TransCanada Reports Strong Third Quarter 2016 Financial Results
Strong Operating Performance Reflects Acquisition of Columbia Pipeline Group
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CALGARY, ALBERTA -- (Marketwired) -- 11/01/16 -- TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada) today announced a net loss attributable to common shares for third quarter 2016 of $135 million or $0.17 per share compared to net income of $402 million or $0.57 per share for the same period in 2015. Third quarter 2016 results included a $656 million after-tax goodwill impairment charge related to our U.S. Northeast Power business. Excluding the net loss on the goodwill impairment and certain other specific items, comparable earnings for third quarter 2016 were $622 million or $0.78 per share compared to $440 million or $0.62 per share for the same period in 2015. TransCanada's Board of Directors also declared a quarterly dividend of $0.565 per common share for the quarter ending December 31, 2016, equivalent to $2.26 per common share on an annualized basis.
"Excluding specific items, comparable earnings per share for the quarter were significantly higher than last year as a result of the Columbia acquisition and continued solid performance from our large portfolio of high-quality energy infrastructure assets," said Russ Girling, TransCanada's president and chief executive officer. "Since completing the Columbia transaction, we have made significant progress in integrating its operations with our existing U.S. natural gas pipeline business and are well on track to realize the targeted US$250 million of annualized benefits associated with the acquisition."
On July 1, 2016, TransCanada completed the acquisition of Columbia Pipeline Group, Inc. (Columbia) for US$13 billion. Columbia operates a portfolio of approximately 24,000 km (15,000 miles) of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets.
"The addition of Columbia reinforces our position as one of North America's leading energy infrastructure companies with an extensive pipeline network that links the continent's most prolific natural gas supply basins to its most attractive markets," added Girling. "Looking forward, the addition of Columbia's US$7.7 billion growth program brings our industry-leading portfolio of near-term capital projects to over $25 billion. As these projects progress through the permitting and construction phases and into operation over the balance of the decade, they are expected to generate significant growth in earnings and cash flow and support an expected annual dividend growth rate at the upper end of the Company's previous expectation of eight to 10 per cent through 2020."
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
-- Third quarter financial results
-- Net loss attributable to common shares of $135 million or $0.17 per
share
-- Comparable earnings of $622 million or $0.78 per share
-- Comparable earnings before interest, taxes, depreciation and
amortization (EBITDA) of $1.9 billion
-- Comparable funds generated from operations of $1.4 billion
-- Comparable distributable cash flow of $1.0 billion or $1.29 per
common share
-- Declared a quarterly dividend of $0.565 per common share for the quarter
ending December 31, 2016
-- On July 1, 2016, we closed the US$13 billion acquisition of Columbia
comprised of a purchase price of approximately US$10.3 billion and
Columbia debt of approximately US$2.7 billion
-- On July 4, 2016, 96.6 million subscription receipts were exchanged into
the same number of common shares
-- Announced the reinstatement of issuance of common shares from treasury
at a two per cent discount under TransCanada's Dividend Reinvestment
Plan commencing with the dividends declared on July 27, 2016
-- Issued US$1.2 billion of junior subordinated notes in the United States
that mature in 2076
-- Announced that ANR filed a comprehensive settlement of its current
Natural Gas Act Section 4 rate case with the Federal Energy Regulatory
Commission (FERC)
-- Launched an open season on the Canadian Mainline seeking binding
commitments on a new long-term, fixed price tolling option
-- On November 1, 2016, we announced the following strategic updates:
-- Expect to realize approximately US$3.7 billion from the monetization
of our U.S. Northeast Power business.
-- The decision to maintain our current ownership interest in our
growing Mexican natural gas pipeline business.
-- An agreement to purchase all of the common units of Columbia
Pipeline Partners LP (CPPL) for US$17.00 per common unit for a total
amount of approximately US$915 million.
-- A bought deal offering of TransCanada common shares.
These initiatives, along with our stable base business and $25
billion of secured near-term growth, position us to deliver an
expected annual dividend growth rate at the upper end of the
Company's previous expectation of eight to 10 per cent through 2020.
Net income attributable to common shares decreased by $537 million to a net loss of $135 million or $0.17 per share for the three months ended September 30, 2016 compared to the same period last year. Third quarter 2016 included a $656 million after-tax goodwill impairment charge, an after-tax charge of $67 million related to costs associated with the acquisition of Columbia, a $50 million after-tax charge related to risk management activities, recognition of $28 million of income tax recoveries resulting from a third party sale of Keystone XL project assets, a $9 million after-tax charge related to Keystone XL maintenance and liquidation costs and $3 million of after-tax costs related to the sale of our U.S. Northeast Power business. All of these specific items are excluded from comparable earnings.
Comparable earnings for third quarter 2016 were $622 million or $0.78 per share compared to $440 million or $0.62 per share for the same period in 2015, an increase of $182 million or $0.16 per share. The increase was primarily the net effect of a higher contribution from U.S. Pipelines primarily due to incremental earnings from Columbia following the acquisition on July 1, 2016 and a higher ANR transportation and storage revenue resulting from higher rates effective August 1, 2016; a higher contribution from Mexican pipelines primarily due to earnings from Topolobampo beginning in July 2016; higher interest income and other due to realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income; higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired in February 2016 and higher sales to customers in the PJM market partially offset by lower capacity revenues in New York; higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest partially offset by higher losses from contracting activities; and higher earnings from Canadian Pipelines primarily due to a higher NGTL investment base and incentive earnings from the Canadian Mainline and NGTL. These gains were partially offset by higher interest expense from debt issuances and lower capitalized interest as well as lower earnings from Liquids Pipelines due to the net effect of higher contracted and lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink.
Notable recent developments include:
Corporate:
-- Acquisition of Columbia Pipeline Group: On July 1, 2016, we closed the
US$13 billion acquisition of Columbia comprised of a purchase price of
approximately US$10.3 billion and Columbia debt of approximately US$2.7
billion. The acquisition was financed through proceeds of $4.4 billion
from the sale of subscription receipts, senior unsecured asset bridge
term loan credit facilities in the aggregate amount of US$6.9 billion
and existing cash on hand. The sale of the subscription receipts was
completed on April 1, 2016 through a public offering and following the
closing of the acquisition, were exchanged into 96.6 million TransCanada
common shares.
-- Monetization of U.S. Northeast Power business: On November 1, 2016, we
announced that we expect to realize approximately US$3.7 billion from
the monetization of our the U.S. Northeast Power business. This includes
the announced sale of Ravenswood, Ironwood, Ocean State Power and Kibby
Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors
for US$2.2 billion and TC Hydro to Great River Hydro, LLC, an affiliate
of ArcLight Capital Partners, LLC for US $1.065 billion, with the
remainder attributed to the marketing business which is expected to be
realized going forward. These two sale transactions are expected to
close in the first half of 2017 subject to certain regulatory and other
approvals and will include closing adjustments. The sales are expected
to result in an approximate $1.1 billion after-tax net loss, which is
comprised of a $656 million after-tax goodwill impairment charge
recorded at September 30, 2016, an approximate $863 million after-tax
net loss on the sale of the thermal and wind package to be recorded in
fourth quarter 2016 and an approximate $443 million after-tax gain on
the sale of the hydro assets upon close of that transaction. Proceeds
from these sales and future realization of value of the marketing
business will be used to repay a portion of the US$6.9 billion senior
unsecured asset bridge term loan credit facilities which were used to
partially finance the Columbia acquisition earlier this year.
-- Decision to maintain our current ownership interest in Mexican natural
gas pipelines: On November 1, 2016, we announced a decision to maintain
our current ownership interest in a growing portfolio of natural gas
pipeline assets in Mexico rather than sell a minority interest in six of
these pipelines, which is consistent with maintaining a simple corporate
structure. We currently own and operate the Tamazunchale and Guadalajara
natural gas pipelines and are in the process of investing US$3.8 billion
to develop and complete construction of four additional pipelines plus
fund our interest in the Sur de Texas project, all of which will serve
growing natural gas demand in Mexico. All projects are expected to be
in-service by the end of 2018 and are underpinned by 25-year take-or-pay
contracts with the Comision Federal de Electricidad (CFE). Once
completed, we expect our Mexican natural gas pipeline assets to be
accretive to earnings per share and generate approximately US$575
million of annual EBITDA, up from US$181 million in 2015.
-- Common Equity Offering: On November 1, 2016, in conjunction with our
decision to maintain our current ownership interest in a growing Mexican
natural gas pipelines business, and concurrent with the release of these
financial results, we also entered into an agreement with a group of
underwriters to proceed with an offering of common shares. The common
shares will be offered to the public in Canada and the United States
through the underwriters or their representatives. The offering is
subject to the receipt of all necessary regulatory and stock exchange
approvals. Proceeds from the offering will be used to repay a portion of
the US$6.9 billion senior unsecured asset bridge term loan credit
facilities which were used to partially finance the acquisition of
Columbia.
-- Agreement to Acquire Columbia Pipeline Partners, LP: On November 1,
2016, we announced that we have entered into an agreement and plan of
merger through which our wholly-owned subsidiary, Columbia Pipeline
Group, Inc., has agreed to acquire, for cash, all of the outstanding
publicly held common units of CPPL at a price of US$17.00 per common
unit for an aggregate transaction value of approximately US$915 million.
The transaction is expected to close in first quarter 2017 subject to
receipt of CPPL unitholder approval and customary closing conditions and
is expected to be accretive to earnings per share and simplify our
corporate structure.
-- Dividend Declaration: Our Board of Directors declared a quarterly
dividend of $0.565 per share for the quarter ending December 31, 2016 on
TransCanada's outstanding common shares. The quarterly amount is
equivalent to $2.26 per common share on an annualized basis.
-- Dividend Reinvestment Plan: Approximately $175 million or 39 per cent of
dividends paid on October 31 were reinvested in TransCanada common
shares through our Dividend Reinvestment Plan following the
reinstatement of issuance from Treasury at a two per cent discount
announced in July 2016.
-- Other Financing Activities: In August 2016, TransCanada Trust issued
US$1.2 billion of 60-year junior subordinated trust notes to third party
investors with a fixed interest rate of 5.875 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 us in US$1.2 billion junior
subordinated notes at a rate of 6.125 per cent which includes a 0.25 per
cent administration charge. On a subordinated basis, the obligations of
the Trust are guaranteed by TransCanada.
Natural Gas Pipelines:
-- NGTL System: On October 31, 2016, the Government of Canada approved our
$1.3 billion NGTL 2017 Facilities Application. In addition, on October
6, 2016, the NEB recommended to the government approval of the $439
million Towerbirch Project. This project consists of a 55 km (34 miles)
pipeline loop and a 32 km (20 miles) pipeline extension of the NGTL
System in northwest Alberta and northeast B.C. The NEB approved NGTL's
continued use of its existing rolled-in toll methodology for this
project. Of NGTL's $5.4 billion near-term capital program, we have
received approvals for $4.0 billion, while $0.5 billion has been filed
and is awaiting approval. Approximately $0.9 billion is expected to be
filed with regulators in the future.
-- North Montney Mainline: In March 2016, we filed a request with the NEB
for a one year extension to the June 10, 2016 sunset clause in the North
Montney Mainline project Certificate of Public Convenience and
Necessity. On September 15, 2016, the NEB approved the sunset clause
extension to June 10, 2017. The extension continues to be subject to the
condition that construction shall not begin until a positive Final
Investment Decision (FID) has been made on the Pacific Northwest LNG
(PNW LNG) Project. NGTL continues to work with our customers and
stakeholders to be ready to initiate construction of the North Montney
facilities, however, the in-service date will be finalized once a FID
has been made.
-- Canadian Mainline Tolling Option: On October 13, 2016 we launched an
open season on the Canadian Mainline seeking binding commitments on a
new long-term, fixed-price proposal to transport WCSB supply from the
Empress receipt point in Alberta to the Dawn hub in Southern Ontario.
The contract term for this service is ten years with tolls ranging from
$0.75/GJ to $0.82/GJ depending on the shippers' contract volume
commitments. Early termination rights are provided and can be exercised
following the initial five years of service upon payment of a premium
fee. Subject to a successful Open Season that closes November 10, 2016
and to NEB regulatory approval, the new service is targeted to begin
November 1, 2017.
-- Columbia Capital Projects: As part of the Columbia acquisition, we are
progressing a US$7.4 billion capital expansion and modernization program
across the Columbia system for facilities planned to be in-service from
2016 to 2020. We also expect to invest approximately US$0.3 billion to
construct the Gibraltar Pipeline project, an approximate 1 MMDth/d dry
gas header pipeline in southwest Pennsylvania.
-- ANR Section 4 Rate Case Settlement: On September 16, 2016, ANR filed
with FERC an unopposed settlement agreement with its customers for
approval. Effective August 1, 2016, transmission reservation rates
increased by 34.8 percent with storage rates largely remaining
unchanged. The settlement includes a moratorium on further rate changes
until August 1, 2019. ANR may file for new rates after that date if it
has spent more than US$0.8 billion in capital additions but must file
for new rates with an effective date of no later than August 1, 2022.
-- Topolobampo Pipeline: In July, we began collecting revenue on the US$1
billion Topolobampo project under a force majeure provision in the 25-
year contract with the Comision Federal de Electricidad. The physical
in-service date is expected to be delayed into 2017 due to right-of-way
acquisition delays.
-- Prince Rupert Gas Transmission: On September 27, 2016 PNW LNG received
an environmental certificate from the Government of Canada for a
proposed LNG plant at Prince Rupert, B.C. PNW LNG has indicated they
will conduct a total project review over the coming months prior to
announcing next steps for the project.
-- Coastal GasLink: On July 11, 2016, the LNG Canada joint venture
participants announced a delay to their FID for the proposed liquefied
natural gas facility in Kitimat, BC. At this time a future FID date has
not been determined. In light of this announcement we are working with
LNG Canada to determine the appropriate pacing of the Coastal GasLink
development schedule and work activities.
Liquids Pipelines:
-- Houston Lateral and Terminal: In August 2016, the Houston Lateral
pipeline and terminal, an extension from the Keystone Pipeline System to
Houston, Texas, went into service. The terminal has an initial storage
capacity of 700,000 barrels of crude oil.
-- Energy East Pipeline: On August 8, 2016, the NEB commenced the first of
a series of community panel sessions held along the pipeline route in
New Brunswick. Panel sessions scheduled for the week of August 29, 2016
in Montreal, Quebec were subsequently canceled as three NEB panelists
announced their decision to recuse themselves from continuing to sit on
the panel to review the project due to allegations of reasonable
apprehension of bias. The Chair of the NEB and the Vice Chair, who is
also a panel member, have recused themselves of any further duties
related to the project. As a result, all hearings for the project were
adjourned until further notice as we wait on the federal government to
appoint new NEB members and then for the NEB to establish a new panel to
hear our applications. The new panel members will then determine how the
review process is to be re-initiated. As a result of these actions, we
expect a delay in the NEB review process.
Energy:
-- Becancour Tolling Agreement: In August 2015, we executed an agreement
with Hydro Quebec (HQ) allowing HQ to dispatch up to 570 MW of peak
winter capacity from our Becancour facility for a term of 20 years
commencing in December 2016. The regulator in Quebec, Regie de l'energie
(the Regie), initially accepted this agreement for implementation but in
July 2016, the Regie reversed its initial decision. HQ continues to
advocate for the contract on its economic merit as part of their
strategy to meet the winter peak capacity needs of the province and is
pursuing regulatory options for our agreement to be reinstated. We
expect the project need and potential timing will be reassessed in the
recently released review of HQ's ten year supply plan.
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 90,300 kilometres (56,100 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 664 billion cubic feet of storage capacity. A large independent power producer, TransCanada owns or has interests in over 10,500 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 TransCanada's Quarterly Report to Shareholders dated November 1, 2016 and 2015 Annual Report on our website at www.transcanada.com or filed under TransCanada's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov and available on TransCanada's website at www.transcanada.com.
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, 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 November 1, 2016.
Additional Information and Where to Find it
In connection with the proposed acquisition of the outstanding common units of CPPL, CPPL will file with the SEC a proxy statement with respect to a special meeting of its unitholders to be convened to approve the transaction. The definitive proxy statement will be mailed to the unitholders of CPPL. INVESTORS ARE URGED TO READ THE PROXY STATEMENT AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION.
Investors will be able to obtain these materials, when they are available, and other documents filed with the SEC free of charge at the SEC's website, www.sec.gov. In addition, copies of the proxy statement, when available, may be obtained free of charge by accessing CPPL's website at www.columbiapipelinepartners.com or by writing CPPL at 5151 San Felipe Street, Suite 2500, Houston, Texas 77056, Attention: Corporate Secretary. Investors may also read and copy any reports, statements and other information filed by CPPL with the SEC, at the SEC public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 or visit the SEC's website for further information on its public reference room.
Participants in the Merger Solicitation
Columbia, an indirect wholly owned subsidiary of the Company, and certain of its directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies in respect of the transaction. Information regarding Columbia's directors and executive officers is available in its Current Report on Form 8-K filed with the SEC on July 1, 2016. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy statement and other relevant materials to be filed with the SEC when they become available.
Quarterly report to shareholders
Third quarter 2016
Financial highlights
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three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, except
per share amounts) 2016 2015 2016 2015
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Income
Revenues 3,632 2,944 8,886 8,449
Net (loss)/income attributable to
common shares (135) 402 482 1,218
per common share - basic and
diluted ($0.17) $0.57 $0.66 $1.72
Comparable EBITDA(1) 1,886 1,483 4,757 4,381
Comparable earnings(1) 622 440 1,482 1,302
per common share(1 ) $0.78 $0.62 $2.02 $1.84
Operating cash flow
Net cash provided by operations 1,183 1,247 3,277 2,976
Comparable funds generated from
operations(1) 1,411 1,148 3,529 3,374
Comparable distributable cash
flow(1) 1,025 953 2,701 2,774
per common share(1) $1.29 $1.34 $3.68 $3.91
Investing activities
Capital spending
- capital expenditures 1,444 976 3,262 2,748
- projects in development 62 130 219 465
Contributions to equity investments 286 105 570 303
Acquisitions, net of cash acquired 12,609 - 13,608 -
Proceeds from sale of assets, net
of transaction costs - - 6 -
Dividends declared
Per common share $0.565 $0.52 $1.695 $1.56
Basic common shares outstanding
(millions)
Average for the period 797 709 734 709
End of period 800 709 800 709
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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
November 1, 2016
This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and nine months ended September 30, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2016 which have been prepared in accordance with U.S. GAAP. On July 1, 2016, we completed the acquisition of Columbia Pipeline Group, Inc. (Columbia). For further information on the acquisition refer to note 4 of the September 30, 2016 unaudited condensed consolidated financial statements. The three and nine months ended September 30, 2016 amounts reflect the results of Columbia post-acquisition from July 1, 2016. Comparative figures do not include Columbia.
This MD&A should also be read in conjunction with our December 31, 2015 audited consolidated financial statements and notes and the MD&A in our 2015 Annual Report.
About this document
Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries. Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2015 Annual Report. All information is as of November 1, 2016 and all amounts are in Canadian dollars, unless noted otherwise.
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 may 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 costs for planned projects, including projects under
construction 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
-- the 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
-- timing of financings and hedging
-- regulatory decisions and outcomes
-- termination of the Alberta PPAs
-- foreign exchange rates
-- 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
-- acquisitions and divestitures.
Risks and uncertainties
-- our ability to realize the anticipated benefits of 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 2015 Annual Report.
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, except as required 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
We use the following non-GAAP measures:
-- EBITDA -- EBIT -- funds generated from operations -- comparable funds generated from operations -- comparable distributable cash flow -- comparable distributable cash flow per common share -- comparable earnings -- comparable earnings per common share -- comparable EBITDA -- comparable EBIT -- comparable income from equity investments -- comparable interest expense -- comparable interest income and other -- comparable income tax expense.
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures.
EBITDA and EBIT
We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings. It is calculated in the same way as EBITDA, less depreciation and amortization.
Funds generated from operations
Funds generated from operations includes 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. See the Financial condition section for a reconciliation to net cash provided by operations.
Comparable measures
We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
----------------------------------------------------------------------------
Comparable measure Original measure
----------------------------------------------------------------------------
comparable earnings net income attributable to common
shares
comparable earnings per common share net income per common share
comparable EBITDA segmented earnings
comparable EBIT segmented earnings
comparable funds generated from cash provided by operations
operations
comparable distributable cash flow cash provided by operations
comparable income from equity income from equity investments
investments
comparable interest expense interest expense
comparable interest income and other interest income and other
comparable income tax expense income tax expense
----------------------------------------------------------------------------
Our decision not to include 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 rates
-- gains or losses on sales of assets
-- 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 ongoing
maintenance and liquidation costs
-- acquisition costs.
We calculate comparable earnings by excluding 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.
Comparable distributable cash flow
Comparable distributable cash flow is defined as comparable funds generated from operations plus distributions received from operating activities in excess of equity earnings from equity-accounted for investments 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.
We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. See the Financial condition section for a reconciliation to net cash provided by operations.
Consolidated results - third quarter 2016
Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, except
per share amounts) 2016 2015 2016 2015
----------------------------------------------------------------------------
Natural Gas Pipelines 753 522 1,952 1,627
Liquids Pipelines 187 284 609 773
Energy (825) 244 (569) 715
Corporate (37) (31) (155) (94)
----------------------------------------------------------------------------
Total segmented earnings 78 1,019 1,837 3,021
Interest expense (522) (341) (1,456) (990)
Interest income and other 122 16 440 83
----------------------------------------------------------------------------
(Loss)/income before income taxes (322) 694 821 2,114
Income tax recovery/(expense) 266 (223) (78) (680)
----------------------------------------------------------------------------
Net (loss)/income (56) 471 743 1,434
Net (loss)/income attributable to
non-controlling interests (52) (46) (184) (145)
----------------------------------------------------------------------------
Net income attributable to
controlling interests (108) 425 559 1,289
Preferred share dividends (27) (23) (77) (71)
----------------------------------------------------------------------------
Net (loss)/income attributable to
common shares (135) 402 482 1,218
----------------------------------------------------------------------------
Net (loss)/income per common share
- basic and diluted ($0.17) $0.57 $0.66 $1.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income attributable to common shares decreased by $537 million to a net loss of $135 million for the three months ended September 30, 2016 and decreased $736 million for the nine months ended September 30, 2016 compared to the same periods in 2015. The 2016 results included:
-- a $656 million after-tax impairment on the 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 exceeds its carrying value.
-- a $176 million after tax impairment charge in first quarter on the
carrying value of our Alberta PPAs as a result of our decision to
terminate the PPAs
-- costs associated with the acquisition of Columbia including an after-tax
charge of $67 million in third quarter, primarily relating to retention,
severance and integration expenses, and $206 million year-to-date which
included $109 million related to the dividend equivalent payments on the
subscription receipts issued as part of the permanent financing of the
transaction, $36 million related to acquisition costs and $6 million
related to interest earned on the subscription receipt funds held in
escrow.
-- $28 million of income tax recoveries in third quarter related to the
realized loss on a third party sale of Keystone XL project assets. A
provision for the expected loss on these assets was included in our
fourth quarter 2015 impairment charge, but the related income tax
recoveries could not be recorded until realized
-- an after-tax charge of $9 million in third quarter and $24 million year-
to-date 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 charge of $10 million year-to-date for restructuring
charges mainly related to 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
-- $3 million of after-tax costs related to the monetization of our U.S.
Northeast Power business
-- an additional $3 million after-tax loss on the sale of TC Offshore which
closed on March 31, 2016.
The 2015 results included:
-- an after-tax charge of $6 million in third quarter and $14 million year-
to-date 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
-- a $34 million adjustment to income tax expense due to the enactment of a
two per cent increase in the Alberta corporate income tax rate in June
2015.
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 $182 million and $180 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 as discussed below in the reconciliation of net income to comparable earnings.
RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, except
per share amounts) 2016 2015 2016 2015
----------------------------------------------------------------------------
Net (loss)/ attributable to common
shares (135) 402 482 1,218
Specific items (net of tax):
Ravenswood goodwill impairment 656 - 656 -
Alberta PPA terminations - - 176 -
Acquisition related costs -
Columbia 67 - 206 -
Keystone XL income tax recoveries (28) - (28) -
Keystone XL asset costs 9 - 24 -
Restructuring costs - 6 10 14
TC Offshore loss on sale - - 3 -
U.S. Northeast Power business
monetization 3 - 3 -
Alberta corporate income tax rate
increase - - - 34
Risk management activities(1) 50 32 (50) 36
----------------------------------------------------------------------------
Comparable earnings 622 440 1,482 1,302
----------------------------------------------------------------------------
Net (loss)/income per common share ($0.17) $0.57 $0.66 $1.72
Specific items (net of tax):
Ravenswood goodwill impairment 0.82 - 0.89 -
Alberta PPA terminations - - 0.25 -
Acquisition related costs -
Columbia 0.09 - 0.29 -
Keystone XL income tax recoveries (0.03) - (0.04) -
Keystone XL asset costs 0.01 - 0.03 -
Restructuring costs - 0.01 0.01 0.02
U.S. Northeast Power business
monetization - - - -
Alberta corporate income tax rate
increase - - - 0.05
Risk management activities 0.06 0.04 (0.07) 0.05
----------------------------------------------------------------------------
Comparable earnings per share $0.78 $0.62 $2.02 $1.84
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-----------------------------------------------------------------------
(1) three months ended nine months ended
Risk management activities September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
-----------------------------------------------------------------------
Canadian Power (4) (14) 3 (7)
U.S. Power (73) (5) 16 (22)
Liquids marketing (8) - (6) -
Natural Gas Storage 4 2 9 2
Foreign exchange - (26) 49 (25)
Income tax attributable to
risk management activities 31 11 (21) 16
-----------------------------------------------------------------------
Total unrealized
(losses)/gains from risk
management activities (50) (32) 50 (36)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Comparable earnings increased by $182 million for the three months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of:
-- higher earnings from U.S. Pipelines due to incremental earnings from
Columbia following the July 1, 2016 acquisition and higher ANR
transportation and storage revenue resulting from higher rates effective
August 1, 2016
-- higher interest expense from debt issuances and lower capitalized
interest
-- lower earnings from Liquids Pipelines due to higher contracted and lower
uncontracted volumes on Keystone Pipeline and lower volumes on
Marketlink
-- higher contribution from Mexican pipelines primarily due to earnings
from Topolobampo beginning in July 2016
-- higher interest income and other due to realized gains in 2016 compared
to realized losses in 2015 on derivatives used to manage our net
exposure to foreign exchange rate fluctuations on U.S. dollar
denominated income
-- higher earnings from U.S. Power mainly due to incremental earnings from
the Ironwood power plant acquired in February 2016 and higher sales to
customers in the PJM market, offset by lower capacity revenues in New
York
-- higher earnings from Bruce Power mainly due to lower depreciation and
our increased ownership interest, partially offset by higher losses from
contracting activities
-- higher earnings from Canadian Pipelines primarily due to a higher NGTL
investment base and incentive earnings from Canadian Mainline and NGTL.
Comparable earnings increased by $180 million for the nine months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of:
-- higher earnings from our U.S. Pipelines due to incremental earnings from
Columbia following the July 1, 2016 acquisition, higher ANR
transportation and storage revenue resulting from higher rates effective
August 1, 2016, higher ANR Southeast Mainline transportation revenues
and lower OM&A expenses
-- higher interest expense from debt issuances and lower capitalized
interest
-- higher interest income and other due to increased AFUDC related to our
rate-regulated projects and realized gains in 2016 compared to realized
losses in 2015 on derivatives used to manage our net exposure to foreign
exchange rate fluctuations on U.S. dollar denominated income
-- lower earnings from Liquids Pipelines due to higher contracted and lower
uncontracted volumes on Keystone Pipeline and lower volumes on
Marketlink
The stronger U.S. dollar on a year-to-date basis compared to the same period in 2015 positively impacted the translated results of our U.S. and Mexican businesses, along with realized gains on foreign exchange hedges used to manage our exposure, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt.
Capital Program
We are developing quality projects under our long-term 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 as of September 30, 2016, consists of $25 billion of near-term projects and $48 billion of commercially secured 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
----------------------------------------------------------------------------
Expected Estimated
at September 30, 2016 in-service project Carrying
(unaudited - billions of $) Segment date cost value
----------------------------------------------------------------------------
Topolobampo(1) Natural Gas 2017 US 1.0 US 0.9
Pipelines
Mazatlan Natural Gas 2016 US 0.4 US 0.3
Pipelines
Canadian Mainline Natural Gas 2016-2017 0.7 0.4
Pipelines
NGTL - 2016/17 Facilities Natural Gas 2016-2020 2.7 0.8
Pipelines
- North Montney Natural Gas 2017+(2) 1.7 0.3
Pipelines
- 2018 Facilities Natural Gas 2018-2020 0.6 -
Pipelines
- Other Natural Gas 2016-2018 0.4 -
Pipelines
Grand Rapids(3) Liquids Pipelines 2017 0.9 0.8
Northern Courier Liquids Pipelines 2017 1.0 0.8
Tula Natural Gas 2017 US 0.5 US 0.2
Pipelines
Columbia - Leach XPress Natural Gas 2017 US 1.4 US 0.3
Pipelines
- Rayne XPress Natural Gas 2017 US 0.4 US 0.2
Pipelines
- Gibraltar Natural Gas 2017 US 0.3 US 0.2
Pipelines
- Modernization I Natural Gas 2016-2017 US 0.6 US 0.3
Pipelines
- Cameron Access Natural Gas 2018 US 0.3 US 0.1
Pipelines
- WB XPress Natural Gas 2018 US 0.9 US 0.2
Pipelines
- Mountaineer Natural Gas 2018 US 2.0 US 0.1
XPress Pipelines
- Gulf XPress Natural Gas 2018 US 0.7 -
Pipelines
- Modernization II Natural Gas 2018-2020 US 1.1 -
Pipelines
Napanee Energy 2018 1.1 0.5
Villa de Reyes Natural Gas 2018 US 0.6 US 0.1
Pipelines
Sur de Texas(3) Natural Gas 2018 US 1.3 -
Pipelines
Bruce Power - life Energy 2016-2020 1.2 0.1
extension(3)
----------------------------------------------------------------------------
21.8 6.6
Foreign exchange impact on near-term
projects(4) 3.6 0.9
----------------------------------------------------------------------------
Total near-term projects
CAD 25.4 7.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) CFE has recognized that a force majeure has delayed construction and
revenue has been recorded in third quarter 2016 as per terms of the
Transportation Service Agreement (TSA). See the Recent developments
section for more information.
(2) In-service date is dependent on a positive final investment decision.
(3) Our proportionate share.
(4) Reflects U.S./Canada foreign exchange rate of $1.31 at September 30,
2016.
Medium to longer-term projects
----------------------------------------------------------------------------
at September 30, 2016 Estimated
(unaudited - billions of $) project Carrying
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 Natural Gas Pipelines 2.0 0.1
BC west coast LNG-related
projects
Coastal GasLink Natural Gas Pipelines 4.8 0.4
Prince Rupert Gas Transmission Natural Gas Pipelines 5.0 0.5
NGTL System - Merrick Natural Gas Pipelines 1.9 -
----------------------------------------------------------------------------
45.2 2.3
Foreign exchange impact on medium
to longer-term projects(4) 2.7 0.1
----------------------------------------------------------------------------
Total medium to longer-term
projects 47.9 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 $1.31 at September 30,
2016.
Outlook
Our overall comparable earnings outlook for 2016 will be higher than what was previously included in the 2015 Annual Report due to the net impact of the acquisition of Columbia on July 1, 2016, increased earnings from the remainder of our Natural Gas Pipelines' assets, changes in our Canadian Power business and lower than expected Liquids and U.S. Power earnings, each of which are addressed within the relevant section of the MD&A.
Consolidated capital spending, equity investments and acquisition
Our expected total capital expenditures as outlined in the 2015 Annual Report remains unchanged.
On April 11, 2016, we announced that we were chosen to build, own and operate the Villa de Reyes pipeline in Mexico. On June 13, 2016, we announced that our joint venture with IEnova, Infraestructura Marina del Golfo (IMG), was chosen to build, own and operate the Sur de Texas natural gas pipeline in Mexico. On July 1, 2016, we acquired Columbia. Although we expect to defer capital expenditures on several of our other natural gas pipelines projects, we expect to spend an estimated additional $1 billion on Columbia capital projects in 2016, approximately $300 million on the Villa de Reyes pipeline project and $200 million on the Sur de Texas pipeline project.
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 as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change. In addition, Columbia results are included in the Natural Gas Pipelines segment from its acquisition on July 1, 2016. Comparative periods do not include Columbia.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable EBITDA 1,196 806 2,974 2,472
Depreciation and amortization (361) (284) (936) (845)
----------------------------------------------------------------------------
Comparable EBIT 835 522 2,038 1,627
----------------------------------------------------------------------------
Specific items:
Acquisition related costs -
Columbia (82) - (82) -
TC Offshore loss on sale - - (4) -
----------------------------------------------------------------------------
Segmented earnings 753 522 1,952 1,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Gas Pipelines segmented earnings increased by $231 million and $325 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. Segmented earnings for the three and nine months ended September 30, 2016 included $82 million primarily related to retention and severance expenses incurred within the Natural Gas Pipelines segment resulting from the Columbia acquisition. Year-to-date 2016 segmented earnings also included an additional $4 million pre-tax loss on the sale of TC Offshore. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Canadian Pipelines
Canadian Mainline 285 286 825 866
NGTL System 253 223 736 666
Foothills 24 26 76 79
Other Canadian pipelines(1) 7 7 20 21
----------------------------------------------------------------------------
Canadian Pipelines - comparable
EBITDA 569 542 1,657 1,632
Depreciation and amortization (219) (212) (653) (632)
----------------------------------------------------------------------------
Canadian Pipelines - comparable
EBIT 350 330 1,004 1,000
----------------------------------------------------------------------------
U.S. and International Pipelines
(US$)
Columbia(2) 174 - 174 -
ANR 76 52 235 171
TC PipeLines, LP(1,3) 32 25 90 76
Great Lakes(3,4) 11 8 47 35
Other U.S. pipelines (Iroquois(1),
GTN(3,5), PNGTS(3,6)) 10 13 33 65
Mexico 82 44 165 138
International and other(1,7) (6) (2) (2) 2
Non-controlling interests(8) 94 68 264 208
----------------------------------------------------------------------------
U.S. and International Pipelines -
comparable EBITDA 473 208 1,006 695
Depreciation and amortization (107) (55) (214) (169)
----------------------------------------------------------------------------
U.S. and International Pipelines -
comparable EBIT 366 153 792 526
Foreign exchange impact 121 48 254 136
----------------------------------------------------------------------------
U.S. and International Pipelines -
comparable EBIT (Cdn$) 487 201 1,046 662
----------------------------------------------------------------------------
Business Development comparable
EBITDA and EBIT (2) (9) (12) (35)
----------------------------------------------------------------------------
Natural Gas Pipelines - comparable
EBIT 835 522 2,038 1,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Results from TQM, Northern Border, Iroquois and TransGas reflect our
share of equity income from these investments. On March 31, 2016, we
closed the acquisition of an additional 4.87 per cent interest in
Iroquois and an additional 0.65 per cent interest was acquired on May 1,
2016.
(2) We completed the acquisition of Columbia on July 1, 2016. Represents our
effective ownership in these assets.
(3) TC PipeLines LP (TCLP) periodically conducts at-the-market equity
issuances which decrease our ownership interest in TCLP. On April 1,
2015, we sold our remaining 30 per cent direct interest in GTN to TCLP.
On January 1, 2016, we sold a 49.9 per cent interest in PNGTS to TCLP.
The following table shows our ownership interest in TCLP and our
effective ownership interest of GTN, Great Lakes and PNGTS through our
ownership interest in TCLP for the periods presented.
------------------------------------------------------------------------
ownership percentage as of
-----------------------------------------------------
September 30, June 30, March 31, January 1, April 1,
2016 2016 2016 2016 2015
------------------------------------------------------------------------
TCLP 27.1 27.4 27.9 28.0 28.3
Effective ownership
through TCLP:
GTN 27.1 27.4 27.9 28.0 28.3
Great Lakes 12.6 12.7 13.0 13.0 13.1
PNGTS 13.5 13.7 13.9 14.0 -
------------------------------------------------------------------------
------------------------------------------------------------------------
(4) Represents our 53.6 per cent direct ownership interest. The remaining
46.4 per cent is held by TCLP.
(5) Represents our 30 per cent direct ownership interest until April 1, 2015
at which point the 30 per cent interest was sold to TCLP.
(6) Represents our 61.7 per cent ownership interest in 2015 and 11.8 per
cent effective January 1, 2016 as a result of the sale of 49.9 per cent
interest to TCLP.
(7) Includes our share of equity income from TransGas as well as general and
administration costs relating to our U.S. and International Pipelines.
(8) Comparable EBITDA for the portions of TCLP, PNGTS and Columbia Pipeline
Partners LP that we do not own.
CANADIAN PIPELINES
Net income and comparable EBITDA for our rate-regulated Canadian 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 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 - WHOLLY OWNED CANADIAN PIPELINES
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Canadian Mainline 52 47 154 161
NGTL System 81 70 233 200
Foothills 4 3 11 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income for the Canadian Mainline increased by $5 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to higher incentive earnings, partially offset by a lower average investment base and higher carrying charges. Net Income for the Canadian Mainline decreased by $7 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to a lower average investment base and higher carrying charges, partially offset by higher incentive earnings in 2016.
Net income for the NGTL System increased by $11 million and $33 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to a higher average investment base and OM&A incentive earnings recorded in 2016.
U.S. AND INTERNATIONAL PIPELINES
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 its storage capacity and incidental commodity sales.
The results for Columbia include our 91.6 per cent effective ownership of Columbia Gas Transmission, Columbia Gulf Transmission, Columbia Midstream and Columbia Energy Ventures through a 84.3 per cent direct ownership and our 46.5 per cent ownership in Columbia Pipeline Partners LP which owns the remaining 15.7 per cent ownership interest in these assets.
Comparable EBITDA for U.S. and International Pipelines increased by US$265 million and US$311 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. This was the net effect of:
-- US$174 million of contributions from Columbia as a result of the
acquisition on July 1, 2016
-- higher contribution from Mexican pipelines primarily due to incremental
earnings from Topolobampo. The Topolobampo project has experienced a
delay in construction, which, under the terms of the TSA, constitutes a
force majeure and, as a result, we began realizing revenue in July 2016.
-- higher ANR transportation and storage revenue resulting from higher
rates as part of our rates settlement effective August 1, 2016, higher
ANR Southeast Mainline transportation revenues and lower OM&A expenses,
offset by a first quarter 2015 non-recurring settlement with a producer
-- higher transportation revenues from Great Lakes
-- higher contribution from TC PipeLines, LP.
As well, a stronger U.S. dollar on a year-to-date basis in 2016 compared to 2015 had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $77 million and $91 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the Columbia acquisition on July 1, 2016, a higher investment base on the NGTL System, increased depreciation rates on ANR following the rate settlement, and the effect of a stronger U.S. dollar.
BUSINESS DEVELOPMENT
Business development expenses were lower by $7 million and $23 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the capitalization of business development activities in 2016 related to the successful Mexico projects, a focus on the Columbia acquisition and decreased business development activity in other areas in 2016.
OUTLOOK
The 2016 earnings outlook for the Canadian regulated and Mexican pipelines remains consistent with what we disclosed in the 2015 Annual Report. We are expecting an increase in 2016 earnings from U.S. Pipelines as a result of the acquisition of Columbia on July 1, 2016 although the impact of the related financing will be reflected in our Corporate segment. Earnings for the other U.S. Pipelines are expected to be slightly higher this year as a result of higher revenues and lower costs.
OPERATING STATISTICS - WHOLLY OWNED PIPELINES
----------------------------------------------------------------------------
nine months ended Canadian
September 30 Mainline(1) NGTL System(2) ANR(3)
--------------- --------------- ----------------
(unaudited) 2016 2015 2016 2015 2016 2015
----------------------------------------------------------------------------
Average investment base
(millions of $) 4,423 4,840 7,401 6,599 n/a n/a
Delivery volumes (Bcf):
Total 1,217 1,204 2,978 2,871 1,190 1,212
Average per day 4.4 4.4 10.9 10.5 4.3 4.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 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 nine months ended September
30, 2016 were 802 Bcf (2015 - 833 Bcf). Average per day was 2.9 Bcf
(2015 - 3.1 Bcf).
(2) Field receipt volumes for the NGTL System for the nine months ended
September 30, 2016 were 3,080 Bcf (2015 - 2,994 Bcf). Average per day
was 11.2 Bcf (2015 - 11.0 Bcf).
(3) Under its current rates, which are approved by the FERC, changes in
average investment base do not affect results.
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 as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable EBITDA 281 352 861 970
Depreciation and amortization (72) (68) (209) (197)
----------------------------------------------------------------------------
Comparable EBIT 209 284 652 773
Specific items:
Keystone XL asset costs (14) - (37) -
Risk management activities (8) - (6) -
----------------------------------------------------------------------------
Segmented earnings 187 284 609 773
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liquids Pipelines segmented earnings decreased by $97 million and $164 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included pre-tax charges related to Keystone XL costs for the maintenance and liquidation 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. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Liquids Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Keystone Pipeline System 284 360 870 988
Liquids Pipelines Business
Development and Other (3) (8) (9) (18)
----------------------------------------------------------------------------
Liquids Pipelines - comparable
EBITDA 281 352 861 970
Depreciation and amortization (72) (68) (209) (197)
----------------------------------------------------------------------------
Liquids Pipelines - comparable EBIT 209 284 652 773
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBIT denominated as
follows:
Canadian dollars 52 57 164 172
U.S. dollars 119 171 369 474
Foreign exchange impact 38 56 119 127
----------------------------------------------------------------------------
209 284 652 773
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBITDA for the Keystone Pipeline System is 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 the Keystone Pipeline System decreased by $76 million and $118 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was due to the net effect of lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink, partially offset by higher contracted volumes on Keystone Pipeline.
BUSINESS DEVELOPMENT AND OTHER
Business development and other, which primarily includes business development activity and our marketing business, decreased by $5 million and $9 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was the effect of lower business development spending and a growing contribution from the marketing business.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $4 million and $12 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.
OUTLOOK
Excluding specified items, our 2016 earnings are expected to be lower than our 2015 earnings due to lower uncontracted volumes and market conditions related to the lower crude oil price environment.
Following our Keystone XL impairment charge in 2015, expenditures on the project for the maintenance and liquidation of project assets are being expensed pending further advancement of this project and are expected to be approximately $55 million before tax ($36 million after tax) in 2016. These costs will continue to be excluded from comparable earnings.
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 as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable EBITDA 419 340 984 990
Depreciation and amortization (81) (79) (251) (248)
----------------------------------------------------------------------------
Comparable EBIT 338 261 733 742
----------------------------------------------------------------------------
Specific items:
Ravenswood goodwill impairment (1,085) - (1,085) -
Alberta PPA terminations - - (240) -
U.S. Northeast Power business
monetization (5) - (5) -
Risk management activities (73) (17) 28 (27)
----------------------------------------------------------------------------
Segmented (losses)/earnings (825) 244 (569) 715
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy segmented earnings decreased by $1,069 million and $1,284 million to segmented losses of $825 million and $569 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:
-- a $1,085 million pre-tax impairment charge on the 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 no longer exceeds the carrying value.
-- 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 in March 2016
-- $5 million of pre-tax costs related to the process of monetizing our
U.S. Northeast Power business
-- 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 nine months ended
Risk management activities September 30 September 30
-------------------- --------------------
(unaudited - millions of $, pre-
tax) 2016 2015 2016 2015
--------------------------------------------------------------------------
Canadian Power (4) (14) 3 (7)
U.S. Power (73) (5) 16 (22)
Natural Gas Storage 4 2 9 2
--------------------------------------------------------------------------
Total unrealized (losses)/gains
from risk management activities (73) (17) 28 (27)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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.
Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast Power business, we were required to discontinue hedge accounting for certain cash flow hedges. This, along with the increased volume of our risk management activities associated with the expansion of our customer base in the PJM market, has contributed to higher volatility in U.S. Power risk management activities.
The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Canadian Power
Western Power(1) 26 24 49 73
Eastern Power 82 86 270 306
Bruce Power 76 57 210 202
----------------------------------------------------------------------------
Canadian Power - comparable
EBITDA(1,2) 184 167 529 581
Depreciation and amortization (35) (47) (117) (141)
----------------------------------------------------------------------------
Canadian Power-comparable EBIT(1,2) 149 120 412 440
----------------------------------------------------------------------------
U.S. Power (US$)
U.S. Power - comparable EBITDA 164 140 323 335
Depreciation and amortization (33) (23) (95) (78)
----------------------------------------------------------------------------
U.S. Power - comparable EBIT 131 117 228 257
Foreign exchange impact 44 36 74 68
----------------------------------------------------------------------------
U.S. Power-comparable EBIT (Cdn$) 175 153 302 325
----------------------------------------------------------------------------
Natural Gas Storage and other -
comparable EBITDA 20 (1) 39 8
Depreciation and amortization (3) (3) (9) (9)
----------------------------------------------------------------------------
Natural Gas Storage and other -
comparable EBIT 17 (4) 30 (1)
----------------------------------------------------------------------------
Business Development comparable
EBITDA and EBIT (3) (8) (11) (22)
----------------------------------------------------------------------------
Energy-comparable EBIT(1,2) 338 261 733 742
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included Sundance A and Sheerness PPAs, and the Sundance B PPA held
through our investment in ASTC Power Partnership up to March 7, 2016.
(2) Includes our share of equity income from our investments in Portlands
Energy and Bruce Power and ASTC Power Partnership up to March 7, 2016.
Comparable EBITDA for Energy increased by $79 million for the three months ended September 30, 2016 compared to the same period in 2015 due to the net effect of:
-- higher earnings from U.S. Power mainly due to incremental earnings from
the Ironwood power plant acquired in February 2016 and higher
contributions from sales to customers in the PJM market, offset by lower
capacity revenues in New York
-- higher earnings from Natural Gas Storage due to higher realized natural
gas storage price spreads
-- higher earnings from Bruce Power mainly due to lower depreciation and
our increased ownership interest, partially offset by higher losses from
contracting activities.
Comparable EBITDA for Energy decreased by $6 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to the net effect of:
-- lower earnings from Eastern Power due to lower contributions from the
sales of unused natural gas transportation and lower contractual
earnings at Becancour
-- higher earnings from Natural Gas Storage due to higher realized natural
gas storage price spreads
-- lower earnings from Western Power as a result of lower realized power
prices and termination of the PPAs
-- higher earnings from Bruce Power mainly due to lower depreciation and
our increased ownership interest, partially offset by lower volumes and
higher operating costs from higher planned outage days.
CANADIAN POWER
Western and Eastern Power
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Revenue(1)
Western Power 39 126 170 412
Eastern Power 112 119 315 358
Other(2) 2 1 31 49
----------------------------------------------------------------------------
153 246 516 819
Comparable income from equity
investments(3) 9 (2) 16 13
Commodity purchases resold (1) (83) (60) (266)
Plant operating costs and other (57) (65) (150) (194)
Exclude risk management
activities(1) 4 14 (3) 7
----------------------------------------------------------------------------
Comparable EBITDA(4) 108 110 319 379
Depreciation and amortization (35) (47) (117) (141)
----------------------------------------------------------------------------
Comparable EBIT(4) 73 63 202 238
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Breakdown of comparable EBITDA
Western Power(4) 26 24 49 73
Eastern Power 82 86 270 306
----------------------------------------------------------------------------
Comparable EBITDA(4) 108 110 319 379
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The realized and unrealized gains and losses from financial derivatives
used to manage Canadian Power's assets are presented on a net basis in
Western and Eastern Power revenues. The unrealized gains and losses from
financial derivatives included in revenue are 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 comparable equity income from our investments in
ASTC Power Partnership, which held the Sundance B PPA, and Portlands
Energy. Comparable equity income does not include any gains or losses
related to our risk management activities and, for the nine months ended
September 30, 2016 excludes a $29 million charge related to the Sundance
B PPA termination which was held in ASTC Power Partnership.
(4) Included Sundance A, Sundance B and Sheerness PPAs up to March 7, 2016.
Sales volumes and plant availability
Includes our share of volumes from our equity investments.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited) 2016 2015 2016 2015
----------------------------------------------------------------------------
Sales volumes (GWh)
Supply
Generation
Western Power 606 589 1,824 1,876
Eastern Power 1,152 1,083 2,767 3,145
Purchased
Sundance A & B and Sheerness
PPAs(1) - 2,734 1,620 7,226
Other purchases 21 281 409 677
----------------------------------------------------------------------------
1,779 4,687 6,620 12,924
----------------------------------------------------------------------------
Sales
Contracted
Western Power 627 2,188 2,752 5,627
Eastern Power 1,152 1,083 2,767 3,145
Spot
Western Power - 1,416 1,101 4,152
----------------------------------------------------------------------------
1,779 4,687 6,620 12,924
----------------------------------------------------------------------------
Plant availability(2)
Western Power(3) 94% 96% 92% 97%
Eastern Power(4) 96% 96% 93% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes volumes from Sundance A and Sheerness PPAs and our 50 per cent
ownership interest of the Sundance B PPA held through the ASTC Power
Partnership up to March 7, 2016.
(2) The percentage of time the plant was available to generate power,
regardless of whether it was running.
(3) Does not include facilities that provided power to us under PPAs.
(4) Does not include Becancour because power generation remains suspended.
Western Power
Comparable EBITDA for Western Power increased by $2 million for the three months ended September 30, 2016 compared to the same period in 2015 mainly due to higher realized prices on generated volumes offset by lower earnings following the termination of the PPAs.
Comparable EBITDA for Western Power decreased by $24 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to lower realized power prices and termination of the PPAs.
Results from the Alberta PPAs are included up to March 7, 2016 when we sent notice to the Balancing Pool to terminate the PPAs for the Sundance A, Sundance B and Sheerness facilities. Comparable income from equity investments included earnings from the ASTC Power Partnership which held our 50 per cent ownership in the Sundance B PPA. See the Recent developments section for more information on the PPA terminations.
Average spot market power prices in Alberta decreased 31 per cent from $26/MWh to $18/MWh for the three months ended September 30, 2016 and decreased 54 per cent from $37/MWh to $17/MWh for the nine months ended September 30, 2016 compared to the same periods in 2015. The Alberta power market remained well-supplied and power consumption was down due to a weak economy. Realized power prices on power sales can be higher or lower than spot market power prices in any given period as a result of contracting activities.
One hundred per cent of Western Power sales volumes were sold under contract in third quarter 2016 compared to 61 per cent in third quarter 2015.
Depreciation and amortization decreased by $12 million and $24 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 following the termination of the PPAs.
We continue to expect Western Power 2016 earnings to be consistent with 2015 earnings. Although Alberta power prices are expected to remain low in the remaining months of 2016, the natural gas-fired cogeneration assets are expected to perform well in the lower natural gas price environment and the March 2016 decision to exercise the right to terminate the PPAs is expected to result in savings from the otherwise increased costs related to carbon emissions.
Eastern Power
Comparable EBITDA for Eastern Power decreased by $4 million and $36 million for the three and nine months ended September 30, 2016 compared to the same period in 2015 mainly due to lower contractual earnings at Becancour, and lower earnings on the sale of unused natural gas transportation for the nine months ended September 30, 2016 compared to the same period in 2015.
Our 2016 earnings outlook provided in the 2015 Annual Report will be modestly lower as a result of a delay in the implementation of amendments to the Becancour electricity supply contract. See the Recent developments section for more information about this agreement.
BRUCE POWER
Results reflect our proportionate share. Bruce A and B were merged in December 2015 and comparative information for 2015 is reported on a combined basis to reflect the merged entity.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, unless
noted otherwise) 2016 2015 2016 2015
----------------------------------------------------------------------------
Income from equity investments(1) 76 57 210 202
Comprised of:
Revenues 365 298 1,094 945
Operating expenses (204) (159) (643) (498)
Depreciation and other (85) (82) (241) (245)
----------------------------------------------------------------------------
76 57 210 202
----------------------------------------------------------------------------
Bruce Power - Other information
Plant availability(2) 88% 86% 82% 85%
Planned outage days 50 88 335 287
Unplanned outage days 37 8 49 30
Sales volumes (GWh)(1) 5,886 4,621 16,420 13,970
Realized sales price per MWh(3,4) $66 $64 $66 $66
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents our 48.5 per cent ownership interest in Bruce Power after the
merger on December 4, 2015 and our 48.9 per cent ownership interest in
Bruce A and 31.6 per cent ownership interest in Bruce B up to December
3, 2015. 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.
(4) Excludes unrealized gains and losses on contracting activities and
revenues from cobalt sales.
Equity income from Bruce Power increased by $19 million and $8 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to lower depreciation as a result of the Bruce Power facility's operating life extension and our increased ownership interest. These increases were partially offset by higher losses from contracting activities in the three months ended September 30, 2016 and lower volumes and higher operating costs from higher planned outage days for the nine months ended September 30, 2016 compared to the same periods in 2015.
In December 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the Bruce Power facility to 2064. As part of this agreement, Bruce Power began receiving a uniform price of $65.73 per MWh for all units, which includes certain flow-through items such as fuel and lease expenses recovery. Over time, the price will be subject to adjustments for the return of and on capital invested under the Asset Management and Major Component Replacement capital programs, along with various other pricing adjustments that allow for a better matching of revenues and costs over the long term.
----------------------------------------------------------------------------
Bruce Power contract price(1) per MWh
----------------------------------------------------------------------------
January 1, 2016 - March 31, 2016 $65.73
April 1, 2016 - March 31, 2017 $66.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes fuel and lease expenses recovery on a flow-through basis
estimated at approximately $8.00 per MWh.
Prior to the amended agreement with the IESO, all of the output from Bruce units 1 to 4 was sold at a fixed price/MWh which was adjusted annually on April 1 for inflation and other provisions under the contract.
----------------------------------------------------------------------------
Bruce Units 1 to 4 contract price(1) per MWh
----------------------------------------------------------------------------
April 1, 2014 - March 31, 2015 $76.70
April 1, 2015 - December 31, 2015 $78.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes fuel expense recovery on a flow-through basis estimated at
approximately $5.00 per MWh.
Prior to the amended agreement with the IESO, all output from Bruce units 5 to 8 was subject to a floor price adjusted annually for inflation on April 1.
---------------------------------------------------------------------------- Bruce Units 5 to 8 floor price per MWh ---------------------------------------------------------------------------- April 1, 2014 - March 31, 2015 $52.86 April 1, 2015 - December 31, 2015 $54.13 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
Bruce Power also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.
The contract with the IESO provides for payment if the IESO reduces Bruce Power's generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered deemed generation for which Bruce Power is paid the contract price.
During second quarter 2016, Bruce units 1 to 4 were removed from service for approximately three weeks to facilitate a station containment outage. The station containment outage involved inspecting and maintaining key safety systems including containment structures and is required to be completed approximately once every decade. Additional planned maintenance was completed on unit 3 in third quarter 2016. Planned maintenance on unit 7 began in third quarter 2016 and is scheduled to be completed in fourth quarter 2016. The overall average plant availability percentage in 2016 is expected to be in the low 80s.
We expect 2016 equity income from Bruce Power to be slightly higher than our 2016 Outlook in the 2015 Annual Report primarily due to strong results year-to-date.
U.S. POWER
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of US$) 2016 2015 2016 2015
----------------------------------------------------------------------------
Revenue(1)
Power(2) 764 568 1,666 1,552
Capacity 84 99 223 254
----------------------------------------------------------------------------
848 667 1,889 1,806
Commodity purchases resold (594) (412) (1,188) (1,159)
Plant operating costs and other(3) (147) (119) (362) (329)
Exclude risk management
activities(2) 57 4 (16) 17
----------------------------------------------------------------------------
Comparable EBITDA(1) 164 140 323 335
Depreciation and amortization (33) (23) (95) (78)
----------------------------------------------------------------------------
Comparable EBIT(1) 131 117 228 257
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Ironwood acquisition commencing February 1, 2016.
(2) The realized and unrealized gains and losses from financial derivatives
used to manage U.S. Power's assets are presented on a net basis in Power
revenues. The unrealized gains and losses from financial derivatives
included in revenue are excluded to arrive at Comparable EBITDA.
(3) Includes the cost of fuel consumed in generation.
Sales volumes and plant availability
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited) 2016 2015 2016 2015
----------------------------------------------------------------------------
Physical sales volumes (GWh)
Supply
Generation(1) 4,387 2,707 10,043 5,756
Purchased 9,924 6,919 19,734 15,800
----------------------------------------------------------------------------
14,311 9,626 29,777 21,556
Plant availability(2,3) 97% 93% 85% 77%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Increase primarily due to Ironwood acquisition.
(2) The percentage of time the plant was available to generate power,
regardless of whether it was running.
(3) Plant availability was lower in the nine months ended September 30, 2015
compared to the same period in 2016 due to an unplanned outage at the
Ravenswood facility from September 2014 to May 2015.
U.S. Power - other information
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- -------------------
(unaudited) 2016 2015 2016 2015
----------------------------------------------------------------------------
Average Spot Power Prices (US$ per
MWh)
New England(1) 32 29 29 47
New York(2) 33 31 29 44
PJM(3) 28 n/a 25 n/a
Average New York(2) Spot Capacity
Prices (US$ per KW-M) 12.19 15.27 9.39 12.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 the nine months ended September 30, 2016 is from the
Ironwood acquisition date of February 1 to September 30, 2016.
Comparable EBITDA for U.S. Power increased US$24 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to the net effect of:
-- higher earnings due to our acquisition of the Ironwood power plant on
February 1, 2016
-- higher sales to wholesale utility customers in the PJM market
-- lower capacity revenues due to lower realized capacity prices in New
York and the impact of lower availability as a result of a unit outage
from September 2014 to May 2015, partially offset by insurance
recoveries, net of deductibles at Ravenswood.
Comparable EBITDA for U.S. Power decreased US$12 million for the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to the net effect of:
-- lower capacity revenues due to lower realized capacity prices in New
York and the impact of lower availability as a result of a unit outage
from September 2014 to May 2015, partially offset by insurance
recoveries, net of deductibles at Ravenswood
-- lower margins on sales to wholesale, commercial and industrial customers
partially offset by higher sales to customers in the PJM wholesale
utility market
-- lower realized power prices at our facilities in New York and New
England, partially offset by lower fuel costs
-- higher earnings due to our acquisition of the Ironwood power plant
-- insurance recoveries related to an unplanned outage at the Ravenswood
facility that occurred in 2008.
Higher sales to wholesale utility customers in the PJM market resulted in higher earnings for the three months ended September 30, 2016 compared to the same period in 2015 as we continue to expand our customer base in the PJM market. However, significantly lower realized power prices and mild winter weather have resulted in lower margins in our wholesale business in both the PJM and New England markets for the nine months ended September 30, 2016 compared to the same period in 2015, the impact of which was primarily seen in the first quarter results.
Wholesale electricity prices in New York and New England were slightly higher for the three months ended September 30, 2016 and significantly lower for the nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to unseasonably warm weather in first quarter 2016. In New England, spot power prices for the three and nine months ended September 30, 2016 were 10 per cent higher and 38 per cent lower compared to the same periods in 2015. In New York City, spot power prices for the three and nine months ended September 30, 2016 were six per cent higher and 34 per cent lower compared to the same periods in 2015.
Average New York Zone J spot capacity prices were approximately 20 per cent and 23 per cent lower for the three and nine months ended September 30, 2016 compared to the same periods in 2015. The decrease in spot 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 New York City's Zone J market. The impact of lower capacity prices in New York was partially offset by capacity revenues earned by our Ironwood power plant acquired in February 2016.
Capacity revenues were also negatively impacted by an outage at Unit 30 from September 2014 to May 2015 at Ravenswood. The calculation used by the NYISO to determine the capacity volume for which a generator is compensated utilizes a rolling average forced outage rate. As a result of this methodology, outages impact capacity volumes and associated revenues on a lagged basis. Accordingly, capacity revenues for the three and nine months ended September 30, 2016 were negatively impacted compared to the same periods in 2015. The outage continues to be included in the rolling average forced outage rate. Insurance recoveries, net of deductibles, for this event have been received and are being recognized in capacity revenues to offset amounts lost during the periods impacted by the lower forced outage rate. As a result of these insurance recoveries, the Unit 30 unplanned outage has not had a significant impact on our earnings although the recording of earnings has not coincided exactly with lost revenues due to timing of the insurance proceeds. In addition, insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008 were received in June 2016 and a portion of the proceeds were recognized in Power Revenue.
Physical generation volumes in 2016 were higher compared to the same period in 2015 due to our acquisition of the Ironwood power plant and higher generation at our Ravenswood facilities. Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three and nine month months ended September 30, 2016 than the same periods in 2015 as we have expanded our customer base in the PJM and New England markets.
As at September 30, 2016, approximately 1,500 GWh, or 43 per cent, of U.S. Power's planned generation was contracted for the remainder of 2016 and 3,900 GWh, or 30 per cent, for 2017. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage and plant availability.
U.S. Power results for 2016 are not expected to be significantly impacted by the announced monetization of the U.S. Northeast Power business as these transactions are not expected to close until the first half of 2017. See the Recent developments section for more information. Nevertheless, operating results for the full year in 2016 are expected to be lower than the Outlook in our 2015 Annual Report due to lower commodity prices experienced in the first half of 2016.
NATURAL GAS STORAGE AND OTHER
Comparable EBITDA increased by $21 million and $31 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to increased storage revenues as a result of higher realized natural gas storage price spreads.
The full year 2016 results are expected to be higher compared to 2015 due to the lack of seasonal winter weather conditions, excess natural gas supply and the resulting increase in natural gas storage price spreads which have provided the opportunity to hedge available storage capacity at higher values than originally expected in the Outlook in our 2015 Annual Report.
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 as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable EBITDA (10) (15) (62) (51)
Depreciation and amortization (13) (8) (29) (23)
----------------------------------------------------------------------------
Comparable EBIT (23) (23) (91) (74)
Specific items:
Acquisition related costs -
Columbia (14) - (50) -
Restructuring costs - (8) (14) (20)
----------------------------------------------------------------------------
Segmented losses (37) (31) (155) (94)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Corporate segmented losses in 2016 increased by $6 million and $61 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:
-- acquisition and integration costs associated with the acquisition of
Columbia
-- restructuring costs related to expected future losses under lease
commitments.
Interest expense
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable interest on long-term
debt
(including interest on junior
subordinated notes)
Canadian-dollar denominated (122) (109) (343) (324)
U.S. dollar-denominated (US$) (315) (231) (811) (677)
Foreign exchange impact (102) (72) (260) (177)
----------------------------------------------------------------------------
(539) (412) (1,414) (1,178)
Other interest and amortization
expense (23) (11) (60) (35)
Capitalized interest 46 82 133 223
----------------------------------------------------------------------------
Comparable interest expense (516) (341) (1,341) (990)
Specific item:
Acquisition related costs -
Columbia(1) (6) - (115) -
----------------------------------------------------------------------------
Interest expense (522) (341) (1,456) (990)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) This amount represents the dividend equivalent payments of $109 million
on the subscription receipts issued to partially fund the Columbia
acquisition and $6 million of other acquisitions related costs. See the
Financial condition section for more information.
Comparable interest expense increased by $175 million and $351 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 due to the net effect of:
-- higher interest expense as a result of long-term debt issuances in 2015
and 2016, partially offset by Canadian and U.S. dollar-denominated debt
maturities
-- higher interest expense on debt acquired in the acquisition of Columbia
on July 1, 2016
-- higher foreign exchange on interest on U.S. dollar denominated debt
-- lower capitalized interest on Keystone XL and related projects following
the November 6, 2015 denial of a U.S. Presidential Permit, partially
offset by higher capitalized interest on liquids projects, LNG projects
and the Napanee power generating facility.
Interest income and other
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
AFUDC
Canadian-dollar denominated 44 30 133 81
U.S. dollar-denominated (US$) 55 37 149 98
Foreign exchange impact 11 11 40 25
----------------------------------------------------------------------------
Total AFUDC 110 78 322 204
Other 12 (36) 63 (96)
----------------------------------------------------------------------------
Comparable interest income and
other 122 42 385 108
Specific items:
Acquisition related costs -
Columbia(1) - - 6 -
Risk management activities - (26) 49 (25)
----------------------------------------------------------------------------
Interest income and other 122 16 440 83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) This amount represents interest income on the gross proceeds of the
subscriptions receipts issued to partially fund the Columbia
acquisition. See the Financial condition section for more information.
Comparable interest income and other increased by $80 million and $277 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 due to the net effect of:
-- higher AFUDC related to our rate-regulated projects, primarily Mexico
Pipelines, Energy East Pipeline, NGTL expansion and Columbia projects
-- realized gains in 2016 compared to realized losses in 2015 on
derivatives used to manage our net exposure to foreign exchange rate
fluctuations on U.S. dollar denominated income.
Income tax expense
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable income tax expense (261) (236) (630) (668)
Specific items:
Ravenswood goodwill impairment 429 - 64 -
Alberta PPA terminations - - 64 -
Acquisition related costs -
Columbia 32 - 32 -
Keystone XL income tax recoveries 28 - 28 -
Keystone XL asset costs 5 - 13 -
Restructuring costs - 2 4 6
TC Offshore loss on sale - - 1 -
U.S. Northeast Power business
monetization 2 - 2 -
Alberta corporate income tax rate
increase - - - (34)
Risk management activities 31 11 (21) 16
----------------------------------------------------------------------------
Income tax recovery/(expense) 266 (223) (78) (680)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable income tax expense increased by $25 million and decreased by $38 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was mainly the result of changes in the proportion of income earned between Canadian and foreign jurisdictions and lower flow-through taxes in 2016 on Canadian regulated pipelines.
Net income attributable to non-controlling interests
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable net income attributable
to non-controlling interests (55) (46) (187) (145)
Specific item:
Acquisition related costs -
Columbia 3 - 3 -
----------------------------------------------------------------------------
Net income attributable to non-
controlling interests (52) (46) (184) (145)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income attributable to non-controlling interests increased by $6 million and $39 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included a $3 million charge related to the non-controlling interest portion of retention and severance expenses resulting from the Columbia acquisition.
Comparable net income attributable to non-controlling interests increased by $9 million and $42 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to the acquisition of Columbia which included a non-controlling interest in Columbia Pipeline Partners LP. In addition, the sale of our 30 per cent direct interest in GTN in April 2015 and 49.9 per cent direct interest in PNGTS in January 2016 to TC PipeLines, LP along with the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP increased net income attributable to non-controlling interests year-over-year.
Preferred share dividends
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
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(unaudited - millions of $) 2016 2015 2016 2015
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Preferred share dividends (27) (23) (77) (71)
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Preferred share dividends increased by $4 million and $6 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to preferred shares issuances in 2016 and 2015 offset by lower dividend rates on certain series.
Recent developments
ACQUISITION OF COLUMBIA PIPELINE GROUP, INC.
Acquisition
On July 1, 2016, we closed the acquisition of Columbia valued at US$13 billion comprised of a purchase price of approximately US$10.3 billion and Columbia debt of approximately US$2.7 billion. The acquisition was financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, following the closing of the acquisition, were exchanged into 96.6 million TransCanada common shares. See Financial condition section for additional information on the bridge term loan credit facilities and the subscription receipts.
Columbia operates a portfolio of approximately 24,000 km (15,000 miles) of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets. We acquired Columbia to expand our natural gas business in the U.S. market, positioning ourselves for additional long-term growth opportunities. The acquisition also includes a large portfolio of new capital growth projects which includes seven pipeline expansion projects designed to transport growing supply from the Marcellus / Utica production basins to markets as well as a scheduled program for modernization of existing infrastructure out to 2020 to ensure the continuation of a safe, reliable and efficient system. We are currently executing plans to ensure an effective integration of Columbia into the TransCanada organization. We remain on track to realizing our $250 million of annual cost, revenue and financing benefits.
The following table summarizes the acquisition related costs for Columbia that have been excluded from comparable earnings for the three and nine months ended September 30, 2016.
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three months nine months
ended ended
September 30 September 30
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(unaudited - millions of $) 2016 2016
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Natural Gas Pipelines 82 82
Corporate 14 50
Interest expense 6 115
Interest income and other - (6)
Income tax expense (32) (32)
Non-controlling interests (3) (3)
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Total excluded from comparable earnings 67 206
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Monetization of U.S. Northeast Power business
We currently expect to realize approximately US$3.7 billion from the monetization of our U.S. Northeast Power business. This includes the November 1, 2016 announced sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors for US$2.2 billion and TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC for US$1.065 billion, with the remainder attributed to the marketing business which is expected to be realized going forward. These two sale transactions are expected to close in the first half of 2017 subject to certain regulatory and other approvals and will include closing adjustments. These sales are expected to result in an approximate $1.1 billion after-tax net loss which is comprised of a $656 million after-tax goodwill impairment charge recorded at September 30, 2016, an approximate $863 million after-tax net loss on the sale of the thermal and wind package to be recorded in fourth quarter 2016 and an approximate $443 million after-tax gain on the sale of the hydro assets to be recorded upon close of that transaction. Proceeds from these sales and future realization of value of the marketing business will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to partially finance the Columbia acquisition earlier this year.
Minority interest in Mexican pipelines
As part of the Columbia acquisition financing plan, we previously disclosed our intention to monetize a minority interest in our Mexico natural gas pipeline business. On November 1, 2016, we announced a decision to maintain our full ownership interest in a growing portfolio of natural gas pipeline assets in Mexico rather than sell a minority interest in six of these pipelines, which is consistent with maintaining a simple corporate structure. We currently own and operate the Tamazunchale and Guadalajara pipelines and are investing US$3.8 billion to develop and complete construction of four additional pipelines plus fund our interest in the Sur de Texas project, all of which will serve growing natural gas demand in Mexico. All projects are expected to be in-service by the end of 2018 and are underpinned by 25-year take-or-pay contracts with the CFE. Once completed, we expect our Mexican natural gas pipeline assets to be accretive to earnings per share and generate approximately US$575 million of annual EBITDA, up from US$181 million in 2015.
In connection with this decision, we also entered into an agreement with a group of underwriters to proceed with a common equity offering concurrent with the release of these financial results. See Corporate recent developments for more information.
NATURAL GAS PIPELINES
Canadian Regulated Pipelines
NGTL System
On October 31, 2016, the Government of Canada approved our $1.3 billion NGTL 2017 Facilities Application. In addition, on October 6, 2016, the NEB recommended to the government approval of the $0.4 billion Towerbirch Project. This project consists of a 55 km (34 miles) pipeline loop and a 32 km (20 miles) pipeline extension of the NGTL System in northwest Alberta and northeast B.C. Of NGTL's $5.4 billion near-term capital program we have received approvals for $4.0 billion, while $0.5 billion has been filed and is awaiting approval. Approximately $0.9 billion is expected to filed with regulators in the future.
We continue to work closely with our shippers to ensure that new proposed facilities meet our shippers and market demands. In second quarter 2016, we added new long term delivery contracts on the NGTL System to meet demand in the Pacific Northwest and California which will require the construction of $135 million of new facilities (the Sundre Crossover Project) that were not previously included in our 2018 Facilities program. The open season process supporting the development of these new contracts identified further demand for service to this market that we are currently assessing.
In second quarter 2016, in response to cancellations or deferrals of our certain customer projects, contract non-renewals, and contract transfers, we re-evaluated planned facility requirements to meet future aggregate system service requirements and made changes in the spending profile of our programs to match revised in-service dates. The projected expansion capital spend for the NGTL System remains at approximately $7.3 billion, including the new Sundre Crossover Project, the North Montney and Merrick pipelines and the cancellation of a $66 million project. We have deferred approximately $225 million of spending for facilities in the 2016/17 Facilities program with revised service dates of 2018 through 2020 as well as $210 million of spending for facilities in the 2018 Facilities program with revised service dates of 2019 and 2020.
North Montney Mainline
In March 2016, we filed a request with the NEB for a one year extension to the June 10, 2016 sunset clause in the North Montney Mainline (NMML) project Certificate of Public Convenience and Necessity (CPCN). On September 15, 2016, the NEB approved the sunset clause extension to June 10, 2017. The extension continues to be subject to the condition that construction shall not begin until a positive Final Investment Decision (FID) has been made on the Pacific Northwest LNG (PNW LNG) Project. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the NMML facilities, however, the in-service date will be finalized once a FID has been made.
2016-2017 NGTL Revenue Requirement Settlement
In April 2016, the NEB approved the NGTL revenue requirement settlement application that was filed in December 2015, subject to certain reporting requirements that were subsequently met and approved by the NEB. The settlement includes a ROE of 10.1 per cent on a deemed common equity of 40 per cent, continuation of 2015 depreciation rates, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration cost amount and flow-through treatment of all other costs.
Canadian Mainline Tolling Option Open Season
On October 13, 2016, we launched an open season for the Canadian Mainline, seeking binding commitments on our new long-term, fixed-price proposal to transport WCSB supply from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The contract term for this service is ten years with tolls ranging from $0.75/GJ to $0.82/GJ depending on the shippers' contract volume commitments. Early termination rights are provided and can be exercised following the initial five years of service upon payment of a premium fee. Subject to a successful open season that closes November 10, 2016, and to NEB regulatory approval, the new service is targeted to begin November 1, 2017.
U.S. Pipelines
Columbia Capital Projects
The July 1, 2016 acquisition of Columbia included a capital expansion program that was underway for new facilities planned to be in service in 2017 and 2018 as well as modernization programs for existing assets to be completed through 2020. The large capital expansion program consists of US$7.4 billion related to our regulated pipeline business and US$0.3 billion related to our midstream business. The following summarizes the key capital projects for this new set of assets that are now part of the our overall Natural Gas Pipelines footprint in North America.
Leach XPress
This Columbia Gas Transmission (TCO) project is designed to transport up to 1.5 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the Columbia Gulf System (CGT). The project consists of 219 km (136 miles) of 36-inch greenfield pipe, 39 km (24 miles) of 36-inch loop, three km (two miles) of 30-inch greenfield pipe, 82.8 MW (111,000 hp) of greenfield compression and 24.6 MW (33,000 hp) of brownfield compression. We expect the project, with an estimated capital investment of US$1.4 billion, to be in service in fourth quarter 2017. The FERC 7© application was filed in June 2015 and the Final Environmental Impact Statement (FEIS) was received September 1, 2016.
Rayne XPress
This CGT project is designed to transport up to 1.1 Bcf/d of southwest Marcellus and Utica production associated with the Leach XPress expansion and an interconnect with the Texas Eastern System (TETCO) to various delivery points on the CGT system and Gulf Coast. The project consists of bi-directional compressor station modifications along the CGT system, 38.8 MW (52,000 hp) of greenfield compression, 20.1 MW (27,000 hp) of replacement compression and six km (four miles) of 30-inch pipe replacement. We expect the project, with an estimated capital investment of US$420 million, to be in service in fourth quarter 2017. The FERC 7© application was filed in July 2015 and the FEIS was received September 1, 2016.
Mountaineer XPress
This TCO project is designed to transport up to 2.7 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the CGT system. The project consists of 264 km (164 miles) of 36-inch greenfield pipeline, ten km (six miles) of 24-inch lateral pipeline, 0.6 km (0.4 miles) of 30-inch replacement pipeline, 114.1 MW (153,000 hp) of greenfield compression and 55.9 MW (75,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$2 billion, to be in service in fourth quarter 2018. The FERC 7© application was filed in April 2016.
Gulf XPress
This CGT project is designed to transport up to 0.9 Bcf/d associated with the Mountaineer XPress expansion to various delivery points on the CGT system and Gulf Coast. The project consists of adding seven greenfield midpoint compressor stations along the CGT System route totaling 182.7 MW (254,000 hp). We expect this project, with an estimated capital investment of US$0.7 billion, to be placed in service in fourth quarter 2018. The FERC 7© application was filed in April 2016.
Cameron Access Project
This CGT project is designed to transport up to 0.8 Bcf/d of gas supply to the Cameron LNG export terminal in Louisiana. The project consists of 44 km (27 miles) of 36-inch greenfield pipeline, 11 km (seven miles) of 30-inch looping and 9.7 MW (13,000 hp) of greenfield compression. We expect this project, with an estimated capital investment of US$300 million, to be in service in first quarter 2018. The FERC certificate was received in September 2015.
WB XPress
This TCO project is designed to transport up to 1.3 Bcf/d of Marcellus gas supply westbound (0.8 Bcf/d) to the Gulf Coast via an interconnect with the Tennessee Gas Pipeline, and eastbound (0.5 Bcf/d) to Mid-Atlantic markets, WGL Midstream and Transco interconnects. The project consists of 47 km (29 miles) of various diameter pipeline, 338 km (210 miles) of restoring and uprating maximum operating pressure of existing pipeline, 29.8 MW (40,000 hp) of greenfield compression and 99.9 MW (134,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$0.9 billion, to have a Western build in service in the beginning of second quarter 2018 and an Eastern build in service in fourth quarter 2018. The FERC 7© application for both segments was filed in December 2015.
Modernization I & II
TCO and its customers have entered into a settlement arrangement, approved by FERC, which provides recovery and return on investment to modernize its system, improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Modernization I has been approved for up to US$0.6 billion of work yet to be completed in 2016 through 2017. Modernization II has been approved for up to US$1.1 billion of work to be completed in 2018 through 2020. As per terms of the arrangements, facilities in service by October 31 collect revenues effective February 1 of the following year.
Columbia Midstream - Gibraltar Pipeline Project
We expect to invest US$260 million to construct an approximate 1 MMDth/d dry gas header pipeline in southwest Pennsylvania to be completed in multiple phases with an initial in-service date in fourth quarter 2016 and a final in-service date in fourth quarter 2017.
ANR Section 4 Rate Case Settlement
ANR reached a settlement with its shippers effective August 1, 2016 and filed the final, unopposed settlement agreement with the FERC for approval on September 16, 2016. Transmission reservation rates will increase by 34.8 per cent and storage rates will remain the same for contracts one to three years in length, while increasing slightly for contracts of less than one year and decreasing slightly for contracts more than three years in duration. There is a moratorium on any further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions, but must file for new rates no later than an effective date of August 1, 2022.
Columbia Pipeline Partners, LP
On November 1, 2016, we announced that we have entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia Pipeline Group, Inc, has agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. Common unitholders will also continue to receive regular quarterly distributions of US$0.1975 per common unit including a pro-rated distribution for any partial period to the closing date. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions, and is expected to be accretive to earnings per share and simplify our corporate structure. There will be no gain or loss recorded on closing this transaction as CPPL is a consolidated subsidiary.
Mexico
Topolobampo Pipeline
The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver natural gas from interconnections with third party pipelines to Topolobampo, Sinaloa and into the Mazatlan pipeline. Construction of the pipeline is supported by a 25-year natural gas Transportation Service Agreement (TSA) for 670 MMcf/d with the CFE. The physical in-service date is expected to be delayed into 2017 due to right-of-way acquisition delays. Under the terms of the TSA, this delay is recognized as a force majeure event with provisions allowing for the collection of revenue as per the original TSA service commencement date of July 2016.
Mazatlan Pipeline
The Mazatlan project is a 413 km (257 miles), 24-inch diameter pipeline running from El Oro to Mazatlan within the state of Sinaloa with an estimated cost of US$0.4 billion and is supported by 25-year contract with the CFE. Construction of the pipeline is supported by a 25-year natural gas TSA for 200 MMcf/d with the CFE. Physical construction is complete and is awaiting natural gas to commence in-service under the contract.
Tula Pipeline
The Tula project is a US$500 million, 36 inch, 250 km (155 mile) pipeline with a contracted capacity of 886 MMcf/d for 25 years with the CFE. The pipeline begins at Tuxpan, Veracruz extending through the states of Puebla and Hidalgo, supplying natural gas to markets near Tula, Queretaro. Construction has commenced with one pipeline spread and at the compressor stations.
Villa de Reyes Pipeline
On April 11, 2016, we announced that we were awarded the contract to build, own and operate the Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 MMcf/d with the CFE. We expect to invest approximately US$0.5 billion to construct a 36-inch diameter, 420 km (261 mile) pipeline with an anticipated in-service date of early 2018. The pipeline will begin in Tula, in the state of Hidalgo, and terminate in Villa de Reyes, in the state of San Luis Potosi, transporting natural gas to power generation facilities in the central region of the country. The project will interconnect with our Tamazunchale and Tuxpan-Tula pipelines as well as with other transporters in the region.
Sur de Texas Pipeline
On June 13, 2016, we announced that our joint venture with IEnova had been chosen to build, own and operate the US$2.1 billion Sur de Texas pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 2.6 bcf/d with the CFE. We expect to invest approximately US$1.3 billion in the partnership to construct the 42-inch diameter, approximately 800 km (497 mile) pipeline with an anticipated in-service date of late 2018. The pipeline will start offshore in the Gulf of Mexico, at the border point near Brownsville, Texas, and end in Tuxpan, Mexico in the state of Veracruz. The project will deliver natural gas to our Tamazunchale and Tuxpan-Tula pipelines and to other transporters in the region.
LNG Pipeline Projects
Prince Rupert Gas Transmission
On September 27, 2016, Pacific NorthWest LNG (PNW LNG) received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. PNW LNG has indicated they will conduct a total project review over the coming months prior to announcing next steps for the project.
PRGT continues engagement with Aboriginal groups and other stakeholders along the route in preparation for a FID by PNW LNG. To date, PRGT has executed long-term project agreements with twelve First Nation groups along the pipeline route.
Coastal GasLink
On July 11th, 2016, the LNG Canada joint venture participants announced a delay to their FID for the proposed liquefied natural gas facility in Kitimat, B.C. At this time, a future FID date has not been determined. In light of this announcement, we are working with LNG Canada to determine the appropriate pacing of the Coastal GasLink development schedule and work activities.
LIQUIDS PIPELINES
Keystone Pipeline
On April 2, 2016, we shut down the Keystone pipeline after a leak was detected along the pipeline right-of-way in Hutchinson County, South Dakota. We reported the total volume of the release of 400 barrels to the National Response Center and the Pipeline and Hazardous Materials Safety and Administration (PHMSA). Temporary repairs were completed on April 9, 2016, and the Keystone pipeline was restarted on April 10, 2016. On May 5, 2016, permanent pipeline repairs were completed and restoration work was completed on July 3, 2016. Corrective measures required by PHMSA were completed in September 2016. This shutdown did not significantly impact our 2016 earnings.
Houston Lateral and Terminal
In August 2016, the Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline System to Houston, Texas, went into service. The terminal has an initial storage capacity for 700,000 barrels of crude oil.
Energy East Pipeline
On March 1, 2016, the Province of Quebec filed a court action seeking an injunction to compel the Energy East Pipeline to comply with the province's environmental regulations. On March 30, 2016, the Quebec Superior Court joined the injunction action led by the Province of Quebec with the prior action led by Quebec Environmental Law Centre / Centre quebecois du droit de l'environnement (CQDE), which sought a declaration to compel Energy East to submit to the mandatory provincial environmental review process. As a result of communication with the Ministere du Developpement durable, Environnement et la Lutte contre les changements climatiques, on April 22, 2016, we filed a project review engaging an environmental assessment under the Environmental Quality Act (Quebec) according to an agreed upon schedule for key steps in that process. This process is in addition to environmental assessment required under the NEB Act and the Canadian Environmental Assessment Act, 2012. The Attorney General for Quebec has agreed to suspend its litigation against TransCanada and Energy East and to withdraw it once the provincial environmental assessment process has been completed. The CQDE has similarly agreed to suspend the action. These suspensions are in effect until early November 2016, but may have to be extended given the delay in the NEB process noted below.
On May 17, 2016, we filed a consolidated application with the NEB for Energy East. On June 16, 2016, Energy East achieved a major milestone with the NEB's announcement determining the Energy East application is sufficiently complete to initiate the formal regulatory review process. This determination of completeness also marked the start of the mandated 21 month NEB review process which culminates in a formal recommendation to the Governor in Council (Federal Cabinet). The Governor in Council will then have six months to decide whether to approve the project and, if so, on what conditions. On July 20, 2016, the NEB issued the hearing order which provides further detail on the regulatory process.
On August 8, 2016, the NEB commenced the first of a series of community panel sessions held along the pipeline route in New Brunswick. Panel sessions scheduled for the week of August 29, 2016 in Montreal, Quebec were subsequently cancelled as three NEB panelists announced their decision to recuse themselves from continuing to sit on the panel to review the project due to allegations of reasonable apprehension of bias. The Chair of the NEB and the Vice Chair, who is also a panel member, have recused themselves of any further duties related to the project. As a result, all hearings for the project were adjourned until further notice as we wait on the federal government to appoint new NEB members and then for the NEB to establish a new panel to hear our applications. The new panel members will then determine how the review process is to be re-initiated. As a result of these actions, we expect a delay in the NEB review process.
Keystone XL NAFTA challenge
On June 24, 2016, we filed a Request for Arbitration in a dispute against the U.S. Government pursuant to the Convention on Settlement of Investment Disputes between States and Nationals of Other States, the Rules of Procedure for the Institution of Conciliation and Arbitration Proceedings and Chapter 11 of the North American Free Trade Agreement (NAFTA). The claim arises out of the November 6, 2015 denial of our application for a Presidential Permit to construct the Keystone XL Pipeline. We have requested an award of damages arising from the U.S. Government's breaches of its NAFTA obligations in an amount of more than US$15 billion, together with applicable interest and the costs of arbitration.
ENERGY
Alberta PPAs
On March 7, 2016, we issued notice to the Balancing Pool to terminate our Alberta PPAs. The arrangements contain a provision that permits the PPA buyers to terminate the PPAs if there is a change in the law that makes the arrangements unprofitable or more unprofitable. This termination affects the Sheerness, Sundance A and Sundance B PPAs. On July 22, 2016, we, along with the ASTC Power Partnership, referred the matter to be resolved by binding arbitration pursuant to the dispute resolution provisions of the PPAs. On July 25, 2016, the Government of Alberta brought an application in the Court of Queen's Bench to prevent the Balancing Pool from allowing termination of a PPA held by another party which contains identically worded termination provisions to our PPAs. The outcome of this court application may affect resolution of the arbitration of the Sheerness, Sundance A and Sundance B PPAs. The Balancing Pool has refused to proceed with the arbitrations pending resolution of the court application. On October 20, 2016, we made an application to the Court of Queen's Bench requesting that the court order the Balancing Pool to proceed. Unprofitable market conditions are expected to continue as costs related to carbon emissions have increased and are forecast to continue to increase over the remaining term of the PPA agreements. We expect the termination will improve cash flow and comparable earnings in the near term.
As a result of our decision to terminate the PPAs, we recorded a non-cash impairment charge of $240 million before tax ($176 million after tax) comprised of $211 million before tax ($155 million after tax) related to the carrying value of our Sundance A and Sheerness PPAs and $29 million before tax ($21 million after tax) on our equity investment in the ASTC Power Partnership which holds the Sundance B PPA.
Ontario Cap and Trade
In May 2016, legislation enabling Ontario's cap and trade program was signed into law with the new regulation taking effect July 1, 2016. This regulation sets a limit on annual province-wide greenhouse gas emissions beginning in January 2017 and introduces a market to administer the purchase and trading of emissions allowances. The regulation places the compliance obligation for emissions from our natural gas fired power facilities on local gas distributors, with the distributors flowing the associated costs to the assets.
The IESO is continuing to develop proposed contract amendments for eligible contract holders to address costs and other issues associated with this change in law. We do not expect a significant overall impact as a result of this new regulation.
Becancour tolling agreement
In August 2015, we executed an agreement with Hydro Quebec (HQ) allowing HQ to dispatch up to 570 MW of peak winter capacity from our Becancour facility for a term of 20 years commencing in December 2016. The regulator in Quebec, Regie de l'energie (the Regie), initially accepted this agreement for implementation but in July 2016, the Regie reversed this initial decision. HQ continues to advocate for the contract on its economic merit as part of their strategy to meet the winter peak capacity needs of the province and is pursuing regulatory options for our agreement to be reinstated. We expect the project need and potential timing will be reassessed in the recently released review of HQ's ten year supply plan.
Bruce Power financing
In second quarter 2016, Bruce Power issued bonds and borrowed under its bank credit facility as part of a financing program to fund its capital program and make distributions to its partners. Distributions received from Bruce Power in second quarter 2016 included $725 million from this financing program.
CORPORATE
Common equity offering
On November 1, 2016, in conjunction with our decision to maintain our current ownership interest in a growing Mexican natural gas pipelines business, and concurrent with the release of these financial results, we also entered into an agreement with a group of underwriters to proceed with an offering of common shares. The common shares will be offered to the public in Canada and the United States through the underwriters or their representatives. The offering is subject to the receipt of all necessary regulatory and stock exchange approvals.
Proceeds from the offering will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to finance a portion of the purchase price of Columbia. The closing for the offering is expected to be on November 16, 2016.
Dividend Reinvestment Plan
Under our Dividend Reinvestment Plan (DRP), eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent.
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 cash flow from our operations, access to capital markets (including through the establishment of an at-the-market equity issuance program, if applicable), monetization of assets, cash on hand and substantial committed credit facilities.
At September 30, 2016, our current assets were $5.4 billion and current liabilities were $6.1 billion, leaving us with a working capital deficit of $0.7 billion compared to a deficit of $3.4 billion at December 31, 2015. 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 $8.6 billion of unutilized, unsecured committed credit
facilities.
CASH PROVIDED BY OPERATING ACTIVITIES
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three months ended nine months ended
September 30 September 30
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(unaudited - millions of $) 2016 2015 2016 2015
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Net cash provided by operations 1,183 1,247 3,277 2,976
Increase/(decrease) in operating
working capital 110 (107) (28) 378
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Funds generated from operations(1) 1,293 1,140 3,249 3,354
Specific items:
Acquisition related costs -
Columbia 99 - 238 -
Keystone XL asset costs 14 - 37 -
Restructuring costs - 8 - 20
U.S. Northeast Power business
monetization 5 - 5 -
Current income taxes - - - -
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Comparable funds generated from
operations 1,411 1,148 3,529 3,374
Dividends on preferred shares (28) (23) (74) (69)
Distributions paid to non-
controlling interests (77) (60) (201) (168)
Distributions received in excess of
equity earnings(2) 30 111 217 221
Maintenance capital expenditures
including equity investments (311) (223) (770) (584)
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Comparable distributable cash flow 1,025 953 2,701 2,774
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Comparable distributable cash flow
per common share $1.29 $1.34 $3.68 $3.91
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(1) See the non-GAAP measures section in this MD&A for further discussion of
funds generated from operations.
(2) Reflects distributions received from equity investee operating
activities and excludes additional distributions of $725 million
resulting from Bruce Power's financing program.
COMPARABLE FUNDS GENERATED FROM OPERATIONS
Comparable funds generated from operations is a non-GAAP measure. 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. We calculate this comparable measure by adjusting funds generated from operations for specific items we believe are significant but not reflective of our underlying operations. See the non-GAAP measures section of this MD&A for further discussion on specific items.
Comparable funds generated from operations increased $263 million and $155 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to the increase in net income due to the Columbia acquisition on July 1, 2016.
COMPARABLE DISTRIBUTABLE CASH FLOW
Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation. See our non-GAAP measures section for more information.
Maintenance capital expenditures for the three and nine months ended September 30, 2016 on our Canadian regulated natural gas pipelines were $105 million and $202 million, respectively (2015 - $87 million and $201 million, respectively) which contributed to their respective rate bases and net income.
CASH USED IN INVESTING ACTIVITIES
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three months ended nine months ended
September 30 September 30
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(unaudited - millions of $) 2016 2015 2016 2015
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Capital spending
Capital expenditures (1,444) (976) (3,262) (2,748)
Capital projects in development (62) (130) (219) (465)
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(1,506) (1,106) (3,481) (3,213)
Contributions to equity investments (286) (105) (570) (303)
Restricted cash 13,113 - - -
Acquisitions, net of cash acquired (12,609) - (13,608) -
Proceeds from sale of assets, net
of transaction costs - - 6 -
Distributions received in excess of
equity earnings 30 111 942 221
Deferred amounts and other (38) 36 (18) 240
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Net cash used in investing
activities (1,220) (1,064) (16,693) (3,055)
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Capital expenditures in 2016 were primarily related to:
-- expansion of the NGTL System -- construction of Mexico pipelines -- expansion of the ANR pipeline -- expansion of Columbia pipelines -- construction of the Northern Courier pipeline -- expansion of the Canadian Mainline -- 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 2016 compared to 2015 primarily due to our investments in Grand Rapids, Bruce Power and Sur de Texas.
Restricted cash held in escrow at June 30, 2016 was used for the purchase of Columbia on July 1, 2016.
On February 1, 2016, we acquired the Ironwood natural gas fired, combined cycle power plant with a capacity of 778 MW, for US$653 million in cash after post-acquisition adjustments.
On March 31, 2016, we acquired an additional 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million. On May 1, 2016, we acquired an additional 0.65 per cent for an aggregate purchase price of US$7 million. As a result of these acquisitions, our interest in Iroquois has increased to 50 per cent.
The increase in distributions received in excess of equity earnings is primarily due to distributions from Bruce Power. In second quarter 2016, Bruce Power issued bonds and borrowed under its bank credit facility as part of its financing program to fund its capital program and make distributions to its partners which resulted in $725 million being received by us.
CASH PROVIDED BY FINANCING ACTIVITIES
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Notes payable repaid, net (423) (358) (100) (828)
Long-term debt issued, net of issue
costs 6 962 12,333 3,323
Long-term debt repaid (53) (183) (2,343) (2,066)
Junior subordinated notes issued,
net of issue costs 1,551 - 1,551 917
Dividends and distributions paid (502) (452) (1,434) (1,315)
Common shares/subscription receipts
issued, net of issue costs (37) 1 4,337 12
Common shares repurchased - - (14) -
Partnership units of subsidiary
issued, net of issue costs 45 - 151 31
Preferred shares issued, net of
issue costs - - 492 243
----------------------------------------------------------------------------
Net cash provided by/(used in)
financing activities 587 (30) 14,973 317
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LONG-TERM DEBT ISSUED
----------------------------------------------------------------------------
(unaudited -
millions of $) Maturity Interest
Company Issue date Type date Amount rate
----------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED
June 2016 Acquisition June 2018 US $5,213 Floating
Bridge
Facility(1)
June 2016 Medium Term July 2023 $300 3.690%(2)
Notes
June 2016 Medium Term June 2046 $700 4.350%
Notes
January 2016 Senior January US $400 3.125%
Unsecured 2019
Notes
January 2016 Senior January US $850 4.875%
Unsecured 2026
Notes
ANR PIPELINE COMPANY
June 2016 Senior June 2026 US $240 4.140%
Unsecured
Notes
TRANSCANADA PIPELINE USA LTD.
June 2016 Acquisition June 2018 US $1,700 Floating
Bridge
Facility(1)
TUSCARORA GAS TRANSMISSION COMPANY
April 2016 Term Loan April 2019 US $9.5 Floating
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) These facilities were put in place to finance a portion of the Columbia
acquisition and bear interest at LIBOR plus an applicable margin.
Proceeds from the U.S. Northeast Power business monetizations and the
November 2016 common equity offering will be used to partially repay
these facilities.
(2) Reflects coupon rate on re-opening of existing medium term notes (MTN)
issue. New MTNs were issued at a premium resulting in a re-issuance
yield of 2.69 per cent.
JUNIOR SUBORDINATED DEBT ISSUED
----------------------------------------------------------------------------
(unaudited -
millions of Maturity Interest
$) Company Issue date Type date Amount rate
----------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED
August 2016 Junior August 2076 US $1,200 6.125%(2)
Subordinated
Unsecured
Notes(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Junior subordinated unsecured notes are subordinated in right of
payment to existing and future senior indebtedness or other obligations
of TCPL and are callable at TCPL's option at any time on or after August
15, 2026 at 100 per cent of the principal amount plus accrued and unpaid
interest to the date of redemption.
(2) The Junior subordinated unsecured notes were issued to TransCanada
Trust. The interest rate is fixed at 6.125 per cent per annum and will
reset starting August 2026 until August 2046 to the three month LIBOR
plus 4.89 per cent per annum; from August 2046 to August 2076 the
interest rate will reset to the three month LIBOR plus 5.64 per cent per
annum.
On August 15, 2016, TransCanada Trust (the Trust), a wholly owned trust subsidiary of TCPL, issued US$1.2 billion of Trust Notes to third party investors with a fixed interest rate of 5.875 per cent for the first ten years converting to a floating rate thereafter. The proceeds of the Trust Notes were loaned to TCPL through the subscription for US$1.2 billion of junior subordinated notes of TCPL at a rate of 6.125 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully 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 receivables from TCPL.
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 other outstanding first preferred shares of TCPL.
LONG-TERM DEBT RETIRED
----------------------------------------------------------------------------
(unaudited -
millions of $) Interest
Company Retirement date Type Amount rate
----------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED
October 2016 Medium Term Notes $400 4.65%
June 2016 Senior Unsecured Notes US $84 7.69%
June 2016 Senior Unsecured Notes US $500 Floating
January 2016 Senior Unsecured Notes US $750 0.75%
NOVA GAS TRANSMISSION LTD.
February 2016 Debentures $225 12.20%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
COMMON SHARES REPURCHASED
In November 2015, the TSX approved our normal course issuer bid (NCIB), which allows for the repurchase and cancellation of up to 21.3 million common shares, representing three per cent of our then issued and outstanding common shares, between November 23, 2015 and November 22, 2016 at prevailing market prices plus brokerage fees, or such other prices as may be permitted by the TSX. Since inception of the NCIB, 7.1 million shares were repurchased at an average price of $43.63. With the acquisition of Columbia, we do not anticipate further repurchases under this NCIB.
The following table summarizes shares repurchased in 2016 under the NCIB:
----------------------------------------------------------------------------
at September 30, 2016
(millions of $, except number of common shares and per share
data)
----------------------------------------------------------------------------
Number of common shares repurchased(1) 305,407
Weighted-average price per common share(2) $44.90
Amount repurchased $13.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes repurchases of common shares pursuant to private agreements
with third-parties.
(2) Includes brokerage fees.
SUBSCRIPTION RECEIPTS
On April 1, 2016, we issued 96.6 million subscription receipts to partially fund the Columbia acquisition at a price of $45.75 each for total proceeds of $4.4 billion. Each subscription receipt holder received one common share upon closing of the Columbia acquisition. Holders received dividend equivalent payments per subscription receipt equal to dividends declared on each common share, with the first payment on April 29, 2016 for holders of record at close of business on April 15, 2016. The second dividend equivalent payment was made on July 29, 2016 to holders of record at the close of business on June 30, 2016. For the nine months ended September 30, 2016, $109 million of dividend equivalent payments were recorded as interest expense and have been excluded from comparable earnings. See the Reconciliation of non-GAAP measures section.
Interest income of $6 million relating to the proceeds while held in escrow has also been excluded from comparable earnings. See the Reconciliation of non-GAAP measures section.
On July 4, 2016, the subscription receipts were automatically exchanged for TransCanada common shares in accordance with the terms of the subscription receipt agreement and were delisted from the TSX.
DIVIDEND REINVESTMENT PLAN
Under our Dividend Reinvestment Plan (DRP), eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent. Approximately $175 million or 39 per cent of dividends paid on October 31, 2016 were reinvested in TransCanada common shares.
PREFERRED SHARE ISSUANCE AND CONVERSION
In February 2016, holders of 1.3 million Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.54 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 5 preferred shares was reset for five years at 2.263 per cent per annum. Such rate will reset every five years.
In April 2016, we completed a public offering of 20 million Series 13 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $500 million. The Series 13 preferred shareholders will have the right to convert their Series 13 preferred shares into Series 14 cumulative redeemable first preferred shares on May 31, 2021 and on the last business day of May of every fifth year thereafter. The holders of Series 14 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the sum of the then applicable 90-day Government of Canada treasury bill rate plus 4.69 per cent. The fixed dividend rate on the Series 13 preferred shares was set for its initial period at 5.5 per cent per annum and will reset every five years to a rate equal to the sum of the then applicable five-year Government of Canada bond yield plus 4.69 per cent subject to a floor of not less than 5.5 per cent per annum.
The following table summarizes the impact of the 2016 conversion and issuance of preferred shares discussed above:
----------------------------------------------------------------------------
Number of Redemption
shares Annual and
issued and dividend Redemption conversion Right to
outstanding Current per price per option convert
(unaudited) (thousands) yield share(1) share(2) date(2,3) into(3)
----------------------------------------------------------------------------
Cumulative
first
preferred
shares
Series 5 12,714 2.263% $0.56575 $25.00 January Series 6
30, 2021
Series 6 1,286 Floating(4) Floating $25.00 January Series 5
30, 2021
Series 13 20,000 5.5% $1.375 $25.00 May 31, Series 14
2021
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Holders of the cumulative redeemable first preferred shares set out in
this table are entitled to receive a fixed cumulative quarterly
preferred dividend, as and when declared by the Board, with the
exception of Series 6 preferred shares. The holders of Series 6
preferred shares are entitled to receive a quarterly floating rate
cumulative preferred dividend, as and when declared by the Board.
(2) We may, at our option, redeem all or a portion of the outstanding
preferred shares for the redemption price per share, plus all accrued
and unpaid dividends, on the redemption option date and on every fifth
anniversary date thereafter. In addition, Series 6 preferred shares are
redeemable by us at any time other than on a designated redemption
option date for $25.50 per share plus all accrued and unpaid dividends
on such redemption date.
(3) The holder will have the right, subject to certain conditions, to
convert their first preferred shares of a specified series into first
preferred shares of another specified series on the conversion option
date and every fifth anniversary thereafter.
(4) Commencing September 30, 2016, the floating quarterly dividend rate for
the Series 6 preferred shares is 2.073 per cent and will reset every
quarter going forward.
TC PIPELINES, LP AT-THE-MARKET (ATM) EQUITY ISSUANCE PROGRAM
Since January 1, 2016, 2.7 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$143 million. Our ownership interest in TC PipeLines, LP was 27 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. 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 November 1, 2016, we declared quarterly dividends as follows:
---------------------------------------------------------------------------- Quarterly dividend on our common shares ---------------------------------------------------------------------------- $0.565 per share Payable on January 30, 2017 to shareholders of record at the close of business on January 3, 2017 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Quarterly dividends on our preferred shares ---------------------------------------------------------------------------- Series 1 $0.204125 Series 2 $0.15283060 Series 3 $0.1345 Series 4 $0.11212020 Payable on December 30, 2016 to shareholders of record at the close of business on November 30, 2016 Series 5 $0.14143750 Series 6 $0.13038299 Series 7 $0.25 Series 9 $0.265625 Payable on January 30, 2017 to shareholders of record at the close of business on January 3, 2017 Series 11 $0.2375 Series 13 $0.34375 Payable on November 30, 2016 to shareholders of record at the close of business on November 14, 2016 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
SHARE INFORMATION
----------------------------------------------------------------------------
as at October 28, 2016
----------------------------------------------------------------------------
Common shares Issued and outstanding
800 million
----------------------------------------------------------------------------
Preferred shares Issued and outstanding Convertible to
Series 1 9.5 million Series 2 preferred shares
Series 2 12.5 million Series 1 preferred shares
Series 3 8.5 million Series 4 preferred shares
Series 4 5.5 million Series 3 preferred shares
Series 5 12.7 million Series 6 preferred shares
Series 6 1.3 million Series 5 preferred shares
Series 7 24 million Series 8 preferred shares
Series 9 18 million Series 10 preferred shares
Series 11 10 million Series 12 preferred shares
Series 13 20 million Series 14 preferred shares
Options to buy common
shares Outstanding Exercisable
11 million 6 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CREDIT FACILITIES
We use committed revolving credit facilities to support our commercial paper programs and, along with demand facilities, for general corporate purposes including issuing letters of credit, providing additional liquidity and completing the acquisition of Columbia.
At November 1, 2016, we had approximately $19.2 billion in unsecured credit facilities, including:
----------------------------------------------------------------------------
Unused Description and
Amount capacity Subsidiary use Matures
----------------------------------------------------------------------------
$3.0 billion $3.0 billion TCPL Committed, December 2020
syndicated,
revolving,
extendible TCPL
credit facility
that supports
TCPL's Canadian
commercial paper
program
----------------------------------------------------------------------------
US$5.2 billion - TCPL Committed, June 2018
syndicated, senior
asset sale bridge
term loan
commitment that
supports the
acquisition of
Columbia(1)
----------------------------------------------------------------------------
US$1.0 billion US$1.0 billion TCPL Committed, December 2016
syndicated,
revolving,
extendible TCPL
credit facility
that supports
TCPL's U.S.
commercial paper
program
----------------------------------------------------------------------------
US$1.7 billion - TCPL USA Committed, June 2018
syndicated, senior
asset sale bridge
term loan
commitment that
supports the
acquisition of
Columbia(1)
----------------------------------------------------------------------------
US$1.5 billion US$1.3 billion TCPL USA Committed, December 2016
syndicated,
revolving,
extendible TCPL
USA credit
facility that is
used for TCPL USA
general corporate
purposes
----------------------------------------------------------------------------
US$1.5 billion US$1.5 billion TAIL/TCPM Committed, December 2016
syndicated,
revolving,
extendible credit
facility that
supports the joint
TAIL/TCPM
commercial paper
program in the
U.S.
----------------------------------------------------------------------------
$1.9 billion $0.6 billion TCPL/TCPL Supports the Demand
USA issuance of
letters of credit
and provides
additional
liquidity
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) These facilities were put in place to finance a portion of the Columbia
acquisition and bear interest at the LIBOR plus an applicable margin.
Proceeds from the U.S. Northeast Power business monetizations and the
November 2016 common equity offering will be used to partially repay
these facilities.
At November 1, 2016, our operated affiliates had an additional $0.4 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 increased by approximately $1.5 billion since December 31, 2015 as a result of the new commitments for the Tula, Villa de Reyes and Sur de Texas natural gas pipelines partially offset by decreased commitments on Grand Rapids and Napanee. Our other purchase obligations are consistent with the amounts reported at December 31, 2015.
Our commitments at December 31, 2015 included fixed payments net of sublease receipts for Alberta PPAs. With the March 7, 2016 notice to terminate our Sheerness, Sundance A and Sundance B PPAs, our future obligations from December 31, 2015 have decreased as follows: 2016 - $195 million, 2017 - $200 million, 2018 - $141 million, 2019 - $138 million and 2020 - $115 million. Our commitments for 2021 and beyond increased by approximately $0.5 billion as a result of the extension of premises leases in second quarter 2016. The acquisition of Columbia on July 1, 2016 resulted in a total increase to our contractual obligations of $349 million for transportation contracts and premises leases. There were no other material changes to our contractual obligations in third quarter 2016 or to payments due in the next five years or after. See the MD&A in our 2015 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.
Our liquids marketing business began operations in the first quarter of 2016. It enters into short-term or long-term pipeline and storage terminal capacity contracts, primarily on the Company's assets, increasing the utilization of those assets and earning the market value of the capacity. Derivative instruments are used to fix a portion of the variable price exposures that arise from physical liquids transactions.
See our 2015 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2015.
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 September 30, 2016, we had no significant credit losses and no significant amounts past due or impaired. We had a credit risk concentration of $191 million (US$146 million) at September 30, 2016 with one counterparty (December 31, 2015 - $248 million (US$179 million)). This amount is secured by a guarantee from the counterparty's parent company and is expected to be fully collectible.
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
Certain of our businesses generate income in U.S. dollars, but since we report 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 further managed by using foreign exchange derivatives.
We have floating interest rate debt which subjects us to interest rate cash flow risk, a portion of which we manage using a combination of interest rate swaps and options.
Average exchange rate - U.S. to Canadian dollars
---------------------------------------------------------------------------- three months ended September 30, 2016 1.31 three months ended September 30, 2015 1.31 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- nine months ended September 30, 2016 1.32 nine months ended September 30, 2015 1.26 ----------------------------------------------------------------------------
The impact of changes in the value of the U.S. dollar on our U.S. and international operations, on a pre-tax basis, 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
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-----------------------------------------
(unaudited - millions of US$) 2016 2015 2016 2015
----------------------------------------------------------------------------
U.S. and International Natural Gas
Pipelines comparable EBIT 366 153 792 526
U.S. Liquids Pipelines comparable
EBIT 119 171 369 474
U.S. Power comparable EBIT 131 117 228 257
AFUDC on U.S. dollar-denominated
projects 55 37 149 98
Interest on U.S. dollar-denominated
long-term debt (315) (231) (811) (677)
Capitalized interest on U.S.
dollar-denominated capital
expenditures 6 42 22 102
U.S. non-controlling interests (38) (35) (138) (115)
----------------------------------------------------------------------------
324 254 611 665
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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:
----------------------------------------------------------------------------
September 30, 2016 December 31, 2015
------------------- -------------------
Notional Notional
or or
(unaudited - millions of Canadian $, Fair principal Fair principal
unless noted otherwise) value(1) amount value(1) amount
----------------------------------------------------------------------------
Asset/(liability)
U.S. dollar cross-currency interest
rate swaps (maturing 2016 to
2019)(2) (433) US 2,400 (730) US 3,150
U.S. dollar foreign exchange forward
contracts (maturing 2016 to 2017) (16) US 200 50 US 1,800
----------------------------------------------------------------------------
(449) US 2,600 (680) US 4,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fair values equal carrying values.
(2) In the three and nine months ended September 30, 2016, net realized
gains of $1 million and $5 million, respectively, (2015 - gains of $2
million and $7 million, respectively) 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
---------------------------------------------------------------------------- (unaudited - millions of Canadian $, unless noted otherwise) September 30, 2016 December 31, 2015 ---------------------------------------------------------------------------- Notional amount 30,200 (US 23,000) 23,100 (US 16,700) Fair value 33,700 (US 25,700) 23,800 (US 17,200) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
FINANCIAL INSTRUMENTS
All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.
Derivative instruments
We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify and are designated for hedge accounting treatment.
The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.
Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of the derivative instruments is as follows:
----------------------------------------------------------------------------
September 30, December 31,
(unaudited - millions of $) 2016 2015
----------------------------------------------------------------------------
Other current assets 332 442
Intangible and other assets 181 168
Accounts payable and other (616) (926)
Other long-term liabilities (428) (625)
----------------------------------------------------------------------------
(531) (941)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Unrealized and realized gains/(losses) of derivative instruments
The following summary does not include hedges of our net investment in foreign operations.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, pre-
tax) 2016 2015 2016 2015
----------------------------------------------------------------------------
Derivative instruments held for
trading(1)
Amount of unrealized (losses)/gains
in the period
Commodities(2) (97) (27) 23 (30)
Foreign exchange - (26) 47 (25)
Amount of realized (losses)/gains
in the period
Commodities (23) (52) (165) (84)
Foreign exchange (5) (34) 52 (87)
Derivative instruments in hedging
relationships
Amount of realized (losses)/gains
in the period
Commodities (15) (35) (155) (132)
Foreign exchange 5 - (101) -
Interest rate 1 2 4 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 (2015 - nil) 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:
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, pre-
tax) 2016 2015 2016 2015
----------------------------------------------------------------------------
Change in fair value of derivative
instruments recognized in OCI
(effective portion)(1)
Commodities 7 (48) 33 (77)
Foreign exchange (5) - - -
Interest rate 4 (1) - (1)
----------------------------------------------------------------------------
6 (49) 33 (78)
----------------------------------------------------------------------------
Reclassification of (losses)/gains
on derivative instruments from
AOCI to net income (effective
portion)(1)
Commodities(2) (7) 76 54 124
Foreign exchange(3) 5 - - -
Interest rate(4) 3 4 11 12
----------------------------------------------------------------------------
1 80 65 136
----------------------------------------------------------------------------
Gains/(losses) on derivative
instruments recognized in net
income (ineffective portion)
Commodities(2) 14 10 (1) 3
----------------------------------------------------------------------------
14 10 (1) 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
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 September 30, 2016, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $24 million (December 31, 2015 - $32 million), with collateral provided in the normal course of business of nil (December 31, 2015 - nil). If the credit-risk-related contingent features in these agreements were triggered on September 30, 2016, we would have been required to provide additional collateral of $24 million (December 31, 2015 - $32 million) to our counterparties. 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 September 30, 2016, 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.
We acquired Columbia on July 1, 2016. Assets attributable to Columbia as of July 1, 2016 represented approximately 25 per cent of our total assets as of July 1, 2016, and revenues attributable to Columbia for the period July 1, 2016 to September 30, 2016 represented approximately 12 per cent of our total revenues for third quarter 2016. Management is currently in the process of evaluating and integrating Columbia's controls over financial reporting with ours. We expect to complete this integration in 2017.
Other than as described above, there were no changes in third quarter 2016 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. The fair value of assets and liabilities acquired in a business combination accounted for under the acquisition method are also subject to estimates and judgement. 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 2015 Annual Report.
Impairment of long-lived assets and goodwill
We test goodwill for impairment on an annual basis or more frequently if events or changes in circumstances indicate that it might be impaired. 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 did not exceed its carrying value, including goodwill, at September 30, 2016. The fair value of Ravenswood was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. Plant, property and equipment was also tested for impairment. As a result, at September 30, 2016, we recorded a goodwill impairment charge on the full goodwill amount of $1,085 million ($656 million after tax) related to the Ravenswood facility within the Energy segment and also determined there was no impairment on the plant, property and equipment.
At September 30, 2016, our goodwill included $1.9 billion related to the ANR natural gas transportation business. As a result of our ANR Section 4 rate case settlement filed on September 16, 2016, we tested this reporting unit for impairment. The fair value of this reporting unit was measured by using a discounted cash flow analysis incorporating the key terms of the settlement. While no impairment of goodwill was necessary, the estimated fair value of ANR exceeds its carrying value, including goodwill, by less than 10 per cent. Under the settlement, there is a moratorium on any further rate changes until August 1, 2019. Adverse conditions impacting rates and volumes on ANR beyond the moratorium period could result in a reduction for our estimated future cash flows, which could result in future impairment of a portion of the goodwill balance related to ANR.
Our significant accounting policies have remained unchanged since December 31, 2015 other than described below. You can find a summary of our significant accounting policies in our 2015 Annual Report.
Changes in accounting policies for 2016
Extraordinary and unusual income statement items
In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from U.S. GAAP the concept of extraordinary items. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on our consolidated financial statements.
Consolidation
In February 2015, the FASB issued new guidance on consolidation. This update requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016, was applied retrospectively and did not result in any change to our consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 16, Variable interest entities.
Imputation of interest
In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance was effective January 1, 2016, was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on our consolidated balance sheet.
Business combinations
In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on our consolidated financial statements.
Future accounting changes
Revenue from contracts with customers
In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. We are currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and have begun an assessment in order to determine any impact on our consolidated financial statements.
Inventory
In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify 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 is effective January 1, 2017 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.
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 our other deferred tax assets. This new guidance is effective January 1, 2018. 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 leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may 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 and will be applied using a modified retrospective approach. We are currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on our consolidated financial statements as a result of adopting this new standard.
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 is effective January 1, 2017 and we do not expect the adoption of this guidance to have a material 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. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. We do not expect the adoption of this new standard to have a material 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 the 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. This new guidance is effective January 1, 2017 and we do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.
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.
Classification of certain cash receipts and cash payments
In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments. These include debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance and distributions received from equity method investees. The new guidance is effective January 1, 2018 and will be applied using a retrospective approach. The new guidance also specifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the impact on our consolidated financial statements.
Reconciliation of non-GAAP measures
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, except
per share amounts) 2016 2015 2016 2015
----------------------------------------------------------------------------
EBITDA 605 1,458 3,262 4,334
Ravenswood goodwill impairment 1,085 - 1,085 -
Alberta PPA terminations - - 240 -
Acquisition related costs -
Columbia 96 - 132 -
Keystone XL asset costs 14 - 37 -
Restructuring costs - 8 14 20
TC Offshore loss on sale - - 4 -
U.S. Northeast Power business
monetization 5 - 5 -
Risk management activities(1) 81 17 (22) 27
----------------------------------------------------------------------------
Comparable EBITDA 1,886 1,483 4,757 4,381
Depreciation and amortization (527) (439) (1,425) (1,313)
----------------------------------------------------------------------------
Comparable EBIT 1,359 1,044 3,332 3,068
----------------------------------------------------------------------------
Other income statement items
Comparable interest expense (516) (341) (1,341) (990)
Comparable interest income and
other 122 42 385 108
Comparable income tax expense (261) (236) (630) (668)
Comparable net income attributable
to non-controlling interests (55) (46) (187) (145)
Preferred share dividends (27) (23) (77) (71)
----------------------------------------------------------------------------
Comparable earnings 622 440 1,482 1,302
Specific items (net of tax):
Ravenswood goodwill impairment (656) - (656) -
Alberta PPA terminations - - (176) -
Acquisition related costs -
Columbia (67) - (206) -
Keystone XL income tax recoveries 28 - 28 -
Keystone XL asset costs (9) - (24) -
Restructuring costs - (6) (10) (14)
TC Offshore loss on sale - - (3) -
U.S. Northeast Power business
monetization (3) - (3) -
Alberta corporate income tax rate
increase - - - (34)
Risk management activities(1) (50) (32) 50 (36)
----------------------------------------------------------------------------
Net (loss)/income attributable to )
common shares (135 402 482 1,218
----------------------------------------------------------------------------
Comparable interest expense (516) (341) (1,341) (990)
Specific item:
Acquisition related costs -
Columbia (6) - (115) -
----------------------------------------------------------------------------
Interest expense (522) (341) (1,456) (990)
----------------------------------------------------------------------------
Comparable interest income and
other 122 42 385 108
Specific items:
Acquisition related costs -
Columbia - - 6 -
Risk management activities(1) - (26) 49 (25)
----------------------------------------------------------------------------
Interest income and other 122 16 440 83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of $, except
per share amounts) 2016 2015 2016 2015
----------------------------------------------------------------------------
Comparable income tax expense (261) (236) (630) (668)
Specific items:
Ravenswood goodwill impairment 429 - 429 -
Alberta PPA terminations - - 64 -
Acquisition related costs -
Columbia 32 - 32 -
Keystone XL income tax recoveries 28 - 28 -
Keystone XL asset costs 5 - 13 -
Restructuring costs - 2 4 6
TC Offshore loss on sale - - 1 -
U.S. Northeast Power business
monetization 2 - 2 -
Alberta corporate income tax rate
increase - - - (34)
Risk management activities(1) 31 11 (21) 16
----------------------------------------------------------------------------
Income tax recovery/ (expense) 266 (223) (78) (680)
----------------------------------------------------------------------------
Comparable net income attributable
to non-controlling interests (55) (46) (187) (145)
Specific item:
Acquisition related costs -
Columbia 3 - 3 -
----------------------------------------------------------------------------
Net income attributable to non-
controlling interests (52) (46) (184) (145)
----------------------------------------------------------------------------
Comparable earnings per common
share $0.78 $0.62 $2.02 $1.84
Specific items (net of tax):
Ravenswood goodwill impairment (0.82) - (0.89) -
Alberta PPA terminations - - (0.25) -
Acquisition related costs -
Columbia (0.09) - (0.29) -
Keystone XL income tax recoveries 0.03 - 0.04 -
Keystone XL asset costs (0.01) - (0.03) -
Restructuring costs - (0.01) (0.01) (0.02)
U.S. Northeast Power business
monetization - - - -
Alberta corporate income tax rate
increase - - - (0.05)
Risk management activities (0.06) (0.04) 0.07 (0.05)
----------------------------------------------------------------------------
Net (loss)/income per common share $0.17 $0.57 $0.66 $1.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-----------------------------------------------------------------------
(1) three months ended nine months ended
Risk management activities September 30 September 30
-------------------- --------------------
(unaudited - millions of $) 2016 2015 2016 2015
-----------------------------------------------------------------------
Canadian Power (4) (14) 3 (7)
U.S. Power (73) (5) 16 (22)
Liquids (8) - (6) -
Natural Gas Storage 4 2 9 2
Foreign exchange - (26) 49 (25)
Income tax attributable to
risk management activities 31 11 (21) 16
-----------------------------------------------------------------------
Total unrealized
(losses)/gains from risk
management activities (50) (32) 50 (36)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Comparable EBITDA and EBIT by business segment
---------------------------------------------------------------------------- three months ended September 30, Natural 2016(unaudited - millions Gas Liquids of $) Pipelines Pipelines Energy Corporate Total ---------------------------------------------------------------------------- EBITDA 1,114 259 (744) (24) 605 Ravenswood goodwill impairment - - 1,085 - 1,085 Alberta PPA terminations - - - - - Acquisition related costs - Columbia 82 - - 14 96 Keystone XL asset costs - 14 - - 14 Restructuring costs - - - - - U.S. Northeast Power business monetization - - 5 - 5 Risk management activities - 8 73 - 81 ---------------------------------------------------------------------------- Comparable EBITDA 1,196 281 419 (10) 1,886 Comparable depreciation and amortization (361) (72) (81) (13) (527) ---------------------------------------------------------------------------- Comparable EBIT 835 209 338 (23) 1,359 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- three months ended September 30, Natural 2015(unaudited - millions Gas Liquids of $) Pipelines Pipelines Energy Corporate Total ---------------------------------------------------------------------------- EBITDA 806 352 323 (23) 1,458 Restructuring costs - - - 8 8 Risk management activities - - 17 - 17 ---------------------------------------------------------------------------- Comparable EBITDA 806 352 340 (15) 1,483 Comparable depreciation and amortization (284) (68) (79) (8) (439) ---------------------------------------------------------------------------- Comparable EBIT 522 284 261 (23) 1,044 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- nine months ended September 30, Natural 2016(unaudited - millions Gas Liquids of $) Pipelines Pipelines Energy Corporate Total ---------------------------------------------------------------------------- EBITDA 2,888 818 (318) (126) 3,262 Ravenswood goodwill impairment - - 1,085 - 1,085 Alberta PPA terminations - - 240 - 240 Acquisition related costs - Columbia 82 - - 50 132 Keystone XL asset costs - 37 - - 37 Restructuring costs - - - 14 14 TC Offshore loss on sale 4 - - - 4 U.S. Northeast Power business monetization - - 5 - 5 Risk management activities - 6 (28) - (22) ---------------------------------------------------------------------------- Comparable EBITDA 2,974 861 984 (62) 4,757 Depreciation and amortization (936) (209) (251) (29) (1,425) ---------------------------------------------------------------------------- Comparable EBIT 2,038 652 733 (91) 3,332 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- nine months ended September 30, Natural 2015(unaudited - millions Gas Liquids of $) Pipelines Pipelines Energy Corporate Total ---------------------------------------------------------------------------- EBITDA 2,472 970 963 (71) 4,334 Restructuring costs - - - 20 20 Risk management activities - - 27 - 27 ---------------------------------------------------------------------------- Comparable EBITDA 2,472 970 990 (51) 4,381 Depreciation and amortization (845) (197) (248) (23) (1,313) ---------------------------------------------------------------------------- Comparable EBIT 1,627 773 742 (74) 3,068 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
----------------------------------------------------------------------------
2016 2015 2014
-------------------- --------------------------- ------
(unaudited - millions
of $, except per
share amounts) Third Second First Fourth Third Second First Fourth
----------------------------------------------------------------------------
Revenues 3,632 2,751 2,503 2,851 2,944 2,631 2,874 2,616
Net (loss)/income
attributable to
common shares (135) 365 252 (2,458) 402 429 387 458
Comparable earnings 622 366 494 453 440 397 465 511
Share statistics
Net (loss)/income
per common share -
basic and diluted ($0.17) $0.52 $0.36 ($3.47) $0.57 $0.60 $0.55 $0.65
Comparable earnings
per share $0.78 $0.52 $0.70 $0.64 $0.62 $0.56 $0.66 $0.72
Dividends declared
per common share $0.565 $0.565 $0.565 $0.52 $0.52 $0.52 $0.52 $0.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 Natural Gas Pipelines, quarter-over-quarter revenues and net income from the Canadian regulated pipelines generally remain relatively stable during any fiscal year. Our U.S. natural gas pipelines are generally seasonal in nature with higher earnings in the winter months as a result of increased customer demands. Over the long term, however, results from both our Canadian and U.S. natural gas pipelines 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. -- impairment of goodwill and other assets.
FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.
Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.
In third quarter 2016, comparable earnings excluded:
-- a $656 million after-tax impairment on the 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 exceeds its carrying value.
-- costs associated with the acquisition of Columbia including a charge of
$67 million after tax primarily relating 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 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.
In fourth quarter 2014, comparable earnings excluded an $8 million after-tax gain on the sale of our interest in Gas Pacifico/INNERGY.
Condensed consolidated statement of income
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of Canadian
$, except per share amounts) 2016 2015 2016 2015
----------------------------------------------------------------------------
Revenues
Natural Gas Pipelines 1,884 1,305 4,511 3,896
Liquids Pipelines 440 507 1,292 1,410
Energy 1,308 1,132 3,083 3,143
----------------------------------------------------------------------------
3,632 2,944 8,886 8,449
Income from Equity Investments 154 94 355 350
Operating and Other Expenses
Plant operating costs and other 1,177 823 2,646 2,344
Commodity purchases resold 783 624 1,628 1,731
Property taxes 136 133 405 390
Depreciation and amortization 527 439 1,425 1,313
Goodwill and other asset impairment
charges 1,085 - 1,296 -
----------------------------------------------------------------------------
3,708 2,019 7,400 5,778
----------------------------------------------------------------------------
Loss on Sale of Assets - - (4) -
Financial Charges
Interest expense 522 341 1,456 990
Interest income and other (122) (16) (440) (83)
----------------------------------------------------------------------------
400 325 1,016 907
----------------------------------------------------------------------------
(Loss)/Income before Income Taxes (322) 694 821 2,114
----------------------------------------------------------------------------
Income Tax (Recovery)/Expense
Current 14 30 103 124
Deferred (280) 193 (25) 556
----------------------------------------------------------------------------
(266) 223 78 680
----------------------------------------------------------------------------
Net (Loss)/Income (56) 471 743 1,434
Net income attributable to non-
controlling interests 52 46 184 145
----------------------------------------------------------------------------
Net (Loss)/Income Attributable to )
Controlling Interests (108 425 559 1,289
Preferred share dividends 27 23 77 71
----------------------------------------------------------------------------
Net (Loss)/Income Attributable to )
Common Shares (135 402 482 1,218
----------------------------------------------------------------------------
Net (Loss)/Income per Common Share
Basic and diluted ($0.17) $0.57 $0.66 $1.72
----------------------------------------------------------------------------
Dividends Declared per Common Share $0.565 $0.52 $1.695 $1.56
----------------------------------------------------------------------------
Weighted Average Number of Common
Shares (millions)
Basic 797 709 734 709
Diluted 798 710 735 710
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated statement of comprehensive income
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of Canadian
$) 2016 2015 2016 2015
----------------------------------------------------------------------------
Net (Loss)/Income (56) 471 743 1,434
----------------------------------------------------------------------------
Other Comprehensive Income/(Loss),
Net of Income Taxes
Foreign currency translation
gains/(losses) on net investment
in foreign operations 55 356 (152) 688
Change in fair value of net
investment hedges (1) (153) (9) (361)
Change in fair value of cash flow
hedges 5 (29) 21 (50)
Reclassification to net income of
gains on cash flow hedges - 50 40 83
Reclassification to net income of
actuarial gains and prior service
costs on pension and other post-
retirement benefit plans 4 7 12 24
Other comprehensive income on
equity investments 4 3 11 10
----------------------------------------------------------------------------
Other comprehensive income/(loss)
(Note 11) 67 234 (77) 394
----------------------------------------------------------------------------
Comprehensive Income 11 705 666 1,828
Comprehensive income attributable
to non-controlling interests 76 171 104 388
----------------------------------------------------------------------------
Comprehensive (Loss)/Income
Attributable to Controlling
Interests (65) 534 562 1,440
Preferred share dividends 27 23 77 71
----------------------------------------------------------------------------
Comprehensive (Loss)/Income
Attributable to Common Shares (92) 511 485 1,369
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated statement of cash flows
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of Canadian
$) 2016 2015 2016 2015
----------------------------------------------------------------------------
Cash Generated from Operations
Net (loss)/income (56) 471 743 1,434
Depreciation and amortization 527 439 1,425 1,313
Goodwill and other asset impairment
charges 1,085 - 1,296 -
Deferred income taxes (280) 193 (25) 556
Income from equity investments (154) (94) (355) (350)
Distributed earnings received from
equity investments 155 117 408 397
Employee post-retirement benefits
expense, net of funding 4 11 (5) 41
Loss on sale of assets - - 4 -
Equity allowance for funds used
during construction (71) (45) (195) (115)
Unrealized losses/(gains) on
financial instruments 82 43 (71) 52
Other 1 5 24 26
(Increase)/decrease in operating
working capital (110) 107 28 (378)
----------------------------------------------------------------------------
Net cash provided by operations 1,183 1,247 3,277 2,976
----------------------------------------------------------------------------
Investing Activities
Capital expenditures (1,444) (976) (3,262) (2,748)
Capital projects in development (62) (130) (219) (465)
Contributions to equity investments (286) (105) (570) (303)
Restricted cash 13,113 - - -
Acquisitions, net of cash acquired (12,609) - (13,608) -
Proceeds from sale of assets, net
of transaction costs - - 6 -
Distributions received in excess of
equity earnings 30 111 942 221
Deferred amounts and other 38 36 18 240
----------------------------------------------------------------------------
Net cash used in investing
activities (1,220) (1,064) (16,693) (3,055)
----------------------------------------------------------------------------
Financing Activities
Notes payable repaid, net (423) (358) (100) (828)
Long-term debt issued, net of issue
costs 6 962 12,333 3,323
Long-term debt repaid (53) (183) (2,343) (2,066)
Junior subordinated notes issued,
net of issue costs 1,551 - 1,551 917
Dividends on common shares (397) (369) (1,159) (1,078)
Dividends on preferred shares (28) (23) (74) (69)
Distributions paid to non-
controlling interests (77) (60) (201) (168)
Common shares/subscription receipts
issued, net of issue costs (37) 1 4,337 12
Common shares repurchased - - (14) -
Preferred shares issued, net of
issue costs - - 492 243
Partnership units of subsidiary
issued, net of issue costs 45 - 151 31
----------------------------------------------------------------------------
Net cash provided by/(used in)
financing activities 587 (30) 14,973 317
----------------------------------------------------------------------------
Effect of Foreign Exchange Rate
Changes on Cash and Cash
Equivalents 3 12 (127) 28
----------------------------------------------------------------------------
Increase in Cash and Cash
Equivalents 553 165 1,430 266
Cash and Cash Equivalents
Beginning of period 1,727 590 850 489
----------------------------------------------------------------------------
Cash and Cash Equivalents
End of period 2,280 755 2,280 755
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated balance sheet
----------------------------------------------------------------------------
September 30, December 31,
(unaudited - millions of Canadian $) 2016 2015
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 2,280 850
Accounts receivable 1,765 1,387
Inventories 424 323
Other 927 1,358
----------------------------------------------------------------------------
5,396 3,918
Plant, Property and net of accumulated
Equipment depreciation of
$23,279 and
$22,299,
respectively 56,203 44,817
Equity Investments 6,496 6,214
Regulatory Assets 1,346 1,184
Goodwill 13,638 4,812
Intangible and Other Assets 3,567 3,102
Restricted Investments 612 351
----------------------------------------------------------------------------
87,258 64,398
----------------------------------------------------------------------------
LIABILITIES
Current Liabilities
Notes payable 1,000 1,218
Accounts payable and other 3,781 3,077
Accrued interest 549 520
Current portion of long-term debt 790 2,547
----------------------------------------------------------------------------
6,120 7,362
Regulatory Liabilities 2,093 1,159
Other Long-Term Liabilities 1,262 1,260
Deferred Income Tax Liabilities 7,345 5,144
Long-Term Debt 43,273 28,909
Junior Subordinated Notes 3,842 2,409
----------------------------------------------------------------------------
63,935 46,243
Common Units of TC PipeLines, LP Subject to
Rescission 106 -
----------------------------------------------------------------------------
EQUITY
Common shares, no par value 16,480 12,102
Issued and outstanding: September 30, 2016 -
800 million shares
December 31, 2015 -
703 million shares
Preferred shares 2,992 2,499
Additional paid-in capital - 7
Retained earnings 1,992 2,769
Accumulated other comprehensive loss (Note 11) (936) (939)
----------------------------------------------------------------------------
Controlling Interests 20,528 16,438
Non-controlling interests 2,689 1,717
----------------------------------------------------------------------------
23,217 18,155
----------------------------------------------------------------------------
87,258 64,398
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and Guarantees (Note 15)
Variable Interest Entities (Note 16)
Subsequent Events (Note 17)
See accompanying notes to the condensed consolidated financial statements.
Condensed consolidated statement of equity
----------------------------------------------------------------------------
nine months ended September 30
------------------------------
(unaudited - millions of Canadian $) 2016 2015
----------------------------------------------------------------------------
Common Shares
Balance at beginning of period 12,102 12,202
Shares issued on exercise of stock options 70 12
Shares repurchased (6) -
Shares issued on exchange of subscription
receipts 4,314 -
----------------------------------------------------------------------------
Balance at end of period 16,480 12,214
----------------------------------------------------------------------------
Preferred Shares
Balance at beginning of period 2,499 2,255
Shares issued under public offering, net of
issue costs 493 244
----------------------------------------------------------------------------
Balance at end of period 2,992 2,499
----------------------------------------------------------------------------
Additional Paid-In Capital
Balance at beginning of period 7 370
Issuance of stock options, net of exercises 3 8
Dilution impact from TC PipeLines, LP units
issued 17 4
Impact of common shares repurchased (8) -
Impact of asset drop down to TC PipeLines, LP (38) (213)
Reclassification of Additional Paid-In Capital
deficit to Retained Earnings 19 -
----------------------------------------------------------------------------
Balance at end of period - 169
----------------------------------------------------------------------------
Retained Earnings
Balance at beginning of period 2,769 5,478
Net income attributable to controlling
interests 559 1,289
Common share dividends (1,246) (1,106)
Preferred share dividends (71) (69)
Reclassification of Additional Paid-In Capital
deficit to Retained Earnings (19) -
----------------------------------------------------------------------------
Balance at end of period 1,992 5,592
----------------------------------------------------------------------------
Accumulated Other Comprehensive Loss
Balance at beginning of period (939) (1,235)
Other comprehensive income 3 151
----------------------------------------------------------------------------
Balance at end of period (936) (1,084)
----------------------------------------------------------------------------
Equity Attributable to Controlling Interests 20,528 19,390
----------------------------------------------------------------------------
Equity Attributable to Non-Controlling
Interests
Balance at beginning of period 1,717 1,583
Acquisition of non-controlling interests in
Columbia Pipeline Partners LP 1,051 -
Net income attributable to non-controlling
interests
TC PipeLines, LP 153 132
Portland 27 13
Columbia Pipeline Partners LP 4 -
Other comprehensive (loss)/income attributable
to non-controlling interests (80) 243
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs 151 31
Decrease in TransCanada's ownership of TC
PipeLines, LP (28) (6)
Reclassification to Common Units of TC
PipeLines, LP Subject to Rescission (106) -
Distributions declared to non-controlling
interests (200) (161)
----------------------------------------------------------------------------
Balance at end of period 2,689 1,835
----------------------------------------------------------------------------
Total Equity 23,217 21,225
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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), which now includes Columbia Pipeline Group (Columbia) 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, 2015, 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 2015 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 2015 audited consolidated financial statements included in TransCanada's 2015 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 segment 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 fair value of assets and liabilities acquired in a business combination accounted for under the acquisition method are also subject to estimates and judgement. 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, 2015, except as described in Note 2, Accounting changes.
2. Accounting changes
CHANGES IN ACCOUNTING POLICIES FOR 2016
Extraordinary and unusual income statement items
In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from U.S. GAAP the concept of extraordinary items. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.
Consolidation
In February 2015, the FASB issued new guidance on consolidation. This update requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 16, Variable Interest Entities.
Imputation of interest
In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance was effective January 1, 2016, was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on the Company's consolidated balance sheet.
Business combinations
In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.
FUTURE ACCOUNTING CHANGES
Revenue from contracts with customers
In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. The Company is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and has begun an assessment in order to determine any impact on the consolidated financial statements.
Inventory
In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify 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 is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.
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. 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 leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may 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 and will be applied using a modified retrospective approach. The Company is currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on its consolidated financial statements as a result of adopting this new standard.
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 is effective January 1, 2017 and the Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.
Equity method investments
In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its 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 the 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. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.
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.
Classification of certain cash receipts and cash payments
In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments. These include debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance and distributions received from equity method investees. The new guidance is effective January 1, 2018 and will be applied using a retrospective approach. The new guidance also specifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the impact on its consolidated financial statements.
3. Segmented information
----------------------------------------------------------------------------
three months
ended Natural Gas Liquids
September 30 Pipelines Pipelines Energy Corporate Total
--------------------------------------------------------------
(unaudited -
millions of
Canadian $) 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015
----------------------------------------------------------------------------
Revenues 1,884 1,305 440 507 1,308 1,132 - - 3,632 2,944
Income from
equity
investments 66 41 - - 88 53 - - 154 94
Plant
operating
costs and
other (733) (452) (160) (133) (260) (215) (24) (23) (1,177) (823)
Commodity
purchases
resold - - - - (783) (624) - - (783) (624)
Property taxes (103) (88) (21) (22) (12) (23) - - (136) (133)
Depreciation
and
amortization (361) (284) (72) (68) (81) (79) (13) (8) (527) (439)
Goodwill and
other asset
impairment
charges - - - - (1,085) - - - (1,085) -
----------------------------------------------------------------------------
Segmented
earnings/
(losses) 753 522 187 284 (825) 244 (37) (31) 78 1,019
--------------------------------------------------------------
Interest
expense (522) (341)
Interest income and other 122 16
----------------------------------------------------------------------------
(Loss)/income before income taxes (322) 694
Income tax recovery/(expense) (266) (223)
----------------------------------------------------------------------------
Net (loss)/income (56) 471
Net income attributable to non-controlling interests (52) (46)
----------------------------------------------------------------------------
Net (loss)/income attributable to controlling interests (108) 425
Preferred share dividends (27) (23)
----------------------------------------------------------------------------
Net (loss)/income attributable to common shares (135) 402
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
nine months ended Natural Gas
September 30 Pipelines Liquids Pipelines
----------------------------------------
(unaudited - millions of
Canadian $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Revenues 4,511 3,896 1,292 1,410
Income/(loss) from equity
investments 157 134 (1) -
Plant operating costs and other (1,496) (1,294) (406) (379)
Commodity purchases resold - - - -
Property taxes (280) (264) (67) (61)
Depreciation and amortization (936) (845) (209) (197)
Goodwill and other asset impairment
charges - - - -
Loss on sale of assets (4) - - -
----------------------------------------------------------------------------
Segmented earnings/(losses) 1,952 1,627 609 773
----------------------------------------------------------------------------
Interest expense
Interest income and other
----------------------------------------------------------------------------
Income before income taxes
Income tax expense
----------------------------------------------------------------------------
Net income
Net income attributable to non-controlling interests
----------------------------------------------------------------------------
Net income attributable to controlling interests
Preferred share dividends
----------------------------------------------------------------------------
Net income attributable to common shares
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
nine months ended
September 30 Energy Corporate
----------------------------------------
(unaudited - millions of
Canadian $) 2016 2015 2016 2015
----------------------------------------------------------------------------
Revenues 3,083 3,143 - -
Income/(loss) from equity
investments 199 216 - -
Plant operating costs and other (618) (600) (126) (71)
Commodity purchases resold (1,628) (1,731) - -
Property taxes (58) (65) - -
Depreciation and amortization (251) (248) (29) (23)
Goodwill and other asset impairment
charges (1,296) - - -
Loss on sale of assets - - - -
----------------------------------------------------------------------------
Segmented earnings/(losses) (569) 715 (155) (94)
----------------------------------------------------------------------------
Interest expense
Interest income and other
----------------------------------------------------------------------------
Income before income taxes
Income tax expense
----------------------------------------------------------------------------
Net income
Net income attributable to non-controlling interests
----------------------------------------------------------------------------
Net income attributable to controlling interests
Preferred share dividends
----------------------------------------------------------------------------
Net income attributable to common shares
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
nine months ended
September 30 Total
----------------------------------------
(unaudited - millions of
Canadian $) 2016 2015
----------------------------------------------------------------------------
Revenues 8,886 8,449
Income/(loss) from equity
investments 355 350
Plant operating costs and other (2,646) (2,344)
Commodity purchases resold (1,628) (1,731)
Property taxes (405) (390)
Depreciation and amortization (1,425) (1,313)
Goodwill and other asset impairment
charges (1,296) -
Loss on sale of assets (4) -
----------------------------------------------------------------------------
Segmented earnings/(losses) 1,837 3,021
----------------------------------------------
Interest expense (1,456) (990)
Interest income and other 440 83
----------------------------------------------------------------------------
Income before income taxes 821 2,114
Income tax expense (78) (680)
----------------------------------------------------------------------------
Net income 743 1,434
Net income attributable to non-
controlling interests (184) (145)
----------------------------------------------------------------------------
Net income attributable to
controlling interests 559 1,289
Preferred share dividends (77) (71)
----------------------------------------------------------------------------
Net income attributable to common
shares 482 1,218
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TOTAL ASSETS
----------------------------------------------------------------------------
September 30, December 31,
(unaudited - millions of Canadian $) 2016 2015
----------------------------------------------------------------------------
Natural Gas Pipelines 53,247 31,039
Liquids Pipelines 16,278 16,046
Energy 13,881 15,614
Corporate 3,852 1,699
----------------------------------------------------------------------------
87,258 64,398
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. Acquisition of Columbia
On July 1, 2016, TransCanada acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash, based on US$25.50 per share for all of Columbia's outstanding common shares as well as restricted and performance stock units. The acquisition was financed through proceeds of approximately $4.4 billion from the sale of subscription receipts, draws on committed bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering. Upon closing of the acquisition, the subscription receipts were exchanged into approximately 96.6 million common shares of TransCanada. Refer to Note 7, Long-term debt for additional information on the bridge term loan credit facilities and Note 10, Equity and share capital for additional information on the subscription receipts.
Columbia operates a portfolio of approximately 24,000 km of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets in various regions in the U.S. TransCanada acquired Columbia to expand the Company's natural gas business in the U.S. market, positioning the Company for additional long-term growth opportunities.
The Goodwill of $10.1 billion (US$7.7 billion) arising from the acquisition consists largely of the opportunities to expand the Company's natural gas pipelines segment in the U.S. market and to gain a stronger competitive position in the North American natural gas business. The Goodwill resulting from the acquisition is not deductible for income tax purposes.
The acquisition has been accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The purchase price equation reflects management's estimate of the fair value of Columbia's assets and liabilities as at July 1, 2016.
----------------------------------------------------------------------------
July 1, 2016
(unaudited - millions of $) U.S. Canadian
----------------------------------------------------------------------------
Purchase Price Consideration 10,294 13,392
Fair Value Assigned to Net Assets
Current Assets 658 856
Plant, Property and Equipment 7,556 9,830
Equity Investments 441 574
Regulatory Assets 190 248
Intangibles and Other Assets 135 175
Current Liabilities (597) (777)
Regulatory Liabilities (294) (383)
Other Long-Term Liabilities (144) (187)
Deferred Income Tax Liabilities (1,611) (2,095)
Long-Term Debt (2,981) (3,878)
Non-controlling Interests (808) (1,051)
----------------------------------------------------------------------------
Fair Value of Net Assets Acquired 2,545 3,312
----------------------------------------------------------------------------
Goodwill 7,749 10,080
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair values of current assets including cash and cash equivalents, accounts receivable, inventories and other and the fair values of current liabilities including notes payable and accrued interest approximate their carrying values due to the short-term nature of these items. Certain acquisition related working capital items resulted in an adjustment to accounts payable and other.
Columbia's natural gas pipelines are subject to FERC regulations and, as a result, their rate bases are expected to be recovered with a reasonable rate of return over the life of the assets. These assets, as well as related regulatory assets and liabilities, have fair values equal to their carrying values. The fair value of mineral rights included in Columbia's plant, property and equipment was estimated using a discounted cash flow approach which resulted in a fair value increase of $241 million (US$185 million). The Company utilized an independent third party valuation in the assessment of fair value. The fair value of base gas included in Columbia's plant, property and equipment was determined by using quoted market prices multiplied by the volume of gas in place which resulted in a fair value increase of $836 million (US$642 million).
The fair value of Columbia's long-term debt was estimated using an income approach based on quoted market prices for similar debt instruments from external data service providers. This resulted in a fair value increase of $300 million (US$231 million).
The following table summarizes the fair value of Columbia's debt acquired by TransCanada.
----------------------------------------------------------------------------
(unaudited - Fair Interest
millions of $)Maturity date Type Value rate
----------------------------------------------------------------------------
COLUMBIA PIPELINE GROUP INC.
June 2018 Senior Unsecured Notes US $506 2.45%
(US$500)
June 2020 Senior Unsecured Notes US $779 3.30%
(US$750)
June 2025 Senior Unsecured Notes US $1,092 4.50%
(US$1,000)
June 2045 Senior Unsecured Notes US $604 5.80%
(US$500)
----------------------------------------------------------------------------
US $2,981
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair values of Columbia's defined pension benefit plan and OPEB plans were based on an actuarial valuation report as of the acquisition date. The fair value representing the funded status of the plans on the acquisition date resulted in an increase of $15 million (US$12 million) and $5 million (US$4 million) to Regulatory assets and Other long-term liabilities, respectively, and a decrease of $14 million (US$11 million) and $2 million (US$2 million) to Intangible and other assets and Regulatory liabilities, respectively.
Temporary differences created as a result of the fair value changes described above resulted in deferred tax assets and liabilities that were recorded at the Company's U.S. effective tax rate of 39 per cent.
The fair value of Columbia's non-controlling interest is based on the approximately 53.8 million Columbia Pipeline Partners LP common units outstanding to the public as of June 30, 2016, and valued at the June 30, 2016 closing price of US$15.00 per common unit.
Acquisition expenses of approximately $36 million are included in Plant operating costs and other in the condensed consolidated statement of income.
Upon completing the acquisition, the Company began consolidating Columbia. Columbia's significant accounting policies are consistent with TransCanada's and continue to be applied. Columbia contributed $427 million (US$327 million to revenues and $55 million (US$42 million) to net income from the acquisition date to September 30, 2016.
The following supplemental unaudited pro forma consolidated financial information of the Company for the three and nine months ended September 30, 2016 and 2015 includes the results of operations for Columbia as if the acquisition had been completed on January 1, 2015.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- -------------------
(unaudited - millions of Canadian $,
except per share amounts) 2016 2015 2016 2015
----------------------------------------------------------------------------
Revenues 3,632 3,364 9,783 9,680
Net (Loss)/Income (56) 495 873 1,593
Net (Loss)/Income Attributable to
Common Shares (135) 411 580 1,342
Net (Loss)/Income per Common Share ($0.17) $0.51 $0.70 $1.67
----------------------------------------------------------------------------
5. Goodwill and other asset impairments
Goodwill impairment
TransCanada tests goodwill for impairment on an annual basis or more frequently if events or changes in circumstances indicate that goodwill might be impaired. As a result of information received during the process to monetize the Company's U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill, at September 30, 2016. The fair value of Ravenswood was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. Plant, property and equipment was also tested for impairment. As a result, at September 30, 2016, the Company recorded a goodwill impairment charge on the full goodwill amount of $1,085 million ($656 million after-tax) related to the Ravenswood facility within the Energy segment and also determined there was no impairment on the plant, property and equipment.
Power Purchase Arrangements
On March 7, 2016, TransCanada issued notice to the Balancing Pool of the decision to terminate its Sheerness and Sundance A PPAs. In accordance with a provision in the PPAs, a buyer is permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of recent changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expects increasing costs related to carbon emissions to continue throughout the remaining terms of the PPAs resulting in increasing unprofitabilty. As such, at March 31, 2016, the Company recognized a non-cash impairment charge of $211 million ($155 million after-tax) in its Energy segment, which represents the carrying value of the PPAs.
On March 7, 2016, TransCanada also issued notice to the Balancing Pool of the decision to terminate its Sundance B PPA. The Sundance B PPA is held in the ASTC Power Partnership in which the Company holds a 50 per cent ownership interest. As a result, at March 31, 2016 the Company recognized a non-cash impairment charge of $29 million ($21 million after-tax) in its Energy segment, which represents the carrying value of the equity investment. This impairment charge is included in Income from equity investments on the condensed consolidated statement of income.
6. Income taxes
At September 30, 2016, the total unrecognized tax benefit of uncertain tax positions was approximately $20 million (December 31, 2015 - $17 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in income tax expense for the three and nine months ended September 30, 2016 is nil for interest expense and nil for penalties (September 30, 2015 - nil for interest expense and nil for penalties). At September 30, 2016, the Company had $4 million accrued for interest expense and nil accrued for penalties (December 31, 2015 - $4 million accrued for interest expense and nil for penalties).
The effective tax rates for the nine-month periods ended September 30, 2016 and 2015 were 10 per cent and 32 per cent, respectively. The lower effective tax rate in 2016 was primarily the result of lower flow-through taxes in 2016 on Canadian regulated pipelines changes in the proportion of income earned between Canadian and foreign jurisdictions and the goodwill impairment charge.
7. Long-term debt
LONG-TERM DEBT ISSUED
The Company issued long-term debt in the nine months ended September 30, 2016 as follows:
----------------------------------------------------------------------------
(unaudited -
millions of
Canadian $,
unless noted Maturity Interest
otherwise) Issue date Type date Amount rate
----------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED
June 2016 Acquisition June 2018 US $5,213 Floating
Bridge
Facility(1)
June 2016 Medium Term July 2023 $300 3.690%(2)
Notes
June 2016 Medium Term June 2046 $700 4.350%
Notes
January 2016 Senior January US $400 3.125%
Unsecured 2019
Notes
January 2016 Senior January US $850 4.875%
Unsecured 2026
Notes
ANR PIPELINE COMPANY
June 2016 Senior June 2026 US $240 4.140%
Unsecured
Notes
TRANSCANADA PIPELINE USA LTD.
June 2016 Acquisition June 2018 US $1,700 Floating
Bridge
Facility(1)
TUSCARORA GAS TRANSMISSION COMPANY
April 2016 Term Loan April 2019 US $9.5 Floating
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) These facilities were put in place to finance a portion of the Columbia
acquisition and bear interest at Libor plus an applicable margin.
Proceeds from the U.S. Northeast Power business sales and the November
2016 common equity offering will be used to partially repay these
facilities.
(2) Reflects coupon rate on re-opening of existing medium term notes (MTN)
issue. New MTNs were issued at a premium resulting in a re-issuance
yield of 2.69 per cent.
LONG-TERM DEBT RETIRED
The Company retired long-term debt in the nine months ended September 30, 2016 as follows:
----------------------------------------------------------------------------
(unaudited -
millions of
Canadian $,
unless noted Retirement Interest
otherwise) date Type Amount rate
----------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED
June 2016 Senior Unsecured Notes US $84 7.69%
June 2016 Senior Unsecured Notes US $500 Floating
January 2016 Senior Unsecured Notes US $750 0.75%
NOVA GAS TRANSMISSION LTD.
February Debentures $225 12.2%
2016
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the three and nine months ended September 30, 2016, TransCanada capitalized interest related to capital projects of $46 million and $133 million, respectively (2015 - $82 million and $223 million, respectively).
8. Junior subordinated notes
JUNIOR SUBORDINATED DEBT ISSUED
----------------------------------------------------------------------------
(unaudited - Type
millions of
Canadian $,
unless noted Maturity Interest
otherwise) Issue date date Amount rate
----------------------------------------------------------------------------
TRANSCANADA August 2016 Junior August 2076 US $ 1,200 6.125%(2)
PIPELINES Subordinated
LIMITED Unsecured
Notes(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Junior subordinated unsecured notes are subordinated in right of
payment to existing and future senior indebtedness or other obligations
of TCPL and are callable at TCPL's option at any time on or after August
15, 2026 at 100 per cent of the principal amount plus accrued and unpaid
interest to the date of redemption.
(2) The Junior subordinated notes were issued to TransCanada Trust. The
interest rate is fixed at 6.125 per cent per annum and will reset
starting August 2026 until August 2046 to the three month LIBOR plus
4.89 per cent per annum; from August 2046 to August 2076 the interest
rate will reset to the three month LIBOR plus 5.64 per cent per annum.
On August 16, 2016, TransCanada Trust (the Trust), a 100 per cent owned financing trust subsidiary of TCPL, issued US$1.2 billion of Trust Notes - Series 2016-A (Trust Notes) to third party investors with a fixed interest rate of 5.875 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 through the subscription for US$1.2 billion of junior subordinated notes of TCPL at a rate of 6.125 per cent which includes a 0.25 per cent administration charge. 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 receivables from TCPL.
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.
9. Common units of TC PipeLines, LP subject to rescission
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 TC PipeLines, LP 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. 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.
At September 30, 2016, $106 million (US$82 million) was recorded as Common Units of TC PipeLines, LP Subject to Rescission on the Condensed consolidated balance sheet. The Company classified these 1.6 million common units outside Equity because the potential rescission rights of the units are not within the control of the Company.
10. Equity and share capital
COMMON SHARES
In January 2016, the Company repurchased and cancelled 305,407 of its common shares at an average price of $44.90 for a total of $14 million (weighted average cost of $6 million). The difference of $8 million between the total price paid and the weighted average cost was recorded in Additional paid-in capital.
On April 1, 2016, the Company issued 96.6 million subscription receipts to partially fund the Columbia acquisition at a price of $45.75 each for total proceeds of approximately $4.4 billion. Holders of subscription receipts received one common share in exchange for each subscription receipt upon closing of the Columbia acquisition. On April 29, 2016, holders of record at close of business on April 15, 2016 received a cash payment per subscription receipt that was equal to dividends declared on each common share. A second dividend equivalent payment was made on July 29, 2016 to holders of record at the close of business on June 30, 2016. For the nine months ended September 30, 2016, $109 million of dividend equivalent payments was recorded as interest expense.
DIVIDEND REINVESTMENT PLAN
Under the Company's Dividend Reinvestment Plan (DRP), eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent.
PREFERRED SHARES
On February 1, 2016, holders of 1.3 million Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.54 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 5 preferred shares was reset for five years at 2.263 per cent per annum. Such rate will reset every five years.
On April 20, 2016, the Company completed a public offering of 20 million Series 13 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $500 million. The Series 13 preferred shareholders will have the right to convert their Series 13 preferred shares into Series 14 cumulative redeemable first preferred shares on May 31, 2021 and on the last business day of May of every fifth year thereafter. The holders of Series 14 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the sum of the applicable 90-day Government of Canada treasury bill rate plus 4.69 per cent. The fixed dividend rate on the Series 13 preferred shares was set for five years at 5.5 per cent per annum. The dividend rate will reset every five years at a rate equal to the sum of the applicable five-year Government of Canada bond yield plus 4.69 per cent but not less than 5.5 per cent per annum.
PREFERRED SHARE ISSUANCE AND CONVERSIONS
The following table summarizes the impact of the 2016 issuance and conversions of preferred shares discussed above:
----------------------------------------------------------------------------
Number of Redemption
shares Annual and
issued and dividend Redemption conversion Right to
outstanding Current per price per option convert
(unaudited)(thousands) yield share(1) share(2) date (2,3) into(3)
----------------------------------------------------------------------------
Cumulative
first
preferred
shares
Series 5 12,714 2.263 % $0.56575 $25.00 January Series 6
30, 2021
Series 6 1,286 Floating(4) Floating $25.00 January Series 5
30, 2021
Series 13 20,000 5.5 % $1.375 $25.00 May 31, Series 14
2021
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Holders of the cumulative redeemable first preferred shares set out in
this table are entitled to receive a fixed cumulative quarterly
preferred dividend, as and when declared by the Board, with the
exception of Series 6 preferred shares. The holders of Series 6
preferred shares are entitled to receive a quarterly floating rate
cumulative preferred dividend as and when declared by the Board.
(2) TransCanada may, at its option, redeem all or a portion of the
outstanding shares for the redemption price per share, plus all accrued
and unpaid dividends on the applicable redemption option date and on
every fifth anniversary date thereafter. In addition, Series 6 preferred
shares are redeemable by TransCanada at any time other than on a
designated redemption option date for $25.50 per share plus all accrued
and unpaid dividends on such redemption date.
(3) The holder will have the right, subject to certain conditions, to
convert their first preferred shares of a specified series into first
preferred shares of another specified series on the conversion option
date and every fifth anniversary thereafter.
(4) Commencing September 30, 2016 the floating quarterly dividend rate for
the Series 6 preferred shares is 2.073 per cent and will reset every
quarter going forward.
11. Other comprehensive income/(loss) and accumulated other comprehensive loss
Components of other comprehensive income/(loss), including the portion attributable to non-controlling interests and related tax effects, are as follows:
---------------------------------------------------------------------------- three months ended September 30, 2016 Income tax (unaudited - millions of Before tax recovery/ Net of tax Canadian $) amount (expense) amount ---------------------------------------------------------------------------- Foreign currency translation gains on net investment in foreign operations 55 - 55 Change in fair value of net investment hedges (2) 1 (1) Change in fair value of cash flow hedges 6 (1) 5 Reclassification to net income of gains on cash flow hedges 1 (1) - Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 6 (2) 4 Other comprehensive income on equity investments 5 (1) 4 ---------------------------------------------------------------------------- Other comprehensive income 71 (4) 67 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- three months ended September 30, 2015 Income tax (unaudited - millions of Before tax recovery/ Net of tax Canadian $) amount (expense) amount ---------------------------------------------------------------------------- Foreign currency translation gains on net investment in foreign operations 350 6 356 Change in fair value of net investment hedges (207) 54 (153) Change in fair value of cash flow hedges (49) 20 (29) Reclassification to net income of gains on cash flow hedges 80 (30) 50 Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 10 (3) 7 Other comprehensive income on equity investments 4 (1) 3 ---------------------------------------------------------------------------- Other comprehensive income 188 46 234 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- nine months ended September 30, 2016 Income tax (unaudited - millions of Before tax recovery/ Net of tax Canadian $) amount (expense) amount ---------------------------------------------------------------------------- Foreign currency translation losses on net investment in foreign operations (150) (2) (152) Change in fair value of net investment hedges (12) 3 (9) Change in fair value of cash flow hedges 33 (12) 21 Reclassification to net income of gains on cash flow hedges 65 (25) 40 Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 17 (5) 12 Other comprehensive income on equity investments 14 (3) 11 ---------------------------------------------------------------------------- Other comprehensive loss (33) (44) (77) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- nine months ended September 30, 2015 Income tax (unaudited - millions of Before tax recovery/ Net of tax Canadian $) amount (expense) amount ---------------------------------------------------------------------------- Foreign currency translation gains on net investment in foreign operations 675 13 688 Change in fair value of net investment hedges (490) 129 (361) Change in fair value of cash flow hedges (78) 28 (50) Reclassification to net income of gains on cash flow hedges 136 (53) 83 Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans 30 (6) 24 Other comprehensive income on equity investments 13 (3) 10 ---------------------------------------------------------------------------- Other comprehensive income 286 108 394 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
The changes in AOCI by component are as follows:
----------------------------------------------------------------------------
three months ended
September 30, 2016 Currency Cash Pension and
(unaudited - millions translation flow OPEB plan Equity
of Canadian $) adjustments hedges adjustments investments Total(1)
----------------------------------------------------------------------------
AOCI balance at July
1, 2016 (497) (38) (190) (254) (979)
Other comprehensive
income before
reclassifications(2) 33 2 - - 35
Amounts reclassified
from accumulated
other comprehensive
loss - - 4 4 8
----------------------------------------------------------------------------
Net current period
other comprehensive
income 33 2 4 4 43
----------------------------------------------------------------------------
AOCI balance at
September 30, 2016 (464) (36) (186) (250) (936)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) All amounts are net of tax. Amounts in parentheses indicate losses
recorded to OCI.
(2) Other comprehensive income before reclassifications on currency
translation adjustments and cash flow hedges is net of non-controlling
interest gains of $21 million and $3 million, respectively.
----------------------------------------------------------------------------
nine months ended
September 30, 2016 Currency Cash Pension and
(unaudited - millions translation flow OPEB plan Equity
of Canadian $) adjustments hedges adjustments investments Total(1)
----------------------------------------------------------------------------
AOCI balance at
January 1, 2016 (383) (97) (198) (261) (939)
Other comprehensive
(loss)/income before
reclassifications(2) (81) 21 - - (60)
Amounts reclassified
from accumulated
other comprehensive
loss - 40 12 11 63
----------------------------------------------------------------------------
Net current period
other comprehensive
(loss)/income(3) (81) 61 12 11 3
----------------------------------------------------------------------------
AOCI balance at
September 30, 2016 (464) (36) (186) (250) (936)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 is net of non-controlling interest losses of $80
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 $23
million ($14 million, net of tax) at September 30, 2016. 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
accumulated other comprehensive
loss(1)
---------------------------------
three months nine months
ended ended
September 30 September 30
--------------------------------------------------------
Affected line item
in the condensed
(unaudited - millions consolidated
of Canadian $) 2016 2015 2016 2015 statement of income
----------------------------------------------------------------------------
Cash flow hedges
Commodities 7 (76) (54) (124) Revenue (Energy)
Foreign exchange (5) - Interest income and
- - other
Interest (3) (4) (11) (12) Interest expense
----------------------------------------------------------------------------
(1) (80) (65) (136) Total before tax
1 30 25 53 Income tax expense
----------------------------------------------------------------------------
- (50) (40) (83) Net of tax
----------------------------------------------------------------------------
Pension and other post-
retirement benefit
plan adjustments
Amortization of (6) (10) (17) (30) (2)
actuarial loss
2 3 5 6 Income tax expense
----------------------------------------------------------------------------
(4) (7) (12) (24) Net of tax
----------------------------------------------------------------------------
Equity investments
Equity income (5) (4) (14) (13) Income from equity
investments
1 1 3 3 Income tax expense
----------------------------------------------------------------------------
(4) (3) (11) (10) 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 12 for additional
detail.
12. Employee post-retirement benefits
The net benefit cost recognized for the Company's defined benefit pension plans and other post-retirement benefit plans is as follows:
----------------------------------------------------------------------------
three months ended September nine months ended September
30 30
--------------------------------------------------------
Other post- Other post-
Pension retirement Pension retirement
benefit plans benefit plans benefit plans benefit plans
--------------------------------------------------------
(unaudited -
millions of
Canadian $) 2016 2015 2016 2015 2016 2015 2016 2015
----------------------------------------------------------------------------
Service cost 28 27 1 1 79 81 2 2
Interest cost 34 29 4 2 93 86 9 7
Expected return on
plan assets (48) (39) (5) (1) (127) (116) (6) (2)
Amortization of
actuarial loss 5 9 1 1 15 26 2 3
Amortization of past
service cost - - - - - 1 - -
Amortization of
regulatory asset 8 6 - - 17 18 - -
Amortization of
transitional
obligation related
to regulated
business - - - 1 - - 1 2
----------------------------------------------------------------------------
Net benefit cost
recognized 27 32 1 4 77 96 8 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
13. 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 September 30, 2016, 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 September 30, 2016, there were no significant amounts past due or impaired, and there were no significant credit losses during the period.
The Company had a credit risk concentration due from a counterparty of $191 million (US$146 million) at September 30, 2016 (December 31, 2015 - $248 million (US$179 million)). This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.
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.
U.S. dollar-denominated debt designated as a net investment hedge
---------------------------------------------------------------------------- (unaudited - millions of Canadian $, unless noted otherwise) September 30, 2016 December 31, 2015 ---------------------------------------------------------------------------- Notional amount 30,200 (US 23,000) 23,100 (US 16,700) Fair value 33,700 (US 25,700) 23,800 (US 17,200) ----------------------------------------------------------------------------
Derivatives designated as a net investment hedge
----------------------------------------------------------------------------
September 30,
2016 December 31, 2015
---------------------------------------
Notional Notional
or or
(unaudited - millions of Canadian $, Fair principal Fair principal
unless noted otherwise) value(1) amount value(1) amount
----------------------------------------------------------------------------
Asset/(liability)
U.S. dollar cross-currency interest
rate swaps (maturing 2016 to
2019)(2) (433) US 2,400 (730) US 3,150
U.S. dollar foreign exchange forward
contracts (maturing 2016 to 2017) (16) US 200 50 US 1,800
----------------------------------------------------------------------------
(449) US 2,600 (680) US 4,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fair values equal carrying values.
(2) In the three and nine months ended September 30, 2016, net realized
gains of $1 million and $5 million, respectively, (2015 - gains of $2
million and $7 million, respectively) 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:
----------------------------------------------------------------------------
September 30, 2016 December 31, 2015
----------------------------------------
Carrying Fair Carrying Fair
(unaudited - millions of Canadian $) amount value amount value
----------------------------------------------------------------------------
Notes receivable(1) 158 209 214 265
Current and long-term debt(2,3) (44,063) (46,378) (31,456) (34,309)
Junior subordinated notes (3,842) (3,708) (2,409) (2,011)
----------------------------------------------------------------------------
(47,747) (49,877) (33,651) (36,055)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notes receivable are included in other current assets and intangible and
other assets on the condensed consolidated balance sheet.
(2) Long-term debt is recorded at amortized cost except for US$800 million
(December 31, 2015 - US$850 million) that is attributed to hedged risk
and recorded at fair value.
(3) Consolidated net income for the three and nine months ended September
30, 2016 included unrealized gains of $7 million and losses of $6
million, respectively, (2015 - losses of $9 million and $9 million,
respectively) for fair value adjustments attributable to the hedged
interest rate risk associated with interest rate swap fair value hedging
relationships on US$800 million of long-term debt at September 30, 2016
(December 31, 2015 - 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:
----------------------------------------------------------------------------
September 30, 2016 December 31, 2015
-------------------------- --------------------------
(unaudited - millions LMCI Other LMCI Other
of Canadian $) restricted restricted restricted restricted
investments investments(2) investments investments(2)
----------------------------------------------------------------------------
Fair Values(1)
Fixed income
securities (maturing
within 5 years) - 137 - 90
Fixed income
securities (maturing
in 5-10 years) 11 - - -
Fixed income
securities (maturing
after 10 years) 480 - 261 -
----------------------------------------------------------------------------
491 137 261 90
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
----------------------------------------------------------------------------
September 30, 2016 September 30, 2015
----------------------- -----------------------
LMCI Other LMCI Other
restricted restricted restricted restricted
(unaudited - millions of investments investments investments investments
Canadian $) (1) (2) (1) (2)
----------------------------------------------------------------------------
Net unrealized gains/(losses)
in the period
three months ended 3 - 1 -
nine months ended 25 1 (2) -
Net realized gains in the
period
three months ended - - - -
nine months ended 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 September 30, 2016 is as follows:
----------------------------------------------------------------------------
Total Fair
Value of
at September 30, 2016 Fair Net Derivative
(unaudited - millions Cash Flow Value Investment Held for Instruments
of Canadian $) Hedges Hedges Hedges Trading (1)
----------------------------------------------------------------------------
Other current assets
Commodities(2) 15 - - 298 313
Foreign exchange - - 5 10 15
Interest rate - 3 - 1 4
----------------------------------------------------------------------------
15 3 5 309 332
Intangible and other
assets
Commodities(2) 5 - - 165 170
Foreign exchange - - 6 - 6
Interest rate - 4 - 1 5
----------------------------------------------------------------------------
5 4 6 166 181
----------------------------------------------------------------------------
Total Derivative Assets 20 7 11 475 513
----------------------------------------------------------------------------
Accounts payable and
other
Commodities(2) (32) - - (336) (368)
Foreign exchange - - (231) (15) (246)
Interest rate (2) - - - (2)
----------------------------------------------------------------------------
(34) - (231) (351) (616)
Other long-term
liabilities
Commodities(2) - - - (198) (198)
Foreign exchange - - (229) - (229)
Interest rate (1) - - - (1)
----------------------------------------------------------------------------
(1) - (229) (198) (428)
----------------------------------------------------------------------------
Total Derivative
Liabilities (35) - (460) (549) (1,044)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2015 is as follows:
----------------------------------------------------------------------------
Total Fair
Value of
at December 31, 2015 Fair Net Derivative
(unaudited - millions Cash Flow Value Investment Held for Instruments
of Canadian $) Hedges Hedges Hedges Trading (1)
----------------------------------------------------------------------------
Other current assets
Commodities(2) 46 - - 326 372
Foreign exchange - - 65 2 67
Interest rate - 1 - 2 3
----------------------------------------------------------------------------
46 1 65 330 442
Intangible and other
assets
Commodities(2) 11 - - 126 137
Foreign exchange - - 29 - 29
Interest rate - 2 - - 2
----------------------------------------------------------------------------
11 2 29 126 168
----------------------------------------------------------------------------
Total Derivative Assets 57 3 94 456 610
----------------------------------------------------------------------------
Accounts payable and
other
Commodities(2) (112) - - (443) (555)
Foreign exchange - - (313) (54) (367)
Interest rate (1) (1) - (2) (4)
----------------------------------------------------------------------------
(113) (1) (313) (499) (926)
Other long-term
liabilities
Commodities(2) (31) - - (131) (162)
Foreign exchange - - (461) - (461)
Interest rate (1) (1) - - (2)
----------------------------------------------------------------------------
(32) (1) (461) (131) (625)
----------------------------------------------------------------------------
Total Derivative
Liabilities (145) (2) (774) (630) (1,551)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fair value equals carrying value.
(2) Includes purchases and sales of power and natural gas.
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 following tables present the maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations:
----------------------------------------------------------------------------
Natural Foreign
at September 30, 2016 Power Gas Liquids Exchange Interest
----------------------------------------------------------------------------
Purchases(1) 87,257 187 6 - -
Sales(1) 62,109 145 6 - -
Millions of dollars - - - US 2,098 US 1,500
Maturity dates 2016-2020 2016-2020 2016 2016-2017 2016-2019
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Volumes for power, natural gas and liquids derivatives are in GWh, Bcf
and MMBbls, respectively.
----------------------------------------------------------------------------
Natural Foreign
at December 31, 2015 Power Gas Exchange Interest
----------------------------------------------------------------------------
Purchases(1) 70,331 133 - -
Sales(1 ) 54,382 70 - -
Millions of dollars - - US 1,476 US 1,100
Maturity dates 2016-2020 2016-2020 2016 2016-2019
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Volumes for power and natural gas derivatives are in GWh and Bcf,
respectively.
Unrealized and Realized Gains/(Losses) of Derivative Instruments
The following summary does not include hedges of the net investment in foreign operations.
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of Canadian
$) 2016 2015 2016 2015
----------------------------------------------------------------------------
Derivative instruments held for
trading(1)
Amount of unrealized (losses)/gains
in the period
Commodities(2) (97) (27) 23 (30)
Foreign exchange - (26) 47 (25)
Amount of realized (losses)/gains
in the period
Commodities (23) (52) (165) (84)
Foreign exchange (5) (34) 52 (87)
Derivative instruments in hedging
relationships
Amount of realized (losses)/gains
in the period
Commodities (15) (35) (155) (132)
Foreign exchange 5 - (101) -
Interest rate 1 2 4 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 (2015 - nil) 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 11) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows:
----------------------------------------------------------------------------
three months ended nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of Canadian
$, pre-tax) 2016 2015 2016 2015
----------------------------------------------------------------------------
Change in fair value of derivative
instruments recognized in OCI
(effective portion)(1)
Commodities 7 (48) 33 (77)
Foreign exchange (5) - - -
Interest rate 4 (1) - (1)
----------------------------------------------------------------------------
6 (49) 33 (78)
----------------------------------------------------------------------------
Reclassification of (losses)/gains
on derivative instruments from
AOCI to net income (effective
portion)(1)
Commodities(2) (7) 76 54 124
Foreign exchange(3) 5 - - -
Interest rate(4) 3 4 11 12
----------------------------------------------------------------------------
1 80 65 136
----------------------------------------------------------------------------
Gains/(losses) on derivative
instruments recognized in net
income (ineffective portion)
Commodities(2) 14 10 (1) 3
----------------------------------------------------------------------------
14 10 (1) 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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:
----------------------------------------------------------------------------
Gross
derivative
instruments
at September 30, 2016 presented on Amounts
(unaudited - millions of the balance available for
Canadian $) sheet offset(1) Net amounts
----------------------------------------------------------------------------
Derivative - Asset
Commodities 483 (382) 101
Foreign exchange 21 (21) -
Interest rate 9 (1) 8
----------------------------------------------------------------------------
Total 513 (404) 109
----------------------------------------------------------------------------
Derivative - Liability
Commodities (566) 382 (184)
Foreign exchange (475) 21 (454)
Interest rate (3) 1 (2)
----------------------------------------------------------------------------
Total (1,044) 404 (640)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2015:
----------------------------------------------------------------------------
Gross
derivative
instruments
at December 31, 2015 presented on Amounts
(unaudited - millions of the balance available for
Canadian $) sheet offset(1) Net amounts
----------------------------------------------------------------------------
Derivative - Asset
Commodities 509 (418) 91
Foreign exchange 96 (93) 3
Interest rate 5 (1) 4
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Total 610 (512) 98
----------------------------------------------------------------------------
Derivative - Liability
Commodities (717) 418 (299)
Foreign exchange (828) 93 (735)
Interest rate (6) 1 (5)
----------------------------------------------------------------------------
Total (1,551) 512 (1,039)
----------------------------------------------------------------------------
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(1) Amounts available for offset do not include cash collateral pledged or
received.
With respect to the derivative instruments presented above as at September 30, 2016, the Company provided cash collateral of $228 million (December 31, 2015 - $482 million) and letters of credit of $11 million (December 31, 2015 - $41 million) to its counterparties. The Company held nil (December 31, 2015 - nil) in cash collateral and $3 million (December 31, 2015 - $2 million) in letters of credit from counterparties on asset exposures at September 30, 2016.
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 September 30, 2016, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $24 million (December 31, 2015 - $32 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2015 - nil). If the credit-risk-related contingent features in these agreements were triggered on September 30, 2016, the Company would have been required to provide additional collateral of $24 million (December 31, 2015 - $32 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 becomes available, they
are transferred out of Level III and into Level II.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair value of the Company's derivative instrument 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
at September 30, 2016 in active observable unobservable
(unaudited - millions of markets inputs inputs
Canadian $, pre-tax) (Level I)(1) (Level II)(1) (Level III)(1) Total
----------------------------------------------------------------------------
Derivative instrument
assets:
Commodities 66 394 23 483
Foreign exchange - 21 - 21
Interest rate - 9 - 9
Derivative instrument
liabilities:
Commodities (71) (484) (11) (566)
Foreign exchange - (475) - (475)
Interest rate - (3) - (3)
----------------------------------------------------------------------------
(5) (538) 12 (531)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) There were no transfers from Level I to Level II or from Level II to
Level III for the nine months ended September 30, 2016.
The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015, are categorized as follows:
----------------------------------------------------------------------------
Significant
Quoted prices other Significant
at December 31, 2015 in active observable unobservable
(unaudited - millions of markets inputs inputs
Canadian $, pre-tax) (Level I)(1) (Level II)(1) (Level III)(1) Total
----------------------------------------------------------------------------
Derivative instrument
assets:
Commodities 34 462 13 509
Foreign exchange - 96 - 96
Interest rate - 5 - 5
Derivative instrument
liabilities:
Commodities (102) (611) (4) (717)
Foreign exchange - (828) - (828)
Interest rate - (6) - (6)
----------------------------------------------------------------------------
(68) (882) 9 (941)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) There were no transfers from Level I to Level II or from Level II to
Level III for the year ended December 31, 2015.
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 nine months ended
September 30 September 30
-------------------- --------------------
(unaudited - millions of Canadian
$, pre-tax) 2016 2015 2016 2015
----------------------------------------------------------------------------
Balance at beginning of period 12 11 9 4
Total gains/(losses) included in
net income 2 (2) 13 3
Transfers out of Level III (3) - (6) 3
Settlements 1 - (1) -
Sales - (1) (2) (1)
Total gains/(losses) included in
OCI - 1 (1) -
----------------------------------------------------------------------------
Balance at end of period(1) 12 9 12 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For the three and nine months ended September 30, 2016, revenues include
unrealized gains of $1 million and $3 million, respectively, attributed
to derivatives in the Level III category that were still held at
September 30, 2016 (2015 - losses of $2 million and gains of $6 million,
respectively).
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase in the fair value of outstanding derivative instruments included in Level III as at September 30, 2016.
14. Other acquisitions and dispositions
Natural Gas Pipelines
Portland Natural Gas Transmission System
On January 1, 2016, TransCanada completed the sale of a 49.9 per cent interest in Portland Natural Gas Transmission System (PNGTS) to TC PipeLines, LP for an aggregate purchase price of US$223 million. Proceeds were comprised of US$188 million in cash and the assumption of US$35 million in proportional PNGTS debt.
Iroquois Gas Transmission System LP
On March 31, 2016, TransCanada acquired a 4.87 per cent interest in Iroquois for an aggregate purchase price of US$53.8 million, increasing TransCanada's interest in Iroquois to 49.35 per cent. On May 1, 2016, the Company acquired an additional 0.65 per cent interest for an aggregate purchase price of US$7.2 million, further increasing TransCanada's interest in Iroquois to 50 per cent.
TC Offshore LLC
On March 31, 2016, TransCanada completed the sale of TC Offshore LLC to a third party. This resulted in an additional loss on disposal of $4 million pre-tax which is included in loss of sale of assets in the condensed consolidated statement of income.
Energy
Ironwood
On February 1, 2016, TransCanada acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$653 million in cash after post-acquisition adjustments. The Ironwood power plant delivers energy into the PJM power market. The evaluation of assigned fair value of acquired assets and liabilities did not result in the recognition of goodwill. The Company began consolidating Ironwood as of the date of acquisition which has not had a material impact on the consolidated revenues and net income of the Company. In addition, the pro forma incremental impact on the Company's consolidated revenues and net income for each of the periods presented is not material.
15. Commitments and guarantees
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.
COMMITMENTS
TransCanada's commitments at December 31, 2015 included fixed payments, net of sublease receipts for Alberta PPAs. As a result of the March 7, 2016 notice to terminate our Sheerness, Sundance A and Sundance B PPAs, our future obligations from December 31, 2015 have decreased by: 2016 - $195 million, 2017 - $200 million, 2018 - $141 million, 2019 - $138 million and 2020 - $115 million. Our commitments for 2021 and beyond increased by approximately $0.5 billion as a result of the extension of premise leases in second quarter 2016. The acquisition of Columbia on July 1, 2016 resulted in a total increase to our obligations of $349 million for transportation contracts and premise leases.
GUARANTEES
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's exposure under certain of these guarantees is unlimited.
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 including purchase agreements 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 September 30, at December 31,
2016 2015
------------------- -------------------
(unaudited - Potential Potential
millions of exposure Carrying exposure Carrying
Canadian $) Term (1) value (1) value
----------------------------------------------------------------------------
Bruce Power ranging to 2018(2) 88 1 88 2
Sur de Texas-
Tuxpan ranging to 2040 693 46 - -
Other jointly
owned entities ranging to 2040 135 31 139 24
----------------------------------------------------------------------------
916 78 227 26
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) TransCanada's share of the potential estimated current or contingent
exposure.
(2) Except for one guarantee with no termination date.
16. Variable interest entities
As a result of the implementation of the new FASB guidance on consolidation, a number of entities controlled by TransCanada are now considered to be variable interest entities (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:
----------------------------------------------------------------------------
September 30, December 31,
(unaudited - millions of Canadian $) 2016 2015
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 97 54
Accounts receivable 55 55
Inventories 23 25
Other 6 6
----------------------------------------------------------------------------
181 140
Plant, Property and Equipment 3,624 3,704
Equity Investments 592 664
Goodwill 513 541
----------------------------------------------------------------------------
4,910 5,049
----------------------------------------------------------------------------
LIABILITIES
Current Liabilities
Accounts payable and other 60 74
Accrued interest 22 21
Current portion of long-term debt 75 45
----------------------------------------------------------------------------
157 140
Regulatory Liabilities 33 33
Other Long-Term Liabilities 5 4
Deferred Income Tax Liabilities 7 -
Long-Term Debt 2,858 2,998
----------------------------------------------------------------------------
3,060 3,175
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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:
----------------------------------------------------------------------------
September 30, December 31,
(unaudited - millions of Canadian $) 2016 2015
----------------------------------------------------------------------------
Balance sheet
Equity investments 5,043 5,410
Off-balance sheet
Potential exposure to guarantees 222 227
----------------------------------------------------------------------------
Maximum exposure to loss 5,265 5,637
----------------------------------------------------------------------------
----------------------------------------------------------------------------
17. Subsequent events
Assets held for sale
The Company's planned monetization of the U.S. Northeast Power business, for the purposes of permanently financing 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, subsequent to the balance sheet date the Company entered into agreements to sell all of these assets except the marketing business, the value from which is still expected to be realized going forward.
The sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party is expected to close in the first half of 2017. As a result, effective November 1, 2016, the related assets and liabilities are classified as held for sale in the Energy segment and will be recorded at their fair values less costs to sell. This is expected to result in a loss on assets held for sale of approximately $899 million in fourth quarter 2016 or $863 million after-tax which includes the reclassification of an estimated $61 million of foreign currency translation gains from AOCI to net income.
The sale of TC Hydro to another third party is also expected to close in the first half of 2017 resulting in an estimated gain of $719 million or $443 million after-tax which includes the reclassification of an estimated $4 million of foreign currency translation gains from AOCI to net income. This gain will be recognized upon closing of the sale transaction. Effective November 1, 2016, the related assets and liabilities are classified as held for sale in the Energy segment.
As of November 1, 2016, TCPM does not meet the criteria to be classified as held for sale.
The following table details the assets and liabilities as at September 30, 2016 related to the U.S. Northeast Power business that are classified as held for sale effective November 1, 2016. The expected loss on assets held for sale of approximately $899 million (US$686 million) is not reflected in the table below.
(unaudited - millions of $) U.S. Canadian(1) ---------------------------------------------------------------------------- Assets held for sale Accounts receivable 20 26 Inventories 57 75 Other current assets 107 140 Plant, property and equipment 2,862 3,754 Intangible and other assets 324 425 ---------------------------------------------------------------------------- Total assets held for sale 3,370 4,420 ---------------------------------------------------------------------------- Liabilities related to assets held for sale Accounts payable and other 27 35 Other long-term liabilities 31 41 ---------------------------------------------------------------------------- Total liabilities related to assets held for sale 58 76 ---------------------------------------------------------------------------- (1) At September 30, 2016 exchange rate of $1.31
Columbia Pipeline Partners LP
On November 1, 2016, TransCanada announced that it had entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia, has agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions. At September 30, 2016, the common units are recorded as non-controlling interests in these condensed consolidated financial statements. As a result, there will be no gain or loss recorded on closing this transaction.
Common equity offering
On November 1, 2016, concurrent with the release of these financial results, the Company announced it has entered into an agreement with a group of underwriters to proceed with an offering of common shares. The closing for the offering is expected to be on November 16, 2016.
Contacts: TransCanada Media Enquiries: Mark Cooper/Terry Cunha 403.920.7859 or 800.608.7859 TransCanada Investor & Analyst Enquiries: David Moneta/Stuart Kampel 403.920.7911 or 800.361.6522
Source: TRANSCANADA
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