TransCanada Reports Solid Second Quarter 2016 Financial Results
Transformational Columbia Acquisition to Enhance Future Growth
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 07/28/16 -- TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada) today announced net income attributable to common shares for second quarter 2016 of $365 million or $0.52 per share compared to $429 million or $0.60 per share for the same period in 2015. Comparable earnings for second quarter 2016 were $366 million or $0.52 per share compared to $397 million or $0.56 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 September 30, 2016, equivalent to $2.26 per common share on an annualized basis.
"Our portfolio of high-quality energy infrastructure assets continued to perform well during the second quarter of 2016," said Russ Girling, TransCanada''s president and chief executive officer. "Net income was impacted by one-time dividend equivalent payments on the subscription receipts related to the acquisition of Columbia, while comparable earnings largely reflected planned maintenance activities at Bruce Power including an approximate once-a-decade station containment outage. With the addition of Columbia and Bruce Power''s planned maintenance outages now largely complete, we expect to generate stronger results going forward."
On July 1, 2016, TransCanada completed the acquisition of Columbia Pipeline Group, Inc. (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 subscription receipts issued in April to fund a portion of the Columbia acquisition were exchanged into common shares following closing.
"The Columbia acquisition reinforces TransCanada''s position as a leading North American energy infrastructure company with an extensive pipeline network linking the continent''s most prolific natural gas supply basins to its most attractive markets," added Girling. "The Columbia assets are very complementary to our existing business and we expect significant synergies and growth in the years to come. Our industry-leading $25 billion portfolio of near-term capital projects builds upon a solid portfolio of stable and predictable pipeline and energy assets that together supports and may augment an expected eight to ten per cent annual dividend growth rate through 2020."
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Net income attributable to common shares decreased by $64 million to $365 million or $0.52 per share for the three months ended June 30, 2016 compared to the same period last year. Second quarter 2016 included a charge of $113 million related to costs associated with the Columbia acquisition which were primarily related to the dividend equivalent payments on the subscription receipts, a net after-tax $10 million restructuring charge related to expected future losses under lease commitments, and $9 million after-tax related to Keystone XL maintenance and liquidation costs. All of these specific items are excluded from comparable earnings.
Comparable earnings for second quarter 2016 were $366 million or $0.52 per share compared to $397 million or $0.56 per share for the same period in 2015. Comparable earnings were lower in the period due to higher interest expenses as a result of debt issuances and lower capitalized interest, higher planned maintenance outage days at Bruce Power, lower volumes on the Keystone and Marketlink pipelines, and lower earnings from Western Power, partially offset by realized gains in 2016 versus realized losses in 2015 on derivatives used to manage our foreign exchange exposure, higher AFUDC on our rate-regulated projects, greater earnings from ANR due to higher transportation revenue and lower OM&A expenses, and higher earnings from U.S. Power mainly due to incremental earnings from Ironwood.
Notable recent developments include:
Corporate:
Natural Gas Pipelines:
Liquids Pipelines:
Energy:
Teleconference and Webcast:
We will hold a teleconference and webcast on Thursday, July 28, 2016 to discuss our second 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 9 a.m. (MT) / 11 a.m. (ET).
Members of the investment community and other interested parties are invited to participate by calling 866.225.6564 or 416.340.2220 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at .
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on August 4, 2016. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 1967464.
The unaudited interim condensed Consolidated Financial Statements and Management''s Discussion and Analysis (MD&A) are available under TransCanada''s profile on SEDAR at , with the U.S. Securities and Exchange Commission on EDGAR at and on the TransCanada website at .
With more than 65 years'' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 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 July 27, 2016 and 2015 Annual Report on our website at or filed under TransCanada''s profile on SEDAR at and with the U.S. Securities and Exchange Commission at and available on TransCanada''s website at .
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 July 27, 2016.
Management''s discussion and analysis
July 27, 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 six months ended June 30, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2016 which have been prepared in accordance with U.S. GAAP. For greater certainty, given our acquisition of Columbia Pipeline Group, Inc. (Columbia) was not completed until July 1, 2016, Columbia was not a subsidiary during the period ended June 30, 2016 and its results have not been reflected in our condensed consolidated financial statements for the three and six months ended June 30, 2016.
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 July 27, 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:
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.
Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:
Assumptions
Risks and uncertainties
You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 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 ().
NON-GAAP MEASURES
We use the following non-GAAP measures:
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 from operating activities in excess of equity earnings 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 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. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision not to include a specific item is subjective and made after careful consideration. Specific items may include:
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 - second 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.
Net income attributable to common shares decreased by $64 million and $199 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. The 2016 results included:
The 2015 results included:
Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.
Comparable earnings decreased by $31 million and $2 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 as discussed below in the reconciliation of net income to comparable earnings.
Comparable earnings decreased by $31 million for the three months ended June 30, 2016 compared to the same period in 2015. This was primarily the net effect of:
Comparable earnings decreased by $2 million for the six months ended June 30, 2016 compared to the same period in 2015. This was primarily the net effect of:
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 as of June 30, 2016, consists of $15 billion of near-term projects and $45 billion of commercially secured medium- to 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.
Our capital program as of July 1, 2016, including Columbia projects, consists of $25 billion of near-term projects.
Outlook
Our overall earnings outlook for our 2016 earnings, excluding specific items, will be modestly 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, changes in our Canadian Power business and lower than expected U.S. Power earnings, each of which are addressed within the relevant section of the MD&A.
Consolidated capital spending, equity investments and acquisition
On April 11, 2016, we announced that we were chosen to build, own and operate the US$550 million Tula-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 US$2.1 billion Sur de Texas-Tuxpan natural gas pipeline in Mexico. On July 1, 2016, we acquired Columbia for US$10.3 billion. In addition to the capital expenditures outlined in the 2015 Annual Report, we expect to spend an estimated additional $1 billion on Columbia capital projects in 2016, approximately $300 million on the Tula-Villa de Reyes pipeline and $150 million on the Sur de Texas-Tuxpan natural gas pipeline.
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.
Natural Gas Pipelines segmented earnings increased by $75 million and $94 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. Segmented earnings for the six months ended June 30, 2016 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.
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 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
Net income for the Canadian Mainline decreased by $15 million for the three months ended June 30, 2016 compared to the same period in 2015 primarily due to lower incentive earnings and average investment base. Higher incentive earnings were recorded in the second quarter of 2015 because NEB approval of the 2015 - 2020 compliance tolls for the NEB 2014 Decision was received in June 2015 and second quarter 2015 results included the year-to-date impact. The NEB 2014 Decision included an approved ROE of 10.1 per cent with a possible range of achieved ROE outcomes between 8.7 to 11.5 per cent. Net Income for the Canadian Mainline decreased by $12 million for the six months ended June 30, 2016 compared to the same period in 2015 mainly due to a lower average investment base in 2016.
Net income for the NGTL System increased by $13 million and $22 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly due to a higher average investment base and OM&A incentives recorded in 2016.
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. 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 increased by US$46 million in both the three and six months ended June 30, 2016 compared to the same periods in 2015. This was the net effect of:
As well, a stronger U.S. dollar 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 $6 million and $14 million for the three and six months ended June 30, 2016 compared to the same periods 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 $8 million and $16 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly due to capitalization of business development expenses, a focus on the Columbia acquisition and decreased business development activity.
OUTLOOK
The 2016 earnings outlook for the Canadian regulated and Mexican pipelines remain consistent with what we disclosed in the 2015 Annual Report. Earnings for the existing U.S. Pipelines are expected to be slightly higher this year as a result of higher revenues and lower costs. We are also expecting an increase in 2016 earnings 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.
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.
Liquids Pipelines segmented earnings decreased by $43 million and $67 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and included a pre-tax charge related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project, and unrealized gains 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.
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 $38 million and $42 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and was the net effect of:
BUSINESS DEVELOPMENT AND OTHER
Business development and other, which primarily includes business development activity and our marketing business, increased by $5 million and $4 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and was the net effect of:
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $1 million and $8 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the effect of a stronger U.S. dollar.
OUTLOOK
Following our Keystone XL impairment charge in 2015, future expenditures on the project for the maintenance and liquidation of project assets, expected to be approximately $55 million before tax ($36 million after tax) in 2016, are being expensed pending further advancement of this project. These costs will 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.
Energy segmented earnings increased by $116 million and decreased by $215 million for the three and six months ended June 30, 2016 compared to the same periods in 2015.
Energy segmented earnings included the following specific items that have been excluded from comparable EBIT:
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 impact 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 assets, 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, contributed to higher volatility in U.S. Power risk management activities. This increased level of volatility is reflected in the $204 million unrealized gain in second quarter 2016 and the $115 million unrealized loss in first quarter 2016.
The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.
Comparable EBITDA for Energy decreased by $31 million for the three months ended June 30, 2016 compared to the same period in 2015 due to the net effect of:
Comparable EBITDA for Energy decreased by $85 million for the six months ended June 30, 2016 compared to the same period in 2015 due to the net effect of:
Western Power
Comparable EBITDA for Western Power decreased by $15 million and $26 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to lower realized power prices and lower PPA volumes following the 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 74 per cent from $57/MWh to $15/MWh for the three months ended June 30, 2016 and decreased 60 per cent from $43/MWh to $17/MWh for the six months ended June 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, warm weather and the Northern Alberta wildfires. 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 second quarter 2016 compared to 57 per cent in second quarter 2015.
Depreciation and amortization decreased by $10 million in second quarter 2016 compared to second quarter 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 2016, the natural gas-fired cogeneration assets are expected to perform well in the lower 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 $5 million and $32 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. These decreases were mainly due to lower contractual earnings at Becancour. In addition, Eastern Power had lower earnings on the sale of unused natural gas transportation for the six months ended June 30, 2016 compared to the same period in 2015.
Our 2016 earnings outlook provided in the 2015 Annual Report will be unfavourably impacted 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 the Becancour tolling 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.
Equity income from Bruce Power decreased by $46 million and $11 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 mainly due to lower volumes resulting from higher planned outage days partially offset by lower depreciation as a result of the Bruce Power facility''s operating life extension. In addition, Bruce Power had higher gains from contracting activities for the six months ended June 30, 2016 compared to the same period 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.
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.
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 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. Planned maintenance on unit 8 and unit 2 was also completed in second quarter 2016, while planned maintenance activities on unit 3 will continue into third quarter 2016. Additional planned maintenance is scheduled 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.
Comparable EBITDA for U.S. Power increased US$20 million for the three months ended June 30, 2016 compared to the same period in 2015 primarily due to the net effect of:
Comparable EBITDA for U.S. Power decreased US$36 million for the six months ended June 30, 2016 compared to the same period in 2015 primarily due to the net effect of:
The timing of recognizing earnings on certain contracts in our U.S. power marketing business is impacted by different power pricing profiles between the prices we charge our customers and the prices we pay for volumes purchased to fulfill our sales obligations over the term of the contracts. The costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers include the impact of certain contracts to purchase power over multiple periods at a flat price. Because the price we charge our customers is typically shaped to the market, the impact of these two contract pricing profiles has generally resulted in higher earnings in January to March, offset by lower earnings between April and December with overall positive margins realized over the term of the contracts.
Average New York Zone J spot capacity prices were approximately 22 per cent and 25 per cent lower for the three and six months ended June 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 was partially offset by capacity revenues earned by our Ironwood power plant acquired in February 2016.
Capacity revenues were also negatively impacted by a unit outage 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 six months ended June 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. All insurance recoveries 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 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.
Wholesale electricity prices in New York and New England were lower for the three and six months ended June 30, 2016 compared to the same periods in 2015 primarily due to unseasonably warm weather in winter 2016. In New England, spot power prices for the three and six months ended June 30, 2016 were four per cent and 51 per cent lower compared to the same periods in 2015. In New York City, spot power prices for the three and six months ended June 30, 2016 were seven per cent and 47 per cent lower compared to the same periods in 2015. Both markets have also experienced lower natural gas commodity prices during 2016 compared to the same period in 2015.
Lower margins to wholesale, commercial and industrial customers in both PJM and New England markets resulted in lower earnings for the six months ended June 30, 2016 compared to the same period in 2015, the impact of which was primarily seen in first quarter earnings. Although we have expanded our customer base in the PJM market, significantly lower realized power prices and mild winter weather have resulted in lower margins in our wholesale business.
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 six month months ended June 30, 2016 than the same periods in 2015 as we have expanded our customer base in the PJM market.
As at June 30, 2016, approximately 4,700 GWh, or 60 per cent, of U.S. Power''s planned generation was contracted for the remainder of 2016 and 4,200 GWh, or 34 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.
U.S. Power results for 2016 will be dependent on the timing of the previously announced monetization of the U.S. Northeast power assets. See the Recent developments section for more information about the Columbia acquisition and related financing. Nevertheless, operating results for the full year in 2016 are expected to be lower than our Outlook in our 2015 Annual Report due to lower commodity prices experienced in the first half of 2016 and forecast for the remainder of the year.
NATURAL GAS STORAGE AND OTHER
Comparable EBITDA increased by $4 million and $10 million for the three and six months ended June 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 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.
Corporate segmented losses in 2016 increased by $26 million and $55 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT:
Comparable interest expense increased by $74 million and $176 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the net effect of:
Comparable interest income and other increased by $64 million and $197 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the net effect of:
Comparable income tax expense increased by $4 million and decreased by $63 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 and was mainly the result of lower pre-tax earnings in 2016 compared to 2015, 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 increased by $12 million and $33 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 primarily due to 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 and the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.
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, 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 and delisted from the TSX. See Financial condition section for additional information on the bridge term loan credit facilities and the subscription receipts.
Columbia operates a portfolio of 24,250 km (15,100 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 long-term growth opportunities. The acquisition also includes a large portfolio of new capital growth projects totalling approximately US$7.3 billion which includes six 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 2021 to ensure a safe, reliable and efficient system. We have plans in place to ensure an effective transition to integrate Columbia into the TransCanada organization.
Acquisition-related expenses were $10 million and $36 million for the three and six months ended June 30, 2016 and have been excluded from comparable earnings. The dividend equivalent payments on the subscription receipts of $109 million were included in interest expense in the three and six months ended June 30, 2016 and the interest earned on the funds received from the subscription receipts held in escrow of $6 million have also been excluded from comparable earnings.
Monetization of U.S. Northeast power assets and a minority interest in Mexican pipelines
The permanent financing for the acquisition of the Columbia Pipeline Group involves portfolio management that includes the monetization of our U.S. Northeast power assets and a minority interest in our Mexico gas pipeline business.
The process of engaging advisors has been completed and the initial stages of soliciting interested parties is well underway. We expect to provide an update as to the outcome of that process by the end of 2016. Proceeds from these monetizations will be used to retire draws under the bridge term loan credit facilities.
Master Limited Partnership strategy review
On July 1, 2016, we announced that a financial advisor has been retained to assist us in developing a master limited partnership (MLP) strategy. A decision on the MLP strategy is expected to be communicated by the end of 2016.
NATURAL GAS PIPELINES
Canadian Regulated Pipelines
NGTL System
In second quarter 2016, we placed approximately $450 million of facilities in service with another $400 million of facilities approved and currently under construction, while approximately $2.9 billion of commercially secured expansion projects have not yet been filed with the regulators.
We continue to work closely with our shippers to ensure that new proposed facilities meet our shippers and market demands. We recently added new long term delivery contracts on the NGTL System to meet demand in the Pacific Northwest and California. These contracts will require the construction of a new approximately $135 million facility (the Sundre Crossover Project) that was not previously included in our 2018 Facilities program. The open season process followed for the development of these new contracts identified further demand for service to this market that we are currently assessing.
We have also seen some cancellation or deferral of our customer''s specific projects, contract non-renewals, and contract transfers. As a result, we have re-evaluated planned facility requirements to meet future aggregate system service requirements and expect some changes in the spending profile of our programs to match revised facility in-service dates. The projected capital 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 are however, deferring approximately $225 million of spending for facilities in the 2016/17 Facilities program with revised service dates of 2018 through 2020. We are also deferring $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). The NEB has extended the sunset clause until the end of the year to allow time to further review the request and make a final decision subject to Governor-In-Council approval. A pre-construction CPCN condition requires that Petronas make a positive FID on the proposed Pacific Northwest LNG (PNW LNG) Project. Petronas is waiting on completion of the federal environmental assessment process for the LNG Project before it makes an FID. The environmental review process is currently scheduled to conclude this fall. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the NMML facilities for an in-service date as early as 2017, however, the in-service date will be finalized once a FID has been made.
2016-2017 NGTL Revenue Requirement Settlement
On April 7, 2016, the NEB approved the NGTL revenue requirement settlement application that was filed in December 2015, subject to certain reporting requirements. 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.
U.S. Pipelines
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) from one of our partners for US$54 million. Following this acquisition, our ownership interest in Iroquois increased to 49.35 per cent. On May 1, 2016, we acquired an additional 0.65 per cent interest from the remaining partner equalizing our overall ownership interests to 50 per cent each.
ANR Section 4 Rate Case
In January 2016, ANR filed a Section 4 Rate Case with the FERC that requests an increase to ANR''s maximum transportation rates. In February 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, in March 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.
TC Offshore
Effective March 31, 2016, we completed the sale of TC Offshore LLC to a third party. The sale includes 860 km (535 miles) of natural gas gathering and transmission pipeline, seven offshore platforms and other facilities.
Mexico
Tula-Villa de Reyes Pipeline
On April 11, 2016, we announced we were awarded the 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 CFE. We expect to invest approximately US$550 million 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-Tuxpan 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 to Tuxpan pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 2.6 billion cubic feet per day 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.
LNG Pipeline Projects
Prince Rupert Gas Transmission
PRGT continues to engage with Aboriginal groups and other stakeholders along the route in preparation for a FID by PNW LNG.
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, 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
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. Further investigative activities and corrective measures required by PHMSA are planned for 2016.
This shutdown is not expected to have a significant impact on our 2016 earnings.
Houston Lateral and Terminal
We commenced commercial transactions in July 2016 for August 2016 deliveries on the Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline System to Houston, Texas. 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. We do not anticipate this will result in a delay with regard to the NEB''s review process.
On March 17, 2016, the first phase of Energy East public hearings for the voluntary Quebec le Bureau d''audiences publiques sur l''environnement (BAPE) process was completed. The voluntary BAPE hearing process is intended to inform the Province of Quebec 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 as described above.
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 marks 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. The NEB also noted, that starting on August 8, 2016, there will be a series of community panel sessions held along the pipeline route. On July 20, 2016, the NEB issued the hearing order which provides further detail on the regulatory process. We are currently reviewing the contents.
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. 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 carbon tax
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 will set a limit on annual province-wide greenhouse gas emissions beginning in January 2017 and will introduce 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 latter 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. Impacted contracts have varying provisions with respect to amendment entitlement and management is reviewing each of our contracts to assess potential impacts.
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 is considering its regulatory options in light of this development, as the need for winter peaking capacity remains.
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.
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, monetization of assets, cash on hand and substantial committed credit facilities.
Funds generated from operations decreased $230 million and $258 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. These decreases were primarily due to $109 million of dividend equivalent payments on the subscription receipts issued to partially finance the Columbia acquisition.
At June 30, 2016, our current assets were $4.6 billion and current liabilities were $9.9 billion, leaving us with a working capital deficit of $5.3 billion compared to a deficit of $3.4 billion at December 31, 2015. The increase was mainly due to subscription receipts held in preparation for the closing of the Columbia acquisition on July 1, 2016. Our working capital deficiency is considered to be in the normal course of business and is managed through:
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 on our Canadian regulated natural gas pipelines were $42 million and $97 million for the three and six months ended June 30, 2016 compared to $61 million and $114 million for the same periods in 2015, which contributed to their respective rate bases and net income.
Capital expenditures in 2016 were primarily related to:
Costs incurred on capital projects under development primarily relate to the Energy East and LNG pipeline projects.
Contributions to equity investments have increased in 2016 compared to 2015 primarily due to our investments in Grand Rapids and Bruce Power.
Restricted cash represents the amount held in escrow at June 30, 2016 for the purchase of Columbia on July 1, 2016 and includes the proceeds from the sale of subscription receipts, net of dividend equivalent payments, and draws on the committed bridge loan credit facilities.
On February 1, 2016, we acquired the Ironwood natural gas fired, combined cycle power plant with a capacity of 778 MW, for US$657 million in cash before 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 the bank credit facility as part of its financing program to fund its capital program and make distributions to the partners. Therefore, the distributions received from Bruce Power in second quarter 2016 were funded from both operating and financing activities and included $725 million from Bruce Power financing program.
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:
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 entitled the holder to automatically receive one common share upon closing of the Columbia acquisition on July 1, 2016. H
Themen in dieser Pressemitteilung:
Unternehmensinformation / Kurzprofil:
Datum: 28.07.2016 - 05:30 Uhr
Sprache: Deutsch
News-ID 1449536
Anzahl Zeichen: 3087
contact information:
Contact person:
Town:
CALGARY, ALBERTA
Phone:
Kategorie:
Oil & Gas
Typ of Press Release:
type of sending:
Date of sending:
Anmerkungen:
Diese Pressemitteilung wurde bisher 177 mal aufgerufen.
Die Pressemitteilung mit dem Titel:
"TransCanada Reports Solid Second Quarter 2016 Financial Results
"
steht unter der journalistisch-redaktionellen Verantwortung von
TRANSCANADA (Nachricht senden)
Beachten Sie bitte die weiteren Informationen zum Haftungsauschluß (gemäß TMG - TeleMedianGesetz) und dem Datenschutz (gemäß der DSGVO).
