Toronto, Canada
Toronto, Canada

Bruce Power Limited Partnership is a Canadian business partnership composed of several corporations. It exists as a partnership between Cameco Corporation , TransCanada Corporation , BPC Generation Infrastructure Trust , the Power Workers Union and The Society of Energy Professionals . It is the licensed operator of the Bruce Nuclear Generating Station, located on the shores of Lake Huron, roughly 250 kilometres northwest of Toronto, between the towns of Kincardine and Saugeen Shores. This is the largest operating nuclear plant in the world by output With eight units in operation, the facility supplies 6,300 megawatts of electricity to Ontario's power grid. That's nearly 30 per cent of homes, schools, hospitals and businesses in the province. Bruce Power became the world's largest operating nuclear facility in 2012, when Units 1 and 2 returned to operation after a multi-billion dollar refurbishment project. This achievement returned the site to full operating capacity for the first time in 17 years. Wikipedia.

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News Article | April 26, 2017
Site: www.forbes.com

Led by Ontario, Canada is looking to fill their looming energy supply gap, and address climate change, by building a fleet of the new super-safe small modular nuclear reactors (SMRs) over the next 20 years. Ontario’s electricity supply is quite low-carbon already, with about 60% nuclear and 20% hydropower, with gas about 10%. Canada overall is about 60% hydropower and 16% nuclear, with the rest spread out among coal, gas and wind. At 50 grams of CO2 per kWh, Canada is one of the cleanest grids in the world. Aggressive targets for further reducing carbon emissions from Ontario resulted in 7 GW of coal-fired generation closing between 2005 and 2014. The province’s largest utility, Ontario Power Generation, replaced all its coal with renewable energy backed-up by natural gas, plus life extensions of almost 7 GW of existing nuclear. In October 2016, Ontario Power Generation started a US$9.6 billion refurbishment project at its 3.5 GW Darlington nuclear plant to extend the lifespan by 30 years. Bruce Power has also begun a US$10 billion life-extension project for its 6.3 GW nuclear plant northwest of Toronto. The utility plans to close its 3 GW Pickering nuclear plant in 2024, so it needs new carbon-free power to ensure Ontario meets its 2030 goal to cut carbon emissions by 37% below 1990 levels, and its even more ambitious 2050 goal of being 80% below 1990 levels. As Nicolle Butcher, Vice President of Strategy & Acquisitions at Ontario Power Generation, told the 2017 International SMR and Advanced Reactor Summit in Atlanta, Georgia last month, “Ontario Power Generation forecasts a significant gap in its power generation mix after 2030, and it intends to fill this gap with nuclear power.” Butcher added that long-term economic uncertainties and a lack of long-term political stability favor SMR plants with short lead times rather than large-scale nuclear projects. Ontario Power Generation has maintained the option to build new nuclear plants by obtaining a 10-year site preparation license in 2012 at its Darlington nuclear plant near Toronto. Canada is a pioneer in nuclear power. The CANDU (CANada Deuterium Uranium) reactor was designed in the 1950s – a heavy water reactor that can make the most of Canada's uranium supplies without the need to enrich. All 19 of Canada's nuclear reactors are CANDU and there are 31 CANDU reactors around the world. A number of advanced nuclear reactor developers are targeting the Canadian market, where a risk-informed regulatory framework is considered more flexible and conducive to licensing new designs than in the United States, and where numerous remote communities and industrial facilities represent captive electricity consumers. Canada even has a fusion reactor design company, General Fusion. Ontario has most of the large-scale nuclear power plants in the country, but several Canadian provinces are seen as potential markets for SMRs, making for a Pan-Canadian nuclear approach with standardized designs. Saskatchewan is a global uranium producer that could easily supply all these reactors with nuclear fuel for centuries. GE Hitachi Nuclear Energy and Advanced Reactor Concepts are jointly developing and licensing a sodium-cooled advanced small modular reactor (aSMR) based on their reactor technologies, and plan to enter the Canadian Nuclear Safety Commission's Vendor Design Review process. In January, NuScale Power out of Oregon announced their submission to the Nuclear Regulatory Commission of the first design certification application for any SMR in the United States. It is expected to be built in the early 2020s. ThorCon has a molten salt design that uses thorium as well as uranium. But Canada’s own new SMR company, Terrestrial Energy Inc. (TEI), has a new small modular Integral Molten Salt Reactor (IMSR) design that is ideal for this future, that is, a nuclear reactor that: - is cheaper than coal and can last for decades longer - is a 400 MWt (190 MWe) modular design, one able to be adapted to needs for both on and off-grid heat and power - is small and modular enough to allow simple construction in under 4 years, and trucking of modules to the site - operates at normal pressures, removing those safety issues, and at higher temperatures, providing more energy for the same amount of fuel - it does not require water for cooling and has the type of passive safety systems that make it walk-away safe - can load-follow rapidly to buffer the intermittency of renewables - generates less waste that is also more easily managed Terrestrial Energy’s reactor uses the natural convection of the molten salt to remove the heat to the vessel walls passively where its containment silo simply adsorbs the heat decay and conducts it away – this is passive cooling at its simplest. The Canadian Power Workers Union is all for expanding nuclear. They understand safe, secure, high-paying jobs. Nuclear is the foundation of Ontario’s and New Brunswick’s electricity systems and nuclear will be providing large volumes of affordable, baseload, low-carbon electricity, week in and week out, for decades to come. Besides, nuclear power shrugs off a Polar Vortex like it’s a summer’s day. Dr. James Conca is an expert on energy, nuclear and dirty bombs, a planetary geologist, and a professional speaker. Follow him on Twitter @jimconca and see his book at Amazon.com


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: motherboard.vice.com

This is a series around POWER, a Motherboard 360/VR documentary about nuclear energy. Follow along here. As Chinese Premier Li Keqiang stood alongside Justin Trudeau at Parliament's centre block in September, a quiet confidence was growing in Canada's nuclear industry. The Prime Minister and the Chinese leader were overseeing a signing ceremony between the China National Nuclear Corporation (CNNC) and Canadian engineering giant, SNC-Lavalin, which owns CANDU technology. The agreement will see two next-generation CANDU nuclear reactors installed about 100 kilometres southwest of Shanghai, and could transform nuclear power. Canada's nuclear industry is on the upswing, partly because of a global push to cut greenhouse gas emissions. The deal with CNNC is part of that. Teams here are developing advanced nuclear technologies that will ideally help wean us off fossil fuels, which is one reason many environmentalists are starting to embrace nuclear. Watch more from Motherboard: Going Nuclear If all goes according to plan, the CANDU reactors slated for the Qinshan nuclear site will be powered by what the industry calls advanced fuels: reprocessed uranium recycled from conventional reactors, and later, the radioactive element thorium, said Justin Hannah, Director of Marketing, Strategy and External Relations for SNC's CANDU division. Only a handful of sites in Europe and Japan are able to reprocess uranium today, and there is no standard on how to reuse it as a fuel, so it's not widely used. Even so, it has the potential to reduce stockpiles of radioactive waste and make countries that use it less dependent on uranium imports. CANDUs could start using thorium, with China's backing, putting the world closer to what proponents call the thorium dream Thorium has its own advantages when compared to uranium: it's about three times more abundant and can provide just as much power, plus it's far less useful for making nuclear weapons, mainly because its fuel cycle doesn't produce plutonium. But thorium is notoriously difficult to mine. Using it as a fuel is also complex, so reactor designs and supply chains aren't readily available. The fact that CANDUs could start using thorium, with China's backing, may put the world closer to what proponents call the thorium dream of safer, cleaner and more abundant nuclear power. China currently has 36 nuclear reactors in operation, another 21 under construction, and wants to double its nuclear power generation by 2021. Most of the existing reactors are conventional pressurized water reactors that run on enriched uranium, but the country is moving aggressively towards advanced reactor designs that can make use of the spent uranium from their current reactors, and the growing stockpiles of thorium that are a byproduct of mining for rare earth elements, a market that China dominates. China has a growing appetite for carbon-free energy, and the government has declared war on pollution from coal-fired power plants, so nuclear makes sense. But Canada's technology could also be of strategic value. "They have the thorium, they have the spent uranium," said Hannah. This country stands to benefit from the agreement with China, too. If we get this joint venture right, "Canada's nuclear industry could be seen as world leaders," said Jerry Hopwood, President of the University Network of Excellence in Nuclear Engineering, a partnership between 12 Canadian universities, government, and Canada's nuclear industry. The new Chinese-Canadian commercial entity is expected to be registered in China by mid-2017, with pre-construction work beginning in 2019 and 2026 targeted for the first AFCR to be operational, said Hannah. Thorium could be in use in the 2030s. As for whether Canada could one day switch to thorium, we've got large, high-quality uranium reserves, so any move to bring a thorium-powered AFCR here will depend on both politics and economics. "There's no strong economic driver for it," argued John Luxat, a nuclear safety expert at McMaster University. "The utilities don't want to switch over, but it's nice to know that we could." After what Hopwood called a lull in Canada's industry in the early 2000s, he believes recent investments and the push for carbon-free power show there's a resurgence in nuclear. The industry got a boost in 2016 from Ontario's support for the refurbishment of the Darlington nuclear plant, and the 2015 plan to extend the life of Bruce Power's nuclear reactors—each project projected to cost about $13 billion. Apart from that, SNC may be building another CANDU reactor in Argentina. Canadian nuclear startups are also chasing new technologies. Terrestrial Energy has plans to build a commercially-viable molten salt reactor (MSR) by the 2020s. Read More: The Plan to Build a Million-Year Nuclear Waste Dump on the Great Lakes Since the concept was first developed at the Oak Ridge National Laboratory in the 1960s, it's been touted as a safer alternative. Terrestrial's small, modular design is targeted at remote communities and providing carbon-free power directly to heavy industrial installations. The nuclear fuel used in an MSR is liquid, so it can't melt down, and it's chemically bound to the molten salt coolant. That means a loss of coolant, like the one that happened at the Fukushima nuclear plant in 2011, isn't possible, said Canon Bryan, Terrestrial's co-founder. Watch more from Motherboard: The Thorium Dream The molten fuel is highly corrosive, so MSRs still need further development to be proven safe. But the company has garnered nearly $30 million in investment, among other undisclosed grants, and Terrestrial's application to the US government for a $1 billion loan guarantee through its US subsidiary is advancing well, said Bryan. While Terrestrial's MSR design could potentially use thorium fuel in the future, the goal of becoming commercially viable as soon as possible means that the company will be sticking with uranium for now, since it's well-understood by the industry. "The conversation is changing," said Jerry Hopwood. "The fact that Canada is serious about dealing with climate change [has] put nuclear in a good position." Subscribe to Science Solved It, Motherboard's new show about the greatest mysteries that were solved by science.


News Article | July 13, 2017
Site: www.eurekalert.org

Two major investments in research partnerships that will strengthen the links between the UK's research base, industry and business partners will be announced today, Thursday 13th July, by Jo Johnson, Minister for Universities and Science. Both investments show the pivotal importance of engineering and the physical sciences to the country's continued development as a global research and innovation leader. The first investment is a new initiative, a set of Prosperity Partnerships, which will receive £31 million of government funding from the Engineering and Physical Sciences Research Council (EPSRC) and the Industrial Strategy Challenge Fund (ISCF). This will be matched by a further £36 million from partner organisations in cash or in-kind contributions, and £11 million from universities' funds, resulting in a £78 million investment. These will be launched at 18.00 hrs at a special event at BT's HQ, 81 Newgate Street, London EC1A 7AJ. News and picture editors are invited to send a reporter/photographer - For further information and accreditation contact the EPSRC Press Office on 01793 444 404 or email pressoffice@epsrc.ac.uk Ten universities will lead on 11 projects that range from the future networks for digital infrastructure to offshore wind and they will partner with businesses operating in key areas of the innovation landscape. These include household names such as Siemens, BP and Unilever and also firms like M Squared Lasers that are leading in areas such as advanced photonics. Jo Johnson, Minister for Universities and Science said: "A central part of our Industrial Strategy is boosting the economic impact of our world-class research base by supporting the flow of innovative ideas and techniques from concept to market-place. "This investment will ensure the work of our universities continues to have positive impact around the world and maintain the UK's global leadership in science and innovation." Professor Nigel Titchener-Hooker, Professor of Biochemical Engineering at UCL, who chaired the panel that approved the Prosperity Partnerships projects, said: "The Partnerships awards are a further demonstration of EPSRC's vision in creating exciting opportunities for industry and academia to work together on strategically significant problems. The quality of the applications we reviewed was outstanding and demonstrated strength of vision, relevance and a determination to pursue long term collaborative research. The breadth of applications too speaks to the diversity of UK industry and to the alignment between the UK's very best academic teams and our industrial base. The grants promise to create a series of exciting avenues of research leading to industrial implementation. It's a wonderful new example of how, in partnership, we can harness our collective capabilities to strengthen our economy and once again underscores the importance of ongoing investment in the HE research base." Jonathan Legh-Smith, Head of Partnerships & Strategic Research BT Technology, Service and Operations, said: "BT is very pleased to host the launch event for the EPSRC Prosperity Partnerships today. Having close links with the UK's research base has proved highly valuable to us, and many other companies operating across the economy. Collaborations between business, academics and funders, such as EPSRC, are vital to delivering impact from our world-class research. We believe the Prosperity Partnerships programme is a strategic opportunity to build on those collaborations and make a significant difference to the future prosperity of the country." The second EPSRC investment is £60 million for 33 universities to advance their Impact Acceleration Accounts (IAA). These allow institutions the flexibility to operate tailored schemes that help increase the likelihood of impact from their research. The IAAs speed up the contribution that scientists make towards new innovation, successful businesses and the economic returns that benefit the UK. Professor Philip Nelson, Chief Executive of the Engineering and Physical Sciences Research Council said: "If innovation is an ecosystem then it is dependent on having a fertile soil of research and the fresh air of ideas to nourish its growth. These new EPSRC Prosperity Partnerships and IAA investments will provide the right conditions in which new technologies and products can be developed more quickly. In turn, this will return social and economic benefits and ensure the UK continues to be one of the best places in the world to research, innovate and grow business." The IAAs' aims are to promote movement between universities, businesses and other organisations; to support the very early stage of turning research outputs into a commercial proposition; improve engagement with businesses, government and third sector to sow the seeds of new collaboration and more strategic engagement, and reach out to researchers who do not normally engage in exploitation activities and driving culture change within the university. The flexibility within each IAA means that different universities support activities in different ways, in line with their own unique needs and opportunities. University of Exeter QinetiQ The 'Tailored Electromagnetic and Acoustic Materials' Accelerator (Team A) EP/R004781/1 A collaboration to develop new materials and technologies that can control the propagation of electromagnetic (eg radiated heat, light, radiowaves) and acoustic (sound, vibration, shock) energy in a highly tailored, bespoke fashion, solving real-world problems. Lancaster University BT University of Surrey University of Cambridge University of Bristol Next Generation Converged Digital infrastructure (NG-CDI) EP/R004935/1 Developing new data-driven methods and technologies for the resilient, autonomic digital infrastructure of the future. University of Southampton Rockley Photonics Rockley Photonics and the Silicon Photonics Group at the University of Southampton EP/R003076/1 Rockley Photonics and the Silicon Photonics Group at the University of Southampton are developing a new integrated photonics platform for mass markets. Disruptive photonic integration at the chip level will impact networking technology in data centres, enable new consumer devices and provide robust sensing solutions all at dramatically lower cost and power requirements. University of St Andrews M Squared Lasers M Squared Lasers - University of St Andrews Biophotonics Nexus EP/R004854/1 Developing a new suite of ultra-compact super-resolution microscopes for pathology and disease management. University of Sheffield Siemens Gamesa Renewable Energy + DONG Energy Durham University University of Hull A New Partnership in Offshore Wind EP/R004900/1 Address the challenges of both the current and future generations of wind turbine (WT) technology in such a way that a chain of critical issues regarding availability and reliability of such structures will be explored and solved. The University of Manchester Unilever + Process Systems Enterprises Ltd STFC Laboratories The Centre in Advanced Fluid Engineering for Digital Manufacturing (CAFE4DM) EP/R00482X/1 Developing a new modelling approach to enable a significant reduction in conventional physical experimentation. University of Bristol Thales Thales-Bristol Partnership in Hybrid Autonomous Systems Engineering (T-B PHASE) EP/R004757/1 Designing new processes that guide the engineering of hybrid systems with embedded autonomy. University of Warwick Jaguar Land Rover + Brandauer Holdings Limited Dynex Semiconductor ST Microelectronics The science of high performance electrified propulsion. EP/R004927/1 Addressing emergent challenges in vehicle electrification through a unique collaboration to grow scientific understanding. University of Nottingham Rolls-Royce University of Oxford Imperial College London Strategic Partnership in Mechanical Integrity for Advanced Propulsion Systems EP/R004951/1 Meeting the challenges of high power density mechanical systems under extreme power levels and in safety critical environments. The University of Manchester BP Imperial College London University of Cambridge University of Edinburgh University of Leeds Preventing Surface Degradation in Demanding Environments EP/R00496X/1 New insights into the surface degradation of materials under demanding environments by harnessing advances in computer modelling, atomic level experimental techniques, in-operando imaging and characterisation, and by accessing previously untapped in-field data sets. University of Strathclyde Babcock International + EDF Energy Kinectrics Inc Bruce Power The Weir Group BAM Nuttall Imperial College London University of Surrey Cranfield University The Alan Turing Institute Delivering Enhanced Through-Life Nuclear Asset Management EP/R004889/1 Advanced inspection techniques, biotechnology solutions for infrastructure repair and engineering application tuned data science will create new products and processes for through-life management and lifetime extension of critical assets. H2GO Power, a University of Cambridge spin-out company formed by Dr Enass Abo-Hamed and Professor Oren Scherman, developed a safe method for hydrogen production and storage. It is based on a hybrid smart material capable of behaving like a 'sponge', which catalytically produces and stores hydrogen gas at room temperature and atmospheric pressure, and only releases the stored gas upon heating. The technology was developed by Enass through her work as a doctoral student in the Scherman research group. She went on to be named as one of three European finalists in Cartier's 2015 global Women's Initiative Awards. H2GO Power estimates that fuel cells using its technology will have five times the energy capacity of current battery technologies, and will be suitable for numerous applications, from mobile phone chargers to electric aircraft. The company is piloting a plug and play unit in Nigeria for use in buildings such as hospitals, enabling them to continue functioning during black outs. Lancaster University scientists are developing a portable bedside blood diagnostics device in collaboration with eBiogen Limited and clinicians from Morecambe Bay NHS Foundation Trust. The device takes pinprick samples of blood and is able to provide rapid chemical analysis in less than a minute, compared to the many hours it takes to send samples for analysis at hospital laboratories. The technology, part-funded through an IAA, promises to improve treatments for cancer patients, post-operative care and monitoring of the health of babies in the womb. A next-generation X-ray scanner being developed with IAA funding at Cranfield and Nottingham Trent universities is predicted to lead to a revolution in security in the aviation sector. Unlike conventional systems, the scanner can identify the presence of hidden explosives or illegal drugs in milliseconds. The technology, developed by a team led by Professor Keith Rogers, was the fortuitous but inadvertent outcome of previous EPSRC-supported research. A second tranche of IAA funding was recently obtained to further the medical diagnostics aspect of this work. A spin-out company, Halo X-ray Technologies Ltd, is developing the technology, which has the potential to be exploited commercially across a range of applications, such as for patient bone density measurements for and for the assessment of production line processes. Dr Karen Johnson, from Durham University, is using IAA funding to build on EPSRC-supported research into the regeneration of brownfield land using sustainable technologies that can clean up contaminated land. The project will showed how iron-rich mineral by-products (such as ochre) and compost can be used on the brownfield site, to immobilise contaminants and enhance soil structure to provide greater water holding capacity, and increase soil erosional resistance amongst other benefits. This has considerable implications for flood resilience, and the collaborating partner, Northumbrian Water Limited has co-funded the proof of concept project. Dr Johnson was recently supported by the RCUK Global Challenge Research Fund to apply her research to African cities using similar waste materials from both the water industry and the mining industry. Here enhancing soil structure can help smallholder farmers deal with both drought and floods. Dr David Harris-Birtill and Mr David Morrison, from the University of St Andrews, are using their IAA to further develop a research project that uses low-cost miniaturised radar technology and machine learning to reliably detect water pollutants. The project is a collaboration between St Andrews and the Universidade Federal de Goiás in Brazil, a country that faces unprecedented problems caused by water pollution. The long-term plan is to enable environmental researchers to make cheaper, faster measurements in the field using smartphones and other mobile devices. 1 University of Bath 2 University of Birmingham 3 University of Bristol 4 Brunel University 5 University of Cambridge 6 Cardiff University 7 Cranfield University 8 Durham University 9 University of Edinburgh 10 University of Exeter 11 University of Glasgow 12 Heriot-Watt University 13 Imperial College London 14 King's College London 15 Lancaster University 16 University of Leeds 17 University of Liverpool 18 Loughborough University 19 The University of Manchester 20 Newcastle University 21 University of Nottingham 22 University of Oxford 23 Queen Mary, University of London 24 Queen's University of Belfast 25 University of Sheffield 26 University of Southampton 27 University of St Andrews 28 University of Strathclyde 29 University of Surrey 30 Swansea University 31 University College London 32 University of Warwick 33 University of York The Industrial Strategy Challenge Fund (ISCF) builds on the UK's world-class research base and delivers the science that business needs to transform existing industries and create new ones. It accelerates commercial exploitation of the most exciting technologies the UK has to offer the world to ensure that scientific investment truly delivers economic impact, jobs and growth right across the country. The ISCF is delivered by Innovate UK and Research Councils UK, and eventually UK Research and Innovation, the single voice for the UK's research and innovation landscape. As the main funding agency for engineering and physical sciences research, our vision is for the UK to be the best place in the world to Research, Discover and Innovate. By investing £800 million a year in research and postgraduate training, we are building the knowledge and skills base needed to address the scientific and technological challenges facing the nation. Our portfolio covers a vast range of fields from healthcare technologies to structural engineering, manufacturing to mathematics, advanced materials to chemistry. The research we fund has impact across all sectors. It provides a platform for future economic development in the UK and improvements for everyone's health, lifestyle and culture. We work collectively with our partners and other Research Councils on issues of common concern via Research Councils UK. http://www.


PETERBOROUGH, Ontario--(BUSINESS WIRE)--BWX Technologies, Inc. (NYSE: BWXT) announced today that its subsidiary BWXT Nuclear Energy Canada Inc. (BWXT NEC) has been awarded a CA$34 million, five year contract to supply seven primary heat transport motors for Bruce Power. The motors are part of Bruce Power’s life-extension program that will extend the life of six of its reactors to continue providing Ontario with clean, low-cost and reliable electricity for decades to come. The primary heat transport motors are required to drive the main circulating pumps used to push heavy water through the reactor core into the steam generators. The scope of the contract includes the project management, engineering and manufacturing of seven 11,000 horsepower motors. Work under this contract will commence immediately with the first motor scheduled to be delivered to Bruce Power in mid-2018. “We appreciate the opportunity to execute this important project for Bruce Power and take great pride in our contributions to its life extension program,” said John MacQuarrie, president of BWXT Canada Ltd. and BWXT NEC. “BWXT is pleased to be in a position to supply its customers with a multitude of product and service solutions to assist them in extending the lives of their nuclear plants.” “Partnering with BWXT for this important motor work is critical to ensuring the life extension and operation through 2064,” said Mike Rencheck, Bruce Power’s president and CEO. “Planning and preparation is key to our continued on-time and on-budget performance since January 2016 when our life extension program was started. Suppliers like BWXT and their performance are critical to our success; it’s a team effort.” “Nuclear energy plays a significant role to Ontario’s economy and it is great to see the positive effects of Bruce Power’s life extension project being felt right here in Peterborough,” said Jeff Leal, Member of Provincial Parliament. “Throughout its program to extend the life of six of its reactors, Bruce Power will inject billions into Ontario’s economy and generate thousands of jobs.” Bruce Power supplies 30% of Ontario’s electricity at 30% less than the average cost to generate residential power. Extending the operational life of the Bruce Power units to 2064 will create and sustain 22,000 direct and indirect jobs every year, create $4 billion in annual Ontario economic benefit, and will ensure low-cost, clean and reliable energy for Ontario families and businesses. BWXT cautions that this release contains forward-looking statements, including statements relating to the performance, timing and value, to the extent contract value can be viewed as an indicator of future revenues, of the Bruce Power contract. These forward-looking statements involve a number of risks and uncertainties, including, among other things, modification or termination of the contract and delays. If one or more of these or other risks materialize, actual results may vary materially from those expressed. For a more complete discussion of these and other risk factors, please see BWXT’s annual report on Form 10-K for the year ended December 31, 2016 and subsequent quarterly reports on Form 10-Q filed with the Securities and Exchange Commission. BWXT cautions not to place undue reliance on these forward-looking statements, which speak only as of the date of this release, and undertakes no obligation to update or revise any forward-looking statement, except to the extent required by applicable law. BWXT Nuclear Energy Canada Inc. (BWXT NEC), a subsidiary of BWXT Canada Ltd., has more than 60 years of extensive experience and innovation in the supply of nuclear fuel and fuel channel components, services, equipment and parts for the CANDU® nuclear power industry. This includes designing and supplying highly reliable nuclear equipment to fuel, inspect and refurbish reactors. BWXT NEC employs approximately 350 skilled employees at three locations in Ontario: Peterborough, Toronto and Arnprior. Learn more at www.nec.bwxt.com. Formed in 2001, Bruce Power is an electricity company based in Bruce County, Ontario. We are powered by our people. Our 4,200 employees are the foundation of our accomplishments and are proud of the role they play in safely delivering clean, reliable, low-cost nuclear power to families and businesses across the province. Bruce Power has worked hard to build strong roots in Ontario and is committed to protecting the environment and supporting the communities in which we live. Learn more at www.brucepower.com and follow us on Facebook, Twitter, LinkedIn, Instagram and YouTube.


News Article | August 10, 2017
Site: www.businesswire.com

CAMBRIDGE, Ontario--(BUSINESS WIRE)--BWX Technologies, Inc. (NYSE:BWXT) announced today that its subsidiary BWXT Canada Ltd. (BWXT Canada) has been awarded a CA$48 million amendment to its existing steam generator purchase agreement from Bruce Power. The amendment reflects the addition of steam drums to Bruce Power’s steam generator agreement with BWXT Canada previously announced July 2016. The steam drums and associated steam separation internals will be designed and fabricated in BWXT’s Cambridge, Ontario facility as part of eight steam generators that will be supplied to Bruce Power’s Bruce B Unit 6 reactor. The supply of steam generators is part of Bruce Power’s Life-Extension Program that will extend the life of six of its reactors. “BWXT values its contributions to Bruce Power’s Life Extension Program, which is critical to ensuring the supply of low-cost, clean and reliable energy for Ontario,” said John MacQuarrie, President of BWXT Canada. “As a major supplier of nuclear products and services, BWXT is committed to ensuring its customers are successful in completing their projects on-time and on-budget.” BWXT has been a proud supplier of products and services to the Bruce Nuclear Generating Station since it went online in 1977. In December 2015, Bruce Power and the Independent Electricity System Operator (IESO) announced an amended long-term agreement that will see Units 3 through 8 refurbished over the next two decades to extend the life of the site to 2064 and secure 6,400 megawatts to fulfill commitments to Ontario’s Long-Term Energy Plan (LTEP). “The addition of steam drums integrally manufactured with the steam generators will add to the efficiency of our Steam Generator Replacements that are part of our life extension outage in Unit 6 in 2020 and will be crucial in helping us to safely and reliably operate the site through to 2064,” said Mike Rencheck, Bruce Power’s president and CEO. “Partnerships such as this one with BWXT will help us to continue to deliver innovations that keep our life extension project on time and on budget, benefitting the people of Ontario.” This agreement also supports BWXT as a major employer providing highly skilled jobs within the Kitchener-Waterloo-Cambridge region. Executives from Bruce Power and BWXT, along with the Member of Provincial Parliament for Cambridge, Ontario and Minister of Natural Resources and Forestry, Kathryn McGarry, will tour the Bruce Power site tomorrow. "The ongoing collaboration between BWXT and Bruce Power is creating safe, clean and low-cost electricity for the people of Ontario,” McGarry said. “This partnership is an example of how we can continue to make Ontario a hub for advanced manufacturing – providing stable jobs and economic benefits in communities like Cambridge, and right across this great province of ours.” Bruce Power supplies 30% of Ontario’s electricity at 30% less than the average cost to generate residential power. Extending the operational life of the Bruce Power units to 2064 will create and sustain 22,000 direct and indirect jobs every year, create $4 billion in annual Ontario economic benefit, and will ensure low-cost, clean and reliable energy for Ontario families and businesses. BWXT cautions that this release contains forward-looking statements, including statements relating to the performance, timing, impact and value, to the extent contract value can be viewed as an indicator of future revenues, of the Bruce Power amendment. These forward-looking statements involve a number of risks and uncertainties, including, among other things, modification or termination of the contract and delays. If one or more of these or other risks materialize, actual results may vary materially from those expressed. For a more complete discussion of these and other risk factors, please see BWXT’s annual report on Form 10-K for the year ended December 31, 2016 and subsequent quarterly reports on Form 10-Q filed with the Securities and Exchange Commission. BWXT cautions not to place undue reliance on these forward-looking statements, which speak only as of the date of this release, and undertakes no obligation to update or revise any forward-looking statement, except to the extent required by applicable law BWXT Canada Ltd. (BWXT Canada) has over 60 years of expertise and experience in the design, manufacturing, commissioning and service of nuclear power generation equipment. This includes CANDU® and Pressurized Water Reactor steam generators, nuclear fuel and fuel components, critical plant components, parts and related plant services. Headquartered in Cambridge, Ontario, BWXT Canada has approximately 850 employees at locations in Cambridge, Peterborough, Toronto and Arnprior, Ontario. BWXT Canada is a subsidiary of BWX Technologies, Inc. (NYSE:BWXT). BWXT is a leading supplier of nuclear components and fuel to the U.S. government; provides technical, management and site services to support governments in the operation of complex facilities and environmental remediation activities; and supplies precision manufactured components, fuel and services for the commercial nuclear power industry. Learn more at www.BWXT.com. Formed in 2001, Bruce Power is an electricity company based in Bruce County, Ontario. We are powered by our people. Our 4,200 employees are the foundation of our accomplishments and are proud of the role they play in safely delivering clean, reliable, low-cost nuclear power to families and businesses across the province. Bruce Power has worked hard to build strong roots in Ontario and is committed to protecting the environment and supporting the communities in which we live. Learn more at www.brucepower.com and follow us on Facebook, Twitter, LinkedIn, Instagram and YouTube.


News Article | February 16, 2017
Site: www.marketwired.com

CALGARY, ALBERTA--(Marketwired - Feb. 16, 2017) - News Release - TransCanada Corporation (TSX:TRP)(NYSE:TRP) (TransCanada) today announced a net loss attributable to common shares for fourth quarter 2016 of $358 million or $0.43 per share compared to a net loss of $2.5 billion or $3.47 per share for the same period in 2015. For the year ended December 31, 2016, net income attributable to common shares was $124 million or $0.16 per share compared to a net loss of $1.2 billion or $1.75 per share in 2015. Comparable earnings for fourth quarter 2016 were $626 million or $0.75 per share compared to $453 million or $0.64 per share for the same period in 2015. For the year ended December 31, 2016, comparable earnings were $2.1 billion or $2.78 per share compared to $1.8 billion or $2.48 per share in 2015. TransCanada's Board of Directors also declared a quarterly dividend of $0.625 per common share for the quarter ending March 31, 2017, equivalent to $2.50 per common share on an annualized basis, an increase of 10.6 per cent. This is the seventeenth consecutive year the Board of Directors has raised the dividend. "Excluding specific items, we generated record financial results in 2016," said Russ Girling, TransCanada's president and chief executive officer. "Comparable earnings per share increased 12 per cent when compared to 2015 while net cash provided by operations exceeded $5 billion for the first time in the Company's history." "It was also a transformational year for TransCanada," added Girling. "The Columbia acquisition reinforced our position as one of North America's leading energy infrastructure companies with an extensive pipeline network linking the continent's most prolific natural gas supply basins to its most attractive markets and provided us with another growth platform. Today we are advancing an industry leading $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." "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. This portfolio is currently comprised of more than $45 billion in large-scale projects that include Keystone XL and the Bruce Power life extension program. 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 loss attributable to common shares decreased by $2.1 billion to a net loss of $358 million or $0.43 per share for the three months ended December 31, 2016 compared to the same period last year. Fourth quarter 2016 included an $870 million after-tax loss related to the monetization of our U.S. Northeast Power business, an additional $68 million after-tax charge to settle the termination of our Alberta PPAs, an after-tax charge of $67 million for costs associated with the acquisition of Columbia Pipeline Group, Inc. (Columbia), and certain other specific items including unrealized gains and losses on risk management activities. Fourth quarter 2015 included a $2.9 billion after-tax impairment charge related to Keystone XL and related projects as well as certain other specific items. All of these specific items are excluded from comparable earnings. Net income attributable to common shares for the year ended December 31, 2016 was $124 million or $0.16 per share compared to a net loss of $1.2 billion or $1.75 per share in 2015. Results in 2016 included a net loss of $2.0 billion related to specific items including those noted above for the fourth quarter as well as a $656 million after-tax impairment of Ravenswood goodwill, an additional $176 after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs, $206 million of additional after-tax costs associated with the acquisition of Columbia, primarily related to the dividend equivalent payments on the subscription receipts, and certain other specific items including unrealized gains and losses on risk management activities. Results in 2015 included the $2.9 billion after-tax impairment charge related to Keystone XL noted above and certain other specific items. These amounts were excluded from comparable earnings. Comparable earnings for fourth quarter 2016 were $626 million or $0.75 per share compared to $453 million or $0.64 per share for the same period in 2015, an increase of $173 million or $0.11 per share. The increase was primarily the net effect of higher contributions from U.S. Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenue resulting from higher rates effective August 1, 2016, higher interest expense from debt issuances and lower capitalized interest, a higher contribution from Mexican pipelines primarily due to earnings from Topolobampo beginning in July 2016, reduced earnings from Liquids Pipelines due to the net effect of lower volumes on Marketlink and higher volumes on Keystone pipeline, higher earnings from Western Power due to higher realized prices on generated volumes and termination of the Alberta PPAs, and higher earnings from Natural Gas Storage due to higher realized natural gas storage price spreads. Comparable earnings for the year ended December 31, 2016 were $2.1 billion or $2.78 per share compared to $1.8 billion or $2.48 per share in 2015. Higher income from our U.S. Pipelines due to incremental earnings from Columbia and ANR, higher AFUDC on our rate-regulated projects, an increased contribution from our Mexico Pipelines due to earnings from Topolobampo and higher earnings from our natural gas storage assets were partially offset by lower earnings from our Liquids Pipelines. Per share figures in 2016 also include the dilutive effect of issuing 161 million common shares in 2016. We will hold a teleconference and webcast on Thursday, February 16, 2017 to discuss our fourth quarter 2016 financial results as well as provide an update on our business and financial outlook. 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 1 p.m. (MT) / 3 p.m. (ET). Members of the investment community and other interested parties are invited to participate by calling 800.377.0758 or 416.340.2218 (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 February 23, 2017. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 9119753. 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 10,700 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. 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 news release 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 news release. 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 2015 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 news release 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. Comparable earnings represents 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. 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. Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. See the Reconciliation of non-GAAP measures section for a reconciliation to net cash provided by operations. 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. Effective December 31, 2016, we adopted, on a retrospective basis, a new accounting standard under U.S. GAAP which allows us to classify certain distributed earnings received from equity investments as cash from operations on the consolidated statement of cash flows, which had previously been included in Investing activities. As a result, we no longer need to adjust for distributions in excess of equity earnings in the calculation of comparable distributable cash flow. We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. The following table identifies our non-GAAP measures against their equivalent GAAP measures. We operate in three core businesses - Natural Gas Pipelines, Liquids Pipelines and Energy. As a result of our acquisition of Columbia on July 1, 2016 and the pending monetization of the U.S. Northeast power business, we have determined that a change in our operating segments is appropriate. Accordingly, we consider ourselves to be operating our business in the following segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. This provides information that is aligned with how management decisions about our business are made and how performance of our business is assessed. We also have a non-operational Corporate segment consisting of corporate and administrative functions that provide governance and other support to our operational business segments. Prior period segment information has been adjusted to reflect the new segments. Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been adjusted to reflect this change. In addition, Columbia results are included in the U.S. Natural Gas Pipelines segment from its acquisition on July 1, 2016. Comparative periods do not include Columbia. Net loss attributable to common shares decreased by $2,100 million or $3.04 per share to a net loss of $358 million or $0.43 per share for the three months ended December 31, 2016 compared to the same period in 2015. Net (loss)/income per common share in 2016 includes 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 $173 million for the three months ended December 31, 2016 compared to the same period in 2015 as discussed below in the reconciliation of net income to comparable earnings. Comparable earnings increased by $173 million or $0.11 per share for the three months ended December 31, 2016 compared to the same period in 2015. Comparable earnings per share in 2016 includes the dilutive effect of issuing 161 million common shares in 2016. The 2016 increase in comparable earnings was primarily the net effect of: The stronger U.S. dollar on a year-to-date basis compared to the same period in 2015 positively impacted the translated results of our U.S. and Mexican businesses, along with realized gains on foreign exchange hedges used to manage our exposure, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt. 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 $23 billion of near-term projects and $48 billion of commercially secured medium and 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 2019 and beyond, 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 but are subject to approvals that include sponsor FID and/or complex regulatory processes. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been adjusted to reflect this change. Canadian Natural Gas Pipelines comparable EBIT and segmented earnings decreased by $44 million for the three months ended December 31, 2016 compared to the same period in 2015. 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 $16 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to a higher average investment base and OM&A incentive earnings recorded in 2016. Net income for the Canadian Mainline increased by $2 million for the three months ended December 31, 2016 compared to the same period in 2015 primarily due to higher incentive earnings, partially offset by a lower average investment base and higher carrying charges to shippers on the 2016 net revenue surplus. Depreciation and amortization increased by $7 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to new NGTL System facilities that were placed in service in 2016. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been adjusted to reflect this change. In addition, Columbia results are included in the U.S. Natural Gas Pipelines segment from its acquisition on July 1, 2016. Comparative periods do not include Columbia. U.S. Natural Gas Pipelines segmented earnings increased by $317 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to the acquisition of Columbia. Segmented earnings for the three months ended December 31, 2016 included an $11 million pre-tax charge, primarily related to retention and severance expenses resulting from the Columbia acquisition. Segmented earnings for the three months ended December 31, 2015 included a $125 million pre-tax loss provision ($86 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 its storage capacity and incidental commodity sales. Comparable EBITDA for U.S. Pipelines increased by US$213 million for the three months ended December 31, 2016 compared to the same period in 2015. This was the net effect of: Depreciation and amortization increased by US$60 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to the Columbia acquisition on July 1, 2016 and increased depreciation rates on ANR following its rate settlement effective August 1, 2016. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been adjusted to reflect this change. Mexico segmented earnings increased by $64 million for the three months ended December 31, 2016 compared to the same period in 2015. Mexico Natural Gas Pipelines segmented earnings 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$49 million for the three months ended December 31, 2016 compared to the same period in 2015. This was the net effect of: Depreciation and amortization increased by US$4 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to the commencement of depreciation on Topolobampo. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been adjusted to reflect this change. Liquids Pipelines segmented earnings increased by $3,634 million for the three months ended December 31, 2016 compared to the same period in 2015 and included pre-tax charges related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project as well as unrealized losses from changes in the fair value of derivatives related to our liquids marketing business. The segmented loss in 2015 included a $3,686 million pre-tax impairment charge related to Keystone XL and related projects in connection with the denial of the U.S. Presidential permit. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Liquids Pipelines segmented earnings are equivalent to comparable EBIT. Comparable EBITDA for the Keystone Pipeline System is generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings. Comparable EBITDA for Liquids Pipelines decreased by $34 million for the three months ended December 31, 2016 compared to the same period in 2015 and was the net effect of: Depreciation and amortization increased by $7 million for the three months ended December 31, 2016 compared to the same period in 2015 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 as a result of our 2015 business transformation initiative. 2015 results have been adjusted to reflect this change. Energy segmented earnings decreased by $648 million to segmented losses of $571 million for the three months ended December 31, 2016 compared to the same period in 2015 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. Following the March 17, 2016 announcement of our intention to monetize the U.S. Northeast power business, we were required to discontinue hedge accounting for certain cash flow hedges. This, along with the increased volume of our risk management activities associated with the expansion of our customer base in the PJM market, contributed to higher volatility in U.S. Power risk management activities. The remainder of the Energy segmented earnings are equivalent to comparable EBIT. Comparable EBITDA for Energy increased by $35 million to $305 million for the three months ended December 31, 2016 compared to $270 million for the same period in 2015 primarily due to the net effect of: The following are the components of comparable EBITDA and comparable EBIT. Comparable EBITDA for Western Power increased by $27 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to higher realized prices on generated volumes and termination of the Alberta PPAs. Results from the Alberta PPAs are included up to March 7, 2016 when we sent notice to the Balancing Pool to terminate the PPAs for the Sundance A, Sundance B and Sheerness facilities. Income/(loss) from equity investments included earnings from the ASTC Power Partnership which held our 50 per cent ownership in the Sundance B PPA. Alberta power prices are impacted by several factors including the prevailing power supply and demand conditions and natural gas price levels. Average spot market power prices in Alberta increased five per cent from $21/MWh to $22/MWh for the three months ended December 31, 2016 compared to the same period in 2015. Average AECO natural gas prices increased by 25 per cent from approximately $2.34/GJ to $2.93/GJ for the three months ended December 31, 2016 compared to the same period in 2015. The Alberta power market remained well-supplied and power consumption was down primarily due to a weak economy. Depreciation and amortization decreased by $24 million for the three months ended December 31, 2016 compared to the same period in 2015 following the termination of the Alberta PPAs. Comparable EBITDA for Eastern Power decreased by $1 million for the three months ended December 31, 2016 compared to the same period in 2015. Bruce Power results reflect our proportionate share. Bruce A and B were merged in December 2015 and comparative information for 2015 is reported on a combined basis to reflect the merged entity. The following is our proportionate share of the components of comparable EBITDA and comparable EBIT. Comparable EBITDA from Bruce Power remained unchanged for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to our increased ownership interest and higher realized sales price offset by lower volumes from increased outage days compared to the same period in 2015. In December 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the Bruce Power facility to 2064. As part of this agreement, Bruce Power began receiving a uniform price of $65.73 per MWh for all units, which includes certain flow-through items such as fuel and lease expenses recovery. Over time, the price will be subject to adjustments for the return of and on capital invested in Bruce Power under the Asset Management and Major Component Replacement capital programs, along with various other pricing adjustments that allow for a better matching of revenues and costs over the long term. Bruce Power also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price. The contract with the IESO provides for payment if the IESO reduces Bruce Power's generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered deemed generation for which Bruce Power is paid the contract price. 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 US$6 million for the three months ended December 31, 2016 compared to the same period in 2015 primarily due to the net effect of: Average New York Zone J spot capacity prices were approximately 30 per cent lower for the three months ended December 31, 2016 compared to the same period in 2015. The decrease in spot prices and the offsetting impact of hedging activities resulted in lower realized capacity prices in New York. This was primarily due to an increase in demonstrated capability from existing resources in New York City's Zone J market. The impact of lower capacity prices in New York was partially offset by capacity revenues earned by our Ironwood power plant. Insurance recoveries for the 2014 outage at Ravenswood are being recognized in capacity revenues to offset amounts lost during the periods impacted by the lower forced outage rate. As a result of these insurance recoveries, the Unit 30 unplanned outage has not had a significant impact on our earnings although the recording of earnings has not coincided exactly with lost revenues due to timing of the insurance proceeds. In addition, insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008 were recognized in power revenue in December 2015. Higher margins and higher sales volumes to wholesale, commercial, and industrial customers in both the New England and PJM markets resulted in higher earnings for the three months ended December 31, 2016 compared to the same period in 2015. The expansion of our customer base in these markets, combined with higher power prices during the three months ended December 31, 2016, provided the opportunity for higher earnings. Wholesale electricity prices in New York and New England were higher for the three months ended December 31, 2016 compared to the same period in 2015. In New England, spot power prices for the three months ended December 31, 2016 were 13 per cent higher compared to the same period in 2015. In New York City, spot power prices for the three months ended December 31, 2016 were 29 per cent higher compared to the same period in 2015. Physical generation volumes for the three months ended December 31, 2016 were higher compared to the same period in 2015 due to our acquisition of the Ironwood power plant. Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three months ended December 31, 2016 than the same period in 2015 as we have expanded our customer base in the PJM and New England markets. Comparable EBITDA increased by $14 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to increased third party storage revenues as a result of higher realized natural gas storage price spreads. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been adjusted to reflect this change. Corporate segmented losses decreased by $73 million for the three months ended December 31, 2016 compared to the same period in 2015 and included the following specific items that have been excluded from comparable EBIT: Comparable EBITDA in 2015 included the portion of our corporate restructuring costs that were recovered through our tolling mechanisms. The increase in Corporate depreciation for the three months ended December 31, 2016 compared to 2015 reflected incremental depreciation on our Corporate capital additions, including those in Columbia. Interest expense increased by $162 million for the three months ended December 31, 2016 compared to the same period in 2015 due to the net effect of: AFUDC increased by $6 million for the three months ended December 31, 2016 compared to the same period in 2015 primarily due to increased investment in our NGTL System expansions, Energy East and Columbia projects, partially offset by bringing into service the Topolobampo and Mazatlán pipelines. Interest income and other decreased by $4 million for the three months ended December 31, 2016 compared to the same period in 2015 due to the net effect of: Income tax expense included in comparable earnings decreased by $24 million for the three months ended December 31, 2016 compared to the same period in 2015 mainly due to a change in the proportion of income earned between Canadian and foreign jurisdictions and lower flow-through taxes in 2016 on Canadian regulated pipelines, partially offset by higher pre-tax earnings in 2016 compared to 2015. Net income attributable to non-controlling interests increased by $207 million for the three months ended December 31, 2016 compared to the same period in 2015 due to the net effect of a $2 million charge in 2016 related to the non-controlling interests' portion of retention and severance expenses resulting from the Columbia acquisition and an impairment charge recorded by TC PipeLines, LP in 2015 related to their equity investment goodwill in Great Lakes. On consolidation, we recorded the non-controlling interests' 72 per cent of this TC PipeLines, LP impairment charge, which was US$143 million, or $199 million (in Canadian dollars). TC PipeLines, LP's impairment charge is not recognized at the TransCanada consolidation level as a result of our lower carrying value of Great Lakes. Both of these amounts have been excluded from comparable earnings. Net income attributable to non-controlling interests included in comparable earnings increased by $10 million for the three months ended December 31, 2016 compared to the same period in 2015 primarily due to the acquisition of Columbia which included a non-controlling interest in Columbia Pipeline Partners LP. In addition, the sale of our 30 per cent direct interest in GTN in April 2015 and 49.9 per cent direct interest in PNGTS in January 2016 to TC PipeLines, LP, along with the impact of a stronger U.S. dollar, increased net income attributable to non-controlling interests year-over-year. Preferred share dividends increased by $9 million for the three months ended December 31, 2016 compared to the same period in 2015 primarily due to the issuance of Series 13 and Series 15 preferred shares in April 2016 and November 2016. Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation. The increase from 2015 to 2016 was driven by an increase in funds generated from operations partially offset by higher maintenance capital expenditures primarily on Columbia pipelines since the acquisition on July 1, 2016 and ANR. 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:


News Article | February 27, 2017
Site: www.businesswire.com

LYNCHBURG, Va.--(BUSINESS WIRE)--BWX Technologies, Inc. (NYSE: BWXT) ("BWXT" or the "Company") today reported fourth quarter 2016 revenues of $403.9 million, 11% growth compared to $363.9 million in the fourth quarter of 2015. GAAP earnings per share (EPS) for the fourth quarter of 2016 were $0.34 compared to $0.00 in the fourth quarter of 2015. Adjusted (non-GAAP) EPS from continuing operations for the fourth quarter of 2016 were $0.46 compared to $0.38 in the fourth quarter of 2015. A reconciliation of non-GAAP results is detailed in Exhibit 1. Unless stated otherwise, the results of operations discussed in this release are on a continuing operations basis and exclude the results of operations from our former Power Generation business, which are included as part of discontinued operations in the attached financial statements. GAAP EPS for the full year 2016, which include a $0.14 per share impact of non-cash, mark-to-market loss for pension and other post-retirement benefits, increased to $1.76 compared to $1.31 in 2015. Adjusted EPS for the full year 2016 increased 24% to $1.76 versus adjusted EPS of $1.42 in the prior year. In the fourth quarter of 2016, we adopted new stock compensation accounting rules retrospectively, which resulted in $0.02 per share of additional earnings through reduced provision for income taxes during the nine months ended September 30, 2016. "BWXT closed an outstanding 2016 with an exciting fourth quarter, successfully delivering on our commitments to our customers and our shareholders," said Mr. John A. Fees, Executive Chairman. "We completed the high-quality, strategic acquisition of GE-Hitachi Nuclear Energy Canada Inc., which is now called BWXT Nuclear Energy Canada Inc. With the provincial government's strong commitment to nuclear energy and a low-carbon energy portfolio, we expect to expand the Nuclear Energy business's product and service offering to the Canadian nuclear market and we believe the Canadian refurbishment activities offer significant long-term growth opportunities to BWXT. Our Nuclear Operations business continued to produce near record results and our Nuclear Energy business achieved a 20.3% operating profit margin for the year, which was an 11.8% adjusted operating profit margin when the impact of a reversal of a $16.1 million loss contingency is excluded. Lastly, we continued to increase return to shareholders by repurchasing $293 million of BWXT stock in 2016, increasing our dividend by 50%, and outperforming the market (S&P 500) by more than 1,500 basis points.” The Company’s consolidated GAAP operating income for the fourth quarter of 2016 was $45.8 million compared to GAAP operating income of $9.6 million in the fourth quarter of 2015. Adjusted (non-GAAP) operating income for the fourth quarter of 2016 was $71.8 million compared to adjusted (non-GAAP) operating income of $62.1 million in the fourth quarter of 2015. The increase in GAAP and non-GAAP operating income compared to the prior year period was driven by increases in our Nuclear Operations and Nuclear Energy segments’ operating income. Nuclear Operations segment revenues increased approximately 10.3% to $331.5 million in the fourth quarter of 2016 compared to $300.4 million in the same quarter of 2015 due to increased activity in component manufacturing. Nuclear Operations operating income was a near record $76.6 million in the fourth quarter of 2016, almost 17% higher than the $65.5 million in the prior year period. Revenues from our Nuclear Energy segment grew 18.7% to $49.5 million in the fourth quarter of 2016 compared to $41.7 million in the prior year period, primarily due to higher volume in the equipment business related to the Bruce Power refurbishment activities. Nuclear Energy's operating income was $3.6 million in the fourth quarter of 2016, ahead of the prior year period operating income of $1.6 million. Technical Services segment revenues reached $25.4 million in the fourth quarter of 2016 compared to $22.4 million in the same quarter of 2015 due to increased management and operations activity at certain sites. Consistent with expectations, Technical Services operating income decreased to $1.8 million in the fourth quarter of 2016 from $2.6 million in the prior year period due to increased business development costs, finishing the year within our previously provided guidance range. "BWXT accomplished several key strategic initiatives this year and we are excited about the upcoming prospects for all of our segments as we head into 2017," said Mr. Fees. "Our Nuclear Operations business has a record backlog and several near-term organic growth opportunities related to options that the Navy is considering for expansion of their submarine and aircraft carrier fleet. Our Nuclear Energy segment is positioned for long-term growth as it supports ongoing outage work and the refurbishment activities at Ontario Power Generation and Bruce Power. Furthermore, the addition of BWXT Nuclear Energy Canada to our Canadian Nuclear Energy business is expected to open up new growth opportunities in CANDU fuel, equipment and services. We continue to invest in a robust pipeline of opportunities in the Technical Service segment, and we intend to begin restoring that business to higher levels of profitability over the next few years. Lastly, we remain committed to our balanced capital allocation approach and continue to evaluate opportunities for acquired growth and strategic investments." The Company had net cash from operating activities of $147.4 million in the fourth quarter of 2016 compared with net cash from operating activities of $96.3 million in the fourth quarter of 2015. At the end of the fourth quarter, the Company’s cash and investments position, net of restricted cash, was $149.2 million. As of December 31, 2016, outstanding balances under our credit facility included $285.0 million on our original term loan, $246.0 million term loans made available to us through the September amendment, and letters of credit issued under the facility totaling $154.9 million. As a result, the Company has $245.1 million of remaining availability under our credit facility, taking into account the additional capacity provided by the amendment. The remaining availability excludes the additional $250 million accordion provision. During 2016, the Company paid a total of $293 million to repurchase shares, including $200 million for an accelerated share repurchase (ASR) that we entered into during the third quarter. As of December 31, 2016, $43.0 million remained under our current $300 million share repurchase authorization. On February 24, 2017, our Board of Directors authorized the repurchase of up to $150 million of additional shares over a three year period ending on February 24, 2020. On February 24, 2017, our Board of Directors declared a quarterly cash dividend of $0.09 per common share within restrictions allowed due to the recent ASR. The dividend will be payable on March 29, 2017, to shareholders of record on March 10, 2017. The Company expects to achieve consolidated revenues between $1.60 billion and $1.70 billion in 2017. Adjusted earnings per share for 2017 are expected to be between $1.85 and $1.95, which excludes mark-to-market adjustments for pension and post-retirement benefits. The Company also expects the following for 2017: Beyond 2017, we anticipate an EPS CAGR in the low double digits over the next 3-5 years based upon our robust organic growth strategy and remaining balance sheet capacity. Starting with the quarter ending March 31, 2017, we will report our results in the following three business segments: Date: Tuesday, February 28, 2017, at 8:30 a.m. EST Live Webcast: Investor Relations section of website at www.bwxt.com BWXT cautions that this release contains forward-looking statements, including, without limitation, statements relating to backlog, to the extent they may be viewed as an indicator of future revenues, anticipated benefits of the acquisition of GE-Hitachi Nuclear Energy Canada Inc., management’s plans and expectations for our Nuclear Energy segment and Canadian Nuclear Energy business, potential growth opportunities in our Nuclear Operations segment, management’s intentions for our Technical Services business, as well as our outlook and guidance for 2017. These forward-looking statements are based on management’s current expectations and involve a number of risks and uncertainties, including, among other things, our ability to execute contracts in backlog; the lack of, or adverse changes in, Federal appropriations to government programs in which we participate; the demand for and competitiveness of nuclear power; capital priorities of power generating utilities; adverse changes in the industries in which we operate and delays, changes or termination of contracts in backlog. If one or more of these risks or other risks materialize, actual results may vary materially from those expressed. For a more complete discussion of these and other risk factors, see BWXT’s filings with the Securities and Exchange Commission, including our annual report on Form 10-K for the year ended December 31, 2016 and subsequent quarterly reports on Form 10-Q. BWXT cautions not to place undue reliance on these forward-looking statements, which speak only as of the date of this release, and undertakes no obligation to update or revise any forward-looking statement, except to the extent required by applicable law. Headquartered in Lynchburg, Va., BWX Technologies, Inc. (NYSE:BWXT) is a leading supplier of nuclear components and fuel to the U.S. government; provides technical and management services to support the U.S. government in the operation of complex facilities and environmental remediation activities; and supplies precision manufactured components, services and fuel for the commercial nuclear power industry. With approximately 6,000 employees, BWXT has nine major operating sites in the U.S. and Canada. In addition, BWXT joint ventures provide management and operations at a dozen U.S. Department of Energy and two National Aeronautics and Space Administration (NASA) facilities. Follow us on Twitter @BWXTech and learn more at www.bwxt.com.


News Article | October 13, 2016
Site: cleantechnica.com

By James Larsen, Director of Business Development with The Advanced Energy Centre at MaRS Discovery District in Toronto, Canada North American households consume almost 2x the amount of energy as typical European households, and 6x that of Latin America or Asia. Read that again. Canadian and U.S. households consume a whopping 12,000 kWh of energy per year. But why? In some jurisdictions, consumers have access to cheap energy. In Quebec, for example, residents have grown accustomed to abundant hydro power. This low-cost, legacy generation, transmission and distribution infrastructure was fully depreciated long ago. The capital cost has since been paid off, therefore the cost of electricity is actually just a function of the very small cost to produce it. This is a big driver for the extremely low residential electricity costs of only around 7 cents/kWh in Quebec. At those prices, typical energy bills reach around $72 per month – a rather weak incentive to reduce consumption. And when compared to average European levels of approximately 18 cents/kWh, which are 150% above Quebec rates, one can begin to understand Europeans’ conservative energy use. It’s no surprise that an abundance of cheap energy has contributed to significantly more liberal consumption habits among North Americans. For example, Canadians watch an average of 30 hours of TV per week; only slightly less than our southern neighbors, who clock in at 33 hours. Compare that to Sweden and China, which each average around 18 hours per week — that’s almost half of our consumption. How about laundry? Approximately 85% of U.S. households own tumble dryers, and the majority of people are running 2 or more loads per week. Dryers account for 6% of the country’s residential electricity consumption each year and add a cumulative $9 billion to American families’ utility bills. By comparison, the U.K. gets by on a 57% dryer ownership rate (most European countries have tumble dryer ownership rates below 50%), and U.K. customers who embrace hang drying far outnumber those who don’t — by a ratio of 14:1. A worse habit still, is our maintenance of indoor temperature. Here, the U.S. statistics are the most bracing. A nation with over 300 million people, accounting for only 4.5% of the world population, consumes more energy for air conditioning than the rest of the world combined. America uses more electricity for cooling than Africa, a population of 1.1 billion, uses for everything! Another key underlying and structural factor that further exacerbates consumption behavior is the size of our houses. In Canada and the U.S., the average home size is around 1,950 sqft and 2,160 sqft, respectively. Compare that to Italy at 870 sq ft, Japan at 1,000 sq ft, Russia at 615 sq ft or China at 650 sq ft. Larger houses mean larger areas to heat and cool to maintain our optimum indoor temperatures. Larger living spaces also boosts the energy we use for lights, devices, and other appliances. Interestingly, as illustrated by the comparisons with our international peers, we can certainly improve our attitudes and behaviors with respect to energy. However, changing habits is hard, and it’s often easier to rely on other solutions to avoid lifestyle adjustments. Therefore, while we have the power to alter all of the above drivers of our aggressively high energy usage, we instead make decisions to supply more energy. Ontario, recently decided to refurbish the Bruce Power Plant at a cost of $13 billion, ensuring the supply of 45,000 GWh of energy per year through 2064 — a massive, long-term capital project. Consider this: if Ontario’s roughly 13 million residents were to decrease their energy usage to European levels (ie. 4,000 kWh/year/household of conserved energy), energy demand could be reduced by 20,000 GWh/year — almost half of the power coming online from Bruce. Given some of the aforementioned structural issues (e.g., our large home sizes), it is unlikely that we could reach that level of conservation, but even attaining half of that goal makes a good argument for us to look to conservation first. There are impressive examples from leading jurisdictions in North America on avoiding the costs of new supply through conservation. California provides an excellent example, as efficiency measures launched during the 1970s have since saved nearly $90 billion on customers’ energy bills and avoided at least 30 power plants, with 11 more plants expected to be avoided over the coming decade. The example from California and Ontario’s previous Conservation and Demand Management Framework and its new Conservation First program are good starts, but more can be done. North Americans are way out of sync with the rest of the world and it is time for us to act. The silver lining is that there are technologies in place that can help us reduce our energy consumption. Part of MaRS Discovery District, the Advanced Energy Centre represents leading technologies, like Ecobee’s smart thermostat, that leverages temperature control data to automatically make intelligent and personalized heating and cooling decisions, as well as Nanoleaf’s light bulbs — the world’s most efficient LEDs. There are also several technologies like Ecotagious or Eyedro that help customers understand their energy usage and meet their demand savings and energy efficiency targets. With an increased awareness and urgency to change our attitudes, habits and behaviour, coupled with new technologies and innovations, we have the ability to further reduce our energy usage, avoiding massive capital projects and their associated costs, while also contributing to the fight against climate change. James Larsen is the Director of Business Development at The Advanced Energy Centre (part of MaRS Discovery District), a public-private partnership with a mission to foster the adoption of innovative clean energy technologies in Canada, and to leverage those successes and experiences into international markets. Prior to joining The Advanced Energy Centre, James was a Management Consultant with Bain & Company, developing strategic solutions for market-leading companies.  James also spent many years as an engineer working in the renewable energy industry with a variety of technologies, including hydrogen fuel cells, micro-hydro and geothermal generation. James has dedicated significant personal time towards his passion for sustainability, founding the 2011 Ivey Business School sustainability conference and ecological footprint reduction challenge.  James also volunteers as an Advisor with MaRS Cleantech’s Venture Services group, providing business advisory to young cleantech companies, to help them grow into successful sector leaders. Buy a cool T-shirt or mug in the CleanTechnica store!   Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech daily newsletter or weekly newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.


CAMBRIDGE, Ontario--(BUSINESS WIRE)--BWX Technologies, Inc. (NYSE:BWXT) announced today that its subsidiary BWXT Canada Ltd. (BWXT Canada) has been awarded a four-year amendment to its existing Master Services Agreement (MSA), which went into effect on January 1, 2015, for feeder inspection services at Bruce Power, located near Kincardine, Ontario, Canada. Valued at approximately $30 million (Canadian), the MSA work scope addition includes the training of personnel followed by inspections during scheduled maintenance outages of feeder pipes that carry coolant to and from the reactor core. The long term nature of this agreement fosters the development of innovative methods to optimize outages in support of Bruce Power’s commitment to providing low-cost power for Ontarians. “We are pleased to provide long-term feeder inspection services for Bruce Power and are committed to ensuring this work is carried out safely, on time and within budget,” said John MacQuarrie, President of BWXT Canada. “The long-term nature of this work will allow us to invest in training and continuous improvement, and allow us to sustain highly skilled, highly paid staff that will carry out this important work.” “Bruce Power is pleased to expand our MSA with BWXT Canada,” said Kevin Kelly, Chief Financial Officer and Executive Vice President, Finance and Commercial Services. “The execution of these critical services will enable Bruce Power to continue providing low-cost power to Ontarians for many years to come.” BWXT Canada has performed feeder inspection services for Bruce Power over the last five years. Feeder inspection services under the MSA will commence in 2017. BWXT Canada Ltd. (BWXT Canada) has over 60 years of expertise and experience in the design, manufacturing, commissioning and service of nuclear power generation equipment. This includes CANDU® and Pressurized Water Reactor steam generators, nuclear fuel and fuel components, critical plant components, parts and related plant services. Headquartered in Cambridge, Ontario, BWXT Canada has approximately 850 employees at locations in Cambridge, Peterborough, Toronto and Arnprior, Ontario. BWXT Canada is a subsidiary of BWX Technologies, Inc. (NYSE:BWXT). BWXT is a leading supplier of nuclear components and fuel to the U.S. government; provides technical and management services to support the U.S. government in the operation of complex facilities and environmental remediation activities; and supplies precision manufactured components, services and fuel for the commercial nuclear power industry. Learn more at www.BWXT.com. BWXT cautions that this release contains forward-looking statements, including statements relating to the timing and value of the MSA amendment, to the extent either can be viewed as an indicator of future revenues. These forward-looking statements involve a number of risks and uncertainties, including, among other things, delays or other difficulties in contract execution, or modification or termination of the contract. If one or more of these or other risks materialize, actual results may vary materially from those expressed. For a more complete discussion of these and other risk factors, please see BWXT’s most recent annual report on Form 10-K and subsequent quarterly reports on Form 10-Q filed with the Securities and Exchange Commission. BWXT cautions not to place undue reliance on these forward-looking statements, which speak only as of the date of this release, and undertakes no obligation to update or revise any forward-looking statement, except to the extent required by applicable law.

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