Transformational Changes Position Company for Near- and Long-Term Growth
CALGARY, ALBERTA–(Marketwired – April 29, 2016) – TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada) today announced net income attributable to common shares for first quarter 2016 of $252 million or $0.36 per share compared to $387 million or $0.55 per share for the same period in 2015. Comparable earnings for first quarter 2016 were $494 million or $0.70 per share compared to $465 million or $0.66 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 June 30, 2016, equivalent to $2.26 per common share on an annualized basis.
“During the first quarter of 2016, our diverse portfolio of high-quality long-life assets generated steady results in what continues to be a challenging environment,” said Russ Girling, TransCanada’s president and chief executive officer. “Comparable earnings increased by six per cent while funds generated from operations of $1.1 billion were consistent with the same period last year.”
On March 17, 2016, TransCanada announced an agreement to acquire Columbia Pipeline Group, Inc. ((NYSE:CPGX) or Columbia) for US$13 billion including approximately US$2.8 billion of assumed debt. Columbia operates an approximate 24,000-kilometre (km) (15,000-mile) network of interstate natural gas pipelines extending from New York to the Gulf of Mexico, with a significant presence in the Appalachia production basin. The assets complement our existing North American footprint which together will create an approximate 91,000 km or 57,000 mile natural gas pipeline system connecting North America’s fastest growing supply basins to premium markets across the continent. On April 1, 2016, TransCanada completed the issuance of $4.4 billion of subscription receipts to finance a portion of the acquisition, representing the largest equity financing in Canadian history. The conversion of subscription receipts to common shares is subject to closing of the Columbia acquisition which, in turn, is subject to Columbia shareholder approval and certain regulatory approvals.
“The acquisition represents a rare opportunity to invest in an extensive, competitively-positioned, growing network of regulated natural gas pipeline and storage assets in the Marcellus and Utica shale gas regions,” added Girling. “The addition of Columbia to our resilient base business is a transformational change and creates an industry-leading portfolio of near-term growth projects that further supports and may augment our expected eight to ten per cent annual dividend growth through 2020.”
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
First quarter financial results
Net income attributable to common shares of $252 million or $0.36 per share
Comparable earnings of $494 million or $0.70 per share
Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.5 billion
Funds generated from operations of $1.1 billion
Comparable distributable cash flow of $1.0 billion or $1.38 per common share
Declared a quarterly dividend of $0.565 per common share for the quarter ending June 30, 2016. Subscription receipts to receive dividend equivalent payment.
Announced an agreement and plan of merger to acquire Columbia Pipeline Group, Inc. for US$13 billion including the assumption of approximately US$2.8 billion in debt
Completed the sale of $4.4 billion of subscription receipts which will be used to finance a portion of the Columbia acquisition
Announced our intention to monetize the U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business
Awarded a contract to construct the US$550 million Tula-Villa de Reyes Pipeline in Mexico
Terminated our Alberta Power Purchase Arrangements (PPAs)
Net income attributable to common shares decreased by $135 million to $252 million or $0.36 per share for the three months ended March 31, 2016 compared to the same period last year. First quarter 2016 included a net after-tax charge of $211 million for specific items including $176 million after tax relating to the remaining net book value associated with our investment in the Alberta PPAs as a result of our termination decision, $26 million relating to costs associated with the announced Columbia acquisition, $6 million after tax of Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project and an additional $3 million after-tax loss on the sale of TC Offshore. Both periods included unrealized gains and losses from changes in risk management activities. All of these specific items are excluded from comparable earnings.
Comparable earnings for first quarter 2016 were $494 million or $0.70 per share compared to $465 million or $0.66 per share for the same period in 2015. A higher contribution from Bruce Power and net corporate financial results was partially offset by lower earnings from the Keystone System, Eastern Power, U.S. Power and Western Power.
Notable recent developments in Corporate, Natural Gas Pipelines, Liquids Pipelines and Energy include:
Corporate:
Acquisition of Columbia Pipeline Group: On March 17, 2016, we entered into an agreement and plan of merger to acquire Columbia Pipeline Group, Inc. (Columbia). Columbia owns one of the largest interstate natural gas pipeline systems in the U.S., providing transportation, storage and related services to a variety of customers in the northeast, mid-west, mid-Atlantic and Gulf Coast regions. Its assets include Columbia Gas Transmission, which operates approximately 18,000 km (11,300 miles) of pipelines and 286 billion cubic feet of working gas storage capacity in the Marcellus and Utica shale production areas, and Columbia Gulf Transmission, an approximate 5,400 km (3,300 mile) pipeline system that extends from Appalachia to the Gulf Coast.Columbia shareholders will receive US$25.50 per share which represents an aggregate transaction value of approximately US$13 billion including the assumption of approximately US$2.8 billion of debt. We expect to finance the US$10.2 billion cash component of the acquisition through an offering of subscription receipts, which closed on April 1, 2016 for gross proceeds of approximately $4.4 billion, the planned monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business, and existing cash on hand. A syndicate of lenders have committed to provide debt bridge facilities in the amount of US$6.9 billion which will be utilized pending the realization of proceeds from the planned monetization of assets outlined. We expect the acquisition, net of financing and the planned asset monetization, to be accretive to earnings per share in the first full year of ownership. We are targeting US$250 million of annual cost, revenue and financing benefits.We and Columbia each filed a Hart-Scott-Rodino Notification with the U.S. Federal Trade Commission on April 4, 2016. We also both submitted a filing with the Committee on Foreign Investment in the United States (CFIUS) which was accepted on April 13, 2016. The special meeting for Columbia stockholders to approve the transaction is scheduled for June 22, 2016.We expect the acquisition to close in second half 2016 subject to the shareholder and regulatory approvals.
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 approximately $4.4 billion. Each subscription receipt will entitle the holder to automatically receive one common share upon closing of the Columbia acquisition. While the subscription receipts remain outstanding, holders will be entitled to receive cash payments per subscription receipt equivalent to dividends paid on each common share.
Preferred Share Issuance: On April 20, 2016, we completed a public offering of 20 million Series 13 cumulative redeemable, minimum rate reset, first preferred shares at $25 per share resulting in gross proceeds of $500 million. 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, provided that such rate shall be not less than 5.5 per cent per annum.
Natural Gas Pipelines:
ANR Section 4 Rate Case: On January 29, 2016, ANR filed a Section 4 Rate Case with the FERC that requests an increase to ANR’s maximum transportation rates. On February 29, 2016, the FERC issued an order that accepted and suspended ANR’s rate and tariff changes to become effective August 1, 2016, subject to refund and the outcome of a hearing. In addition, on March 23, 2016, the FERC established a procedural schedule for the hearing and appointed a settlement judge to assist the parties in their settlement negotiations. The hearing is currently scheduled for early February 2017 and settlement conferences will be held throughout the process.
NGTL System: In first quarter of 2016, we placed approximately $100 million of facilities in service with another $600 million currently under construction. The NGTL System continues to develop approximately $7.3 billion of new supply and demand facilities of which approximately $2.5 billion have received regulatory approval, a further approximately $1.9 billion are currently under regulatory review and applications for approval to construct and operate an additional $2.9 billion of facilities have yet to be filed.
North Montney Mainline: On March 28, 2016, we filed a request with the NEB for a one year extension of the Certificate of Public Convenience and Necessity (CPCN) for the North Montney Mainline (NMML) project. The requested extension ensures our regulatory approvals remain valid and do not expire pending a Final Investment Decision (FID) on the proposed Pacific Northwest LNG project.
2016-2017 NGTL Revenue Requirement Settlement: On April 7, 2016, the NEB approved, subject to certain reporting requirements, the NGTL revenue requirement settlement application that was filed in December 2015. The settlement includes a return on equity of 10.1 per cent on 40 per cent deemed equity plus certain incentive mechanisms.
Iroquois Gas Transmission System: On March 31, 2016, we closed the acquisition of an additional 4.87 per cent interest in Iroquois Gas Transmission System, L.P. (Iroquois) for US$54 million bringing our interest in Iroquois to 49.35 per cent. We also expect to acquire an additional 0.65 per cent in second quarter 2016 that will increase our overall interest to 50 per cent.
Tula-Villa de Reyes Pipeline: On April 11, 2016, we announced we were awarded a contract to build, own and operate the Tula-Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 million cubic feet per day with the Comisión Federal de Electricidad (CFE). We expect to invest approximately US$550 million on a 36-inch diameter, 420-km (261-mile) pipeline with an anticipated in-service in early 2018. The pipeline will extend from our Tamazunchale and Tuxpan-Tula pipelines to a terminus near Villa de Reyes, San Luis Potosí, transporting natural gas to power generation facilities.
Prince Rupert Gas Transmission: We are continuing engagement with Aboriginal groups and have now announced project agreements with eleven First Nation groups along the pipeline route which outline financial and other benefits and commitments that will be provided to each First Nation group for as long as the project is in service.
Coastal GasLink: The LNG Canada joint venture participants anticipate reaching a final investment decision on their Kitimat-based LNG project in late 2016. Based on the current schedule, preliminary construction work could begin in January 2017.
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. Permanent repairs and remaining restoration work at site is planned for May 2016, with further investigative activities and corrective measures required by PHMSA planned in 2016.
Energy East Pipeline: On March 1, 2016, the Province of Québec filed a court action seeking an injunction to compel the Energy East Pipeline to comply with the province’s environmental regulations. On April 22, 2016, we filed a project review engaging an environmental assessment under the Environmental Quality Act (Québec). This process is in addition to an environmental assessment required under the National Energy Board Act and the Canadian Environmental Assessment Act, 2012. The Attorney General for Québec has agreed to suspend its litigation against TransCanada and Energy East and to withdraw it once the provincial environmental assessment process has been completed. We do not anticipate this will result in a delay with regard to the National Energy Board’s review process.On March 17, 2016, the first phase of Energy East public hearings for the voluntary Québec BAPE process was completed. The voluntary BAPE hearing process is intended to inform the Province of Québec in its participation in the federal process and provides project information to the public. A second phase, consisting of a series of public input sessions, has been suspended as it has been replaced with the environmental assessment.
Energy:
Alberta Power Purchase Arrangements: On March 7, 2016, we issued notice to the Balancing Pool terminating our Alberta PPAs. The agreements contain a provision that permits the PPA buyers to terminate the PPAs if there is a change in law that makes the agreements unprofitable or more unprofitable. This termination affects the Sheerness, Sundance A and Sundance B PPAs. We expect the termination will improve cash flow and comparable earnings in the near term.As a result of the termination, we have recorded a non-cash impairment charge of $240 million before-tax ($176 million after-tax) which represents the remaining net book value of our investment in the PPAs.
Teleconference and Webcast:
We will hold a teleconference and webcast on Friday, April 29, 2016 to discuss our first quarter 2016 financial results. Russ Girling, TransCanada President and Chief Executive Officer, and Don Marchand, Executive Vice-President, Corporate Development and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 1 p.m. (MDT) / 3 p.m. (EDT).
Members of the investment community and other interested parties are invited to participate by calling 866.223.7781 or 416.340.2216 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available atwww.transcanada.com.
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) on May 6, 2016. Please call800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 1793973.
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 atwww.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 67,000 kilometres (42,000 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent’s largest providers of gas storage and related services with 368 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 11,400 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America’s largest liquids delivery systems. 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, orconnect 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 April 28, 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, 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 April 28, 2016.
Quarterly report to shareholders
First quarter 2016
Financial highlights
three months ended March 31
(unaudited – millions of $, except per share amounts)
2016
2015
Income
Revenues
2,547
2,874
Net income attributable to common shares
252
387
per common share – basic and diluted
$0.36
$0.55
Comparable EBITDA1
1,502
1,531
Comparable earnings1
494
465
per common share1
$0.70
$0.66
Operating cash flow
Funds generated from operations1
1,125
1,153
Increase in operating working capital
(80
)
(393
)
Net cash provided by operations
1,045
760
Comparable distributable cash flow1
970
956
per common share1
$1.38
$1.35
Investing activities
Capital spending – capital expenditures
836
806
Capital spending – projects in development
67
163
Contributions to equity investments
170
93
Acquisitions, net of cash acquired
995
–
Proceeds from sale of assets, net of transaction costs
6
–
Dividends declared
Per common share
$0.565
$0.52
Basic common shares outstanding (millions)
Average for the period
702
709
End of period
702
709
(1)
Comparable EBITDA, comparable earnings, comparable earnings per common share, 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
April 28, 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 months ended March 31, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months ended March 31, 2016 which have been prepared in accordance with U.S. GAAP.
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 April 28, 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 likeanticipate, 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:
anticipated business prospects, including the expected closing and financing of the Columbia Pipeline Group, Inc. (Columbia) acquisition
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
timing and completion of the Columbia acquisition including receipt of regulatory and Columbia stockholder approval
planned monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline 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
length of time to complete the acquisition of Columbia
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
distributable cash flow
distributable cash flow per common share
comparable earnings
comparable earnings per common share
comparable EBITDA
comparable EBIT
comparable distributable cash flow
comparable distributable cash flow per common share
comparable income from equity investments
comparable interest expense
comparable interest income and other expense
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.
Distributable cash flow
Distributable cash flow is defined as funds generated from operations plus distributions received in excess of equity earnings 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 includes amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. We believe it 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.
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 in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Comparable measure
Original measure
comparable earnings
net income attributable to common shares
comparable earnings per common share
net income per common share
comparable EBITDA
EBITDA
comparable EBIT
segmented earnings
comparable distributable cash flow
distributable cash flow
comparable distributable cash flow per common share
distributable cash flow per common share
comparable income from equity investments
income from equity investments
comparable interest expense
interest expense
comparable interest income and other expense
interest income and other expense
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 assets and investments
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.
Consolidated results – first 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 March 31
(unaudited – millions of $, except per share amounts)
2016
2015
Natural Gas Pipelines
607
585
Liquids Pipelines
218
242
Energy
(122
)
212
Corporate
(60
)
(31
)
Total segmented earnings
643
1,008
Interest expense
(420
)
(318
)
Interest income and other
201
(14
)
Income before income taxes
424
676
Income tax expense
(70
)
(207
)
Net income
354
469
Net income attributable to non-controlling interests
(80
)
(59
)
Net income attributable to controlling interests
274
410
Preferred share dividends
(22
)
(23
)
Net income attributable to common shares
252
387
Net income per common share – basic and diluted
$0.36
$0.55
Net income attributable to common shares decreased by $135 million for the three months ended March 31, 2016 compared to the same period in 2015. The 2016 results included:
a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs
a charge of $26 million relating to costs associated with the acquisition of Columbia
a charge of $6 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project
an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.
Net income in both 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 $29 million for the three months ended March 31, 2016 compared to the same period in 2015 as discussed below in the reconciliation of net income to comparable earnings.
RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
three months ended March 31
(unaudited – millions of $, except per share amounts)
2016
2015
Net income attributable to common shares
252
387
Specific items (net of tax):
Alberta PPA terminations
176
–
Acquisition costs – Columbia Pipeline Group
26
–
Keystone XL asset costs
6
–
TC Offshore loss on sale
3
–
Risk management activities1
31
78
Comparable earnings
494
465
Net income per common share
$0.36
$0.55
Specific items (net of tax):
Alberta PPA terminations
0.25
–
Acquisition costs – Columbia Pipeline Group
0.04
–
Keystone XL asset costs
0.01
–
TC Offshore loss on sale
–
–
Risk management activities
0.04
0.11
Comparable earnings per share
$0.70
$0.66
(1)
Risk management activities
three months ended March 31
(unaudited – millions of $)
2016
2015
Canadian Power
(13
)
(22
)
U.S. Power
(115
)
(68
)
Liquids
(2
)
–
Natural Gas Storage
5
1
Foreign exchange
53
(29
)
Income tax attributable to risk management activities
41
40
Total losses from risk management activities
(31
)
(78
)
Comparable earnings increased by $29 million for the three months ended March 31, 2016 compared to the same period in 2015. This was primarily the net effect of:
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 and increased AFUDC related to our rate-regulated projects
higher earnings from Bruce Power mainly due to higher gains from contracting activities, lower depreciation and our increased ownership interest, partially offset by higher planned outage days
higher interest expense from debt issuances and lower capitalized interest from Keystone XL
lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower realized prices in both New England and New York and lower capacity prices in New York, partially offset by incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania acquired February 1, 2016
lower earnings from Eastern Power due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour
lower earnings from Liquids Pipelines due to lower uncontracted volumes on the Keystone Pipeline System and lower volumes on Marketlink
lower earnings from Western Power as a result of lower realized power prices and volumes.
The stronger U.S. dollar this quarter compared to the same period in 2015 positively impacted the translated results in our U.S. 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 consists of $13 billion of near-term projects and $45 billion of commercially secured medium and longer-term projects. Amounts presented exclude the impact of foreign exchange, 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.
at March 31, 2016
(unaudited – billions of $)
Estimated project cost
Carrying value
Summary
Near-term
13.3
4.3
Medium to longer-term
45.2
2.2
Total capital program
58.5
6.5
Foreign exchange impact on Capital Program1
3.5
0.7
(1)
Reflects U.S. foreign exchange rate of $1.30 at March 31, 2016.
at March 31, 2016
(unaudited – billions of $)
Segment
Expected
in-service date
Estimated project cost
Carrying value
Houston Lateral and Terminal
Liquids Pipelines
2016
US 0.6
US 0.5
Topolobampo
Natural Gas Pipelines
2016
US 1.0
US 0.9
Mazatlan
Natural Gas Pipelines
2016
US 0.4
US 0.3
Canadian Mainline
Natural Gas Pipelines
2016-2017
0.7
0.1
NGTL
– 2016/17 Facilities
Natural Gas Pipelines
2016-2018
2.7
0.5
– North Montney
Natural Gas Pipelines
2017
1.7
0.3
– 2018 Facilities
Natural Gas Pipelines
2018
0.6
–
– Other
Natural Gas Pipelines
2016-2017
0.4
–
Grand Rapids1
Liquids Pipelines
2017
0.9
0.6
Northern Courier
Liquids Pipelines
2017
1.0
0.6
Tuxpan-Tula
Natural Gas Pipelines
2017
US 0.5
US 0.1
Napanee
Energy
2017 or 2018
1.0
0.4
Tula-Villa de Reyes
Natural Gas Pipelines
2018
US 0.6
–
Bruce Power – life extension1
Energy
2016-2020
1.2
–
Total near-term projects
13.3
4.3
(1)
Our proportionate share.
at March 31, 2016
(unaudited – billions of $)
Segment
Estimated project cost
Carrying value
Heartland and TC Terminals
Liquids Pipelines
0.9
0.1
Upland
Liquids Pipelines
US 0.6
–
Grand Rapids Phase 21
Liquids Pipelines
0.7
–
Bruce Power – life extension1
Energy
5.3
–
Keystone projects
Keystone XL2
Liquids Pipelines
US 8.0
US 0.4
Keystone Hardisty Terminal2
Liquids Pipelines
0.3
0.1
Energy East projects
Energy East3
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
0.3
Prince Rupert Gas Transmission
Natural Gas Pipelines
5.0
0.4
NGTL System – Merrick
Natural Gas Pipelines
1.9
–
Total medium to longer-term projects
45.2
2.2
(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.
Outlook
Our overall earnings outlook for 2016 remains consistent with what was previously included in the 2015 Annual Report. Any changes in outlook with respect to specific lines of business are addressed within each business section of the MD&A. This outlook excludes the Columbia acquisition and related financing and asset sales. See Recent developments section for more information.
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.
three months ended March 31
(unaudited – millions of $)
2016
2015
Comparable EBITDA
898
864
Depreciation and amortization
(287
)
(279
)
Comparable EBIT
611
585
Specific item:
TC Offshore loss on sale
(4
)
–
Segmented earnings
607
585
Natural Gas Pipelines segmented earnings increased by $22 million for the three months ended March 31, 2016 compared to the same period in 2015 and included an additional $4 million pre-tax loss on the sale of TC Offshore. This amount has 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 March 31
(unaudited – millions of $)
2016
2015
Canadian Pipelines
Canadian Mainline
240
263
NGTL System
234
219
Foothills
26
26
Other Canadian pipelines1
7
6
Canadian Pipelines – comparable EBITDA
507
514
Depreciation and amortization
(216
)
(209
)
Canadian Pipelines – comparable EBIT
291
305
U.S. and International Pipelines (US$)
ANR
88
86
TC PipeLines, LP1,2
31
26
Great Lakes3
25
20
Other U.S. pipelines (Iroquois1, GTN2,4, PNGTS2,5)
14
41
Mexico (Guadalajara, Tamazunchale)
41
47
International and other1,6
2
2
Non-controlling interests7
95
74
U.S. and International Pipelines – comparable EBITDA
296
296
Depreciation and amortization
(53
)
(57
)
U.S. and International Pipelines – comparable EBIT
243
239
Foreign exchange impact
84
59
U.S. and International Pipelines – comparable EBIT (Cdn$)
327
298
Business Development comparable EBITDA and EBIT
(7
)
(18
)
Natural Gas Pipelines – comparable EBIT
611
585
(1)
Results from TQM, Northern Border, Iroquois and TransGas reflect our share of equity income from these investments. On March 31, 2016, we purchased an additional 4.87 per cent interest in Iroquois.
(2)
On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP. On January 1, 2016 we sold a 49.9 per cent interest in PNGTS to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Great Lakes and PNGTS through our ownership interest in TC PipeLines, LP for the periods presented.
Ownership percentage as of
March 31, 2016
December 31, 2015
April 1, 2015
TC PipeLines, LP
27.9
28.0
28.3
Effective ownership through TC PipeLines, LP:
GTN
27.9
28.0
28.3
Great Lakes
13.0
13.0
13.1
PNGTS
13.9
–
–
(3)
Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.
(4)
Effective April 1, 2015, we have no direct ownership in GTN. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.
(5)
Represents our 61.7 per cent ownership interest in 2015. Effective January 1, 2016, our direct ownership interest in PNGTS was 11.8 per cent as a result of the dropdown transaction between us and TC PipeLines, LP.
(6)
Includes our share of the equity income from TransGas as well as general and administration costs relating to our U.S. and International Pipelines.
(7)
Comparable EBITDA for the portions of TC PipeLines, LP and PNGTS 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, the 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 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 March 31
(unaudited – millions of $)
2016
2015
Canadian Mainline
50
47
NGTL System
73
64
Foothills
4
4
Net income for the Canadian Mainline increased by $3 million for the three months ended March 31, 2016 compared to the same period in 2015 primarily due to higher incentive earnings partially offset by a lower average investment base in 2016. No incentive earnings were recorded in the first quarter of 2015 because NEB approval of 2015 – 2020 compliance tolls for the NEB 2014 Decision was not received until June 2015. The NEB 2014 Decision included an approved ROE of 10.1 per cent with a possible range of achieved ROE outcomes between 8.7 per cent to 11.5 per cent.
Net income for the NGTL System increased by $9 million for the three months ended March 31, 2016 compared to the same period in 2015 mainly due to a higher average investment base.
U.S. AND INTERNATIONAL PIPELINES
Earnings for our U.S. natural gas pipelines operations are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.
Comparable EBITDA for U.S. and International Pipelines was consistent for the three months ended March 31, 2016 compared to the same period in 2015. This was the net effect of:
higher ANR Southeast mainline transportation revenues offset by a first quarter 2015 non-recurring settlement
lower contributions from Mexico Pipelines
higher transportation revenues from Great Lakes.
As well, a stronger U.S. dollar in first quarter 2016 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 $8 million for three months ended March 31, 2016 compared to the same period in 2015 mainly because of a higher investment base on the NGTL System and the effect of a stronger U.S. dollar.
BUSINESS DEVELOPMENT
Business development expenses were lower by $11 million for the three months ended March 31, 2016 compared to the same period in 2015 mainly due to decreased business development activity.
OPERATING STATISTICS – WHOLLY OWNED PIPELINES
three months ended March 31
Canadian Mainline1
NGTL System2
ANR3
(unaudited)
2016
2015
2016
2015
2016
2015
Average investment base (millions of $)
4,384
5,018
7,257
6,419
n/a