Paris, France

Time filter

Source Type

News Article | May 19, 2017
Site: www.PR.com

Hänel Storage Systems of Pittsburgh, PA, USA was part of a group to award an honor scholarship for the 2017-18 academic year. Pittsburgh, PA, May 19, 2017 --( Kelly is a PhD student studying Industrial Engineering with a cumulative GPA of 4.0, and earned her bachelor’s degree in industrial and management systems engineering from Montana State University-Bozeman in 2016. She has worked as a transportation intern for BNSF Railway in Belen, NM, and as a quality assurance intern for CH2M HILL at the U.S. Department of Energy’s Hanford Nuclear Site through ANR Group, Inc. She is a member of the Society of Women Engineers, Institute of Industrial Engineers and American Society for Engineering Management. The scholarship is implemented every year through the Material Handling Education Foundation, Inc. (MHEFI), an independent charitable organization. Since its founding in 1976, it has awarded more than $2.5 million in scholarships. Any graduate or undergraduate student who meets the eligibility requirements and attends a qualified institution is encouraged to apply for the scholarship. MHEFI is affiliated with the Material Handling Institute (MHI), the largest association in the United States dedicated to the promotion and education of the material handling, logistics and supply chain industry. Brian Cohen, Chief Executive of Hänel Storage Systems, was one of the judges for the scholarship competition. Hänel is a leader in the manufacture and integration of automated vertical storage units, and Cohen currently serves on the MHI Board of Governors and is an active member of its AS/RS Industry Group. AS/RS members are the material handling industry’s leading suppliers of automated storage and retrieval systems. They supply systems worldwide in virtually every major manufacturing, industrial and distribution sector. The AS/RS Honor Scholarship was announced on November 1, 2016, and applications were collected through February 28, 2017 and judged through March. The scholarship carries an amount of $2500. About Hänel Storage Systems Founded in Germany in 1953, Hänel’s North American headquarters has been located in Pittsburgh, PA since it was established in 1984. Hänel Storage Systems specializes in the design and engineering of Rotomat® vertical storage carousels and Lean-Lift® Vertical Lift Modules for a wide range of industries and applications. Hänel provides sales, service and technical support to North and South America through a network of factory-trained channel partners and service providers. Introduced in 1957, the Rotomat® Vertical Carousel is based on the Ferris Wheel principal. Inventory is stored in a series of carriers that rotate within an enclosed unit and are accessed at a single opening. This vertical “goods to the user” concept improves productivity, lowers costs, increases security and saves valuable floor space. Introduced in 1994, the Lean-Lift® Vertical Lift Module stores inventory on trays that are automatically measured for height each time they enter the unit. A vertical extractor places each tray within the unit in a location that maximizes available storage space. Trays can be equipped with dividers, totes, bins and specialized holders to store any type of inventory. For more information about Hänel products, visit www.hanel.us. Pittsburgh, PA, May 19, 2017 --( PR.com )-- Katie Kelly from Montana State University-Bozeman has been awarded the Automated Storage/Retrieval Systems (AS/RS) Honor Scholarship for the 2017-18 academic year.Kelly is a PhD student studying Industrial Engineering with a cumulative GPA of 4.0, and earned her bachelor’s degree in industrial and management systems engineering from Montana State University-Bozeman in 2016. She has worked as a transportation intern for BNSF Railway in Belen, NM, and as a quality assurance intern for CH2M HILL at the U.S. Department of Energy’s Hanford Nuclear Site through ANR Group, Inc. She is a member of the Society of Women Engineers, Institute of Industrial Engineers and American Society for Engineering Management.The scholarship is implemented every year through the Material Handling Education Foundation, Inc. (MHEFI), an independent charitable organization. Since its founding in 1976, it has awarded more than $2.5 million in scholarships. Any graduate or undergraduate student who meets the eligibility requirements and attends a qualified institution is encouraged to apply for the scholarship. MHEFI is affiliated with the Material Handling Institute (MHI), the largest association in the United States dedicated to the promotion and education of the material handling, logistics and supply chain industry.Brian Cohen, Chief Executive of Hänel Storage Systems, was one of the judges for the scholarship competition. Hänel is a leader in the manufacture and integration of automated vertical storage units, and Cohen currently serves on the MHI Board of Governors and is an active member of its AS/RS Industry Group. AS/RS members are the material handling industry’s leading suppliers of automated storage and retrieval systems. They supply systems worldwide in virtually every major manufacturing, industrial and distribution sector.The AS/RS Honor Scholarship was announced on November 1, 2016, and applications were collected through February 28, 2017 and judged through March. The scholarship carries an amount of $2500.About Hänel Storage SystemsFounded in Germany in 1953, Hänel’s North American headquarters has been located in Pittsburgh, PA since it was established in 1984. Hänel Storage Systems specializes in the design and engineering of Rotomat® vertical storage carousels and Lean-Lift® Vertical Lift Modules for a wide range of industries and applications. Hänel provides sales, service and technical support to North and South America through a network of factory-trained channel partners and service providers.Introduced in 1957, the Rotomat® Vertical Carousel is based on the Ferris Wheel principal. Inventory is stored in a series of carriers that rotate within an enclosed unit and are accessed at a single opening. This vertical “goods to the user” concept improves productivity, lowers costs, increases security and saves valuable floor space.Introduced in 1994, the Lean-Lift® Vertical Lift Module stores inventory on trays that are automatically measured for height each time they enter the unit. A vertical extractor places each tray within the unit in a location that maximizes available storage space. Trays can be equipped with dividers, totes, bins and specialized holders to store any type of inventory.For more information about Hänel products, visit www.hanel.us. Click here to view the list of recent Press Releases from Hanel Storage Systems


Middle Stone Age humans in the Porc-Epic cave likely used ochre over at least 4,500 years, according to a study published May 24, 2017 in the open-access journal PLOS ONE by Daniela Rosso from the University of Barcelona, Spain, and the University of Bordeaux, France, and colleagues. Ochre, an iron-rich rock characterized by a red or yellow color, is found at many Middle Stone Age sites. The largest known East African collection of Middle Stone Age ochre, found at Porc-Epic Cave in Ethiopia, weighs around 40kg and is thought to date to ca. 40,000 years ago. The authors of the present study conducted a detailed analysis of 3792 pieces of ochre, using microscopy and experimental reproduction of grinding techniques to assess how the ochre was processed and used over a 4,500-year timespan. The researchers found that the cave inhabitants appeared to have persistently acquired, processed, and used the same types of ochre during this period. Overall the inhabitants of the cave seem to have processed almost half of the ochre pieces, although the proportion of ochre which had been modified decreased progressively over the period. Whilst flaking and scraping of ochre pieces appeared to have become more common over time, the authors noted a reduction in the proportion of pieces which underwent grinding. The gradual nature of shifts in preferred processing techniques may indicate that they resulted from cultural drift within this practice. Intensively modified ochre pieces show ground facets likely produced with different types of grindstones, at different times. According to the authors, these pieces were probably curated and processed for the production of small amounts of ochre powder. This is consistent with use in symbolic activities, such as the production of patterns or body painting, although a use for utilitarian activities cannot be discarded. Whilst the increase of ochre use in certain layers could be explained by refining the dating of the sequence and acquiring environmental data, these authors state that their analysis of ochre treatment seems to reflect a "cohesive behavioral system shared by all community members and consistently transmitted through time." In your coverage please use this URL to provide access to the freely available article in PLOS ONE: http://journals. Citation: Rosso DE, d'Errico F, Queffelec A (2017) Patterns of change and continuity in ochre use during the late Middle Stone Age of the Horn of Africa: The Porc-Epic Cave record. PLoS ONE 12(5): e0177298. https:/ Funding: Research by DR was funded by the Generalitat de Catalunya (Ajuts per a la contractació de personal investigador novell, FI-DGR), the Doctoral Research scholarship Programme of the Martine Aublet Foundation, and the Eiffel Excellence Scholarship Programme of the French Ministry of Foreign Affairs and International Development. This research was conducted with the financial support of the Wenner-Gren Foundation (Gr. 8786), the LaScArBx research programme, supported by the ANR ANR-10-LABX-52, and the European Research Council Advanced Grant, TRACSYMBOLS No. 249587 awarded under the FP7 program. The funders had no role in study design, data collection and analysis, decision to publish, or preparation of the manuscript. Competing Interests: The authors have declared that no competing interests exist.


The cognitive abilities of Neanderthals are debated, but a raven bone fragment found at the Zaskalnaya VI (ZSK) site in Crimea features two notches that may have been made by Neanderthals intentionally to display a visually consistent pattern, according to a study by Ana Majkic at the Universite de Bordeaux and colleagues, published in the open access journal, PLOS ONE on March 29, 2017. Majkic and colleagues conducted a mixed-methods study to assess whether the two extra notches on the ZSK raven bone were made by Neanderthals with the intention of making the final series of notches appear to be evenly spaced. First, researchers conducted a multi-phase experiment where recruited volunteers were asked to create evenly spaced notches in domestic turkey bones, which are similar in size to the ZSK raven bone. Morphometric analyses reveal that the equal spacing of the experimental notches was comparable to the spacing of notches in the ZSK raven bone, even when adjusted for errors in human perception. Archeological specimens featuring aligned notches from different sites were also analyzed and compared with the ZSK raven bone specimen. Researchers concluded that the two extra notches on the ZSK raven bone may have been made by Neanderthals intentionally to create a visually consistent, and perhaps symbolic, pattern. A series of recent discoveries of altered bird bones across Neanderthal sites has caused many researchers to argue that the objects were used for personal ornaments, as opposed to butchery tools or activities. But this study is the first that provides direct evidence to support a symbolic argument for intentional modifications on a bird bone. In your coverage please use this URL to provide access to the freely available article in PLOS ONE: http://journals. Citation: Majki A, Evans S, Stepanchuk V, Tsvelykh A, d'Errico F (2017) A decorated raven bone from the Zaskalnaya VI (Kolosovskaya) Neanderthal site, Crimea. PLoS ONE 12(3): e0173435. doi:10.1371/journal.pone.0173435 Funding: This research was conducted with the financial support awarded to the authors through the PICS collaborative research project "The emergence of symbolically mediated behavior in Eastern Europe" by the CNRS and NASU (PICS-NASU 3-15). One of the authors (AM) acknowledges financial support of the Wenner-Gren Foundation. This research was also funded by the LaScArBx, a research programme supported by the ANR (ANR-10-LABX-52). Another author (SE) acknowledges financial support of the AHRC. Competing Interests: The authors have declared that no competing interests exist.


News Article | March 10, 2017
Site: globenewswire.com

« Ces bons résultats 2016 sont la concrétisation de la stratégie initiée par les équipes de Foncière depuis 5 ans. La performance de notre modèle économique, très distinctif, repose sur la complémentarité des métiers de l'investissement, la construction pour compte propre et l'Asset Management. Notre filiale Voisin monte en puissance et constitue un relais de croissance fort sur nos produits SCPI et OPPCI. Je suis très confiant sur notre capacité à poursuivre notre croissance et à maintenir un niveau de rendement récurrent à nos actionnaires » déclare Georges Rocchietta, président de FONCIÈRE ATLAND. Foncière Atland a développé un premier OPPCI RFA avec effet de levier géré par sa filiale Voisin. Cet OPPCI (Transimmo), dédié à l'activité et à l'infrastructure de transport de personnes, a accueilli via sa filiale Transbus, par voie d'apport ou de cession, l'ensemble des dépôts de bus acquis et/ou gérés par Foncière Atland depuis 2007 (détention directe ou dans le cadre de montages en co-investissements). Ces actifs sont loués aux sociétés Keolis (filiale SNCF) et Transdev (filiale de la Caisse des Dépôts et Consignation). Foncière Atland, qui conserve l'asset management et la gestion des actifs, détient 30% de la société Transbus (filiale à 70% de l'OPPCI) qui représente plus de 100 M€ d'actifs (valeur HD). Cet OPPCI a été constitué en partenariat avec AG Real Estate et des investisseurs privés (au travers de la société Immobus, elle-même actionnaire de l'OPPCI). La volonté des actionnaires est de développer ce portefeuille pour le porter à 200 M€. Foncière Atland et le gestionnaire néerlandais de fonds de pensions PGGM ont créé, en septembre 2016, un véhicule d'investissement commun ciblant des actifs de bureaux à Paris et en Ile-de-France. Le fonds dispose d'une capacité d'investissement de 250 M€. PGGM et Foncière Atland ont créé cette société avec pour objectif d'investir dans des actifs tertiaires recélant un potentiel de création de valeur. Au cours du premier semestre, Foncière Atland a réalisé une émission obligataire de 10 M€ d'une durée de 5 ans. L'émission a été réalisée par placement privé. Les Obligations portent intérêt au taux de 4,5 % l'an, payable annuellement et seront remboursées en totalité en numéraire à leur valeur nominale majorée, le cas échéant, d'une prime de remboursement liée à la performance économique de Foncière Atland à la date de remboursement et plafonnée à 7% par an. Par ailleurs, Foncière Atland a décidé de procéder au remboursement anticipé, le 4 mai 2016, des obligations émises en 2013 pour un montant de 5 M€. Foncière Atland a opté pour la méthode du coût amorti et comptabilise ses immeubles de placement à leur coût diminué des amortissements et pertes de valeur. Dans un souci d'information et à titre de comparaison avec les autres acteurs SIIC du marché qui ont opté pour la méthode de juste valeur, le bénéfice net de Foncière Atland se serait élevé à 5,5 M€ au 31 décembre 2016 (soit 9,67 € par action) contre un bénéfice de 7,2 M€ au 31 décembre 2015 (soit 12,72 € par action) si la société avait opté pour la comptabilisation de ses immeubles à la juste valeur dans ses comptes consolidés. Les revenus locatifs des actifs détenus en propre ont baissé de 28% par rapport à l'année 2015, soit de 0,8 M€ en valeur. Cette variation s'explique par la perte des loyers des actifs « dépôts de bus » apportés ou cédés au nouvel ensemble constitué de l'OPPCI Transimmo et ses filiales à partir de septembre 2016 (1,5 M€ de loyer sur la période) non compensée par les loyers relatifs à la l'acquisition, en avril 2016, du portefeuille de 7 centres d'entretien de poids lourds exploités par le Groupe FPLS (0,7 M€ sur la période 2016). Retraitée de ces deux éléments et à périmètre constant, l'évolution des loyers est stable. Jusqu'à fin 2013, l'ANR publié par le Groupe ne tenait pas compte de la valorisation de l'activité d'asset management. Pour la première fois, au 31 décembre 2014, cette activité a atteint une maturité suffisante, renforcée en 2015 par l'acquisition et le développement de la société Voisin. Depuis cette date, elle fait l'objet d'une évaluation par un expert indépendant. Elle contribue respectivement à hauteur de 15,87 € par action à l'ANR EPRA et 12,88 € par action à l'ANR Triple Net (contre respectivement 10,04 € par action pour l'ANR EPRA et 8,77 € par action pour l'ANR Triple Net en 2015) Ainsi, le ratio endettement net sur juste valeur des actifs (composé du portefeuille locatif propre de Foncière Atland, des actifs en cours de construction à leur valeur de marché et de la juste valeur des titres des sociétés non consolidées constituées dans le cadre de partenariats et club-deals) s'élève à 31% à fin décembre 2016 contre 51,9% fin 2015. La conjonction des perspectives de croissance, du développement de l'activité de gestion, des livraisons de projets en développement et d'un coût de la dette maîtrisé permet au Groupe d'envisager la distribution progressive d'un dividende dans le respect des obligations de distribution du régime des Sociétés d'Investissements Immobiliers Cotées (SIIC), et apprécié, pour chaque exercice, en fonction des résultats distribuables de la Société, de sa situation financière et de tout autre facteur jugé pertinent.


CALGARY, ALBERTA--(Marketwired - May 5, 2017) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada) today announced net income attributable to common shares for first quarter 2017 of $643 million or $0.74 per share compared to net income of $252 million or $0.36 per share for the same period in 2016. Comparable earnings for first quarter 2017 were $698 million or $0.81 per share compared to $494 million or $0.70 per share for the same period in 2016. TransCanada's Board of Directors also declared a quarterly dividend of $0.625 per common share for the quarter ending June 30, 2017, equivalent to $2.50 per common share on an annualized basis. "We generated record first quarter financial results, excluding specific items," said Russ Girling, TransCanada's president and chief executive officer. "Comparable earnings per share increased 16 per cent compared to first quarter 2016 primarily due to strong performance across our Natural Gas Pipelines business, including Columbia which was acquired in mid-2016, while net cash provided by operations reached $1.3 billion." "Today we are advancing a $23 billion near-term capital program that is expected to generate significant growth in earnings and cash flow and support an expected annual dividend growth rate at the upper end of an eight to 10 per cent range through 2020," added Girling. "To date we have invested $7.5 billion in these projects and are well positioned to both execute and fund the remainder of the program over the next few years. In addition, we concluded the purchase of Columbia Pipeline Partners LP which results in 100 per cent ownership in the core Columbia assets and further simplifies our corporate structure." "We also continue to progress a number of additional medium to longer-term organic growth opportunities in our three core businesses of natural gas pipelines, liquids pipelines and energy in Canada, the United States and Mexico. Those include Keystone XL and the Bruce Power life extension agreement. During the first quarter, we were very pleased to receive a U.S. Presidential Permit for Keystone XL and are now in the process of seeking regulatory approval in Nebraska while progressing commercial discussions with our customers. Success in advancing these or other growth initiatives could augment or extend the Company's dividend growth outlook through 2020 and beyond," concluded Girling. Net income attributable to common shares increased by $391 million to $643 million or $0.74 per share for the three months ended March 31, 2017 compared to the same period last year. Net income per common share in 2017 includes the dilutive effect of issuing 161 million common shares in 2016. First quarter 2017 included a charge of $24 million after-tax for integration-related costs associated with the acquisition of Columbia, a $10 million after-tax charge for costs related to the monetization of our U.S. Northeast power business, a $7 million after-tax charge related to the maintenance of Keystone XL assets and a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets. First quarter 2016 results included a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs, a $26 million after-tax charge relating to costs associated with the acquisition of Columbia, a $6 million after-tax charge related to Keystone XL costs for the maintenance and liquidation of project assets and a $3 million after-tax loss on the sale of TC Offshore which closed in March 2016. All of these specific items plus risk management activities are excluded from comparable earnings. Comparable earnings for first quarter 2017 were $698 million or $0.81 per share compared to $494 million or $0.70 per share for the same period in 2016, an increase of $204 million or $0.11 per share and includes the dilutive effect of issuing 161 million common shares in 2016. The 2017 increase in comparable earnings was primarily due to the net effect of higher contributions from U.S. Natural Gas Pipelines primarily due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from higher rates effective August 1, 2016, a higher contribution from Mexican Natural Gas Pipelines due to incremental earnings from the Mazatlán and Topolobampo pipelines, higher earnings primarily from U.S. Power due to depreciation no longer being recorded effective November 1, 2016 on these assets along with higher realized power prices and higher earnings from Western Power following the termination of the Alberta PPAs in 2016. These increases were partially offset by higher interest expense as a result of debt assumed in the Columbia acquisition and long-term debt issuances and lower earnings from Bruce Power mainly due to lower gains from contracting activities and higher interest expense partially offset by higher volumes resulting from fewer outage days. We will hold a teleconference and webcast on Friday, May 5, 2017 to discuss our first quarter 2017 financial results. Russ Girling, TransCanada President and Chief Executive Officer, and Don Marchand, Executive Vice-President and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 12:30 p.m. (MT) / 2:30 p.m. (ET). Members of the investment community and other interested parties are invited to participate by calling 800.408.3053 or 905.694.9451 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com. A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on May 12, 2017. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 8663009. The unaudited interim condensed Consolidated Financial Statements and Management's Discussion and Analysis (MD&A) are available under TransCanada's profile on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com. With more than 65 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 91,500 kilometres (56,900 miles), tapping into virtually all major gas supply basins in North America. TransCanada is the continent's largest provider of gas storage and related services with 653 billion cubic feet of storage capacity. A large independent power producer, TransCanada owns or has interests in over 10,100 megawatts of power generation in Canada and the United States. TransCanada is also the developer and operator of one of North America's leading liquids pipeline systems that extends over 4,300 kilometres (2,700 miles) connecting growing continental oil supplies to key markets and refineries. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com and our blog to learn more, or connect with us on social media and 3BL Media. This release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "believe", "may", "will", "should", "estimate", "intend" or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future plans and financial outlook. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to the Quarterly Report to Shareholders dated May 4, 2017 and 2016 Annual Report filed under TransCanada's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov. This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, comparable distributable cash flow, comparable funds generated from operations, comparable earnings per share and comparable distributable cash flow per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada's Quarterly Report to Shareholders dated May 4, 2017. This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three months ended March 31, 2017, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months ended March 31, 2017 which have been prepared in accordance with U.S. GAAP. This MD&A should also be read in conjunction with our December 31, 2016 audited consolidated financial statements and notes and the MD&A in our 2016 Annual Report. We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall. Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words. Forward-looking statements in this MD&A include information about the following, among other things: Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A. Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties: You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2016 Annual Report. As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law. You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com). This MD&A references the following non-GAAP measures: These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be similar to measures presented by other entities. We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include: We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations. The following table identifies our non-GAAP measures against their equivalent GAAP measures. Comparable earnings represent earnings or loss attributable to common shareholders on a consolidated basis adjusted for specific items. Comparable earnings is comprised of segmented earnings, interest expense, AFUDC, interest income and other, income taxes and non-controlling interests adjusted for the specific items. See the Consolidated results section for a reconciliation to net income attributable to common shares. Comparable EBIT represents segmented earnings adjusted for the specific items described above. We use comparable EBIT as a measure of our earnings from ongoing operations as it is a useful measure of our performance and an effective tool for evaluating trends in each segment. Comparable EBITDA is calculated the same way as comparable EBIT but excludes the non-cash charges for depreciation and amortization. See the Reconciliation of non-GAAP measures section for a reconciliation to segmented earnings. Funds generated from operations and comparable funds generated from operations Funds generated from operations reflects net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. Comparable funds generated from operations is adjusted for the cash impact of specific items noted above. See the Financial condition section for a reconciliation to net cash provided by operations. We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. Comparable distributable cash flow is defined as comparable funds generated from operations less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability, and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, in certain of our rate-regulated businesses, maintenance capital expenditures are included in their respective rate bases, on which we earn a regulated return and recover depreciation through future tolls. See the Financial condition section for a reconciliation to net cash provided by operations. Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change. Net income attributable to common shares increased by $391 million or $0.38 per share for the three months ended March 31, 2017 compared to the same period in 2016. Net income per common share in 2017 included the dilutive effect of issuing 161 million common shares in 2016. Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings. Comparable earnings increased by $204 million for the three months ended March 31, 2017 compared to the same period in 2016 as discussed below in the reconciliation of net income to comparable earnings. Comparable earnings increased by $204 million or $0.11 per share for the three months ended March 31, 2017 compared to the same period in 2016. Comparable earnings per share in 2017 included the dilutive effect of issuing 161 million common shares in 2016. The year-over-year increase in comparable earnings was primarily the net effect of: We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow. Our capital program consists of approximately $23 billion of near-term projects and approximately $48 billion of medium to longer-term projects. Amounts presented exclude maintenance capital expenditures, capitalized interest and AFUDC. All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits. The medium to longer-term projects have greater uncertainty with respect to timing and estimated project costs. The expected in-service dates of these projects are post-2020, and costs provided in the schedule below reflect the most recent costs for each project as filed with the various regulatory authorities or otherwise determined. These projects have all been commercially secured or, in the case of Keystone XL, commercial support is expected to be achieved. All these projects are subject to approvals that include sponsor FID and/or complex regulatory processes. Our overall comparable earnings outlook for 2017 remains consistent with what was previously included in the 2016 Annual Report. Our expected total capital expenditures as outlined in the 2016 Annual Report remain unchanged. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change. Canadian Natural Gas Pipelines segmented earnings increased by $10 million for the three months ended March 31, 2017 compared to the same period in 2016 and are equivalent to comparable EBIT. Net income and comparable EBITDA for our rate-regulated Canadian Natural Gas Pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis. Net income for the NGTL System increased by $9 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to a higher average investment base and OM&A incentive earnings recorded in 2017. The NGTL System is operating under the two-year 2016-2017 Revenue Requirement Settlement which includes an ROE of 10.1 per cent on 40 per cent deemed equity and a mechanism for sharing variances above and below a fixed annual OM&A amount with flow-through treatment of all other costs. Net income for the Canadian Mainline increased by $2 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to higher incentive earnings, partially offset by a lower average investment base. The Canadian Mainline is operating under the NEB 2014 Decision which includes an approved ROE of 10.1 per cent on a 40 per cent deemed equity with a possible range of achieved outcomes between 8.7 per cent and 11.5 per cent. The decision also includes an incentive mechanism that has both upside and downside risk and a $20 million annual after-tax contribution from us. Depreciation and amortization increased by $6 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to the NGTL System facilities that were placed in service. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change. U.S. Natural Gas Pipelines segmented earnings increased by $294 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the acquisition of Columbia and included a $10 million pre-tax charge, primarily due to integration-related costs associated with the Columbia acquisition. Segmented earnings for the three months ended March 31, 2016 included a $4 million pre-tax loss provision ($3 million after tax) as a result of a December 2015 agreement to sell TC Offshore which closed in early 2016. These amounts have been excluded from our calculation of comparable EBIT. Earnings for our U.S. Natural Gas Pipelines operations, which include Columbia effective July 1, 2016, are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services. Columbia and ANR results are also affected by the contracting and pricing of their storage capacity and commodity sales. Transmission and storage revenues are generally higher in winter months due to increased seasonal demand for our services. Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$292 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of: Depreciation and amortization increased by US$61 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to the acquisition of Columbia. US$5 million of depreciation related to Columbia information system assets retired as part of the Columbia integration process has been excluded from comparable EBIT and included as part of integration-related costs to arrive at segmented earnings. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change. Mexico Natural Gas Pipelines segmented earnings increased by $73 million for the three months ended March 31, 2017 compared to the same period in 2016 and are equivalent to comparable EBIT. Earnings from our Mexico operations are underpinned by long-term, stable, primarily U.S. dollar-denominated revenue contracts, and are affected by the cost of providing service. Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$67 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of: Depreciation and amortization increased by US$11 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the commencement of depreciation on Topolobampo and Mazatlán. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change. Liquids Pipelines segmented earnings increased by $15 million for the three months ended March 31, 2017 compared to the same period in 2016 and included pre-tax charges related to Keystone XL costs for the maintenance of project assets which are being expensed pending further advancement of the project as well as unrealized losses from changes in the fair value of derivatives related to our liquids marketing business in 2016. Keystone Pipeline System earnings are generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings. Comparable EBITDA for Liquids Pipelines increased by $16 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of: Depreciation and amortization increased by $5 million for the three months ended March 31, 2017 compared to the same period in 2016 as a result of new facilities being placed in service. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change. Energy segmented earnings increased by $324 million for the three months ended March 31, 2017 compared to the same period in 2016 and included the following specific items: The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impacts of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations. The remainder of the Energy segmented earnings are equivalent to comparable EBIT and are discussed in the following sections. The following are the components of comparable EBITDA and comparable EBIT. Comparable EBITDA for Western Power increased by $26 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to the termination of the Alberta PPAs. Results from the Alberta PPAs are included up to March 7, 2016 when we terminated the PPAs for the Sundance A, Sundance B and Sheerness facilities. Depreciation and amortization decreased by $10 million for the three months ended March 31, 2017 compared to the same period in 2016 following the termination of the Alberta PPAs. Comparable EBITDA for Eastern Power decreased by $8 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to lower earnings on the sale of unused natural gas transportation. Bruce Power results reflect our proportionate share. The following is our proportionate share of the components of comparable EBITDA and comparable EBIT. Comparable EBITDA from Bruce Power decreased by $23 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to lower gains from contracting activities and higher interest expense, partially offset by higher volumes resulting from fewer outage days. Planned outage work which commenced on Unit 5 in February 2017 is scheduled to be completed in second quarter 2017. Planned outages for Units 3 and 6 are scheduled to occur in the second half of 2017. The overall average plant availability percentage in 2017 is expected to be approximately 90 per cent. Comparable EBITDA for Natural Gas Storage and Other increased by $12 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to increased third party storage revenues as a result of higher realized natural gas storage price spreads. U.S. POWER (monetization expected to close in the first half of 2017) The following are the components of comparable EBITDA and comparable EBIT. Comparable EBITDA for U.S. Power decreased by US$21 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of: Average New York Zone J spot capacity prices were approximately 41 per cent lower for the three months ended March 31, 2017 compared to the same period in 2016. The decrease in spot capacity prices and the offsetting impact of hedging activities resulted in lower realized capacity prices in New York. This was primarily due to an increase in demonstrated capability from existing resources in the New York City's Zone J market. Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three months ended March 31, 2017 than the same period in 2016 as we have expanded our customer base in the PJM and New England markets. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change. Corporate segmented losses increased by $6 million for the three months ended March 31, 2017 compared to the same period in 2016. Comparable EBIT in 2017 and 2016 excluded acquisition and integration costs associated with the acquisition of Columbia. Interest expense increased by $80 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt issuances, partially offset by Canadian and U.S. dollar-denominated debt maturities. AFUDC was consistent for the three months ended March 31, 2017 compared to the same period in 2016. The increase in Canadian dollar-denominated AFUDC is primarily due to increased investment in our NGTL System expansions, while the decrease in our U.S. dollar-denominated AFUDC is primarily due to the completed construction of Topolobampo and Mazatlán pipelines, partially offset by our increased investment in projects acquired as part of the Columbia acquisition on July 1, 2016. Interest income and other decreased by $80 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of: Income tax expense included in comparable earnings increased by $64 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly as a result of higher pre-tax earnings in 2017 compared to 2016 and changes in the proportion of income earned between Canadian and foreign jurisdictions. Net income attributable to non-controlling interests increased by $10 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the acquisition of Columbia which included a non-controlling interest in CPPL. On February 17, 2017, we acquired all outstanding publicly held common units of CPPL. Preferred share dividends increased by $19 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the issuance of Series 13 and Series 15 preferred shares in April 2016 and November 2016, respectively. The NGTL System currently has a $5.1 billion near-term capital program for completion to 2020. This includes the recently filed application to amend approvals for the North Montney project, with a revised $1.4 billion capital cost estimate, and the recently approved Towerbirch Expansion project. On March 20, 2017, we filed an application with the NEB for a variance to the existing approvals for North Montney to remove the condition that the project could only proceed once a positive FID is made for the Pacific Northwest LNG project. North Montney is now underpinned by restructured, 20-year commercial contracts with shippers and is not dependent on, but still accommodates, the LNG project proceeding. On April 19, 2017, the NEB granted an interim extension of the sunset clause that was due to expire June 10, 2017 to March 31, 2018. In-service dates are planned for April 2019 and April 2020, subject to regulatory approval. On March 10, 2017, the Government of Canada approved the $0.4 billion Towerbirch Expansion project. The project consists of 55 km (34 miles) of 36-inch loop to the Groundbirch Mainline plus 32 km (20 miles) of new 30-inch pipe and four new meter stations. In February 2017, the B.C. Government approved the environmental assessment with conditions that have since been met. On March 13, 2017, we announced the successful conclusion of the long-term fixed-price open season on the Canadian Mainline for service from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The open season resulted in binding, long-term contracts from WCSB gas producers to transport 1.5 PJ/d of natural gas at a simplified toll of $0.77/GJ. The term of each contract is 10 years and includes early termination rights that can be exercised following the initial five years of service and upon payment of an increased toll for the final two years of the contract. The application to the NEB for approval of the service was filed on April 26, 2017 and included the request to implement the service starting November 1, 2017. Sale of Iroquois and PNGTS to TC PipeLines, LP On May 4, 2017, we announced agreements to sell a 49.3 per cent interest in Iroquois Gas Transmission System, LP (Iroquois), together with our remaining 11.8 per cent interest in Portland Natural Gas Transmission System (PNGTS), to our master limited partnership, TC PipeLines, LP for US$765 million. The transaction is comprised of US$597 million in cash and the assumption of US$168 million in proportionate debt at Iroquois and PNGTS. The transaction is expected to close mid-2017. FERC approvals and Notices to Proceed were received in first quarter 2017 for both the Leach XPress and Rayne XPress projects allowing construction activities to begin. The US$1.4 billion Leach XPress project and the US$0.4 billion Rayne XPress project are expected to be in service in November 2017. We received our Environmental Assessment on March 24, 2017 for the WB XPress project and expect to receive our FERC order later this summer after additional FERC Commissioners are appointed and a quorum is re-established. The US$0.8 billion project remains on schedule with Phase I expected to be in-service in June 2018 and Phase II in November 2018. Great Lakes is required to file a new section 4 rate case with rates effective no later than January 1, 2018 as part of the settlement agreement with shippers approved November 2013. On March 31, 2017, Great Lakes submitted a General Section 4 Rate Filing and Tariff Changes with the FERC. The rates proposed in the filing will be effective on October 1, 2017, subject to refund, if alternate resolution to the proceeding is not reached prior to that date. Great Lakes has initiated customer discussions regarding the details of the filing and will seek to achieve a mutually beneficial resolution through settlement with its customers. On February 17, 2017, we completed the acquisition, for cash, of all outstanding publicly held common units of CPPL at a price of US$17.00 and a stub period distribution payment of US$0.10 per common unit for an aggregate transaction value of US$921 million. In January 2017, the NEB appointed three new panel members to undertake the review of the Energy East and Eastern Mainline projects. The new NEB panel members voided all decisions made by the previous hearing panel and will decide how to move forward with the hearing. We are not required to refile the application and parties will not be required to reapply for intervener status, however, all other proceedings and associated deadlines are no longer applicable. If the new panel members determine that the project application is complete, the 21-month NEB review period will commence. On March 29, 2017, the NEB issued its decision to hear the Energy East and Eastern Mainline projects together, however, a hearing date has not yet been announced by the NEB. In February 2017, we filed an application with the Nebraska Public Service Commission (PSC) seeking approval for the Keystone XL pipeline route through that state. A hearing on the application is scheduled in August 2017 and a final decision on the proposed route is expected by the end of November 2017. In March 2017, the U.S. Department of State issued a U.S. Presidential Permit authorizing construction of the U.S./Canada border crossing facilities of the Keystone XL pipeline. We discontinued our claim under Chapter 11 of the North American Free Trade Agreement and have also withdrawn the U.S. Constitutional challenge. With the receipt of the U.S. Presidential Permit, we will continue to work through the Nebraska PSC process. Given the passage of time since the Keystone XL Presidential Permit application was previously denied in November 2015, we are updating the shipping contracts and anticipate the core contract shipper group will be modified with the introduction of new shippers and reductions in volume commitments by other shippers. We expect this transition to be complete within a few months and would anticipate commercial support for the project to be substantially similar to that which existed when we first applied for Keystone XL. In late March 2017, the 972 MW Unit 30 at the Ravenswood Generating Station experienced an unplanned outage as a result of a problem on the generator associated with the low pressure turbine. Repairs to the unit are underway and the unit is expected to be returned to service in second quarter 2017. The incident is not expected to materially affect the sale process for Ravenswood. The sale of TC Hydro to Great River Hydro, LLC closed on April 19, 2017 for proceeds of US$1.065 billion resulting in a gain of approximately $710 million ($440 million after tax) before post-closing adjustments which will be recorded in second quarter 2017. The proceeds received were used to reduce the Columbia acquisition bridge credit facility. The sale of Ravenswood, Ironwood, Ocean State Power and Kibby to Helix Generation, LLC is expected to close in second quarter 2017. We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings. We believe we have the financial capacity to fund our existing capital program through our predictable and growing cash flow from operations, access to capital markets (including through the establishment of an at-the-market equity issuance program, if applicable), our DRP, portfolio management including proceeds from the anticipated drop down of natural gas pipeline assets to TC PipeLines, LP, cash on hand and substantial committed credit facilities. At March 31, 2017, our current assets were $8.0 billion and current liabilities were $9.1 billion, leaving us with a working capital deficit of $1.1 billion compared to a surplus of $0.4 billion at December 31, 2016. Our working capital deficiency is considered to be in the normal course of business and is managed through: Comparable funds generated from operations increased $259 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the increase in comparable earnings. Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation. The increase from first quarter 2016 to 2017 was driven by an increase in comparable funds generated from operations and lower maintenance capital expenditures, primarily at Bruce Power, partially offset by higher dividends on preferred shares and distributions paid to non-controlling interests. Comparable distributable cash flow per share in 2017 included the dilutive effect of issuing 161 million common shares in 2016. Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, in certain of our rate-regulated businesses maintenance capital expenditures are included in their respective rate bases on which we earn a regulated return and recover depreciation through future tolls. The following provides a breakdown of maintenance capital expenditures: Capital expenditures in 2017 were primarily related to: Costs incurred on capital projects under development primarily relate to the Energy East and LNG pipeline projects. Contributions to equity investments have increased in 2017 compared to 2016 primarily due to our investments in Sur de Texas and Bruce Power. The increase in other distributions from equity investments is primarily due to distributions from Bruce Power. In first quarter 2017, Bruce Power issued bonds to fund its capital program and make distributions to its partners which resulted in $362 million being received by us. On February 17, 2017, we acquired all outstanding common units of CPPL for US$921 million. In March 2017, the Trust issued US$1.5 billion of Trust Notes - Series 2017-A (Trust Notes) to third party investors with a fixed interest rate of 5.30 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.55 per cent, including a 0.25 per cent administration charge. The rate will reset commencing March 2027 until March 2047 to the three month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the three month LIBOR plus 4.208 per cent per annum. The Junior subordinated notes are callable at TCPL's option at any time on or after March 15, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL. Under our DRP, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. Common shares are issued from treasury at a discount of two per cent. In the most recent quarter, approximately 40 per cent of common share dividends declared were designated to be reinvested by shareholders in TransCanada common shares under the DRP. During first quarter 2017, 1.2 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$69 million. At March 31, 2017, our ownership interest in TC PipeLines, LP was 26.4 per cent as a result of issuances under the ATM program and resulting dilution. In connection with the late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon the filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the ATM program may have a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP. In March 2017, rescission rights on 0.4 million common units expired. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit. On May 4, 2017, we declared quarterly dividends as follows: We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for general corporate purposes as well as acquisition bridge facilities to support the interim financing of the Columbia acquisition. In addition, we have demand credit facilities that are also used for general corporate purposes, including issuing letters of credit and providing additional liquidity. At May 4, 2017, we had a total of $11.1 billion of committed revolving and demand credit facilities and $2.8 million of acquisition bridge facilities including: At May 4, 2017, our operated affiliates had an additional $0.7 billion of undrawn capacity on committed credit facilities. See Financial risks and financial instruments for more information about liquidity, market and other risks. Our capital commitments have decreased by approximately $0.5 billion since December 31, 2016 primarily as a result of decreased commitments for the NGTL System and Sur de Texas natural gas pipelines due to the progression of construction. Transportation by others commitments have increased by approximately $0.7 billion since December 31, 2016, primarily related to Canadian Mainline contracts. Our commitments at March 31, 2017 include operating leases and other purchase obligations related to our U.S. Northeast power business. At the close of the sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power, our commitments are expected to decrease by $42 million in 2017, $97 million in 2018, $79 million in 2019, $29 million in 2020, $23 million in 2021 and $259 million in 2022 and beyond. There were no other material changes to our contractual obligations in first quarter 2017 or to payments due in the next five years or after. See the MD&A in our 2016 Annual Report for more information about our contractual obligations. Financial risks and financial instruments We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance. See our 2016 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2016. We manage our liquidity risk by continuously forecasting our cash flow for a 12 month period to ensure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions. We have exposure to counterparty credit risk in the following areas: We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2017, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired. We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. We generate revenues and incur expenses that are denominated in currencies other than Canadian dollars. As a result, our earnings and cash flows are exposed to currency fluctuations. A portion of our businesses generate earnings in U.S. dollars, but since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives. We have floating interest rate debt which subjects us to interest rate cash flow risk. We manage this using a combination of interest rate swaps and options. The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly offset by interest on U.S. dollar-denominated long-term debt, as set out in the table below. Comparable EBIT is a non-GAAP measure. See our Reconciliation of non-GAAP measures section for more information. We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options. The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions. We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify and are designated for hedge accounting treatment. The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period. The balance sheet classification of the fair value of derivative instruments is as follows: The following summary does not include hedges of our net investment in foreign operations. The components of the condensed consolidated statement of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests is as follows: Derivatives often contain financial assurance provisions that may require us to provide collateral if a credit risk related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits. Based on contracts in place and market prices at March 31, 2017, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $20 million (December 31, 2016 - $19 million), with collateral provided in the normal course of business of nil (December 31, 2016 - nil). If the credit-risk-related contingent features in these agreements were triggered on March 31, 2017, we would have been required to provide additional collateral of $20 million (December 31, 2016 - $19 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise. Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2017, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level. There were no changes in first quarter 2017 that had or are likely to have a material impact on our internal control over financial reporting. When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2016 Annual Report. Our significant accounting policies have remained unchanged since December 31, 2016 other than described below. You can find a summary of our significant accounting policies in our 2016 Annual Report. Changes in accounting policies for 2017 In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on our consolidated balance sheet. In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance was effective January 1, 2017, was applied prospectively and did not result in any impact on our consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. In these situations, when an increase in ownership interest in an investment qualifies it for equity method accounting, the new guidance eliminates the requirement to retroactively apply the equity method of accounting. This new guidance was effective January 1, 2017, was applied prospectively and did not result in any impact on our consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. We have elected to account for forfeitures when they occur. This new guidance was effective, on a prospective basis, January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to 2017 opening retained earnings and the recognition of a deferred tax asset related to employee share-based payments made prior to the adoption of this standard. In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entity (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions. In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a five-step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. We will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. We are evaluating both methods of adoption as we work through our analysis. We have identified all existing customer contracts that are within the scope of the new guidance and we are in the process of analyzing individual contracts or groups of contracts on a segmented basis to identify any significant changes in how revenues are recognized as a result of implementing the new standard. As we continue our contract analysis, we will also quantify the impact, if any, on prior period revenues. We will address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard. We are currently evaluating the impact on our consolidated financial statements as well as the development of disclosures required under the new standard. In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires us to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and specifies the method of adoption for each component of the guidance. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. Lessees may also be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019. We are currently identifying existing lease agreements that may have an impact on our consolidated financial statements as a result of adopting this new guidance. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. In October 2016, the FASB issued new guidance on income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied on a modified retrospective basis. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The amounts of restricted cash and cash equivalents will be included in Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively, however, early adoption is permitted. In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, with early adoption permitted. In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of the net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of the net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. We are currently evaluating the impact of the adoption of this guidance on our consolidated financial statements. In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT Quarter-over-quarter revenues and net income sometimes fluctuate, the causes of which vary across our business segments. In our Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines segments, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of: In Liquids Pipelines, revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income are also affected by: In Energy, quarter-over-quarter revenues and net income are affected by: We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations. In third quarter 2015, comparable earnings excluded a charge of $6 million after-tax for severance costs as part of a restructuring initiative to maximize the effectiveness and efficiency of our existing operations. In second quarter 2015, comparable earnings excluded a $34 million adjustment to income tax expense due to the enactment of an increase in the Alberta corporate income tax rate in June 2015 and a charge of $8 million after-tax for severance costs primarily as a result of the restructuring of our major projects group in response to delayed timelines on certain of our major projects along with a continued focus on enhancing the efficiency and effectiveness of our operations. These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada's annual audited consolidated financial statements for the year ended December 31, 2016, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada's 2016 Annual Report. These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2016 audited consolidated financial statements included in TransCanada's 2016 Annual Report. Certain comparative figures have been reclassified to conform with the current period's presentation. Earnings for interim periods may not be indicative of results for the fiscal year in the Company's natural gas pipelines segments due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company's Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company's investments in electrical power generation plants and non-regulated gas storage facilities. USE OF ESTIMATES AND JUDGEMENTS In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies included in the consolidated financial statements for the year ended December 31, 2016, except as described in Note 2, Accounting changes. CHANGES IN ACCOUNTING POLICIES FOR 2017 In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Company's consolidated balance sheet. In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance was effective January 1, 2017, was applied prospectively and did not result in any impact on the Company's consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. In these situations, when an increase in ownership interest in an investment qualifies it for equity method accounting, the new guidance eliminates the requirement to retroactively apply the equity method of accounting. This new guidance was effective January 1, 2017, was applied prospectively and did not result in any impact on the Company's consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. The Company has elected to account for forfeitures when they occur. This new guidance was effective January 1, 2017 and resulted in a cumulative-effect adjustment of $12 million to opening retained earnings and the recognition of a deferred tax asset related to employee share-based payments made prior to the adoption of this standard. In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a VIE, it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The new guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a five-step model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Company will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Company is evaluating both methods of adoption as it works through its analysis. The Company has identified all existing customer contracts that are within the scope of the new guidance and is in the process of analyzing individual contracts or groups of contracts on a segmented basis to identify any significant changes in how revenues are recognized as a result of implementing the new standard. As the Company continues its contract analysis, it will also quantify the impact, if any, on prior period revenues. The Company will address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard. The Company is currently evaluating the impact on its consolidated financial statements as well as the development of disclosures required under the new standard. In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018 and specifies the method of adoption for each component of the guidance. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. Lessees may also be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019. The Company is currently identifying existing lease agreements that may have an impact on its consolidated financial statements as a result of adopting this new guidance. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. In October 2016, the FASB issued new guidance on income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance is effective January 1, 2018 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The amounts of restricted cash and cash equivalents will be included in Cash and cash equivalents when reconciling the beginning of year and end of year total amounts on the statement of cash flows. This new guidance is effective January 1, 2018 and will be applied retrospectively, however, early adoption is permitted. In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit's carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, with early adoption permitted. In March 2017, the FASB issued new guidance that will require entities to disaggregate the current service cost component from the other components of the net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of the net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance is effective January 1, 2018. The Company is currently evaluating the impact of the adoption of this guidance on its consolidated financial statements. In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. The Company's planned monetization of its U.S. Northeast power business, for the purpose of permanently financing a portion of the Columbia acquisition, includes the sale of Ravenswood, Ironwood, Kibby Wind, Ocean State Power, TC Hydro and the marketing business, TransCanada Power Marketing (TCPM). On November 1, 2016, the Company entered into agreements to sell all of these assets except TCPM. The sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party for proceeds of approximately US$2.2 billion is expected to close in the second quarter of 2017. As a result, the Company recorded a loss of approximately $829 million ($863 million after tax) in 2016 which included the impact of an estimated $70 million of foreign currency translation gains to be reclassified from AOCI to Net income on close. At March 31, 2017, the related assets and liabilities were classified as held for sale in the Energy segment and were recorded at their fair values less costs to sell based on the proceeds expected on the close of this sale. At March 31, 2017, the assets and liabilities related to TC Hydro were also classified as held for sale in the Energy segment. Subsequently, on April 19, 2017, the Company closed the sale of TC Hydro for gross proceeds of US$1.065 billion, subject to post-closing adjustments. As a result, on April 19, 2017, the Company recorded a gain on sale of approximately $710 million ($440 million after tax) including the impact of an estimated $5 million of foreign currency translation gains. The proceeds received were used to reduce the outstanding balance on the acquisition bridge facility. As of March 31, 2017, TCPM did not meet the criteria to be classified as held for sale. The following table details the assets and liabilities held for sale at March 31, 2017. The effective tax rates for the three-month periods ended March 31, 2017 and 2016 were 21 per cent and 17 per cent, respectively. The higher effective tax rate in 2017 was primarily the result of changes in the proportion of income earned between Canadian and foreign jurisdictions. The Company retired/repaid long-term debt in the three months ended March 31, 2017 as follows: In the three months ended March 31, 2017, TransCanada capitalized interest related to capital projects of $45 million (2016 - $41 million). In March 2017, the Trust issued US$1.5 billion of Trust Notes - Series 2017-A (Trust Notes) to third party investors with a fixed interest rate of 5.30 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.55 per cent, including a 0.25 per cent administration charge. The rate will reset commencing March 2027 until March 2047 to the three month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the three month LIBOR plus 4.208 per cent per annum. The Junior subordinated notes are callable at TCPL's option at any time on or after March 15, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL. On February 17, 2017, the Company acquired all outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 and a stub period distribution payment of US$0.10 per common unit for an aggregate transaction value of US$921 million. As this was a transaction under common control, it was recognized in equity. At December 31, 2016, the entire $1,073 million (US$799 million) of the Company's non-controlling interest in CPPL was recorded as Common units subject to rescission or redemption on the condensed consolidated balance sheet. At March 31, 2017, $82 million (US$63 million) (December 31, 2016 - $106 million (US$82 million)) was recorded as Common units subject to rescission or redemption on the condensed consolidated balance sheet. In March 2017, rescission rights on 0.4 million TC PipeLines, LP common units expired and $24 million was reclassified to equity. The Company continued to classify $82 million with respect to 1.2 million common units outside Equity because the potential rescission rights of the units are not within the control of the Company. At March 31, 2017, no unitholder has claimed or attempted to exercise any rescission rights to date and these remaining rescission rights expire one year from the date of purchase of the units which ranges from April 1, 2016 to May 19, 2016. 9. Other comprehensive loss and accumulated other comprehensive loss Components of other comprehensive loss, including the portion attributable to non-controlling interests and related tax effects, are as follows: The changes in AOCI by component are as follows: Details about reclassifications out of AOCI into the consolidated statement of income are as follows: The net benefit cost recognized for the Company's defined benefit pension plans (DB Plan) and other post-retirement benefit plans is as follows: Effective April 1, 2017, the Company closed its U.S. DB Plan to non-union new entrants. As of April 1, 2017, all non-union hires will participate in the existing defined contribution plan (DC Plan). Non-union U.S. employees who currently participate in the DC Plan will have one final election opportunity to become a member of the DB Plan as of January 1, 2018. TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings and cash flow. TransCanada's maximum counterparty credit exposure with respect to financial instruments at March 31, 2017, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At March 31, 2017, there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the period. The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts and options. The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: The fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows: Fair value of non-derivative financial instruments The fair value of the Company's Notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of Long-term debt and Junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments. The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets: The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses period end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period. The balance sheet classification of the fair value of the derivative instruments as at March 31, 2017 is as follows: The balance sheet classification of the fair value of the derivative instruments as at December 31, 2016 is as follows: The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk. The maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: The following summary does not include hedges of the net investment in foreign operations. The components of OCI (Note 9) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2016: With respect to the derivative instruments presented above as at March 31, 2017, the Company provided cash collateral of $310 million (December 31, 2016 - $305 million) and letters of credit of $22 million (December 31, 2016 - $27 million) to its counterparties. The Company held nil (December 31, 2016 - nil) in cash collateral and $3 million (December 31, 2016 - $3 million) in letters of credit from counterparties on asset exposures at March 31, 2017. Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at March 31, 2017, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $20 million (December 31, 2016 - $19 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2016 - nil). If the credit-risk-related contingent features in these agreements were triggered on March 31, 2017, the Company would have been required to provide additional collateral of $20 million (December 31, 2016 - $19 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise. The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2017, are categorized as follows: The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016, are categorized as follows: The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy: A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a less than $1 million change in the fair value of outstanding derivative instruments included in Level III as at March 31, 2017. TransCanada's operating lease commitments at March 31, 2017 include future payments related to our U.S. Northeast power business. At the close of the sale of Ravenswood, TransCanada's commitments are expected to decrease by $3 million in 2017, $53 million in 2018, $35 million in 2019 and $105 million in 2022 and beyond. TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations. In March 2017, the U.S. Department of State issued a U.S. Presidential Permit authorizing construction of the U.S./Canada border crossing facilities of the Keystone XL pipeline. TransCanada discontinued the claim under Chapter 11 of the North American Free Trade Agreement and has also withdrawn the U.S. Constitutional challenge. TransCanada and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the obligations for construction services during the construction of the pipeline. TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been included in other long-term liabilities. Information regarding the Company's guarantees is as follows: The Company consolidates a number of entities that are considered to be VIEs. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity's operations through voting rights or do not substantively participate in the gains and losses of the entity. In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are accounted for as equity investments. The Company's consolidated VIEs consist of legal entities where the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. A significant portion of the Company's assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE's assets can be used for general corporate purposes. The assets and liabilities of the consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE's obligations are as follows: The Company's non-consolidated VIEs consist of legal entities where the Company does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid. The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows: On April 19, 2017, the Company closed the sale of TC Hydro for gross proceeds of US$1.065 billion, subject to post-closing adjustments. The proceeds received were used to reduce the Columbia acquisition bridge credit facility. Refer to Note 4, Assets held for sale, for further information. Sale of Iroquois and PNGTS to TC PipeLines, LP On May 4, 2017, the Company announced agreements to sell a 49.3 per cent interest in Iroquois Gas Transmission System, LP (Iroquois) together with its remaining 11.8 per cent interest in Portland Natural Gas Transmission System (PNGTS), to its master limited partnership, TC PipeLines, LP for US$765 million. The transaction is comprised of US$597 million in cash and the assumption of US$168 million in proportionate debt at Iroquois and PNGTS. The transaction is expected to close mid-2017.


News Article | May 3, 2017
Site: www.spie.org

A novel fabrication procedure is used to produce flexible devices that include inorganic semiconductor nanowires and that can compete with organic devices in terms of brightness. Nitride LEDs are coming to replace other light sources in almost all general lighting, as well as in displays and life-science applications. Inorganic semiconductor devices, however, are naturally mechanically rigid and cannot be used in applications that require mechanical flexibility. Flexible LEDs are therefore currently a topic of intense research, as they are desirable for use in many applications, including rollable displays, wearable intelligent optoelectronics, bendable or implantable light sources, and biomedical devices. At present, flexible devices are mainly fabricated from organic materials. For example, organic LEDs (OLEDs) are already being used commercially in curved TV and smartphone screens. However, OLEDs have worse temporal stability and lower luminescence (especially in the blue spectral range) than nitride semiconductor LEDs. Substantial research efforts are thus being made to fabricate flexible inorganic LEDs.1 The conventional approach for flexible inorganic LED fabrication consists of number of steps, i.e., layer lift-off, microstructuring, and transfer to plastic supports. To avoid the microstructuring step and facilitate the lift-off, it is advantageous to shrink the active element dimensions and to use bottom-up nanostructures (such as nanowires, NWs) rather than 2D films. These NWs—i.e., elongated nanocrystals with a submicrometer diameter—have remarkable mechanical and optoelectronic properties that stem from their anisotropic geometry, high surface-to-volume ratio, and perfect crystallinity. In addition, such NWs are mechanically flexible and can withstand high levels of deformation without suffering plastic relaxation. Efficient LEDs that include nitride NWs have previously been demonstrated, and in our work,2 we make use of nitride NWs as the active material for flexible LEDs. Our polymer-embedded NWs offer an elegant solution to create flexible optoelectronic devices in which we combine the high efficiency and long lifetimes of inorganic semiconductor materials with the high flexibility of polymers. In our devices, the NW arrays—which are embedded in a flexible film and can be lifted-off from their native substrate—can sustain large deformations because of the high flexibility of the individual NWs. Furthermore, the footprints of individual NWs are much smaller than the typical curvature radius of LEDs (i.e., on the order of a few millimeters or more). In our approach, we used catalyst-free metal-organic chemical vapor deposition (MOCVD) to grow self-assembled gallium nitride (GaN) NWs on c-plane sapphire substrates.3 These NWs (with lengths of about 20μm and radii of about 0.5–1.5μm) have core/shell n–p junctions into which we incorporate multiple radial indium gallium nitride (InGaN)/GaN quantum wells. We control the emission color by changing the indium concentration of the InGaN emitting layer. In our actual device fabrication process4—see Figure 1(a)—the NW array is embedded into the polydimethylsiloxane (PDMS), peeled-off from the sapphire host substrate, and we then flip the composite NW/polymer membrane onto an arbitrary substrate to conduct the metal back-contacting. We subsequently flip the layer again and mount it on a flexible substrate (a metal foil or plastic), at which point we front-contact it with a flexible and transparent electrode. For the front contact we chose a silver NW mesh—see Figure 1(b)—which is characterized by mechanical flexibility, good electrical conductivity, and optical transparency. Figure 1. (a) Schematic illustration of the fabrication process for flexible LEDs that are based on a vertical nitride nanowire (NW) array. Ni: Nickel. Au: Gold. Ti: Titanium. (b) Scanning electron microscope image of the spin-coated silver (Ag) NW network on the polydimethylsiloxane (PDMS)/NW membrane. This silver NW network is used to form the transparent top-contact of the device. The protruding LED NWs are circled in red. We have used this technological procedure to fabricate blue and green flexible NW LEDs.4 We find that our devices exhibit typical behavior for nitride NW LEDs, i.e., with a light-up voltage of about 3V. Moreover, our LEDs can be bent to a curvature radius of ±3mm without any degradation of their electrical or luminescent properties. Photographs of our NW LEDs under operation in flat conditions, and during upward or inward bending are shown in Figure 2. Our flexible NW LEDs also have reasonable stability over time, unlike conventional OLEDs. Indeed, storing our devices in ambient conditions for several months does not cause their properties to degrade, whereas the lifetime of an OLED without encapsulation is limited to only several hours. Figure 2. Photographs of the blue (top), green (middle), and white (bottom) flexible LEDs at operation under different bending conditions. We have also used our composite NW/polymer membrane architecture to realize a flexible white LED (see Figure 2). To achieve this device we follow the standard approach of down-converting blue emission with yellow phosphors, i.e., to get white light from a blue–yellow mixture. To adapt this scheme for our flexible NW LEDs, we added yellow cerium-doped yttrium aluminum garnet phosphors into the PDMS layer between the NWs and covered the surface with an additional phosphorous-doped PDMS cap.5 The phosphor particles we use are smaller than 0.5μm so that they can fill the gaps between the NWs. The light that is emitted by the NWs is thus partially converted by the phosphors from blue to yellow, and we achieve a broad spectrum (covering almost the full visible range). Our NW membrane lift-off and transfer procedure allows free-standing layers of NW materials with different bandgaps to be assembled without any constraints relating to lattice-matching or compatability of growth conditions. Our approach therefore provides a large amount of design freedom and modularity, i.e., because it enables materials with very different physical and chemical properties to be combined (which cannot be achieved with monolithic growth). We made use of this modularity to demonstrate a two-color device, in which we combined two flexible LED layers that contain different active NWs: see Figure 3(a). In this device, we mounted a fully transparent flexible blue LED on top of a green LED. We were able to bias the two LEDs separately by producing either blue or green light, or by simultaneously producing a light mixture. We show the electrolumniscence spectra from the different layers of this bicolor flexible LED in Figure 3(b). Figure 3. (a) Schematic illustration of a blue-green two-color flexible NW LED, in which a fully transparent blue LED is mounted on top of a green LED. The two LEDs are biased separately (i.e., V1 and V2). (b) Electroluminescence (EL) spectra (in arbitrary units) of the two-color flexible NW LED. The blue, green, and red curves show the emissions from the top layer, bottom layer, and both layers together (biased simultaneously), respectively. In summary, we have successfully demonstrated a new procedure for the fabrication of efficient, flexible nitride NW LEDs. In our approach, we embed GaN NWs within a PDMS membrane and have realized blue, green, and white LEDs that exhibit good bending, electrical, luminescent, and temporal stability characteristics. The modularity of our technique means that we can also produce bicolor devices in which one LED is mounted upon another. Our approach thus opens up new routes to achieving efficient flexible LEDs and other optoelectronic devices, such as red-green-blue flexible LEDs or displays, flexible NW-based photodetectors6, or solar cells. In our future research we will concentrate on improving the efficiency of our flexible light-emitting devices, which is not yet comparable to that of commercialized rigid thin-film LEDs. We will also try to integrate the flexible light sources into life-science applications. This work has been financially supported through the 'PLATOFIL' project (ANR-14-CE26-0020-01), the EU H2020 ERC ‘NanoHarvest’ project (grant 639052), and by the French national Labex GaNex project (ANR-11-LABX-2014). The device fabrication was performed at the Centrale de Technologie Universitaire's Institut d'Electronique Fondamental (CTU-IEF) Minerve technological platform, which is a member of the Renatech Recherche Technologique de Base network. Center for Nanosciences and Nanotechnologies Paris-Sud University, CNRS Nan Guan is a PhD candidate in physics. He received both his master's and engineering degrees in optics from Université Paris-Saclay, France, in 2015. His current research interests include nanofabrication, characterization, and optical simulations for nitride nanowire LEDs. Xing Dai received her PhD in applied physics from Nanyang Technological University, Singapore, in 2014. During her time as a postdoctoral researcher at Paris-Sud University, she focused on flexible nanowire LEDs. She is currently a process-development engineer at Almae Technologies. Maria Tchernycheva received her PhD in physics from Paris-Sud University in 2005. She joined CNRS in 2006, where she currently leads the ‘NanoPhotoNit’ research group. Her research focuses on the fabrication and testing of novel optoelectronic devices that are based on semiconductor nanowires. Quantum Photonics, Electronics and Engineering (PHELIQS) Institute for Nanoscience and Cryogenics, French Alternative Energies and Atomic Energy Commission (CEA) Joël Eymery obtained his engineering degree, PhD, and habilitation from Université Grenoble Alpes, France, and now leads CEA's Nanostructures and Synchrotron Laboratory. His research is focused on the development of nanowire physics, including metal–organic vapor-phase epitaxy growth of nitride compounds, structural and optical characterization, and the development of nanodevice demonstrators. Christophe Durand received his PhD in physics from the Université Joseph Fourier, France, in 2004. Since 2006, he has been an associate professor at the Université Grenoble Alpes. In his research, he focuses on the synthesis of novel III-N nanostructures by metal–organic vapor-phase epitaxy to develop new optoelectronic applications. Quantum Photonics, Electronics and Engineering (PHELIQS)Institute for Nanoscience and Cryogenics, French Alternative Energies and Atomic Energy Commission (CEA) 2. N. Guan, X. Dai, J. Eymery, C. Durand, M. Tchernycheva, Nitride nanowires for new functionalities: from single wire properties to flexible light-emitting diodes. Presented at SPIE Photonics West 2016. 3. R. Koester, J.-S. Hwang, D. Salomon, X. Chen, C. Bougerol, J.-P. Barnes, D. Le Si Dang, et al., M-plane core-shell InGaN/GaN multiple-quantum-wells on GaN wires for electroluminescent devices, Nano Lett. 11, p. 4839-4845, 2011. 4. X. Dai, A. Messanvi, H. Zhang, C. Durand, J. Eymery, C. Bougerol, F. H. Julien, M. Tchernycheva, Flexible light-emitting diodes based on vertical nitride nanowires, Nano Lett. 15, p. 6958-6964, 2015. 5. N. Guan, X. Dai, A. Messanvi, H. Zhang, J. Yan, E. Gautier, C. Bougerol, et al., Flexible white light emitting diodes based on nitride nanowires and nanophosphors, ACS Photonics 3, p. 597-603, 2016.


Dublin, April 19, 2017 (GLOBE NEWSWIRE) -- Research and Markets has announced the addition of the "5G Market Assessment: Vendor Strategies, Technology and Infrastructure Outlook and Application Forecasts 2016 - 2025" report to their offering. This research provides an in-depth assessment of both technical issues (enabling technologies, 5G standardization and research initiatives, spectrum bands, etc.) and business areas (market drivers, challenges, use cases, vertical market applications, regulatory issues, trial commitments, introduction strategies, and impact to CSPs), as well as analysis of the emerging 5G ecosystem. The report includes specific ecosystem constituent recommendations and forecasts for both 5G investments, subscriptions, and more for the period of 2016 - 2025. Select Findings: - Large-scale commercial 5G trials to increase 5X by 2021 - Manufacturing to be leading IoT 5G industrial application area by 2021 - Leading 5G apps include IoT, Haptic Internet, Virtual Reality, and Robotics - 5G enabled autonomous robots market is expected to reach $14.6 billion by 2030 - 5G will lead to accelerated Virtual Reality deployment with $72B incremental revenue by 2026 Report Benefits: - Forecasts for leading 5G apps and services - Understand 5G technologies and solutions - Identify company R&D strategies and plans - Learn about 5G challenges and opportunities - Identify 5G investment targets and allocations Target Audience: - Wireless service providers - 5G infrastructure suppliers - Wireless device manufacturers - Big Data and analytics companies - Internet of Things (IoT) companies - Robotics and Virtual Reality suppliers - Enterprise across all industry verticals Key Topics Covered: 1. Introduction 1.1 Background 1.2 Scope of the Research 1.3 Target Audience 1.4 Companies in Report 2. Executive Summary 2.1 5G Requirements 2.1.1 User Driven Requirement 2.1.2 Network Driven Requirement 2.2 Stakeholders to Benefit from Expanded Services 2.3 Anticipated 5G Investment 2016 - 2031 3. Overview 3.1 Market Definition of 5G 3.2 Evolution of Mobile Communication Standards (1G to 5G) 3.3 Introduction to 5G Technology 3.4 5G Spectrum Options and Utilization 3.5 What can 5G Technology Offer? 3.5.1 5G Network will Facilitate Faster and Less Expensive Services 3.6 Key Advantages and Growth Drivers of 5G 3.7 Challenges for 5G 3.7.1 Consistent Growth in Technology Requirements and Service Characteristics 3.7.2 Standardization Challenges 3.7.3 Network Challenges 3.7.4 Mobile Device Challenges 3.7.5 Application Challenges 3.8 5G Roadmap 3.8.1 5G Requirements 2016 - 2020 3.8.2 5G Wireless Subsystem 2016 - 2020 3.8.3 Network Virtualization & Software Networks 2016 - 2020 3.8.4 Converged Connectivity 3.9 5G Use Cases 3.9.1 5G in M2M and IoT 3.9.2 5G in Robotics 3.9.3 5G in Augmented and Virtual Reality 3.9.4 5G in Home Internet 3.9.5 5G in Wireless Office 3.9.6 Other Use Cases 3.9.6.1 High Speed Train 3.9.6.2 Remote Computing 3.9.6.3 Non-Stationary Hot Spots 3.9.6.4 Natural Disaster 3.9.6.5 Public Safety 3.9.6.6 Context Aware Service 4. 5G Enabling Technologies 4.1 OSI Layers in 5G 4.1.1 Physical and Medium Access Control Layer 4.1.2 Network Layer 4.1.3 Application Layer 4.1.4 Differences between 5G and 4G 4.2 5G Technology Requirements 4.2.1 Disruptive Network Architecture 4.2.2 Access 4.2.3 One Millisecond Latency 4.2.4 System Level Principles 4.2.5 Right Business Model 4.2.6 Stakeholder Community 4.2.7 Policy and Standardization Framework 4.2.8 Communication Service Providers (CSP) 4.3 Key 5G Enabling Technologies 4.3.1 Massive MIMO 4.3.2 Network Functions Virtualization (NFV) 4.3.3 SDN and Virtualization 4.3.4 Cognitive Radios (CRs) and Transmission Technologies 4.3.5 Self-Organizing Networks (SONs) 4.3.6 Communication, Navigation, Sensing and Services 4.3.7 Cooperative Communication Functions 4.3.7.1 Multi-Hop 4.3.7.2 Caching 4.3.8 Automated Network Organization 4.3.9 Self-Configuration 4.3.10 Automatic Neighbor Relation (ANR) 4.3.11 Self-Healing 4.3.12 Self-Organization 4.3.13 Advanced traffic management 4.3.14 Visible Light Communications (VLCs) 4.3.15 Energy Efficiency 4.3.16 Millimeter Wave 4.3.17 Massive M2M Communications 4.3.18 C-RAN Architecture 4.3.19 HetNet Solutions 4.3.20 H-CRAN Solution 4.3.20.1 Large-Scale Cooperative Spatial Signal Processing 4.4 Software Defined Radio 4.4.1 Spectrum and Satellite 4.4.2 Drones, Robots, and High Altitude Balloons 4.4.3 5G New Radio 4.4.3.1 Architecture Options 4.4.4 Next Gen Technology 4.4.4.1 Cross Layer Controller 4.4.4.2 Energy Aware 4.4.4.3 Security 5. 5G Research Forecasts and Developments 5.1 5G Vision 2020 5.2 The Evolving 5G Standardization Process 5.3 The IMT 2020 Initiative to Define 5G 5.3.1 RAN Study 5.4 3GPP Roadmap for 5G 5.5 GSMA Definition for 5G 5.6 NGMN Business Model and value Creation for 5G 5.7 TIA Helping Deployment of 5G in North America 5.8 METIS Consensus Building in Europe 5.9 5G PPP Initiated Research Projects 5.9.1 5G PPP Projects 5.10 Research on the use of Quantum Technology in 5G 5.11 Research on Spectrum and Coverage Implications of 5G 5.12 5GNow to Challenge Shortcomings of 4G while Developing 5G 5.13 5G Research and Development in Asia 5.13.1 China IMT-2020 5.13.2 Japan ARIB 20B AH 5.13.3 Korea 5G Forum 5.13.4 China's 863-5G Project 5.14 R&D Initiatives and Collaboration 5.14.1 SK Telecom and Ericsson 5.14.2 Huawei and Samsung 5.14.3 NTT DoCoMo and Multiple Vendors 5.14.4 Turkcell and Ericsson 5.14.5 5G NORMA (Nokia and SK Telecom) 5.14.6 Huawei and Ericsson 5.14.7 FANTASTIC-5G 5.14.8 5GIC 5.14.9 NYU WIRELESS 6. Global 5G Market Forecasts 2016 - 2021 6.1 Global 5G R&D and Trial Investments 2016 - 2021 6.1.1 5G Investment in R & D and Trials by Category 6.2 Global Scenarios for 5G Networks 6.3 5G Considerations 6.3.1 5G Arrival Depends on Specifications and Adoption 6.3.2 New RAN will Improve Mobile Networks 6.3.3 Immediate Technological Developments 6.3.4 LTE May Slow Down 5G Growth 6.3.5 Use of Governmental Interest and Resources 6.3.6 More Sustainable Operator Investment Model in Terms of Capacity 6.4 5G Value Creation 6.4.1 Better User Services with 5G 6.4.2 5G will Enhance Work Processes for Enterprise 6.4.3 Expanded Business Opportunities for Partners 6.5 Global Markets for 5G 2021 - 2030 6.6 5G Adoption by 2025 6.7 5G Deployment by Region 2016 - 2025 6.8 5G Enhancements to Internet of Things (IoT) 6.8.1.1 CAT M LTE for IoT 6.9 5G Fixed Wireless Solutions 7. 5G Company Analysis 7.1 Alcatel-Lucent 7.2 Broadcom 7.3 China Mobile 7.4 Deutsche Telekom 7.5 Ericsson 7.6 Fujitsu 7.7 Huawei 7.8 Intel Corporation 7.9 LG Uplus Corp. 7.10 NEC Corporation 7.11 Nokia Networks 7.12 NTT DoCoMo 7.13 Qualcomm 7.14 Samsung 7.16 SK telecom 7.17 ZTE Corporation 7.18 5G Regulatory Contributor 8. Mobile Operator 5G Requirements 8.1 Network Level Expectations 8.2 Spectrum Usage Expectations 8.3 Service Level Expectations 8.4 5G Development by Region 8.5 5G Commercial Launch Plans 8.6 Data Traffic, Video, and Download Speed Projections 2020 - 2030 8.7 5G Investment Case Analysis 8.7.1 Huawei 8.7.2 South Korea 8.7.3 ZTE 8.7.4 Horizon 2020 8.8 End-to-End Ecosystem 9. Appendix: Forecasts for Leading 5G Apps and Services 9.1 5G Industrial Automation Global Forecasts 2020 - 2025 9.1.1 IIoT 5G Automation Market Value 9.1.1.1 Market by Segment 9.1.1.1.1 Hardware & Equipment Market by Type of Device 9.1.1.2 Market by Industry Verticals 9.1.1.3 Market by Technology Application 9.1.2 Wireless IIoT 5G Device Deployments 9.1.2.1 Deployment by Device Type 9.1.2.2 Deployment by Industry Vertical 9.2 5G Industrial Automation Regional Forecasts 2020 - 2025 9.2.1 Market Value by Region 9.2.2 Market Value by Leading Countries 9.2.3 Deployment by Region 9.2.4 Deployment by Leading Countries 9.2.5 Europe Market Forecasts 9.2.5.1 Market Value by Segment, Devices, Industry Vertical, & Technology Application 9.2.5.2 Deployment Base by Devices & Industry Vertical 9.2.6 North America Market Forecasts 9.2.6.1 Market Value by Segment, Devices, Industry Vertical & Technology Application 9.2.6.2 Deployment Base by Devices & Industry Vertical 9.2.7 APAC Market Forecasts 9.2.7.1 Market Value by Segment, Devices, Industry Vertical & Technology Application 9.2.7.2 Deployment Base by Devices & Industry Vertical 9.3 5G Robotics Global Market Revenue 9.3.1 Autonomous Robot Market 9.3.2 5G Enabled Autonomous Robot Market 9.3.3 5G Enabled Autonomous Robot Market by Categories 9.4 5G Robotics Regional Forecasts 9.4.1 5G Enabled Autonomous Robot by Region 9.5 Global 5G Enabled Virtual Reality Market 9.5.1 Combined Market Revenue 2021 - 2026 9.5.2 Combined Unit Shipment 2021 - 2026 9.5.3 Combined Active User 2021 - 2026 9.6 5G Accelerated VR Uptake Market 9.6.1 Market by Segments 2021 - 2026 9.6.1.1 Hardware Market 9.6.1.1.1 Full Feature Device including Haptic & Eyewear Devices 9.6.1.1.2 Hardware Components including Haptic Sensors & Semiconductor Components 9.6.1.2 Software & Application Market 9.6.1.3 Professional Service Market 9.6.2 VR Shipment Units 2021 - 2026 9.6.3 VR Active Users 2021 - 2026 9.6.4 5G VR Market by Region 2021 - 2026 9.6.4.1 North America Market 9.6.4.2 APAC Market 9.6.4.3 Europe Market 9.6.5 5G Consumer VR Application Market 2021 - 2026 9.6.6 Gaming 9.6.6.1 Pokémon Go Market Learning 9.6.7 Live Events 9.6.8 Video Entertainment 9.7 5G VR Enterprise Application Market 2021 - 2026 9.7.1 Retail Sector 9.7.2 Real Estate 9.7.3 Healthcare 9.7.4 Education 9.8 5G VR Industrial Application Market 2021 - 2026 9.8.1 Military 366 9.8.2 Engineering 9.8.3 Civil Aviation 9.8.4 Medical Industry 9.8.5 Agriculture 9.8.6 Government and Public Sector For more information about this report visit http://www.researchandmarkets.com/research/862pzp/5g_market

Loading ANR Inc collaborators
Loading ANR Inc collaborators