operations -- newly constructed assets being placed in service.
In Liquids Pipelines, revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income are also affected by:
-- developments outside of the normal course of operations -- newly constructed assets being placed in service -- regulatory decisions.
In Energy, quarter-over-quarter revenues and net income are affected by:
-- weather -- customer demand -- market prices for natural gas and power -- capacity prices and payments -- planned and unplanned plant outages -- acquisitions and divestitures -- certain fair value adjustments -- developments outside of the normal course of operations -- newly constructed assets being placed in service.
FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.
Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.
In first quarter 2017, comparable earnings excluded:
-- a charge of $24 million after tax for integration-related costs
associated with the acquisition of Columbia
-- a charge of $10 million after tax for costs related to the monetization
of our U.S. Northeast power business
-- a charge of $7 million after tax related to the maintenance of Keystone
XL assets which are being expensed pending further advancement of the
project
-- a $7 million income tax recovery related to the realized loss on a third
party sale of Keystone XL project assets. A provision for the expected
pre-tax loss on these assets was included in our 2015 impairment charge,
but the related income tax recoveries could not be recorded until
realized
In fourth quarter 2016, comparable earnings excluded:
-- an $870 million after-tax charge related to the loss on U.S. Northeast
power assets held for sale which included an $863 million after-tax loss
on the thermal and wind package held for sale and $7 million of after-
tax costs related to the monetization
-- an additional $68 million after-tax loss on the transfer of
environmental credits to the Balancing Pool upon final settlement of the
Alberta PPA terminations
-- an after-tax charge of $67 million for costs associated with the
acquisition of Columbia which included a $44 million deferred tax
adjustment upon acquisition and $23 million of retention, severance and
integration costs
-- an after-tax charge of $18 million related to Keystone XL costs for the
maintenance and liquidation of project assets which are being expensed
pending further advancement of the project
-- an after-tax restructuring charge of $6 million for additional expected
future losses under lease commitments. These charges form part of a
restructuring initiative, which commenced in 2015, to maximize the
effectiveness and efficiency of our existing operations and reduce
overall costs.
In third quarter 2016, comparable earnings excluded:
-- a $656 million after-tax impairment on Ravenswood goodwill. As a result
of information received during the process to monetize our U.S.
Northeast Power business in third quarter 2016, it was determined that
the fair value of Ravenswood no longer exceeded its carrying value
-- costs associated with the acquisition of Columbia including a charge of
$67 million after tax primarily related to retention, severance and
integration expenses
-- $28 million of income tax recoveries related to the realized loss on a
third party sale of Keystone XL plant and equipment. A provision for the
expected loss on these assets was included in our fourth quarter 2015
impairment charge but the related tax recoveries could not be recorded
until realized
-- a charge of $9 million after tax related to Keystone XL costs for the
maintenance and liquidation of project assets which are being expensed
pending further advancement of the project
-- a $3 million after-tax charge related to the monetization of our U.S.
Northeast Power business.
In second quarter 2016, comparable earnings excluded:
-- a charge of $113 million related to costs associated with the
acquisition of Columbia
-- a charge of $9 million after tax related to Keystone XL costs for the
maintenance and liquidation of project assets which are being expensed
pending further advancement of the project
-- a charge of $10 million after tax for restructuring charges mainly
related to expected future losses under lease commitments.
In first quarter 2016, comparable earnings excluded:
-- a $176 million after-tax impairment charge on the carrying value of our
Alberta PPAs as a result of our decision to terminate the PPAs
-- a charge of $26 million related to costs associated with the acquisition
of Columbia
-- a charge of $6 million after tax related to Keystone XL costs for the
maintenance and liquidation of project assets which are being expensed
pending further advancement of the project
-- an additional $3 million after-tax loss on the sale of TC Offshore which
closed on March 31, 2016.
In fourth quarter 2015, comparable earnings excluded:
-- a $2,891 million after-tax impairment charge on the carrying value of
our investment in Keystone XL and related projects
-- an $86 million after-tax loss provision related to the sale of TC
Offshore expected to close in early 2016
-- a net charge of $60 million after tax for our business restructuring and
transformation initiative comprised of $28 million mainly related to
2015 severance costs and a provision of $32 million for 2016 planned
severance costs and expected future losses under lease commitments.
These charges form part of a restructuring initiative which commenced in
2015 to maximize the effectiveness and efficiency of our existing
operations and reduce overall costs
-- a $43 million after-tax charge related to an impairment in value of
turbine equipment held for future use in our Energy business
-- a charge of $27 million after tax related to Bruce Power's retirement of
debt in conjunction with the merger of the Bruce A and Bruce B
partnerships
-- a $199 million positive income adjustment related to the impact on our
net income from non-controlling interests of TC PipeLines, LP's
impairment of their equity investment in Great Lakes.
In third quarter 2015, comparable earnings excluded a charge of $6 million after-tax for severance costs as part of a restructuring initiative to maximize the effectiveness and efficiency of our existing operations.
In second quarter 2015, comparable earnings excluded a $34 million adjustment to income tax expense due to the enactment of an increase in the Alberta corporate income tax rate in June 2015 and a charge of $8 million after-tax for severance costs primarily as a result of the restructuring of our major projects group in response to delayed timelines on certain of our major projects along with a continued focus on enhancing the efficiency and effectiveness of our operations.
Condensed consolidated statement of income
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three months ended March 31
------------------------------
(unaudited - millions of Canadian $, except
per share amounts) 2017 2016
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Revenues
Canadian Natural Gas Pipelines 882 818
U.S. Natural Gas Pipelines 994 429
Mexico Natural Gas Pipelines 143 66
Liquids Pipelines 472 436
Energy 900 754
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3,391 2,503
Income from Equity Investments 174 135
Operating and Other Expenses
Plant operating costs and other 990 715
Commodity purchases resold 543 470
Property taxes 162 141
Depreciation and amortization 517 454
Asset impairment charges - 211
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2,212 1,991
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Loss on sale of assets - (4)
Financial Charges
Interest expense 500 420
Allowance for funds used during construction (101) (101)
Interest income and other (20) (100)
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379 219
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Income before Income Taxes 974 424
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Income Tax Expense
Current 67 34
Deferred 133 36
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200 70
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Net Income 774 354
Net income attributable to non-controlling
interests 90 80
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Net Income Attributable to Controlling
Interests 684 274
Preferred share dividends 41 22
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Net Income Attributable to Common Shares 643 252
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Net Income per Common Share
Basic and diluted $0.74 $0.36
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Dividends Declared per Common Share $0.625 $0.565
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Weighted Average Number of Common Shares
(millions)
Basic 866 702
Diluted 868 703
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See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated statement of comprehensive income
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three months ended March 31
------------------------------
(unaudited - millions of Canadian $) 2017 2016
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Net Income 774 354
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Other Comprehensive Loss, Net of Income Taxes
Foreign currency translation losses on net
investment in foreign operations (82) (212)
Change in fair value of net investment hedges (1) (2)
Change in fair value of cash flow hedges 5 (39)
Reclassification to net income of gains on
cash flow hedges - 80
Reclassification of actuarial gains and losses
on pension and other post-retirement benefit
plans 3 4
Other comprehensive income on equity
investments 3 3
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Other comprehensive loss (Note 9) (72) (166)
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Comprehensive Income 702 188
Comprehensive income/(loss) attributable to
non-controlling interests 50 (26)
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Comprehensive Income Attributable to
Controlling Interests 652 214
Preferred share dividends 41 22
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Comprehensive Income Attributable to Common
Shares 611 192
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See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated statement of cash flows
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three months ended March 31
------------------------------
(unaudited - millions of Canadian $) 2017 2016
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Cash Generated from Operations
Net income 774 354
Depreciation and amortization 517 454
Asset impairment charges - 211
Deferred income taxes 133 36
Income from equity investments (174) (135)
Distributions received from operating
activities of equity investments 219 259
Employee post-retirement benefits expense, net
of funding 3 11
Loss on sale of assets - 4
Equity allowance for funds used during
construction (64) (57)
Unrealized losses on financial instruments 41 71
Other 8 5
Increase in operating working capital (155) (132)
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Net cash provided by operations 1,302 1,081
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Investing Activities
Capital expenditures (1,560) (836)
Capital projects in development (42) (67)
Contributions to equity investments (192) (170)
Acquisitions, net of cash acquired - (995)
Proceeds from sale of assets, net of
transaction costs - 6
Other distributions from equity investments 363 -
Deferred amounts and other (85) 52
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Net cash used in investing activities (1,516) (2,010)
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Financing Activities
Notes payable issued, net 670 1,176
Long-term debt issued, net of issue costs - 1,992
Long-term debt repaid (1,051) (1,357)
Junior subordinated notes issued, net of issue
costs 1,982 -
Dividends on common shares (300) (365)
Dividends on preferred shares (39) (23)
Distributions paid to non-controlling
interests (80) (62)
Common shares issued, net of issue costs 18 3
Common shares repurchased - (14)
Partnership units of TC PipeLines, LP issued,
net of issue costs 92 24
Common units of Columbia Pipeline Partners LP
acquired (1,205) -
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Net cash provided by financing activities 87 1,374
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Effect of Foreign Exchange Rate Changes on
Cash and Cash Equivalents 5 (57)
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(Decrease)/increase in Cash and Cash
Equivalents (122) 388
Cash and Cash Equivalents
Beginning of period 1,016 850
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Cash and Cash Equivalents
End of period 894 1,238
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See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated balance sheet
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----------------------------------------------------------------------------
March 31, December 31,
(unaudited - millions of Canadian $) 2017 2016
----------------------------------------------------------------------------
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ASSETS
Current Assets
Cash and cash equivalents 894 1,016
Accounts receivable 2,120 2,075
Inventories 384 368
Assets held for sale 3,687 3,717
Other 918 908
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8,003 8,084
Plant, Property and net of accumulated
Equipment depreciation of
$22,696 and $22,263,
respectively 55,353 54,475
Equity Investments 6,262 6,544
Regulatory Assets 1,325 1,322
Goodwill 13,849 13,958
Intangible and Other Assets 3,148 3,026
Restricted Investments 699 642
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88,639 88,051
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LIABILITIES
Current Liabilities
Notes payable 1,493 774
Accounts payable and other 3,806 3,861
Dividends payable 557 526
Accrued interest 549 595
Liabilities related to assets held for sale 60 86
Current portion of long-term debt 2,669 1,838
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9,134 7,680
Regulatory Liabilities 2,259 2,121
Other Long-Term Liabilities 1,134 1,183
Deferred Income Tax Liabilities 7,749 7,662
Long-Term Debt 36,163 38,312
Junior Subordinated Notes 5,879 3,931
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62,318 60,889
Common Units Subject to Rescission or
Redemption 82 1,179
EQUITY
Common shares, no par value 20,308 20,099
Issued and March 31, 2017 - 867
outstanding: million shares
December 31, 2016 -
864 million shares
Preferred shares 3,980 3,980
Additional paid-in capital - -
Retained earnings 1,115 1,138
Accumulated other comprehensive loss (992) (960)
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Controlling Interests 24,411 24,257
Non-controlling interests 1,828 1,726
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26,239 25,983
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88,639 88,051
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Commitments, Contingencies and Guarantees (Note 12)
Variable Interest Entities (Note 13)
Subsequent Events (Note 14)
See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated statement of equity
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three months ended March 31
------------------------------
(unaudited - millions of Canadian $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common Shares
Balance at beginning of period 20,099 12,102
Shares issued on exercise of stock options 19 3
Shares repurchased - (6)
Shares issued under dividend reinvestment and
share purchase plan 190 -
----------------------------------------------------------------------------
Balance at end of period 20,308 12,099
----------------------------------------------------------------------------
Preferred Shares
Balance at beginning and end of period 3,980 2,499
----------------------------------------------------------------------------
Additional Paid-In Capital
Balance at beginning of period - 7
Issuance of stock options, net of exercises 2 5
Dilution impact from TC PipeLines, LP units
issued 10 3
Impact of common shares repurchased - (8)
Impact of asset drop down to TC PipeLines, LP - (38)
Impact of Columbia Pipeline Partners LP
acquisition (171) -
Reclassification of Additional Paid-In Capital
deficit to Retained Earnings 159 31
----------------------------------------------------------------------------
Balance at end of period - -
----------------------------------------------------------------------------
Retained Earnings
Balance at beginning of period 1,138 2,769
Net income attributable to controlling
interests 684 274
Common share dividends (542) (397)
Preferred share dividends (18) (21)
Adjustment related to employee share-based
payments (Note 2) 12 -
Reclassification of Additional Paid-In Capital
deficit to Retained Earnings (159) (31)
----------------------------------------------------------------------------
Balance at end of period 1,115 2,594
----------------------------------------------------------------------------
Accumulated Other Comprehensive Loss
Balance at beginning of period (960) (939)
Other comprehensive loss (32) (60)
----------------------------------------------------------------------------
Balance at end of period (992) (999)
----------------------------------------------------------------------------
Equity Attributable to Controlling Interests 24,411 16,193
----------------------------------------------------------------------------
Equity Attributable to Non-Controlling
Interests
Balance at beginning of period 1,726 1,717
Net income attributable to non-controlling
interests
TC PipeLines, LP 73 71
Portland Natural Gas Transmission System 8 9
Columbia Pipeline Partners LP 9 -
Other comprehensive loss attributable to non-
controlling interests (40) (106)
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs 92 24
Decrease in TransCanada's ownership of TC
PipeLines, LP (17) (4)
Reclassification from common units subject
to rescission 24 -
Distributions declared to non-controlling
interests (80) (68)
Impact of Columbia Pipeline Partners LP
acquisition 33 -
----------------------------------------------------------------------------
Balance at end of period 1,828 1,643
----------------------------------------------------------------------------
Total Equity 26,239 17,836
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the condensed consolidated financial statements.
Notes to condensed consolidated financial statements
(unaudited)
1. Basis of presentation
These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada's annual audited consolidated financial statements for the year ended December 31, 2016, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada's 2016 Annual Report.
These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2016 audited consolidated financial statements included in TransCanada's 2016 Annual Report. Certain comparative figures have been reclassified to conform with the current period's presentation.
Earnings for interim periods may not be indicative of results for the fiscal year in the Company's natural gas pipelines segments due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company's Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company's investments in electrical power generation plants and non-regulated gas storage facilities.
USE OF ESTIMATES AND JUDGEMENTS
In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies included in the consolidated financial statements for the year ended December 31, 2016, except as described in Note 2, Accounting changes.
2. Accounting changes
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 the Company's 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 the Company's 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 the Company's 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. The Company has elected to account for forfeitures when they occur. This new guidance was effective January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to 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 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 the Company's 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. The Company 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. The Company is evaluating both methods of adoption as it works through its analysis.
The Company has identified all existing customer contracts that are within the scope of the new guidance and is 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 the Company continues its contract analysis, it will also quantify the impact, if any, on prior period revenues. The Company will address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard. The Company is currently evaluating the impact on its 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 the Company 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. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its 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. Lessees may also be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019. The Company is currently identifying existing lease agreements that may have an impact on its consolidated financial statements as a result of adopting this new guidance.
Measurement of credit losses on financial instruments
In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.
Income taxes
In October 2016, the FASB issued new guidance on income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.
Restricted cash
In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The amounts of restricted cash and cash equivalents will be included in Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively, however, early adoption is permitted.
Goodwill impairment
In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, with early adoption permitted.
Employee post-retirement benefits
In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of the net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of the net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. The Company is currently evaluating the impact of the adoption of this guidance on its consolidated financial statements.
Amortization on purchased callable debt securities
In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.
3. Segmented information
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months
ended
March 31,
2017
Canadian U.S. Mexico
(unaudited - Natural Natural Natural
millions of Gas Gas Gas Liquids
Canadian $) Pipelines Pipelines Pipelines Pipelines Energy Corporate Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 882 994 143 472 900 - 3,391
Income from
equity
investments 3 65 6 - 100 - 174
Plant
operating
costs and
other (312) (295) (9) (145) (196) (33) (990)
Commodity
purchases
resold - - - - (543) - (543)
Property
taxes (69) (47) - (23) (23) - (162)
Depreciation
and
amortization (222) (156) (22) (77) (40) - (517)
----------------------------------------------------------------------------
Segmented
earnings/
(losses) 282 561 118 227 198 (33) 1,353
---------------------------------------------------------------------
Interest expense (500)
Allowance for funds used during construction 101
Interest income and other 20
----------------------------------------------------------------------------
Income before income taxes 974
Income tax expense (200)
----------------------------------------------------------------------------
Net income 774
Net income attributable to non-controlling interests (90)
----------------------------------------------------------------------------
Net income attributable to controlling interests 684
Preferred share dividends (41)
----------------------------------------------------------------------------
Net income attributable to common shares 643
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months
ended
March 31,
2016
Canadian U.S. Mexico
(unaudited - Natural Natural Natural
millions of Gas Gas Gas Liquids
Canadian $) Pipelines Pipelines Pipelines Pipelines Energy Corporate Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 818 429 66 436 754 - 2,503
Income from
equity
investments 3 48 - - 84 - 135
Plant
operating
costs and
other (260) (118) (13) (129) (168) (27) (715)
Commodity
purchases
resold - - - - (470) - (470)
Property
taxes (73) (21) - (23) (24) - (141)
Depreciation
and
amortization (216) (67) (8) (72) (91) - (454)
Asset
impairment
charges - - - - (211) - (211)
Loss on
assets held
for sale - (4) - - - - (4)
----------------------------------------------------------------------------
Segmented
earnings/
(losses) 272 267 45 212 (126) (27) 643
---------------------------------------------------------------------
Interest expense (420)
Allowance for funds used during construction 101
Interest income and other 100
----------------------------------------------------------------------------
Income before income taxes 424
Income tax expense (70)
----------------------------------------------------------------------------
Net Income 354
Net income attributable to non-controlling interests (80)
----------------------------------------------------------------------------
Net Income attributable to controlling interests 274
Preferred share dividends (22)
----------------------------------------------------------------------------
Net Income attributable to common shares 252
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TOTAL ASSETS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited - millions of Canadian $) March 31, 2017 December 31, 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Natural Gas Pipelines 16,255 15,816
U.S. Natural Gas Pipelines 34,934 34,422
Mexico Natural Gas Pipelines 5,230 5,013
Liquids Pipelines 16,995 16,896
Energy 12,832 13,169
Corporate 2,393 2,735
----------------------------------------------------------------------------
88,639 88,051
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. Assets held for sale
U.S. Northeast Power Assets
The Company's planned monetization of its U.S. Northeast power business, for the purpose of permanently financing a portion of the Columbia acquisition, includes the sale of Ravenswood, Ironwood, Kibby Wind, Ocean State Power, TC Hydro and the marketing business, TransCanada Power Marketing (TCPM).
On November 1, 2016, the Company entered into agreements to sell all of these assets except TCPM.
The sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party for proceeds of approximately US$2.2 billion is expected to close in the second quarter of 2017. As a result, the Company recorded a loss of approximately $829 million ($863 million after tax) in 2016 which included the impact of an estimated $70 million of foreign currency translation gains to be reclassified from AOCI to Net income on close. At March 31, 2017, the related assets and liabilities were classified as held for sale in the Energy segment and were recorded at their fair values less costs to sell based on the proceeds expected on the close of this sale.
At March 31, 2017, the assets and liabilities related to TC Hydro were also classified as held for sale in the Energy segment. Subsequently, on April 19, 2017, the Company closed the sale of TC Hydro for gross proceeds of US$1.065 billion, subject to post-closing adjustments. As a result, on April 19, 2017, the Company recorded a gain on sale of approximately $710 million ($440 million after tax) including the impact of an estimated $5 million of foreign currency translation gains. The proceeds received were used to reduce the outstanding balance on the acquisition bridge facility.
As of March 31, 2017, TCPM did not meet the criteria to be classified as held for sale.
The following table details the assets and liabilities held for sale at March 31, 2017.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(millions of $) U.S. Canadian(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Assets held for sale
Accounts receivable 10 13
Inventories 56 74
Other current assets 73 97
Plant, property and equipment 2,242 2,986(2)
Intangible and other assets 335 447
Foreign currency translation gains - 70(3)
----------------------------------------------------------------------------
Total assets held for sale 2,716 3,687
----------------------------------------------------------------------------
Liabilities related to assets held for
sale
Accounts payable and other 21 28
Other long-term liabilities 24 32
----------------------------------------------------------------------------
Total liabilities related to assets held
for sale 45 60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) At March 31, 2017 exchange rate of $1.33.
(2) Includes $17 million (US$13 million) for a gas plant held for sale in
the U.S. Natural Gas Pipelines segment.
(3) Foreign currency translation gains related to the investments in
Ravenswood, Ironwood, Kibby Wind and Ocean State Power will be
reclassified from AOCI to Net Income on close of the sales.
5. Income taxes
The effective tax rates for the three-month periods ended March 31, 2017 and 2016 were 21 per cent and 17 per cent, respectively. The higher effective tax rate in 2017 was primarily the result of changes in the proportion of income earned between Canadian and foreign jurisdictions.
6. Long-term debt
LONG-TERM DEBT RETIRED/REPAID
The Company retired/repaid long-term debt in the three months ended March 31, 2017 as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited -
millions of
Canadian $, unless
noted otherwise)
Retirement/Repayment Interest
Company date Type Amount rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TRANSCANADA
PIPELINES LIMITED
February 2017 Acquisition US$500 Floating
Bridge
Facility(1)
January 2017 Medium Term $300 5.10 %
Notes
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) This facility was put into place to finance a portion of the Columbia
acquisition and bears interest at LIBOR plus an applicable margin.
In the three months ended March 31, 2017, TransCanada capitalized interest related to capital projects of $45 million (2016 - $41 million).
7. Junior subordinated notes issued
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited -
millions of
Canadian $,
unless noted
otherwise) Maturity Interest
Company Issue date Type date Amount rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TRANSCANADA PIPELINES
LIMITED
March 2017 Junior Subordinated
Notes(1,2) March 2077 US $1,500 5.55 %
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Junior subordinated notes are subordinated in right of payment to
existing and future senior indebtedness or other obligations of TCPL.
(2) The Junior subordinated notes were issued to TransCanada Trust (the
Trust), a financing trust subsidiary wholly-owned by TCPL. While the
obligations of the Trust are fully and unconditionally guaranteed by
TCPL on a subordinated basis, the Trust is not consolidated in
TransCanada's financial statements because TCPL does not have a variable
interest in the Trust and the only substantive assets of the Trust are
junior subordinated notes of TCPL.
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.
8. Common units subject to rescission or redemption
Columbia Pipeline Partners LP acquisition
On February 17, 2017, the Company acquired all outstanding publicly held common units of Columbia Pipeline Partners LP (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. As this was a transaction under common control, it was recognized in equity.
At December 31, 2016, the entire $1,073 million (US$799 million) of the Company's non-controlling interest in CPPL was recorded as Common units subject to rescission or redemption on the condensed consolidated balance sheet.
Common units of TC PipeLines, LP subject to rescission
At March 31, 2017, $82 million (US$63 million) (December 31, 2016 - $106 million (US$82 million)) was recorded as Common units subject to rescission or redemption on the condensed consolidated balance sheet. In March 2017, rescission rights on 0.4 million TC PipeLines, LP common units expired and $24 million was reclassified to equity. The Company continued to classify $82 million with respect to 1.2 million common units outside Equity because the potential rescission rights of the units are not within the control of the Company. At March 31, 2017, no unitholder has claimed or attempted to exercise any rescission rights to date and these remaining rescission rights expire one year from the date of purchase of the units which ranges from April 1, 2016 to May 19, 2016.
9. Other comprehensive loss and accumulated other comprehensive loss
Components of other comprehensive loss, including the portion attributable to non-controlling interests and related tax effects, are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31, 2017
Income Tax
Before Tax Recovery/ Net of Tax
(unaudited - millions of Canadian $) Amount Expense Amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign currency translation losses on
net investment in foreign operations (88) 6 (82)
Change in fair value of net investment
hedges (2) 1 (1)
Change in fair value of cash flow hedges 6 (1) 5
Reclassification of actuarial gains and
losses on pension and other post-
retirement benefit plans 5 (2) 3
Other comprehensive income on equity
investments 4 (1) 3
----------------------------------------------------------------------------
Other comprehensive loss (75) 3 (72)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31, 2016
Income Tax
Before Tax Recovery/ Net of Tax
(unaudited - millions of Canadian $) Amount Expense Amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign currency translation losses on
net investment in foreign operations (210) (2) (212)
Change in fair value of net investment
hedges (3) 1 (2)
Change in fair value of cash flow hedges (54) 15 (39)
Reclassification to net income of gains
on cash flow hedges 120 (40) 80
Reclassification of actuarial gains and
losses on pension and other post-
retirement benefit plans 5 (1) 4
Other comprehensive income on equity
investments 4 (1) 3
----------------------------------------------------------------------------
Other comprehensive loss (138) (28) (166)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The changes in AOCI by component are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended
March 31, 2017
Currency Cash Pension and
(unaudited - millions Translation Flow OPEB Plan Equity
of Canadian $) Adjustments Hedges Adjustments Investments Total(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
AOCI balance at
January 1, 2017 (376) (28) (208) (348) (960)
Other comprehensive
(loss)/income before
reclassifications(2) (42) 4 - - (38)
Amounts reclassified
from accumulated
other comprehensive
loss - - 3 3 6
----------------------------------------------------------------------------
Net current period
other comprehensive
(loss)/income(3) (42) 4 3 3 (32)
----------------------------------------------------------------------------
AOCI balance at March
31, 2017 (418) (24) (205) (345) (992)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) All amounts are net of tax. Amounts in parentheses indicate losses
recorded to OCI.
(2) Other comprehensive (loss)/income before reclassifications on currency
translation adjustments and cash flow hedges is net of non-controlling
interest losses of $41 million and gains of $1 million.
(3) Losses related to cash flow hedges reported in AOCI and expected to be
reclassified to net income in the next 12 months are estimated to be $2
million ($1 million, net of tax) at March 31, 2017. These estimates
assume constant commodity prices, interest rates and foreign exchange
rates over time, however, the amounts reclassified will vary based on
the actual value of these factors at the date of settlement.
Details about reclassifications out of AOCI into the consolidated statement of income are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amounts reclassified
from Affected line item
accumulated other in the condensed
comprehensive consolidated
loss(1) statement of income
---------------------
three months ended
March 31
--------------------------------------------------------
(unaudited - millions of Canadian 2017 2016
$)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash flow hedges
Commodities 4 (82) Revenue (Energy)
Foreign exchange Interest income and
- (34) other
Interest rate (4) (4) Interest expense
----------------------------------------------------------------------------
- (120) Total before tax
- 40 Income tax expense
----------------------------------------------------------------------------
- (80) Net of tax
----------------------------------------------------------------------------
Pension and other post-retirement
benefit plan adjustments
Amortization of actuarial loss Plant operating
(4) (5) costs (2)
2 1 Income tax expense
----------------------------------------------------------------------------
(2) (4) Net of tax
----------------------------------------------------------------------------
Equity investments
Equity income Income from equity
(4) (4) investments
1 1 Income tax expense
----------------------------------------------------------------------------
(3) (3) Net of tax
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) All amounts in parentheses indicate expenses to the condensed
consolidated statement of income.
(2) These accumulated other comprehensive loss components are included in
the computation of net benefit cost. Refer to Note 10 for additional
detail.
10. Employee post-retirement benefits
The net benefit cost recognized for the Company's defined benefit pension plans (DB Plan) and other post-retirement benefit plans is as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
----------------------------------------
Other post-
Pension benefit retirement benefit
plans plans
----------------------------------------
(unaudited - millions of Canadian $) 2017 2016 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Service cost 29 26 1 1
Interest cost 34 30 4 2
Expected return on plan assets (50) (40) (5) -
Amortization of actuarial loss 4 4 - 1
Amortization of regulatory asset 6 4 - -
----------------------------------------------------------------------------
Net benefit cost recognized 23 24 - 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effective April 1, 2017, the Company closed its U.S. DB Plan to non-union new entrants. As of April 1, 2017, all non-union hires will participate in the existing defined contribution plan (DC Plan). Non-union U.S. employees who currently participate in the DC Plan will have one final election opportunity to become a member of the DB Plan as of January 1, 2018.
11. Risk management and financial instruments
RISK MANAGEMENT OVERVIEW
TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings and cash flow.
COUNTERPARTY CREDIT RISK
TransCanada's maximum counterparty credit exposure with respect to financial instruments at March 31, 2017, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At March 31, 2017, there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the period.
NET INVESTMENT IN FOREIGN OPERATIONS
The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts and options.
U.S. dollar-denominated debt designated as a net investment hedge
The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows:
---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (unaudited - millions of Canadian $, unless noted otherwise) March 31, 2017 December 31, 2016 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Notional amount 28,400 (US 21,400) 26,600 (US 19,800) Fair value 31,500 (US 23,600) 29,400 (US 21,900) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
Derivatives designated as a net investment hedge
The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, 2017 December 31, 2016
-----------------------------------------
Notional or Notional or
(unaudited - millions of Canadian Fair principal Fair principal
$, unless noted otherwise) value(1) amount value(1) amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S. dollar cross-currency interest
rate swaps (maturing 2017 to
2019)(2) (337) US 2,000 (425) US 2,350
U.S. dollar foreign exchange
forward contracts - - (7) US 150
----------------------------------------------------------------------------
(337) US 2,000 (432) US 2,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fair values equal carrying values.
(2) In the three months ended March 31, 2017, net realized gains of $1
million (2016 - gains of $2 million) related to the interest component
of cross-currency swap settlements are included in interest expense.
FINANCIAL INSTRUMENTS
Non-derivative financial instruments
Fair value of non-derivative financial instruments
The fair value of the Company's Notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of Long-term debt and Junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.
Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.
Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.
Balance sheet presentation of non-derivative financial instruments
The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, 2017 December 31, 2016
----------------------------------------
Carrying Fair Carrying Fair
(unaudited - millions of Canadian $) amount value amount value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes receivable(1) 115 158 165 211
Current and long-term debt(2,3) (38,832) (43,770) (40,150) (45,047)
Junior subordinated notes (5,879) (6,021) (3,931) (3,825)
----------------------------------------------------------------------------
(44,596) (49,633) (43,916) (48,661)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notes receivable are included in Assets held for sale on the condensed
consolidated balance sheet. The fair value is calculated based on the
original contract terms.
(2) Long-term debt is recorded at amortized cost except for US$850 million
(December 31, 2016 - US$850 million) that is attributed to hedged risk
and recorded at fair value.
(3) Consolidated net income for the three months ended March 31, 2017
included unrealized gains of $2 million (2016 - losses of $12 million)
for fair value adjustments attributable to the hedged interest rate risk
associated with interest rate swap fair value hedging relationships on
US$850 million of long-term debt at March 31, 2017 (December 31, 2016 -
US$850 million). There were no other unrealized gains or losses from
fair value adjustments to the non-derivative financial instruments.
Available for sale assets summary
The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, 2017 December 31, 2016
-----------------------------------------------------------
(unaudited - LMCI Other LMCI Other
millions of restricted restricted restricted restricted
Canadian $) investments investments(2) investments investments(2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair Values(1)
Fixed income
securities
(maturing
within 1 year) - 27 - 19
Fixed income
securities
(maturing
within 1-5
years) - 106 - 117
Fixed income
securities
(maturing
within 5-10
years) 13 - 9 -
Fixed income
securities
(maturing
after 10
years) 572 - 513 -
----------------------------------------------------------------------------
585 133 522 136
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Available for sale assets are recorded at fair value and included in
other current assets and restricted investments on the condensed
consolidated balance sheet.
(2) Other restricted investments have been set aside to fund insurance claim
losses to be paid by the Company's wholly-owned captive insurance
subsidiary.
March 31, 2017 March 31, 2016
-----------------------------------------------------------
(unaudited - LMCI Other LMCI Other
millions of restricted restricted restricted restricted
Canadian $) investments(1) investments(2) investments(1) investments(2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net unrealized
gains in the
period
three months
ended 2 - 5 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Gains and losses arising from changes in the fair value of LMCI
restricted investments impact the subsequent amounts to be collected
through tolls to cover future pipeline abandonment costs. As a result,
the Company records these gains and losses as regulatory assets or
liabilities.
(2) Unrealized gains and losses on other restricted investments are included
in OCI.
Derivative instruments
Fair value of derivative instruments
The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses period end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.
In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.
Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of the derivative instruments as at March 31, 2017 is as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at March 31, 2017
Total Fair
Value of
Cash Fair Net Held Derivative
(unaudited - millions of Flow Value Investment for Instruments
Canadian $) Hedges Hedges Hedges Trading (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other current assets
Commodities(2) 9 - - 387 396
Foreign exchange - - 4 9 13
Interest rate 2 - - 2 4
----------------------------------------------------------------------------
11 - 4 398 413
Intangible and other assets
Commodities(2) 3 - - 141 144
Foreign exchange - - 8 - 8
Interest rate 1 - - - 1
----------------------------------------------------------------------------
4 - 8 141 153
----------------------------------------------------------------------------
Total Derivative Assets 15 - 12 539 566
----------------------------------------------------------------------------
Accounts payable and other
Commodities(2) - - - (373) (373)
Foreign exchange - - (209) (22) (231)
Interest rate (1) (2) - - (3)
----------------------------------------------------------------------------
(1) (2) (209) (395) (607)
Other long-term liabilities
Commodities(2) (1) - - (192) (193)
Foreign exchange - - (140) - (140)
Interest rate - (1) - - (1)
----------------------------------------------------------------------------
(1) (1) (140) (192) (334)
----------------------------------------------------------------------------
Total Derivative Liabilities (2) (3) (349) (587) (941)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Derivatives 13 (3) (337) (48) (375)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fair value equals carrying value.
(2) Includes purchases and sales of power, natural gas and liquids.
The balance sheet classification of the fair value of the derivative instruments as at December 31, 2016 is as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at December 31, 2016
Total Fair
Value of
Cash Fair Net Held Derivative
(unaudited - millions of Flow Value Investment for Instruments
Canadian $) Hedges Hedges Hedges Trading (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other current assets
Commodities(2) 6 - - 351 357
Foreign exchange - - 6 10 16
Interest rate 1 1 - 1 3
----------------------------------------------------------------------------
7 1 6 362 376
Intangible and other assets
Commodities(2) 4 - - 118 122
Foreign exchange - - 10 - 10
Interest rate 1 - - - 1
----------------------------------------------------------------------------
5 - 10 118 133
----------------------------------------------------------------------------
Total Derivative Assets 12 1 16 480 509
----------------------------------------------------------------------------
Accounts payable and other
Commodities(2) - - - (330) (330)
Foreign exchange - - (237) (38) (275)
Interest rate (1) (1) - - (2)
----------------------------------------------------------------------------
(1) (1) (237) (368) (607)
Other long-term liabilities
Commodities(2) - - - (118) (118)
Foreign exchange - - (211) - (211)
Interest rate - (1) - - (1)
----------------------------------------------------------------------------
- (1) (211) (118) (330)
----------------------------------------------------------------------------
Total Derivative Liabilities (1) (2) (448) (486) (937)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Derivatives 11 (1) (432) (6) (428)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fair value equals carrying value.
(2) Includes purchases and sales of power, natural gas and liquids.
The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
Notional and Maturity Summary
The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at March 31, 2017
Natural Foreign
(unaudited) Power Gas Liquids Exchange Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Purchases(1) 104,858 222 12 - -
Sales(1) 66,420 202 14 - -
Millions of U.S. dollars - - - US 2,513 US 2,600
Millions of Mexican pesos - - - MXN 500 -
Maturity dates 2017-2021 2017-2020 2017 2017-2018 2017-2019
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Volumes for power, natural gas and liquids derivatives are in GWh, Bcf
and MMBbls, respectively.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at December 31, 2016
Natural Foreign
(unaudited) Power Gas Liquids Exchange Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Purchases(1) 86,887 182 6 - -
Sales(1) 58,561 147 6 - -
Millions of U.S. dollars - - - US 2,394 US 1,550
Maturity dates 2017-2021 2017-2020 2017 2017 2017-2019
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Volumes for power, natural gas and liquids derivatives are in GWh, Bcf
and MMBbls, respectively.
Unrealized and Realized (Losses)/Gains of Derivative Instruments
The following summary does not include hedges of the net investment in foreign operations.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of Canadian $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative instruments held for trading(1)
Amount of unrealized (losses)/gains in the
period
Commodities(2) (56) (67)
Foreign exchange 15 27
Interest rate 1 -
Amount of realized (losses)/gains in the
period
Commodities (48) (95)
Foreign exchange (4) 44
Derivative instruments in hedging
relationships
Amount of realized gains/(losses) in the
period
Commodities 6 (73)
Foreign exchange 5 (63)
Interest rate 1 2
----------------------------------------------------------------------------
(1) Realized and unrealized gains and losses on held for trading derivative
instruments used to purchase and sell commodities are included net in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative instruments held for trading are included
net in Interest expense and Interest income and other, respectively.
(2) Following the March 17, 2016 announcement of the Company's intention to
sell the U.S. Northeast power assets, a loss of $49 million and a gain
of $7 million were recorded in net income in the three months ended
March 31, 2016 relating to discontinued cash flow hedges where it was
probable that the anticipated underlying transaction would not occur as
a result of a future sale.
Derivatives in cash flow hedging relationships
The components of OCI (Note 9) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of Canadian $, pre-tax) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in fair value of derivative instruments
recognized in OCI (effective portion)(1)
Commodities 5 (16)
Foreign exchange - (35)
Interest rate 1 (3)
----------------------------------------------------------------------------
6 (54)
----------------------------------------------------------------------------
Reclassification of (losses)/gains on
derivative instruments from AOCI to net
income (effective portion)(1)
Commodities(2) (4) 82
Foreign exchange(3) - 34
Interest rate(4) 4 4
----------------------------------------------------------------------------
- 120
----------------------------------------------------------------------------
Losses on derivative instruments recognized in
net income (ineffective portion)
Commodities(2) - (58)
----------------------------------------------------------------------------
- (58)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) No amounts have been excluded from the assessment of hedge
effectiveness. Amounts in parentheses indicate losses recorded to OCI.
(2) Reported within revenues on the condensed consolidated statement of
income.
(3) Reported within interest income and other on the condensed consolidated
statement of income.
(4) Reported within interest expense on the condensed consolidated statement
of income.
Offsetting of derivative instruments
The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at March 31, 2017
Gross
derivative
instruments Amounts
presented on available
the balance for Net
(unaudited - millions of Canadian $) sheet offset(1) amounts
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative - Asset
Commodities 540 (333) 207
Foreign exchange 21 (20) 1
Interest rate 5 (2) 3
----------------------------------------------------------------------------
Total 566 (355) 211
----------------------------------------------------------------------------
Derivative - Liability
Commodities (566) 333 (233)
Foreign exchange (371) 20 (351)
Interest rate (4) 2 (2)
----------------------------------------------------------------------------
Total (941) 355 (586)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts available for offset do not include cash collateral pledged or
received.
The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at December 31, 2016
Gross
derivative
instruments Amounts
presented on available
the balance for Net
(unaudited - millions of Canadian $) sheet offset(1) amounts
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative - Asset
Commodities 479 (362) 117
Foreign exchange 26 (26) -
Interest rate 4 (1) 3
----------------------------------------------------------------------------
Total 509 (389) 120
----------------------------------------------------------------------------
Derivative - Liability
Commodities (448) 362 (86)
Foreign exchange (486) 26 (460)
Interest rate (3) 1 (2)
----------------------------------------------------------------------------
Total (937) 389 (548)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts available for offset do not include cash collateral pledged or
received.
With respect to the derivative instruments presented above as at March 31, 2017, the Company provided cash collateral of $310 million (December 31, 2016 - $305 million) and letters of credit of $22 million (December 31, 2016 - $27 million) to its counterparties. The Company held nil (December 31, 2016 - nil) in cash collateral and $3 million (December 31, 2016 - $3 million) in letters of credit from counterparties on asset exposures at March 31, 2017.
Credit risk related contingent features of derivative instruments
Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade.
Based on contracts in place and market prices at March 31, 2017, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $20 million (December 31, 2016 - $19 million), for which the Company had provided collateral 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, the Company would have been required to provide additional collateral of $20 million (December 31, 2016 - $19 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise.
FAIR VALUE HIERARCHY
The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Levels How fair value has been determined
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Level I Quoted prices in active markets for identical assets and
liabilities that the Company has the ability to access at the
measurement date.
----------------------------------------------------------------------------
Level II Valuation based on the extrapolation of inputs, other than quoted
prices included within Level I, for which all significant inputs
are observable directly or indirectly.
Inputs include published exchange rates, interest rates, interest
rate swap curves, yield curves and broker quotes from external
data service providers.
This category includes interest rate and foreign exchange
derivative assets and liabilities where fair value is determined
using the income approach and commodity derivatives where fair
value is determined using the market approach.
Transfers between Level I and Level II would occur when there is a
change in market circumstances.
----------------------------------------------------------------------------
Level III Valuation of assets and liabilities are measured using a market
approach based on extrapolation of inputs that are unobservable or
where observable data does not support a significant portion of
the derivative's fair value. This category mainly includes long-
dated commodity transactions in certain markets where liquidity is
low and the Company uses the most observable inputs available or,
if not available, long-term broker quotes to estimate the fair
value for these transactions. Valuation of options is based on the
Black-Scholes pricing model.
Assets and liabilities measured at fair value can fluctuate
between Level II and Level III depending on the proportion of the
value of the contract that extends beyond the time frame for which
significant inputs are considered to be observable. As contracts
near maturity and observable market data become available, they
are transferred out of Level III and into Level II.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2017, are categorized as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Significant
Quoted prices other Significant
in active observable unobservable
at March 31, 2017 markets inputs inputs
(unaudited - millions (Level I)(1) (Level II)(1) (Level III)(1) Total
of Canadian $)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative instrument
assets:
Commodities 82 433 25 540
Foreign exchange - 21 - 21
Interest rate - 5 - 5
Derivative instrument
liabilities:
Commodities (64) (487) (15) (566)
Foreign exchange - (371) - (371)
Interest rate - (4) - (4)
----------------------------------------------------------------------------
18 (403) 10 (375)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) There were no transfers from Level I to Level II or from Level II to
Level III for the three months ended March 31, 2017.
The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016, are categorized as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Significant
Quoted prices other Significant
in active observable unobservable
at December 31, 2016 markets inputs inputs
(unaudited - millions
of Canadian $) (Level I)(1) (Level II)(1) (Level III)(1) Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative instrument
assets:
Commodities 134 326 19 479
Foreign exchange - 26 - 26
Interest rate - 4 - 4
Derivative instrument
liabilities:
Commodities (102) (343) (3) (448)
Foreign exchange - (486) - (486)
Interest rate - (3) - (3)
----------------------------------------------------------------------------
32 (476) 16 (428)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) There were no transfers from Level I to Level II or from Level II to
Level III for the year ended December 31, 2016.
The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended March 31
------------------------------
(unaudited - millions of Canadian $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at beginning of period 16 9
Transfers out of Level III (4) (3)
Sales (2) (1)
Settlements - 1
Total gains included in net income - 3
----------------------------------------------------------------------------
Balance at end of period(1) 10 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For the three months ended March 31, 2017, revenues include unrealized
losses of less than $1 million attributed to derivatives in the Level
III category that were still held at March 31, 2017 (2016 - gains of $2
million).
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a less than $1 million change in the fair value of outstanding derivative instruments included in Level III as at March 31, 2017.
12. Commitments, contingencies and guarantees
COMMITMENTS
TransCanada's operating lease commitments at March 31, 2017 include future payments related to our U.S. Northeast power business. At the close of the sale of Ravenswood, TransCanada's commitments are expected to decrease by $3 million in 2017, $53 million in 2018, $35 million in 2019 and $105 million in 2022 and beyond.
CONTINGENCIES
TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.
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. TransCanada discontinued the claim under Chapter 11 of the North American Free Trade Agreement and has also withdrawn the U.S. Constitutional challenge.
GUARANTEES
TransCanada and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the obligations for construction services during the construction of the pipeline.
TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services.
The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.
The carrying value of these guarantees has been included in other long-term liabilities. Information regarding the Company's guarantees is as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
at March 31, 2017 at December 31, 2016
----------------------------------------
(unaudited - millions Potential Carrying Potential Carrying
of Canadian $) Term exposure(1) value exposure(1) value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sur de Texas ranging to 2020 758 10 805 53
Bruce Power ranging to 2018 88 1 88 1
Other jointly owned
entities ranging to 2059 111 16 87 28
----------------------------------------------------------------------------
957 27 980 82
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) TransCanada's share of the potential estimated current or contingent
exposure.
13. Variable interest entities
The Company consolidates a number of entities that are considered to be VIEs. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity's operations through voting rights or do not substantively participate in the gains and losses of the entity.
In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are accounted for as equity investments.
Consolidated VIEs
The Company's consolidated VIEs consist of legal entities where the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE.
A significant portion of the Company's assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE's assets can be used for general corporate purposes. The assets and liabilities of the consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE's obligations are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
(unaudited - millions of Canadian $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 92 77
Accounts receivable 62 71
Inventories 24 25
Other 7 10
----------------------------------------------------------------------------
185 183
Plant, Property and Equipment 3,627 3,685
Equity Investments 595 606
Goodwill 521 525
Intangible and Other Assets 1 1
----------------------------------------------------------------------------
4,929 5,000
----------------------------------------------------------------------------
LIABILITIES
Current Liabilities
Accounts payable and other 94 80
Accrued interest 22 21
Current portion of long-term debt 72 76
----------------------------------------------------------------------------
188 177
Regulatory Liabilities 34 34
Other Long-Term Liabilities 4 4
Deferred Income Tax Liabilities 7 7
Long-Term Debt 2,723 2,827
----------------------------------------------------------------------------
2,956 3,049
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-Consolidated VIEs
The Company's non-consolidated VIEs consist of legal entities where the Company does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid.
The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
(unaudited - millions of Canadian $) 2017 2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance sheet
Equity investments 4,642 4,964
Off-balance sheet
Potential exposure to guarantees 176 163
----------------------------------------------------------------------------
Maximum exposure to loss 4,818 5,127
----------------------------------------------------------------------------
----------------------------------------------------------------------------
14. Subsequent events
U.S. Northeast Power Assets
TC Hydro
On April 19, 2017, the Company closed the sale of TC Hydro for gross proceeds of US$1.065 billion, subject to post-closing adjustments. The proceeds received were used to reduce the Columbia acquisition bridge credit facility. Refer to Note 4, Assets held for sale, for further information.
Sale of Iroquois and PNGTS to TC PipeLines, LP
On May 4, 2017, the Company announced agreements to sell a 49.3 per cent interest in Iroquois Gas Transmission System, LP (Iroquois) together with its remaining 11.8 per cent interest in Portland Natural Gas Transmission System (PNGTS), to its 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.
Contacts: TransCanada Media Enquiries: Mark Cooper/James Millar 403.920.7859 or 800.608.7859 TransCanada Investor & Analyst Enquiries: David Moneta/Stuart Kampel 403.920.7911 or 800.361.6522
Source: TRANSCANADA