Western Power

Perth, Australia

Western Power

Perth, Australia
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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 | 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 | November 1, 2016
Site: www.marketwired.com

CALGARY, ALBERTA--(Marketwired - Nov. 1, 2016) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada) today announced a net loss attributable to common shares for third quarter 2016 of $135 million or $0.17 per share compared to net income of $402 million or $0.57 per share for the same period in 2015. Third quarter 2016 results included a $656 million after-tax goodwill impairment charge related to our U.S. Northeast Power business. Excluding the net loss on the goodwill impairment and certain other specific items, comparable earnings for third quarter 2016 were $622 million or $0.78 per share compared to $440 million or $0.62 per share for the same period in 2015. TransCanada's Board of Directors also declared a quarterly dividend of $0.565 per common share for the quarter ending December 31, 2016, equivalent to $2.26 per common share on an annualized basis. "Excluding specific items, comparable earnings per share for the quarter were significantly higher than last year as a result of the Columbia acquisition and continued solid performance from our large portfolio of high-quality energy infrastructure assets," said Russ Girling, TransCanada's president and chief executive officer. "Since completing the Columbia transaction, we have made significant progress in integrating its operations with our existing U.S. natural gas pipeline business and are well on track to realize the targeted US$250 million of annualized benefits associated with the acquisition." On July 1, 2016, TransCanada completed the acquisition of Columbia Pipeline Group, Inc. (Columbia) for US$13 billion. Columbia operates a portfolio of approximately 24,000 km (15,000 miles) of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets. "The addition of Columbia reinforces our position as one of North America's leading energy infrastructure companies with an extensive pipeline network that links the continent's most prolific natural gas supply basins to its most attractive markets," added Girling. "Looking forward, the addition of Columbia's US$7.7 billion growth program brings our industry-leading portfolio of near-term capital projects to over $25 billion. As these projects progress through the permitting and construction phases and into operation over the balance of the decade, they are expected to generate significant growth in earnings and cash flow and support an expected annual dividend growth rate at the upper end of the Company's previous expectation of eight to 10 per cent through 2020." Net income attributable to common shares decreased by $537 million to a net loss of $135 million or $0.17 per share for the three months ended September 30, 2016 compared to the same period last year. Third quarter 2016 included a $656 million after-tax goodwill impairment charge, an after-tax charge of $67 million related to costs associated with the acquisition of Columbia, a $50 million after-tax charge related to risk management activities, recognition of $28 million of income tax recoveries resulting from a third party sale of Keystone XL project assets, a $9 million after-tax charge related to Keystone XL maintenance and liquidation costs and $3 million of after-tax costs related to the sale of our U.S. Northeast Power business. All of these specific items are excluded from comparable earnings. Comparable earnings for third quarter 2016 were $622 million or $0.78 per share compared to $440 million or $0.62 per share for the same period in 2015, an increase of $182 million or $0.16 per share. The increase was primarily the net effect of a higher contribution from U.S. Pipelines primarily due to incremental earnings from Columbia following the acquisition on July 1, 2016 and a higher ANR transportation and storage revenue resulting from higher rates effective August 1, 2016; a higher contribution from Mexican pipelines primarily due to earnings from Topolobampo beginning in July 2016; higher interest income and other due to realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income; higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired in February 2016 and higher sales to customers in the PJM market partially offset by lower capacity revenues in New York; higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest partially offset by higher losses from contracting activities; and higher earnings from Canadian Pipelines primarily due to a higher NGTL investment base and incentive earnings from the Canadian Mainline and NGTL. These gains were partially offset by higher interest expense from debt issuances and lower capitalized interest as well as lower earnings from Liquids Pipelines due to the net effect of higher contracted and lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink. The unaudited interim condensed Consolidated Financial Statements and Management's Discussion and Analysis (MD&A) are available under TransCanada's profile on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com. With more than 65 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 90,300 kilometres (56,100 miles), tapping into virtually all major gas supply basins in North America. TransCanada is the continent's largest provider of gas storage and related services with 664 billion cubic feet of storage capacity. A large independent power producer, TransCanada owns or has interests in over 10,500 megawatts of power generation in Canada and the United States. TransCanada is also the developer and operator of one of North America's leading liquids pipeline systems that extends over 4,300 kilometres (2,700 miles) connecting growing continental oil supplies to key markets and refineries. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com and our blog to learn more, or connect with us on social media and 3BL Media. This release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "believe", "may", "will", "should", "estimate", "intend" or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future plans and financial outlook. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada's Quarterly Report to Shareholders dated November 1, 2016 and 2015 Annual Report on our website at www.transcanada.com or filed under TransCanada's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov and available on TransCanada's website at www.transcanada.com. This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, comparable distributable cash flow, comparable funds generated from operations, funds generated from operations, comparable earnings per share and comparable distributable cash flow per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada's Quarterly Report to Shareholders dated November 1, 2016. Additional Information and Where to Find it In connection with the proposed acquisition of the outstanding common units of CPPL, CPPL will file with the SEC a proxy statement with respect to a special meeting of its unitholders to be convened to approve the transaction. The definitive proxy statement will be mailed to the unitholders of CPPL. INVESTORS ARE URGED TO READ THE PROXY STATEMENT AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION. Investors will be able to obtain these materials, when they are available, and other documents filed with the SEC free of charge at the SEC's website, www.sec.gov. In addition, copies of the proxy statement, when available, may be obtained free of charge by accessing CPPL's website at www.columbiapipelinepartners.com or by writing CPPL at 5151 San Felipe Street, Suite 2500, Houston, Texas 77056, Attention: Corporate Secretary. Investors may also read and copy any reports, statements and other information filed by CPPL with the SEC, at the SEC public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 or visit the SEC's website for further information on its public reference room. Columbia, an indirect wholly owned subsidiary of the Company, and certain of its directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies in respect of the transaction. Information regarding Columbia's directors and executive officers is available in its Current Report on Form 8-K filed with the SEC on July 1, 2016. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy statement and other relevant materials to be filed with the SEC when they become available. This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and nine months ended September 30, 2016, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2016 which have been prepared in accordance with U.S. GAAP. On July 1, 2016, we completed the acquisition of Columbia Pipeline Group, Inc. (Columbia). For further information on the acquisition refer to note 4 of the September 30, 2016 unaudited condensed consolidated financial statements. The three and nine months ended September 30, 2016 amounts reflect the results of Columbia post-acquisition from July 1, 2016. Comparative figures do not include Columbia. This MD&A should also be read in conjunction with our December 31, 2015 audited consolidated financial statements and notes and the MD&A in our 2015 Annual Report. Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries. Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2015 Annual Report. All information is as of November 1, 2016 and all amounts are in Canadian dollars, unless noted otherwise. We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall. Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words. Forward-looking statements in this MD&A may include information about the following, among other things: Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A. Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties: You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2015 Annual Report. You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, except as required by law. You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com). We use the following non-GAAP measures: These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures. We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings. It is calculated in the same way as EBITDA, less depreciation and amortization. Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. See the Financial condition section for a reconciliation to net cash provided by operations. We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. Our decision not to include a specific item is subjective and made after careful consideration. Specific items may include: We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations. Comparable distributable cash flow is defined as comparable funds generated from operations plus distributions received from operating activities in excess of equity earnings from equity-accounted for investments less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. See the Financial condition section for a reconciliation to net cash provided by operations. Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change. Net income attributable to common shares decreased by $537 million to a net loss of $135 million for the three months ended September 30, 2016 and decreased $736 million for the nine months ended September 30, 2016 compared to the same periods in 2015. The 2016 results included: Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings. Comparable earnings increased by $182 million and $180 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 as discussed below in the reconciliation of net income to comparable earnings. Comparable earnings increased by $182 million for the three months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of: Comparable earnings increased by $180 million for the nine months ended September 30, 2016 compared to the same period in 2015. This was primarily the net effect of: 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 long-term capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow. Our capital program as of September 30, 2016, consists of $25 billion of near-term projects and $48 billion of commercially secured medium- to longer-term projects. Amounts presented exclude maintenance capital expenditures, capitalized interest and AFUDC. All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits. Our overall comparable earnings outlook for 2016 will be higher than what was previously included in the 2015 Annual Report due to the net impact of the acquisition of Columbia on July 1, 2016, increased earnings from the remainder of our Natural Gas Pipelines' assets, changes in our Canadian Power business and lower than expected Liquids and U.S. Power earnings, each of which are addressed within the relevant section of the MD&A. Our expected total capital expenditures as outlined in the 2015 Annual Report remains unchanged. On April 11, 2016, we announced that we were chosen to build, own and operate the Villa de Reyes pipeline in Mexico. On June 13, 2016, we announced that our joint venture with IEnova, Infraestructura Marina del Golfo (IMG), was chosen to build, own and operate the Sur de Texas natural gas pipeline in Mexico. On July 1, 2016, we acquired Columbia. Although we expect to defer capital expenditures on several of our other natural gas pipelines projects, we expect to spend an estimated additional $1 billion on Columbia capital projects in 2016, approximately $300 million on the Villa de Reyes pipeline project and $200 million on the Sur de Texas pipeline project. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change. In addition, Columbia results are included in the Natural Gas Pipelines segment from its acquisition on July 1, 2016. Comparative periods do not include Columbia. Natural Gas Pipelines segmented earnings increased by $231 million and $325 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. Segmented earnings for the three and nine months ended September 30, 2016 included $82 million primarily related to retention and severance expenses incurred within the Natural Gas Pipelines segment resulting from the Columbia acquisition. Year-to-date 2016 segmented earnings also included an additional $4 million pre-tax loss on the sale of TC Offshore. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below. Net income and comparable EBITDA for our rate-regulated Canadian pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis. Net income for the Canadian Mainline increased by $5 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to higher incentive earnings, partially offset by a lower average investment base and higher carrying charges. Net Income for the Canadian Mainline decreased by $7 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to a lower average investment base and higher carrying charges, partially offset by higher incentive earnings in 2016. Net income for the NGTL System increased by $11 million and $33 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to a higher average investment base and OM&A incentive earnings recorded in 2016. Earnings for our U.S. natural gas pipelines operations, which include Columbia effective July 1, 2016, are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services. Columbia and ANR results are also affected by the contracting and pricing of its storage capacity and incidental commodity sales. The results for Columbia include our 91.6 per cent effective ownership of Columbia Gas Transmission, Columbia Gulf Transmission, Columbia Midstream and Columbia Energy Ventures through a 84.3 per cent direct ownership and our 46.5 per cent ownership in Columbia Pipeline Partners LP which owns the remaining 15.7 per cent ownership interest in these assets. Comparable EBITDA for U.S. and International Pipelines increased by US$265 million and US$311 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015. This was the net effect of: As well, a stronger U.S. dollar on a year-to-date basis in 2016 compared to 2015 had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations. Depreciation and amortization increased by $77 million and $91 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the Columbia acquisition on July 1, 2016, a higher investment base on the NGTL System, increased depreciation rates on ANR following the rate settlement, and the effect of a stronger U.S. dollar. Business development expenses were lower by $7 million and $23 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to the capitalization of business development activities in 2016 related to the successful Mexico projects, a focus on the Columbia acquisition and decreased business development activity in other areas in 2016. The 2016 earnings outlook for the Canadian regulated and Mexican pipelines remains consistent with what we disclosed in the 2015 Annual Report. We are expecting an increase in 2016 earnings from U.S. Pipelines as a result of the acquisition of Columbia on July 1, 2016 although the impact of the related financing will be reflected in our Corporate segment. Earnings for the other U.S. Pipelines are expected to be slightly higher this year as a result of higher revenues and lower costs. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change. Liquids Pipelines segmented earnings decreased by $97 million and $164 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included pre-tax charges related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project as well as unrealized losses from changes in the fair value of derivatives related to our liquids marketing business. These amounts have been excluded from our calculation of comparable EBIT. The remainder of the Liquids Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below. Comparable EBITDA for the Keystone Pipeline System is generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings. Comparable EBITDA for the Keystone Pipeline System decreased by $76 million and $118 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was due to the net effect of lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink, partially offset by higher contracted volumes on Keystone Pipeline. Business development and other, which primarily includes business development activity and our marketing business, decreased by $5 million and $9 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was the effect of lower business development spending and a growing contribution from the marketing business. Depreciation and amortization increased by $4 million and $12 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar. Excluding specified items, our 2016 earnings are expected to be lower than our 2015 earnings due to lower uncontracted volumes and market conditions related to the lower crude oil price environment. Following our Keystone XL impairment charge in 2015, expenditures on the project for the maintenance and liquidation of project assets are being expensed pending further advancement of this project and are expected to be approximately $55 million before tax ($36 million after tax) in 2016. These costs will continue to be excluded from comparable earnings. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change. Energy segmented earnings decreased by $1,069 million and $1,284 million to segmented losses of $825 million and $569 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT: The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impacts of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations. Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast Power business, we were required to discontinue hedge accounting for certain cash flow hedges. This, along with the increased volume of our risk management activities associated with the expansion of our customer base in the PJM market, has contributed to higher volatility in U.S. Power risk management activities. The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below. Comparable EBITDA for Energy increased by $79 million for the three months ended September 30, 2016 compared to the same period in 2015 due to the net effect of: Comparable EBITDA for Energy decreased by $6 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to the net effect of: Includes our share of volumes from our equity investments. Comparable EBITDA for Western Power increased by $2 million for the three months ended September 30, 2016 compared to the same period in 2015 mainly due to higher realized prices on generated volumes offset by lower earnings following the termination of the PPAs. Comparable EBITDA for Western Power decreased by $24 million for the nine months ended September 30, 2016 compared to the same period in 2015 due to lower realized power prices and termination of the PPAs. Results from the Alberta PPAs are included up to March 7, 2016 when we sent notice to the Balancing Pool to terminate the PPAs for the Sundance A, Sundance B and Sheerness facilities. Comparable income from equity investments included earnings from the ASTC Power Partnership which held our 50 per cent ownership in the Sundance B PPA. See the Recent developments section for more information on the PPA terminations. Average spot market power prices in Alberta decreased 31 per cent from $26/MWh to $18/MWh for the three months ended September 30, 2016 and decreased 54 per cent from $37/MWh to $17/MWh for the nine months ended September 30, 2016 compared to the same periods in 2015. The Alberta power market remained well-supplied and power consumption was down due to a weak economy. Realized power prices on power sales can be higher or lower than spot market power prices in any given period as a result of contracting activities. One hundred per cent of Western Power sales volumes were sold under contract in third quarter 2016 compared to 61 per cent in third quarter 2015. Depreciation and amortization decreased by $12 million and $24 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 following the termination of the PPAs. We continue to expect Western Power 2016 earnings to be consistent with 2015 earnings. Although Alberta power prices are expected to remain low in the remaining months of 2016, the natural gas-fired cogeneration assets are expected to perform well in the lower natural gas price environment and the March 2016 decision to exercise the right to terminate the PPAs is expected to result in savings from the otherwise increased costs related to carbon emissions. Comparable EBITDA for Eastern Power decreased by $4 million and $36 million for the three and nine months ended September 30, 2016 compared to the same period in 2015 mainly due to lower contractual earnings at Bécancour, and lower earnings on the sale of unused natural gas transportation for the nine months ended September 30, 2016 compared to the same period in 2015. Our 2016 earnings outlook provided in the 2015 Annual Report will be modestly lower as a result of a delay in the implementation of amendments to the Bécancour electricity supply contract. See the Recent developments section for more information about this agreement. Results reflect our proportionate share. Bruce A and B were merged in December 2015 and comparative information for 2015 is reported on a combined basis to reflect the merged entity. Equity income from Bruce Power increased by $19 million and $8 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to lower depreciation as a result of the Bruce Power facility's operating life extension and our increased ownership interest. These increases were partially offset by higher losses from contracting activities in the three months ended September 30, 2016 and lower volumes and higher operating costs from higher planned outage days for the nine months ended September 30, 2016 compared to the same periods in 2015. In December 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the Bruce Power facility to 2064. As part of this agreement, Bruce Power began receiving a uniform price of $65.73 per MWh for all units, which includes certain flow-through items such as fuel and lease expenses recovery. Over time, the price will be subject to adjustments for the return of and on capital invested under the Asset Management and Major Component Replacement capital programs, along with various other pricing adjustments that allow for a better matching of revenues and costs over the long term. Prior to the amended agreement with the IESO, all of the output from Bruce units 1 to 4 was sold at a fixed price/MWh which was adjusted annually on April 1 for inflation and other provisions under the contract. Prior to the amended agreement with the IESO, all output from Bruce units 5 to 8 was subject to a floor price adjusted annually for inflation on April 1. Bruce Power also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price. The contract with the IESO provides for payment if the IESO reduces Bruce Power's generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered deemed generation for which Bruce Power is paid the contract price. During second quarter 2016, Bruce units 1 to 4 were removed from service for approximately three weeks to facilitate a station containment outage. The station containment outage involved inspecting and maintaining key safety systems including containment structures and is required to be completed approximately once every decade. Additional planned maintenance was completed on unit 3 in third quarter 2016. Planned maintenance on unit 7 began in third quarter 2016 and is scheduled to be completed in fourth quarter 2016. The overall average plant availability percentage in 2016 is expected to be in the low 80s. We expect 2016 equity income from Bruce Power to be slightly higher than our 2016 Outlook in the 2015 Annual Report primarily due to strong results year-to-date. Comparable EBITDA for U.S. Power increased US$24 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to the net effect of: Comparable EBITDA for U.S. Power decreased US$12 million for the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to the net effect of: Higher sales to wholesale utility customers in the PJM market resulted in higher earnings for the three months ended September 30, 2016 compared to the same period in 2015 as we continue to expand our customer base in the PJM market. However, significantly lower realized power prices and mild winter weather have resulted in lower margins in our wholesale business in both the PJM and New England markets for the nine months ended September 30, 2016 compared to the same period in 2015, the impact of which was primarily seen in the first quarter results. Wholesale electricity prices in New York and New England were slightly higher for the three months ended September 30, 2016 and significantly lower for the nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to unseasonably warm weather in first quarter 2016. In New England, spot power prices for the three and nine months ended September 30, 2016 were 10 per cent higher and 38 per cent lower compared to the same periods in 2015. In New York City, spot power prices for the three and nine months ended September 30, 2016 were six per cent higher and 34 per cent lower compared to the same periods in 2015. Average New York Zone J spot capacity prices were approximately 20 per cent and 23 per cent lower for the three and nine months ended September 30, 2016 compared to the same periods in 2015. The decrease in spot prices and the offsetting impact of hedging activities resulted in lower realized capacity prices in New York. This was primarily due to an increase in demonstrated capability from existing resources in New York City's Zone J market. The impact of lower capacity prices in New York was partially offset by capacity revenues earned by our Ironwood power plant acquired in February 2016. Capacity revenues were also negatively impacted by an outage at Unit 30 from September 2014 to May 2015 at Ravenswood. The calculation used by the NYISO to determine the capacity volume for which a generator is compensated utilizes a rolling average forced outage rate. As a result of this methodology, outages impact capacity volumes and associated revenues on a lagged basis. Accordingly, capacity revenues for the three and nine months ended September 30, 2016 were negatively impacted compared to the same periods in 2015. The outage continues to be included in the rolling average forced outage rate. Insurance recoveries, net of deductibles, for this event have been received and are being recognized in capacity revenues to offset amounts lost during the periods impacted by the lower forced outage rate. As a result of these insurance recoveries, the Unit 30 unplanned outage has not had a significant impact on our earnings although the recording of earnings has not coincided exactly with lost revenues due to timing of the insurance proceeds. In addition, insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008 were received in June 2016 and a portion of the proceeds were recognized in Power Revenue. Physical generation volumes in 2016 were higher compared to the same period in 2015 due to our acquisition of the Ironwood power plant and higher generation at our Ravenswood facilities. Physical purchased volumes sold to wholesale, commercial and industrial customers were higher for the three and nine month months ended September 30, 2016 than the same periods in 2015 as we have expanded our customer base in the PJM and New England markets. As at September 30, 2016, approximately 1,500 GWh, or 43 per cent, of U.S. Power's planned generation was contracted for the remainder of 2016 and 3,900 GWh, or 30 per cent, for 2017. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage and plant availability. U.S. Power results for 2016 are not expected to be significantly impacted by the announced monetization of the U.S. Northeast Power business as these transactions are not expected to close until the first half of 2017. See the Recent developments section for more information. Nevertheless, operating results for the full year in 2016 are expected to be lower than the Outlook in our 2015 Annual Report due to lower commodity prices experienced in the first half of 2016. Comparable EBITDA increased by $21 million and $31 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 mainly due to increased storage revenues as a result of higher realized natural gas storage price spreads. The full year 2016 results are expected to be higher compared to 2015 due to the lack of seasonal winter weather conditions, excess natural gas supply and the resulting increase in natural gas storage price spreads which have provided the opportunity to hedge available storage capacity at higher values than originally expected in the Outlook in our 2015 Annual Report. The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments as a result of our 2015 business transformation initiative. 2015 results have been restated to reflect this change. Corporate segmented losses in 2016 increased by $6 million and $61 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included the following specific items that have been excluded from comparable EBIT: Comparable interest expense increased by $175 million and $351 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 due to the net effect of: Comparable interest income and other increased by $80 million and $277 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 due to the net effect of: Comparable income tax expense increased by $25 million and decreased by $38 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and was mainly the result of changes in the proportion of income earned between Canadian and foreign jurisdictions and lower flow-through taxes in 2016 on Canadian regulated pipelines. Net income attributable to non-controlling interests increased by $6 million and $39 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 and included a $3 million charge related to the non-controlling interest portion of retention and severance expenses resulting from the Columbia acquisition. Comparable net income attributable to non-controlling interests increased by $9 million and $42 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to the acquisition of Columbia which included a non-controlling interest in Columbia Pipeline Partners LP. In addition, the sale of our 30 per cent direct interest in GTN in April 2015 and 49.9 per cent direct interest in PNGTS in January 2016 to TC PipeLines, LP along with the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP increased net income attributable to non-controlling interests year-over-year. Preferred share dividends increased by $4 million and $6 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to preferred shares issuances in 2016 and 2015 offset by lower dividend rates on certain series. On July 1, 2016, we closed the acquisition of Columbia valued at US$13 billion comprised of a purchase price of approximately US$10.3 billion and Columbia debt of approximately US$2.7 billion. The acquisition was financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, following the closing of the acquisition, were exchanged into 96.6 million TransCanada common shares. See Financial condition section for additional information on the bridge term loan credit facilities and the subscription receipts. Columbia operates a portfolio of approximately 24,000 km (15,000 miles) of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets. We acquired Columbia to expand our natural gas business in the U.S. market, positioning ourselves for additional long-term growth opportunities. The acquisition also includes a large portfolio of new capital growth projects which includes seven pipeline expansion projects designed to transport growing supply from the Marcellus / Utica production basins to markets as well as a scheduled program for modernization of existing infrastructure out to 2020 to ensure the continuation of a safe, reliable and efficient system. We are currently executing plans to ensure an effective integration of Columbia into the TransCanada organization. We remain on track to realizing our $250 million of annual cost, revenue and financing benefits. The following table summarizes the acquisition related costs for Columbia that have been excluded from comparable earnings for the three and nine months ended September 30, 2016. We currently expect to realize approximately US$3.7 billion from the monetization of our U.S. Northeast Power business. This includes the November 1, 2016 announced sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors for US$2.2 billion and TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC for US$1.065 billion, with the remainder attributed to the marketing business which is expected to be realized going forward. These two sale transactions are expected to close in the first half of 2017 subject to certain regulatory and other approvals and will include closing adjustments. These sales are expected to result in an approximate $1.1 billion after-tax net loss which is comprised of a $656 million after-tax goodwill impairment charge recorded at September 30, 2016, an approximate $863 million after-tax net loss on the sale of the thermal and wind package to be recorded in fourth quarter 2016 and an approximate $443 million after-tax gain on the sale of the hydro assets to be recorded upon close of that transaction. Proceeds from these sales and future realization of value of the marketing business will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to partially finance the Columbia acquisition earlier this year. As part of the Columbia acquisition financing plan, we previously disclosed our intention to monetize a minority interest in our Mexico natural gas pipeline business. On November 1, 2016, we announced a decision to maintain our full ownership interest in a growing portfolio of natural gas pipeline assets in Mexico rather than sell a minority interest in six of these pipelines, which is consistent with maintaining a simple corporate structure. We currently own and operate the Tamazunchale and Guadalajara pipelines and are investing US$3.8 billion to develop and complete construction of four additional pipelines plus fund our interest in the Sur de Texas project, all of which will serve growing natural gas demand in Mexico. All projects are expected to be in-service by the end of 2018 and are underpinned by 25-year take-or-pay contracts with the CFE. Once completed, we expect our Mexican natural gas pipeline assets to be accretive to earnings per share and generate approximately US$575 million of annual EBITDA, up from US$181 million in 2015. In connection with this decision, we also entered into an agreement with a group of underwriters to proceed with a common equity offering concurrent with the release of these financial results. See Corporate recent developments for more information. On October 31, 2016, the Government of Canada approved our $1.3 billion NGTL 2017 Facilities Application. In addition, on October 6, 2016, the NEB recommended to the government approval of the $0.4 billion Towerbirch Project. This project consists of a 55 km (34 miles) pipeline loop and a 32 km (20 miles) pipeline extension of the NGTL System in northwest Alberta and northeast B.C. Of NGTL's $5.4 billion near-term capital program we have received approvals for $4.0 billion, while $0.5 billion has been filed and is awaiting approval. Approximately $0.9 billion is expected to filed with regulators in the future. We continue to work closely with our shippers to ensure that new proposed facilities meet our shippers and market demands. In second quarter 2016, we added new long term delivery contracts on the NGTL System to meet demand in the Pacific Northwest and California which will require the construction of $135 million of new facilities (the Sundre Crossover Project) that were not previously included in our 2018 Facilities program. The open season process supporting the development of these new contracts identified further demand for service to this market that we are currently assessing. In second quarter 2016, in response to cancellations or deferrals of our certain customer projects, contract non-renewals, and contract transfers, we re-evaluated planned facility requirements to meet future aggregate system service requirements and made changes in the spending profile of our programs to match revised in-service dates. The projected expansion capital spend for the NGTL System remains at approximately $7.3 billion, including the new Sundre Crossover Project, the North Montney and Merrick pipelines and the cancellation of a $66 million project. We have deferred approximately $225 million of spending for facilities in the 2016/17 Facilities program with revised service dates of 2018 through 2020 as well as $210 million of spending for facilities in the 2018 Facilities program with revised service dates of 2019 and 2020. In March 2016, we filed a request with the NEB for a one year extension to the June 10, 2016 sunset clause in the North Montney Mainline (NMML) project Certificate of Public Convenience and Necessity (CPCN). On September 15, 2016, the NEB approved the sunset clause extension to June 10, 2017. The extension continues to be subject to the condition that construction shall not begin until a positive Final Investment Decision (FID) has been made on the Pacific Northwest LNG (PNW LNG) Project. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the NMML facilities, however, the in-service date will be finalized once a FID has been made. In April 2016, the NEB approved the NGTL revenue requirement settlement application that was filed in December 2015, subject to certain reporting requirements that were subsequently met and approved by the NEB. The settlement includes a ROE of 10.1 per cent on a deemed common equity of 40 per cent, continuation of 2015 depreciation rates, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration cost amount and flow-through treatment of all other costs. On October 13, 2016, we launched an open season for the Canadian Mainline, seeking binding commitments on our new long-term, fixed-price proposal to transport WCSB supply from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The contract term for this service is ten years with tolls ranging from $0.75/GJ to $0.82/GJ depending on the shippers' contract volume commitments. Early termination rights are provided and can be exercised following the initial five years of service upon payment of a premium fee. Subject to a successful open season that closes November 10, 2016, and to NEB regulatory approval, the new service is targeted to begin November 1, 2017. The July 1, 2016 acquisition of Columbia included a capital expansion program that was underway for new facilities planned to be in service in 2017 and 2018 as well as modernization programs for existing assets to be completed through 2020. The large capital expansion program consists of US$7.4 billion related to our regulated pipeline business and US$0.3 billion related to our midstream business. The following summarizes the key capital projects for this new set of assets that are now part of the our overall Natural Gas Pipelines footprint in North America. This Columbia Gas Transmission (TCO) project is designed to transport up to 1.5 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the Columbia Gulf System (CGT). The project consists of 219 km (136 miles) of 36-inch greenfield pipe, 39 km (24 miles) of 36-inch loop, three km (two miles) of 30-inch greenfield pipe, 82.8 MW (111,000 hp) of greenfield compression and 24.6 MW (33,000 hp) of brownfield compression. We expect the project, with an estimated capital investment of US$1.4 billion, to be in service in fourth quarter 2017. The FERC 7(C) application was filed in June 2015 and the Final Environmental Impact Statement (FEIS) was received September 1, 2016. This CGT project is designed to transport up to 1.1 Bcf/d of southwest Marcellus and Utica production associated with the Leach XPress expansion and an interconnect with the Texas Eastern System (TETCO) to various delivery points on the CGT system and Gulf Coast. The project consists of bi-directional compressor station modifications along the CGT system, 38.8 MW (52,000 hp) of greenfield compression, 20.1 MW (27,000 hp) of replacement compression and six km (four miles) of 30-inch pipe replacement. We expect the project, with an estimated capital investment of US$420 million, to be in service in fourth quarter 2017. The FERC 7(C) application was filed in July 2015 and the FEIS was received September 1, 2016. This TCO project is designed to transport up to 2.7 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with the CGT system. The project consists of 264 km (164 miles) of 36-inch greenfield pipeline, ten km (six miles) of 24-inch lateral pipeline, 0.6 km (0.4 miles) of 30-inch replacement pipeline, 114.1 MW (153,000 hp) of greenfield compression and 55.9 MW (75,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$2 billion, to be in service in fourth quarter 2018. The FERC 7(C) application was filed in April 2016. This CGT project is designed to transport up to 0.9 Bcf/d associated with the Mountaineer XPress expansion to various delivery points on the CGT system and Gulf Coast. The project consists of adding seven greenfield midpoint compressor stations along the CGT System route totaling 182.7 MW (254,000 hp). We expect this project, with an estimated capital investment of US$0.7 billion, to be placed in service in fourth quarter 2018. The FERC 7(C) application was filed in April 2016. This CGT project is designed to transport up to 0.8 Bcf/d of gas supply to the Cameron LNG export terminal in Louisiana. The project consists of 44 km (27 miles) of 36-inch greenfield pipeline, 11 km (seven miles) of 30-inch looping and 9.7 MW (13,000 hp) of greenfield compression. We expect this project, with an estimated capital investment of US$300 million, to be in service in first quarter 2018. The FERC certificate was received in September 2015. This TCO project is designed to transport up to 1.3 Bcf/d of Marcellus gas supply westbound (0.8 Bcf/d) to the Gulf Coast via an interconnect with the Tennessee Gas Pipeline, and eastbound (0.5 Bcf/d) to Mid-Atlantic markets, WGL Midstream and Transco interconnects. The project consists of 47 km (29 miles) of various diameter pipeline, 338 km (210 miles) of restoring and uprating maximum operating pressure of existing pipeline, 29.8 MW (40,000 hp) of greenfield compression and 99.9 MW (134,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$0.9 billion, to have a Western build in service in the beginning of second quarter 2018 and an Eastern build in service in fourth quarter 2018. The FERC 7(C) application for both segments was filed in December 2015. TCO and its customers have entered into a settlement arrangement, approved by FERC, which provides recovery and return on investment to modernize its system, improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Modernization I has been approved for up to US$0.6 billion of work yet to be completed in 2016 through 2017. Modernization II has been approved for up to US$1.1 billion of work to be completed in 2018 through 2020. As per terms of the arrangements, facilities in service by October 31 collect revenues effective February 1 of the following year. We expect to invest US$260 million to construct an approximate 1 MMDth/d dry gas header pipeline in southwest Pennsylvania to be completed in multiple phases with an initial in-service date in fourth quarter 2016 and a final in-service date in fourth quarter 2017. ANR reached a settlement with its shippers effective August 1, 2016 and filed the final, unopposed settlement agreement with the FERC for approval on September 16, 2016. Transmission reservation rates will increase by 34.8 per cent and storage rates will remain the same for contracts one to three years in length, while increasing slightly for contracts of less than one year and decreasing slightly for contracts more than three years in duration. There is a moratorium on any further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions, but must file for new rates no later than an effective date of August 1, 2022. On November 1, 2016, we announced that we have entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia Pipeline Group, Inc, has agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. Common unitholders will also continue to receive regular quarterly distributions of US$0.1975 per common unit including a pro-rated distribution for any partial period to the closing date. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions, and is expected to be accretive to earnings per share and simplify our corporate structure. There will be no gain or loss recorded on closing this transaction as CPPL is a consolidated subsidiary. The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver natural gas from interconnections with third party pipelines to Topolobampo, Sinaloa and into the Mazatlán pipeline. Construction of the pipeline is supported by a 25-year natural gas Transportation Service Agreement (TSA) for 670 MMcf/d with the CFE. The physical in-service date is expected to be delayed into 2017 due to right-of-way acquisition delays. Under the terms of the TSA, this delay is recognized as a force majeure event with provisions allowing for the collection of revenue as per the original TSA service commencement date of July 2016. The Mazatlán project is a 413 km (257 miles), 24-inch diameter pipeline running from El Oro to Mazatlán within the state of Sinaloa with an estimated cost of US$0.4 billion and is supported by 25-year contract with the CFE. Construction of the pipeline is supported by a 25-year natural gas TSA for 200 MMcf/d with the CFE. Physical construction is complete and is awaiting natural gas to commence in-service under the contract. The Tula project is a US$500 million, 36 inch, 250 km (155 mile) pipeline with a contracted capacity of 886 MMcf/d for 25 years with the CFE. The pipeline begins at Tuxpan, Veracruz extending through the states of Puebla and Hidalgo, supplying natural gas to markets near Tula, Querétaro. Construction has commenced with one pipeline spread and at the compressor stations. On April 11, 2016, we announced that we were awarded the contract to build, own and operate the Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 MMcf/d with the CFE. We expect to invest approximately US$0.5 billion to construct a 36-inch diameter, 420 km (261 mile) pipeline with an anticipated in-service date of early 2018. The pipeline will begin in Tula, in the state of Hidalgo, and terminate in Villa de Reyes, in the state of San Luis Potosí, transporting natural gas to power generation facilities in the central region of the country. The project will interconnect with our Tamazunchale and Tuxpan-Tula pipelines as well as with other transporters in the region. On June 13, 2016, we announced that our joint venture with IEnova had been chosen to build, own and operate the US$2.1 billion Sur de Texas pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 2.6 bcf/d with the CFE. We expect to invest approximately US$1.3 billion in the partnership to construct the 42-inch diameter, approximately 800 km (497 mile) pipeline with an anticipated in-service date of late 2018. The pipeline will start offshore in the Gulf of Mexico, at the border point near Brownsville, Texas, and end in Tuxpan, Mexico in the state of Veracruz. The project will deliver natural gas to our Tamazunchale and Tuxpan-Tula pipelines and to other transporters in the region. On September 27, 2016, Pacific NorthWest LNG (PNW LNG) received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. PNW LNG has indicated they will conduct a total project review over the coming months prior to announcing next steps for the project. PRGT continues engagement with Aboriginal groups and other stakeholders along the route in preparation for a FID by PNW LNG. To date, PRGT has executed long-term project agreements with twelve First Nation groups along the pipeline route. On July 11th, 2016, the LNG Canada joint venture participants announced a delay to their FID for the proposed liquefied natural gas facility in Kitimat, B.C. At this time, a future FID date has not been determined. In light of this announcement, we are working with LNG Canada to determine the appropriate pacing of the Coastal GasLink development schedule and work activities. On April 2, 2016, we shut down the Keystone pipeline after a leak was detected along the pipeline right-of-way in Hutchinson County, South Dakota. We reported the total volume of the release of 400 barrels to the National Response Center and the Pipeline and Hazardous Materials Safety and Administration (PHMSA). Temporary repairs were completed on April 9, 2016, and the Keystone pipeline was restarted on April 10, 2016. On May 5, 2016, permanent pipeline repairs were completed and restoration work was completed on July 3, 2016. Corrective measures required by PHMSA were completed in September 2016. This shutdown did not significantly impact our 2016 earnings. In August 2016, the Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline System to Houston, Texas, went into service. The terminal has an initial storage capacity for 700,000 barrels of crude oil. On March 1, 2016, the Province of Québec filed a court action seeking an injunction to compel the Energy East Pipeline to comply with the province's environmental regulations. On March 30, 2016, the Québec Superior Court joined the injunction action led by the Province of Québec with the prior action led by Québec Environmental Law Centre / Centre québécois du droit de l'environnement (CQDE), which sought a declaration to compel Energy East to submit to the mandatory provincial environmental review process. As a result of communication with the Ministère du Développement durable, Environnement et la Lutte contre les changements climatiques, on April 22, 2016, we filed a project review engaging an environmental assessment under the Environmental Quality Act (Québec) according to an agreed upon schedule for key steps in that process. This process is in addition to environmental assessment required under the NEB Act and the Canadian Environmental Assessment Act, 2012. The Attorney General for Québec has agreed to suspend its litigation against TransCanada and Energy East and to withdraw it once the provincial environmental assessment process has been completed. The CQDE has similarly agreed to suspend the action. These suspensions are in effect until early November 2016, but may have to be extended given the delay in the NEB process noted below. On May 17, 2016, we filed a consolidated application with the NEB for Energy East. On June 16, 2016, Energy East achieved a major milestone with the NEB's announcement determining the Energy East application is sufficiently complete to initiate the formal regulatory review process. This determination of completeness also marked the start of the mandated 21 month NEB review process which culminates in a formal recommendation to the Governor in Council (Federal Cabinet). The Governor in Council will then have six months to decide whether to approve the project and, if so, on what conditions. On July 20, 2016, the NEB issued the hearing order which provides further detail on the regulatory process. On August 8, 2016, the NEB commenced the first of a series of community panel sessions held along the pipeline route in New Brunswick. Panel sessions scheduled for the week of August 29, 2016 in Montréal, Québec were subsequently cancelled as three NEB panelists announced their decision to recuse themselves from continuing to sit on the panel to review the project due to allegations of reasonable apprehension of bias. The Chair of the NEB and the Vice Chair, who is also a panel member, have recused themselves of any further duties related to the project. As a result, all hearings for the project were adjourned until further notice as we wait on the federal government to appoint new NEB members and then for the NEB to establish a new panel to hear our applications. The new panel members will then determine how the review process is to be re-initiated. As a result of these actions, we expect a delay in the NEB review process. On June 24, 2016, we filed a Request for Arbitration in a dispute against the U.S. Government pursuant to the Convention on Settlement of Investment Disputes between States and Nationals of Other States, the Rules of Procedure for the Institution of Conciliation and Arbitration Proceedings and Chapter 11 of the North American Free Trade Agreement (NAFTA). The claim arises out of the November 6, 2015 denial of our application for a Presidential Permit to construct the Keystone XL Pipeline. We have requested an award of damages arising from the U.S. Government's breaches of its NAFTA obligations in an amount of more than US$15 billion, together with applicable interest and the costs of arbitration. On March 7, 2016, we issued notice to the Balancing Pool to terminate our Alberta PPAs. The arrangements contain a provision that permits the PPA buyers to terminate the PPAs if there is a change in the law that makes the arrangements unprofitable or more unprofitable. This termination affects the Sheerness, Sundance A and Sundance B PPAs. On July 22, 2016, we, along with the ASTC Power Partnership, referred the matter to be resolved by binding arbitration pursuant to the dispute resolution provisions of the PPAs. On July 25, 2016, the Government of Alberta brought an application in the Court of Queen's Bench to prevent the Balancing Pool from allowing termination of a PPA held by another party which contains identically worded termination provisions to our PPAs. The outcome of this court application may affect resolution of the arbitration of the Sheerness, Sundance A and Sundance B PPAs. The Balancing Pool has refused to proceed with the arbitrations pending resolution of the court application. On October 20, 2016, we made an application to the Court of Queen's Bench requesting that the court order the Balancing Pool to proceed. Unprofitable market conditions are expected to continue as costs related to carbon emissions have increased and are forecast to continue to increase over the remaining term of the PPA agreements. We expect the termination will improve cash flow and comparable earnings in the near term. As a result of our decision to terminate the PPAs, we recorded a non-cash impairment charge of $240 million before tax ($176 million after tax) comprised of $211 million before tax ($155 million after tax) related to the carrying value of our Sundance A and Sheerness PPAs and $29 million before tax ($21 million after tax) on our equity investment in the ASTC Power Partnership which holds the Sundance B PPA. In May 2016, legislation enabling Ontario's cap and trade program was signed into law with the new regulation taking effect July 1, 2016. This regulation sets a limit on annual province-wide greenhouse gas emissions beginning in January 2017 and introduces a market to administer the purchase and trading of emissions allowances. The regulation places the compliance obligation for emissions from our natural gas fired power facilities on local gas distributors, with the distributors flowing the associated costs to the assets. The IESO is continuing to develop proposed contract amendments for eligible contract holders to address costs and other issues associated with this change in law. We do not expect a significant overall impact as a result of this new regulation. In August 2015, we executed an agreement with Hydro Québec (HQ) allowing HQ to dispatch up to 570 MW of peak winter capacity from our Bécancour facility for a term of 20 years commencing in December 2016. The regulator in Québec, Régie de l'énergie (the Régie), initially accepted this agreement for implementation but in July 2016, the Régie reversed this initial decision. HQ continues to advocate for the contract on its economic merit as part of their strategy to meet the winter peak capacity needs of the province and is pursuing regulatory options for our agreement to be reinstated. We expect the project need and potential timing will be reassessed in the recently released review of HQ's ten year supply plan. In second quarter 2016, Bruce Power issued bonds and borrowed under its bank credit facility as part of a financing program to fund its capital program and make distributions to its partners. Distributions received from Bruce Power in second quarter 2016 included $725 million from this financing program. On November 1, 2016, in conjunction with our decision to maintain our current ownership interest in a growing Mexican natural gas pipelines business, and concurrent with the release of these financial results, we also entered into an agreement with a group of underwriters to proceed with an offering of common shares. The common shares will be offered to the public in Canada and the United States through the underwriters or their representatives. The offering is subject to the receipt of all necessary regulatory and stock exchange approvals. Proceeds from the offering will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to finance a portion of the purchase price of Columbia. The closing for the offering is expected to be on November 16, 2016. Under our Dividend Reinvestment Plan (DRP), eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent. We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings. We believe we have the financial capacity to fund our existing capital program through our predictable cash flow from our operations, access to capital markets (including through the establishment of an at-the-market equity issuance program, if applicable), monetization of assets, cash on hand and substantial committed credit facilities. At September 30, 2016, our current assets were $5.4 billion and current liabilities were $6.1 billion, leaving us with a working capital deficit of $0.7 billion compared to a deficit of $3.4 billion at December 31, 2015. Our working capital deficiency is considered to be in the normal course of business and is managed through: Comparable funds generated from operations is a non-GAAP measure. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. We calculate this comparable measure by adjusting funds generated from operations for specific items we believe are significant but not reflective of our underlying operations. See the non-GAAP measures section of this MD&A for further discussion on specific items. Comparable funds generated from operations increased $263 million and $155 million for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to the increase in net income due to the Columbia acquisition on July 1, 2016. Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation. See our non-GAAP measures section for more information. Maintenance capital expenditures for the three and nine months ended September 30, 2016 on our Canadian regulated natural gas pipelines were $105 million and $202 million, respectively (2015 - $87 million and $201 million, respectively) which contributed to their respective rate bases and net income. Capital expenditures in 2016 were primarily related to: Costs incurred on capital projects under development primarily relate to the Energy East and LNG pipeline projects. Contributions to equity investments have increased in 2016 compared to 2015 primarily due to our investments in Grand Rapids, Bruce Power and Sur de Texas. Restricted cash held in escrow at June 30, 2016 was used for the purchase of Columbia on July 1, 2016. On February 1, 2016, we acquired the Ironwood natural gas fired, combined cycle power plant with a capacity of 778 MW, for US$653 million in cash after post-acquisition adjustments. On March 31, 2016, we acquired an additional 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million. On May 1, 2016, we acquired an additional 0.65 per cent for an aggregate purchase price of US$7 million. As a result of these acquisitions, our interest in Iroquois has increased to 50 per cent. The increase in distributions received in excess of equity earnings is primarily due to distributions from Bruce Power. In second quarter 2016, Bruce Power issued bonds and borrowed under its bank credit facility as part of its financing program to fund its capital program and make distributions to its partners which resulted in $725 million being received by us. On August 15, 2016, TransCanada Trust (the Trust), a wholly owned trust subsidiary of TCPL, issued US$1.2 billion of Trust Notes to third party investors with a fixed interest rate of 5.875 per cent for the first ten years converting to a floating rate thereafter. The proceeds of the Trust Notes were loaned to TCPL through the subscription for US$1.2 billion of junior subordinated notes of TCPL at a rate of 6.125 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL. Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with other outstanding first preferred shares of TCPL. In November 2015, the TSX approved our normal course issuer bid (NCIB), which allows for the repurchase and cancellation of up to 21.3 million common shares, representing three per cent of our then issued and outstanding common shares, between November 23, 2015 and November 22, 2016 at prevailing market prices plus brokerage fees, or such other prices as may be permitted by the TSX. Since inception of the NCIB, 7.1 million shares were repurchased at an average price of $43.63. With the acquisition of Columbia, we do not anticipate further repurchases under this NCIB. The following table summarizes shares repurchased in 2016 under the NCIB: On April 1, 2016, we issued 96.6 million subscription receipts to partially fund the Columbia acquisition at a price of $45.75 each for total proceeds of $4.4 billion. Each subscription receipt holder received one common share upon closing of the Columbia acquisition. Holders received dividend equivalent payments per subscription receipt equal to dividends declared on each common share, with the first payment on April 29, 2016 for holders of record at close of business on April 15, 2016. The second dividend equivalent payment was made on July 29, 2016 to holders of record at the close of business on June 30, 2016. For the nine months ended September 30, 2016, $109 million of dividend equivalent payments were recorded as interest expense and have been excluded from comparable earnings. See the Reconciliation of non-GAAP measures section. Interest income of $6 million relating to the proceeds while held in escrow has also been excluded from comparable earnings. See the Reconciliation of non-GAAP measures section. On July 4, 2016, the subscription receipts were automatically exchanged for TransCanada common shares in accordance with the terms of the subscription receipt agreement and were delisted from the TSX. Under our Dividend Reinvestment Plan (DRP), eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent. Approximately $175 million or 39 per cent of dividends paid on October 31, 2016 were reinvested in TransCanada common shares. In February 2016, holders of 1.3 million Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.54 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 5 preferred shares was reset for five years at 2.263 per cent per annum. Such rate will reset every five years. In April 2016, we completed a public offering of 20 million Series 13 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $500 million. The Series 13 preferred shareholders will have the right to convert their Series 13 preferred shares into Series 14 cumulative redeemable first preferred shares on May 31, 2021 and on the last business day of May of every fifth year thereafter. The holders of Series 14 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the sum of the then applicable 90-day Government of Canada treasury bill rate plus 4.69 per cent. The fixed dividend rate on the Series 13 preferred shares was set for its initial period at 5.5 per cent per annum and will reset every five years to a rate equal to the sum of the then applicable five-year Government of Canada bond yield plus 4.69 per cent subject to a floor of not less than 5.5 per cent per annum. The following table summarizes the impact of the 2016 conversion and issuance of preferred shares discussed above: Since January 1, 2016, 2.7 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$143 million. Our ownership interest in TC PipeLines, LP was 27 per cent as a result of issuances under the ATM program and resulting dilution. In connection with the late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon the filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the ATM program may have a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit. On November 1, 2016, we declared quarterly dividends as follows: We use committed revolving credit facilities to support our commercial paper programs and, along with demand facilities, for general corporate purposes including issuing letters of credit, providing additional liquidity and completing the acquisition of Columbia. At November 1, 2016, we had approximately $19.2 billion in unsecured credit facilities, including: At November 1, 2016, our operated affiliates had an additional $0.4 billion of undrawn capacity on committed credit facilities. See Financial risks and financial instruments for more information about liquidity, market and other risks. Our capital commitments have increased by approximately $1.5 billion since December 31, 2015 as a result of the new commitments for the Tula, Villa de Reyes and Sur de Texas natural gas pipelines partially offset by decreased commitments on Grand Rapids and Napanee. Our other purchase obligations are consistent with the amounts reported at December 31, 2015. Our commitments at December 31, 2015 included fixed payments net of sublease receipts for Alberta PPAs. With the March 7, 2016 notice to terminate our Sheerness, Sundance A and Sundance B PPAs, our future obligations from December 31, 2015 have decreased as follows: 2016 - $195 million, 2017 - $200 million, 2018 - $141 million, 2019 - $138 million and 2020 - $115 million. Our commitments for 2021 and beyond increased by approximately $0.5 billion as a result of the extension of premises leases in second quarter 2016. The acquisition of Columbia on July 1, 2016 resulted in a total increase to our contractual obligations of $349 million for transportation contracts and premises leases. There were no other material changes to our contractual obligations in third quarter 2016 or to payments due in the next five years or after. See the MD&A in our 2015 Annual Report for more information about our contractual obligations. Financial risks and financial instruments We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance. Our liquids marketing business began operations in the first quarter of 2016. It enters into short-term or long-term pipeline and storage terminal capacity contracts, primarily on the Company's assets, increasing the utilization of those assets and earning the market value of the capacity. Derivative instruments are used to fix a portion of the variable price exposures that arise from physical liquids transactions. See our 2015 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2015. 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 September 30, 2016, we had no significant credit losses and no significant amounts past due or impaired. We had a credit risk concentration of $191 million (US$146 million) at September 30, 2016 with one counterparty (December 31, 2015 - $248 million (US$179 million)). This amount is secured by a guarantee from the counterparty's parent company and is expected to be fully collectible. We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and further managed by using foreign exchange derivatives. We have floating interest rate debt which subjects us to interest rate cash flow risk, a portion of which we manage using a combination of interest rate swaps and options. The impact of changes in the value of the U.S. dollar on our U.S. and international operations, on a pre-tax basis, is significantly offset by interest on U.S. dollar-denominated long-term debt, as set out in the table below. Comparable EBIT is a non-GAAP measure. See our Reconciliation of non-GAAP measures section for more information. 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 the 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 September 30, 2016, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $24 million (December 31, 2015 - $32 million), with collateral provided in the normal course of business of nil (December 31, 2015 - nil). If the credit-risk-related contingent features in these agreements were triggered on September 30, 2016, we would have been required to provide additional collateral of $24 million (December 31, 2015 - $32 million) to our counterparties. We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise. Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at September 30, 2016, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level. We acquired Columbia on July 1, 2016. Assets attributable to Columbia as of July 1, 2016 represented approximately 25 per cent of our total assets as of July 1, 2016, and revenues attributable to Columbia for the period July 1, 2016 to September 30, 2016 represented approximately 12 per cent of our total revenues for third quarter 2016. Management is currently in the process of evaluating and integrating Columbia's controls over financial reporting with ours. We expect to complete this integration in 2017. Other than as described above, there were no changes in third quarter 2016 that had or are likely to have a material impact on our internal control over financial reporting. When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. The fair value of assets and liabilities acquired in a business combination accounted for under the acquisition method are also subject to estimates and judgement. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2015 Annual Report. We test goodwill for impairment on an annual basis or more frequently if events or changes in circumstances indicate that it might be impaired. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill, at September 30, 2016. The fair value of Ravenswood was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. Plant, property and equipment was also tested for impairment. As a result, at September 30, 2016, we recorded a goodwill impairment charge on the full goodwill amount of $1,085 million ($656 million after tax) related to the Ravenswood facility within the Energy segment and also determined there was no impairment on the plant, property and equipment. At September 30, 2016, our goodwill included $1.9 billion related to the ANR natural gas transportation business. As a result of our ANR Section 4 rate case settlement filed on September 16, 2016, we tested this reporting unit for impairment. The fair value of this reporting unit was measured by using a discounted cash flow analysis incorporating the key terms of the settlement. While no impairment of goodwill was necessary, the estimated fair value of ANR exceeds its carrying value, including goodwill, by less than 10 per cent. Under the settlement, there is a moratorium on any further rate changes until August 1, 2019. Adverse conditions impacting rates and volumes on ANR beyond the moratorium period could result in a reduction for our estimated future cash flows, which could result in future impairment of a portion of the goodwill balance related to ANR. Our significant accounting policies have remained unchanged since December 31, 2015 other than described below. You can find a summary of our significant accounting policies in our 2015 Annual Report. Changes in accounting policies for 2016 In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from U.S. GAAP the concept of extraordinary items. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on our consolidated financial statements. In February 2015, the FASB issued new guidance on consolidation. This update requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016, was applied retrospectively and did not result in any change to our consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 16, Variable interest entities. In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance was effective January 1, 2016, was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on our consolidated balance sheet. In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on our consolidated financial statements. In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. We are currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and have begun an assessment in order to determine any impact on our consolidated financial statements. In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements. In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires us to assess valuation allowances for deferred tax assets related to available-for-sale debt securities in combination with our other deferred tax assets. This new guidance is effective January 1, 2018. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. In February 2016, the FASB issued new guidance on leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. We are currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on our consolidated financial statements as a result of adopting this new standard. In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance is effective January 1, 2017 and we do not expect the adoption of this guidance to have a material impact on our consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. This new guidance is effective January 1, 2017 and we do not expect the adoption of this new standard to have a material impact on our consolidated financial statements. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write-down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. Classification of certain cash receipts and cash payments In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments. These include debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance and distributions received from equity method investees. The new guidance is effective January 1, 2018 and will be applied using a retrospective approach. The new guidance also specifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the impact on our consolidated financial statements. FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT Quarter-over-quarter revenues and net income sometimes fluctuate, the causes of which vary across our business segments. In Natural Gas Pipelines, quarter-over-quarter revenues and net income from the Canadian regulated pipelines generally remain relatively stable during any fiscal year. Our U.S. natural gas pipelines are generally seasonal in nature with higher earnings in the winter months as a result of increased customer demands. Over the long term, however, results from both our Canadian and U.S. natural gas pipelines fluctuate because of: 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 part 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. In fourth quarter 2014, comparable earnings excluded an $8 million after-tax gain on the sale of our interest in Gas Pacifico/INNERGY. See accompanying notes to the condensed consolidated financial statements. See accompanying notes to the condensed consolidated financial statements. See accompanying notes to the condensed consolidated financial statements. See accompanying notes to the condensed consolidated financial statements. See accompanying notes to the condensed consolidated financial statements. These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company), which now includes Columbia Pipeline Group (Columbia) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada's annual audited consolidated financial statements for the year ended December 31, 2015, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada's 2015 Annual Report. These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2015 audited consolidated financial statements included in TransCanada's 2015 Annual Report. Certain comparative figures have been reclassified to conform with the current period's presentation. Earnings for interim periods may not be indicative of results for the fiscal year in the Company's Natural Gas Pipelines segment due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company's Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company's investments in electrical power generation plants and non-regulated gas storage facilities. USE OF ESTIMATES AND JUDGEMENTS In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The fair value of assets and liabilities acquired in a business combination accounted for under the acquisition method are also subject to estimates and judgement. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies included in the consolidated financial statements for the year ended December 31, 2015, except as described in Note 2, Accounting changes. CHANGES IN ACCOUNTING POLICIES FOR 2016 In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from U.S. GAAP the concept of extraordinary items. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on the Company's consolidated financial statements. In February 2015, the FASB issued new guidance on consolidation. This update requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 16, Variable Interest Entities. In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance was effective January 1, 2016, was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on the Company's consolidated balance sheet. In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on the Company's consolidated financial statements. In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. The Company is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and has begun an assessment in order to determine any impact on the consolidated financial statements. In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available-for-sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. In February 2016, the FASB issued new guidance on leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on its consolidated financial statements as a result of adopting this new standard. In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements. Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write-down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Classification of certain cash receipts and cash payments In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments. These include debt pre-payments or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance and distributions received from equity method investees. The new guidance is effective January 1, 2018 and will be applied using a retrospective approach. The new guidance also specifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the impact on its consolidated financial statements. On July 1, 2016, TransCanada acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash, based on US$25.50 per share for all of Columbia's outstanding common shares as well as restricted and performance stock units. The acquisition was financed through proceeds of approximately $4.4 billion from the sale of subscription receipts, draws on committed bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering. Upon closing of the acquisition, the subscription receipts were exchanged into approximately 96.6 million common shares of TransCanada. Refer to Note 7, Long-term debt for additional information on the bridge term loan credit facilities and Note 10, Equity and share capital for additional information on the subscription receipts. Columbia operates a portfolio of approximately 24,000 km of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets in various regions in the U.S. TransCanada acquired Columbia to expand the Company's natural gas business in the U.S. market, positioning the Company for additional long-term growth opportunities. The Goodwill of $10.1 billion (US$7.7 billion) arising from the acquisition consists largely of the opportunities to expand the Company's natural gas pipelines segment in the U.S. market and to gain a stronger competitive position in the North American natural gas business. The Goodwill resulting from the acquisition is not deductible for income tax purposes. The acquisition has been accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The purchase price equation reflects management's estimate of the fair value of Columbia's assets and liabilities as at July 1, 2016. The fair values of current assets including cash and cash equivalents, accounts receivable, inventories and other and the fair values of current liabilities including notes payable and accrued interest approximate their carrying values due to the short-term nature of these items. Certain acquisition related working capital items resulted in an adjustment to accounts payable and other. Columbia's natural gas pipelines are subject to FERC regulations and, as a result, their rate bases are expected to be recovered with a reasonable rate of return over the life of the assets. These assets, as well as related regulatory assets and liabilities, have fair values equal to their carrying values. The fair value of mineral rights included in Columbia's plant, property and equipment was estimated using a discounted cash flow approach which resulted in a fair value increase of $241 million (US$185 million). The Company utilized an independent third party valuation in the assessment of fair value. The fair value of base gas included in Columbia's plant, property and equipment was determined by using quoted market prices multiplied by the volume of gas in place which resulted in a fair value increase of $836 million (US$642 million). The fair value of Columbia's long-term debt was estimated using an income approach based on quoted market prices for similar debt instruments from external data service providers. This resulted in a fair value increase of $300 million (US$231 million). The following table summarizes the fair value of Columbia's debt acquired by TransCanada. The fair values of Columbia's defined pension benefit plan and OPEB plans were based on an actuarial valuation report as of the acquisition date. The fair value representing the funded status of the plans on the acquisition date resulted in an increase of $15 million (US$12 million) and $5 million (US$4 million) to Regulatory assets and Other long-term liabilities, respectively, and a decrease of $14 million (US$11 million) and $2 million (US$2 million) to Intangible and other assets and Regulatory liabilities, respectively. Temporary differences created as a result of the fair value changes described above resulted in deferred tax assets and liabilities that were recorded at the Company's U.S. effective tax rate of 39 per cent. The fair value of Columbia's non-controlling interest is based on the approximately 53.8 million Columbia Pipeline Partners LP common units outstanding to the public as of June 30, 2016, and valued at the June 30, 2016 closing price of US$15.00 per common unit. Acquisition expenses of approximately $36 million are included in Plant operating costs and other in the condensed consolidated statement of income. Upon completing the acquisition, the Company began consolidating Columbia. Columbia's significant accounting policies are consistent with TransCanada's and continue to be applied. Columbia contributed $427 million (US$327 million to revenues and $55 million (US$42 million) to net income from the acquisition date to September 30, 2016. The following supplemental unaudited pro forma consolidated financial information of the Company for the three and nine months ended September 30, 2016 and 2015 includes the results of operations for Columbia as if the acquisition had been completed on January 1, 2015. TransCanada tests goodwill for impairment on an annual basis or more frequently if events or changes in circumstances indicate that goodwill might be impaired. As a result of information received during the process to monetize the Company's U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill, at September 30, 2016. The fair value of Ravenswood was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. Plant, property and equipment was also tested for impairment. As a result, at September 30, 2016, the Company recorded a goodwill impairment charge on the full goodwill amount of $1,085 million ($656 million after-tax) related to the Ravenswood facility within the Energy segment and also determined there was no impairment on the plant, property and equipment. On March 7, 2016, TransCanada issued notice to the Balancing Pool of the decision to terminate its Sheerness and Sundance A PPAs. In accordance with a provision in the PPAs, a buyer is permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of recent changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expects increasing costs related to carbon emissions to continue throughout the remaining terms of the PPAs resulting in increasing unprofitabilty. As such, at March 31, 2016, the Company recognized a non-cash impairment charge of $211 million ($155 million after-tax) in its Energy segment, which represents the carrying value of the PPAs. On March 7, 2016, TransCanada also issued notice to the Balancing Pool of the decision to terminate its Sundance B PPA. The Sundance B PPA is held in the ASTC Power Partnership in which the Company holds a 50 per cent ownership interest. As a result, at March 31, 2016 the Company recognized a non-cash impairment charge of $29 million ($21 million after-tax) in its Energy segment, which represents the carrying value of the equity investment. This impairment charge is included in Income from equity investments on the condensed consolidated statement of income. At September 30, 2016, the total unrecognized tax benefit of uncertain tax positions was approximately $20 million (December 31, 2015 - $17 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in income tax expense for the three and nine months ended September 30, 2016 is nil for interest expense and nil for penalties (September 30, 2015 - nil for interest expense and nil for penalties). At September 30, 2016, the Company had $4 million accrued for interest expense and nil accrued for penalties (December 31, 2015 - $4 million accrued for interest expense and nil for penalties). The effective tax rates for the nine-month periods ended September 30, 2016 and 2015 were 10 per cent and 32 per cent, respectively. The lower effective tax rate in 2016 was primarily the result of lower flow-through taxes in 2016 on Canadian regulated pipelines changes in the proportion of income earned between Canadian and foreign jurisdictions and the goodwill impairment charge. The Company issued long-term debt in the nine months ended September 30, 2016 as follows: The Company retired long-term debt in the nine months ended September 30, 2016 as follows: In the three and nine months ended September 30, 2016, TransCanada capitalized interest related to capital projects of $46 million and $133 million, respectively (2015 - $82 million and $223 million, respectively). On August 16, 2016, TransCanada Trust (the Trust), a 100 per cent owned financing trust subsidiary of TCPL, issued US$1.2 billion of Trust Notes - Series 2016-A (Trust Notes) to third party investors with a fixed interest rate of 5.875 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL through the subscription for US$1.2 billion of junior subordinated notes of TCPL at a rate of 6.125 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL. Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL. In connection with the late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon the filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the TC PipeLines, LP ATM program may have a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit. At September 30, 2016, $106 million (US$82 million) was recorded as Common Units of TC PipeLines, LP Subject to Rescission on the Condensed consolidated balance sheet. The Company classified these 1.6 million common units outside Equity because the potential rescission rights of the units are not within the control of the Company. In January 2016, the Company repurchased and cancelled 305,407 of its common shares at an average price of $44.90 for a total of $14 million (weighted average cost of $6 million). The difference of $8 million between the total price paid and the weighted average cost was recorded in Additional paid-in capital. On April 1, 2016, the Company issued 96.6 million subscription receipts to partially fund the Columbia acquisition at a price of $45.75 each for total proceeds of approximately $4.4 billion. Holders of subscription receipts received one common share in exchange for each subscription receipt upon closing of the Columbia acquisition. On April 29, 2016, holders of record at close of business on April 15, 2016 received a cash payment per subscription receipt that was equal to dividends declared on each common share. A second dividend equivalent payment was made on July 29, 2016 to holders of record at the close of business on June 30, 2016. For the nine months ended September 30, 2016, $109 million of dividend equivalent payments was recorded as interest expense. Under the Company's Dividend Reinvestment Plan (DRP), eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent. On February 1, 2016, holders of 1.3 million Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.54 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 5 preferred shares was reset for five years at 2.263 per cent per annum. Such rate will reset every five years. On April 20, 2016, the Company completed a public offering of 20 million Series 13 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $500 million. The Series 13 preferred shareholders will have the right to convert their Series 13 preferred shares into Series 14 cumulative redeemable first preferred shares on May 31, 2021 and on the last business day of May of every fifth year thereafter. The holders of Series 14 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the sum of the applicable 90-day Government of Canada treasury bill rate plus 4.69 per cent. The fixed dividend rate on the Series 13 preferred shares was set for five years at 5.5 per cent per annum. The dividend rate will reset every five years at a rate equal to the sum of the applicable five-year Government of Canada bond yield plus 4.69 per cent but not less than 5.5 per cent per annum. The following table summarizes the impact of the 2016 issuance and conversions of preferred shares discussed above: 11. Other comprehensive income/(loss) and accumulated other comprehensive loss Components of other comprehensive income/(loss), including the portion attributable to non-controlling interests and related tax effects, are as follows: 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 and other post-retirement benefit plans is as follows: 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 September 30, 2016, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At September 30, 2016, there were no significant amounts past due or impaired, and there were no significant credit losses during the period. The Company had a credit risk concentration due from a counterparty of $191 million (US$146 million) at September 30, 2016 (December 31, 2015 - $248 million (US$179 million)). This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company. 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. 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 September 30, 2016 is as follows: The balance sheet classification of the fair value of the derivative instruments as at December 31, 2015 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 following tables present the maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations: The following summary does not include hedges of the net investment in foreign operations. The components of OCI (Note 11) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: 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, 2015: With respect to the derivative instruments presented above as at September 30, 2016, the Company provided cash collateral of $228 million (December 31, 2015 - $482 million) and letters of credit of $11 million (December 31, 2015 - $41 million) to its counterparties. The Company held nil (December 31, 2015 - nil) in cash collateral and $3 million (December 31, 2015 - $2 million) in letters of credit from counterparties on asset exposures at September 30, 2016. Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at September 30, 2016, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $24 million (December 31, 2015 - $32 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2015 - nil). If the credit-risk-related contingent features in these agreements were triggered on September 30, 2016, the Company would have been required to provide additional collateral of $24 million (December 31, 2015 - $32 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise. 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 instrument assets and liabilities measured on a recurring basis, including both current and non-current portions for 2016, are categorized as follows: The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015, are categorized as follows: 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 $2 million decrease or increase in the fair value of outstanding derivative instruments included in Level III as at September 30, 2016. On January 1, 2016, TransCanada completed the sale of a 49.9 per cent interest in Portland Natural Gas Transmission System (PNGTS) to TC PipeLines, LP for an aggregate purchase price of US$223 million. Proceeds were comprised of US$188 million in cash and the assumption of US$35 million in proportional PNGTS debt. On March 31, 2016, TransCanada acquired a 4.87 per cent interest in Iroquois for an aggregate purchase price of US$53.8 million, increasing TransCanada's interest in Iroquois to 49.35 per cent. On May 1, 2016, the Company acquired an additional 0.65 per cent interest for an aggregate purchase price of US$7.2 million, further increasing TransCanada's interest in Iroquois to 50 per cent. On March 31, 2016, TransCanada completed the sale of TC Offshore LLC to a third party. This resulted in an additional loss on disposal of $4 million pre-tax which is included in loss of sale of assets in the condensed consolidated statement of income. On February 1, 2016, TransCanada acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$653 million in cash after post-acquisition adjustments. The Ironwood power plant delivers energy into the PJM power market. The evaluation of assigned fair value of acquired assets and liabilities did not result in the recognition of goodwill. The Company began consolidating Ironwood as of the date of acquisition which has not had a material impact on the consolidated revenues and net income of the Company. In addition, the pro forma incremental impact on the Company's consolidated revenues and net income for each of the periods presented is not material. 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. TransCanada's commitments at December 31, 2015 included fixed payments, net of sublease receipts for Alberta PPAs. As a result of the March 7, 2016 notice to terminate our Sheerness, Sundance A and Sundance B PPAs, our future obligations from December 31, 2015 have decreased by: 2016 - $195 million, 2017 - $200 million, 2018 - $141 million, 2019 - $138 million and 2020 - $115 million. Our commitments for 2021 and beyond increased by approximately $0.5 billion as a result of the extension of premise leases in second quarter 2016. The acquisition of Columbia on July 1, 2016 resulted in a total increase to our obligations of $349 million for transportation contracts and premise leases. TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company's exposure under certain of these guarantees is unlimited. The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services including purchase agreements and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been included in other long-term liabilities. Information regarding the Company's guarantees is as follows: As a result of the implementation of the new FASB guidance on consolidation, a number of entities controlled by TransCanada are now considered to be variable interest entities (VIEs). A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity's operations through voting rights or do not substantively participate in the gains and losses of the entity. In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are accounted for as equity investments. 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: The Company's planned monetization of the U.S. Northeast Power business, for the purposes of permanently financing the Columbia acquisition, includes the sale of Ravenswood, Ironwood, Kibby Wind, Ocean State Power, TC Hydro and the marketing business, TransCanada Power Marketing (TCPM). On November 1, 2016, subsequent to the balance sheet date the Company entered into agreements to sell all of these assets except the marketing business, the value from which is still expected to be realized going forward. The sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party is expected to close in the first half of 2017. As a result, effective November 1, 2016, the related assets and liabilities are classified as held for sale in the Energy segment and will be recorded at their fair values less costs to sell. This is expected to result in a loss on assets held for sale of approximately $899 million in fourth quarter 2016 or $863 million after-tax which includes the reclassification of an estimated $61 million of foreign currency translation gains from AOCI to net income. The sale of TC Hydro to another third party is also expected to close in the first half of 2017 resulting in an estimated gain of $719 million or $443 million after-tax which includes the reclassification of an estimated $4 million of foreign currency translation gains from AOCI to net income. This gain will be recognized upon closing of the sale transaction. Effective November 1, 2016, the related assets and liabilities are classified as held for sale in the Energy segment. As of November 1, 2016, TCPM does not meet the criteria to be classified as held for sale. The following table details the assets and liabilities as at September 30, 2016 related to the U.S. Northeast Power business that are classified as held for sale effective November 1, 2016. The expected loss on assets held for sale of approximately $899 million (US$686 million) is not reflected in the table below. On November 1, 2016, TransCanada announced that it had entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia, has agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions. At September 30, 2016, the common units are recorded as non-controlling interests in these condensed consolidated financial statements. As a result, there will be no gain or loss recorded on closing this transaction. On November 1, 2016, concurrent with the release of these financial results, the Company announced it has entered into an agreement with a group of underwriters to proceed with an offering of common shares. The closing for the offering is expected to be on November 16, 2016.


News Article | March 9, 2016
Site: www.altenergystocks.com

Three public companies end our series on wave and tidal power development.  Marine and HydroKinetic energy has only recently received enough interest from scientists and engineers to merit an acronym  - MHK.  It is an all-encompassing category, stretching across ocean tides and waves and reaching into the currents of inland rivers and straights.  It is separated from hydropower, which involves the construction of dams to create elevation differences in water levels that can be used to turn turbines.Still this promising source of renewable energy is populated mostly by small, private companies that survive on government grants and investments from family and friends.  A few angel investors have also found their way to MHK, but minority investors have few options. OPTT :  Nasdaq) has been previously featured in our articles.  The post ‘ Ocean Powers Up the Big Apple ’  on June 26, 2015, described the company’s success in getting permits to place one of its power buoys of the coast southeast of New York City.  In January 2016, the company announced the achievement of milestones in the project, including a generation record of 32 kilowatt hours for a twenty-four hour period.  Most importantly the system is still working despite extreme ocean conditions since deployment in October 2015.In the twelve months ending October 2015, Ocean Power managed to earn $1.4 million in total sales, mostly from engineering work on development projects.  Of course, still in a developmental stage, Ocean Power reported a deep net loss of $12.7 million.  The company used $12.1 million in cash to support operations during this period, leaving $10.4 million in the bank at the end of October last year.  As much as half of that is probably gone, unless management found a way to bring in more revenue or cut costs.  Indeed, in January 2016, the company received $1.7 million from the State of New Jersey in the form of business tax credits. Carnegie Wave Energy Ltd. (CWGYF:  OTC/PK or CWE.ASX ) is another public company option on wave energy.  The company has patented a novel design for an underwater device that captures energy from ocean current movements.  The device is tethered to the ocean floor and remains below the ocean surface.  The company has spent over $100 million to develop the device and has completed over 10,000 hours of testing.That price tag can only be justified by a significant commercial opportunity.  The primary application of the device is to power desalination plants on-shore, but excess electricity could be delivered to an electrical grid.  Island applications seem to have merit as well.    Carnegie has partnered with Western Power, an energy utility in Western Australia, to develop a project at Garden Island.  Construction is scheduled to begin yet in 2016 on six of the wave power devices and a desalination plant.  When completed the Australian Department of Defense has pledged to buy the power and water supplies.Both Carnegie and Ocean Power are priced more like options on their technology than companies with sales and earnings expectations.  For risk averse investors or those with shorter investment horizons that might be required to see these developmental stage companies to full commercial operations, there is an alternative. Lockheed Martin (LMT:  NYSE) has taken an interest in wave and tidal power generation.  The company has considerable experience in maritime systems and tidal power apparently does not seem like a big stretch for its engineers.  Lockheed is a partner of Atlantis Resources Ltd. ARL :  LN), which was featured in this post in February.  Atlantis is deploying its proprietary turbine in the largest tidal power project so far off the coast of Scotland.  Lockheed will be manufacturing the nacelle or the business component of the Atlantis tidal turbine and supplying the controls and gearbox.  Then Lockheed will serve as the system integrator and use is considerable balance sheet strength to provide the required project assurances to the owner.Make no mistake, LMT is no small-cap company.  Lockheed Martin reported $46.1 billion in total sales in 2015, providing $3.6 billion in net income or $11.46 per share.  Of course, a share of Lockheed is more than a stake in tidal power.   Lockheed is still an aerospace company with additional interests in communications and security technology and services.  Tidal power at its current state of development is merely a drop in Lockheed’s very large bucket.  Some investors might take Lockheed’s partnership with Atlantis as a cue, much like the purchase of shares by an insider.  The logic is that a large company like Lockheed would not bother with a very small company like Atlantis and its tidal power project, it its engineers and planners did not see some potential in the sector.  It could be an appealing investment.  LMT is trading at 16 times the consensus earnings estimate for Lockheed in the year 2016.  The stock also offers a dividend yield of 6.6%. Neither the author of the Small Cap Strategist web log, Crystal Equity Research nor its affiliates have a beneficial interest in the companies mentioned herein.  Ocean Power Technologies and Carnegie Wave Power are included in the Ocean Group of Crystal Equity Research’s Electric Earth Index of company’s developing power sources from the earth.


News Article | November 18, 2015
Site: cleantechnica.com

West Australian energy minister Mike Nahan said the electricity industry is in the process of being “Uber’d” by battery storage technology, which would fundamentally change the nature of the system. Nahan also announced that battery storage installations in the state would be allowed to export back into the WA grid from December 1, reversing what he had described as a major error from the state-owned electricity utilities. Speaking at a battery storage conference in Perth, Nahan said it was up to authorities to allow technology to challenge “the existing paradigm” of investment. “In other words, the electricity industry, like the taxi industry, is getting Uber’d,” Nahan said, Business News reported. “Technology, innovation, entrepreneurship love monopolies because they love to attack them and that’s what’s happening.” Nahan’s comments follows those earlier this year when he said that solar would become the dominant technology in the WA electricity market, meeting all daytime demand within a decade and pushing out coal-fired generation. That represents a major turnaround from the former head of the Institute of Public Affairs, who had a skeptical view of renewable energy, as well as climate change. The transformation of the grid through solar, however, will be put to the test by the ability of the government to allow technologies and new investors to challenge its state-owned utilities. The first piece of the puzzle would be the introduction from both Synergy (the retailer) and Western Power (the network operator) of “non reference” services that would allow exports from battery storage back to the grid. The two utilities had been under pressure to move on the issue of battery storage, after earlier attempting to shift the blame to the state regulator for the ruling. Nahan said in a statement that it has been a “significant inconsistency” that customers were able to export electricity onto the SWIS from residential rooftop solar systems, but not from a battery or electric vehicle storage facilities. “This arrangement now means eligible customers can install battery storage or EV facilities to complement their solar PV systems and export unused electricity onto the network,” Nahan said. “This is an important development given the emerging future trends which forecast widespread installation of solar PV, plus storage systems.” Synergy is to start selling rooftop solar panels to its customers from mid next year – well behind its eastern state rivals – and will follow this up with battery storage by the end of 2016. Nahan also spoke of the Alkimos Beach housing development, where a 1.1MWh battery storage system is being used in a new housing estate trial to test the integration of solar and storage into the local grid. Nahan said the trial would study the implications of subdivision-scale battery storage, which along with small-scale storage promised to not only help households but also relieve pressure on the grid during peak demand periods. “Some day this will be the norm,” Nahan said. WA Greens energy spokesman Robin Chapple said battery storage is clearly “the way of the future”, and said the party  was reviewing its state vision for energy, Energy 2029, to incorporate the technology. “Battery storage systems are going to completely revolutionise the way that we use energy, offering West Australians the opportunity to simultaneously save money and cut their household emissions,” he said. Reprinted with permission.    Get CleanTechnica’s 1st (completely free) electric car report → “Electric Cars: What Early Adopters & First Followers Want.”   Come attend CleanTechnica’s 1st “Cleantech Revolution Tour” event → in Berlin, Germany, April 9–10.   Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.  


News Article | November 14, 2016
Site: www.topix.com

Widely touted electricity reforms aimed at sending regulation of Western Power to the Eastern States and paving the way for WA's next wave of renewable energy projects are officially dead. Energy Minister Mike Nahan has confirmed the so-called national energy law Bills had run out of time to pass State Parliament despite describing them as urgent only three months ago.


News Article | December 7, 2016
Site: www.prweb.com

Access Intelligence, a business-to-business media and information leader, has won IAEE’s prestigious award for the Most Innovative Use of Technology for its EventTech show. “Big ideas, new concepts and fresh technologies are always showcased and experienced at EventTech,” says Access Intelligence group marketing director Sarah Szczesny. “Our entire team is excited about the award, and appreciate the recognition from the judges.” EventTech, an annual conference and exposition for event professionals produced by AI’s Event Marketer brand and held each fall in Las Vegas, features one of the most innovative conference and trade show formats: A 100,000-sq.-ft. “Campus” environment houses five amphitheaters used for breakout sessions, more than 100 exhibitors and a general session area. Key to the experience is an innovative wireless audio technology—attendees are given ear buds and proximity audio devices they use in all amphitheaters. The technology allows them to get an intimate audio experience in all sessions and provides the flexibility to move from theater to theater with crystal clear audio and zero distractions from background noise. Rounding out EventTech’s portfolio of engagement technologies are airport-style registration self check-in lounges, BLE beacons used for location alerts and attendee messaging, a custom mobile app and more. The show returns November 13-15, 2017 at the Paris in Las Vegas. For more information on EventTech, visit eventmarketer.com/eventtech. About Access Intelligence Access Intelligence, a portfolio company of Veronis Suhler Stevenson, is a b-to-b media and information company headquartered in Rockville, Md., serving the media, PR, cable, healthcare management, defense, chemical engineering, satellite and aviation markets. Leading brands include PR News, AdMonsters, Cynopsis, Cablefax, Folio:, Event Marketer, LeadsCon, Chief Marketer, Media Industry Newsletter, Defense Daily Network, AviationToday, Studio Daily, Power, Via Satellite and Exchange Monitor. Market-leading shows include LeadsCon, AdMonsters OPS and Publisher Summits, The Folio: Show, Experiential Marketing Summit, EventTech SATELLITE 2017, OR Manager, LDC Gas Forums, Clean Gulf, ELECTRIC POWER, and Western Power Summit.


News Article | November 11, 2016
Site: www.prweb.com

A record high of 700 publishing, advertising, and marketing professionals from across the globe visited The Folio: Show, magazine media’s most comprehensive industry trade show and conference, enjoying 50-plus sessions spanning six tracks, four keynote sessions, two co-located summits, and an exhibit hall featuring over 40 industry suppliers. “The 2016 Folio: Show was a three-day celebration of the creativity, dynamism, and resilience of magazine media,” said Folio: VP Tony Silber. “We had three strikingly different and equally provocative keynotes, and a rich conference program with an all-star faculty from all sectors of the industry. Our co-located C-Summit was a huge success, as well.” In line with Folio:’s mission of providing all segments of the publishing industry with cutting-edge insights and best practices, new additions to the Folio: Show program this year included entire conference tracks dedicated to content marketing and events – two of the fastest growing revenue sources for publishers – as well as keynotes delivered by HTC’s Dan O’Brien, author Douglas Rushkoff, and a panel consisting of Wasserstein & Co. co-managing partner Anup Bagaria, Good Housekeeping editor-in-chief Jane Francisco, IDG CEO Michael Friedenberg, and Damali Campbell, Print Investment Director at Media Assembly. The Folio: C-Summit, running concurrently with the conference program, had more than 50 participants in an exclusive, invite-only format, attracting executives from across the B2B and B2C segments of the industry, including keynoter David Carey, president of Hearst Magazines, and moderator Peter Goldstone, CEO of Hanley Wood. Folio:’s cornerstone awards program, the Eddie & Ozzie Awards, returned to the Folio: Show to honor over 250 examples of outstanding design, uncompromising journalism, and fearless innovation. Also honored were the Folio: 100, a selection of the industry’s top achievers in 2016, as well as the 30 Under 30, representing the next wave of industry talent. “We are thrilled and honored to play a critical role for magazine media with the largest and most inclusive conference in the industry—the one show every year that is truly a ‘must attend’ event, where magazine media professionals converge to rethink, renew, and refresh,” added Silber. Next year’s Folio: Show, scheduled for October 9-11, 2017, will return to the Hilton Midtown Hotel. For more information, visit http://www.folioshow.com. About Folio: Folio: is dedicated to providing magazine publishing professionals with the news, insights, and best practices to keep them in tune with today’s media industry trends. Folio: has a wide range of resources to help you stay on top of the latest news and find real solutions that help you drive revenue including newsletters, Folio: magazine, awards programs, webinars, conferences and networking events. For more information, visit http://www.foliomag.com. About Access Intelligence: Access Intelligence, a portfolio company of Veronis Suhler Stevenson, is a b-to-b media and information company headquartered in Rockville, Md., serving the media, PR, cable, healthcare management, defense, chemical engineering, satellite and aviation markets. Leading brands include PR News, AdMonsters, Cynopsis, Cablefax, Folio:, Event Marketer, LeadsCon, Chief Marketer, Media Industry Newsletter, Defense Daily Network, AviationToday, Studio Daily, Power, Via Satellite and Exchange Monitor. Market-leading shows include LeadsCon, AdMonsters OPS and Publisher Summits, The Folio: Show, Experiential Marketing Summit, SATELLITE 2017, OR Manager, LDC Gas Forums, Clean Gulf, ELECTRIC POWER, and Western Power Summit.


Kangaroo Island, the iconic tourist attraction off the South Australian coast near Adelaide, would likely find it cheaper to go 100 per cent renewable, with its own resources, rather than stay connected to the main grid, according to a detailed study led by the Institute of Sustainable Futures. The study, released on Thursday, shows that the direct and indirect costs of going it alone with the island’s wind, solar and biomass resources, along with battery storage, would be about the same as the cost of upgrading the link to the mainland and paying for fuel. But while that may be good news for the island, it is likely that the main electricity provider, SA Power Networks, will go for the main grid option, unless enough community support can be gathered to force its hand. The report into the situation in Kangaroo Island highlights a fascinating but important conundrum facing many communities, and many power providers: should millions be spent upgrading or replacing ageing poles and wires, or in this case submarine cables? Or should they be spent in new technologies that offer independence, greater security of supply, clean energy, and local jobs? Sounds like a no-brainer, but because of the regulatory structure governing the country’s network providers, it is not. In Western Australia, the grid operator Western Power is facing similar issues. It knows that it would be cheaper to cut the links to some remote and regional centres and set up local renewables-based micro grids. But the regulator won’t allow it. In South Australia, it’s not entirely clear that SAPN is as excited about the idea of cutting the link to Kangaroo Island, and to some extent it is a test of its willingness to change. It was, however, SAPN that asked if there were any alternatives to simply laying a new cable. It has to be said that some in the local community are also cautious. But the mayor, Peter Clements, is interested, and wants to test the community response. “Kangaroo Island has a wealth of wind, solar and biomass resources,” he says. “Developing a mini-grid to take advantage of these natural assets and produce reliable, affordable power is a win-win for the island’s residents and businesses.” A meeting will be held next week (September 22), where the findings of the report will be presented. The response will be crucial for what avenues are then pursued. Chris Dunstan, one of the lead authors, says that Kangaroo Island is a proxy for similar decisions that are likely to be made in Australia, and it has international importance. The scale of the project is significantly bigger than other high renewables projects undertaken on King Island or Lord Howe Island, and it would be one of the first places in the world where such a large community eventually is removed from the grid. Dunstan and his team at the ISF in Sydney modelled 10 local electricity supply scenarios as alternative sources of power for Kangaroo Island. “Replacing the 15km undersea cable is estimated to cost $77 million over a 25-year period, which includes $36 million for the cable and $37 million for the imported power,” Dunstan says. “The most cost-effective alternative is a local supply of wind, solar photovoltaics and diesel generation, complemented by battery storage and demand management. This wind-solar-diesel hybrid solution could supply Kangaroo Island with 86 per cent renewable energy for only $10 million more than a new cable option. “For a further $13 million, 100 per cent renewable power could be provided by upgrading diesel generation to cutting-edge biomass technology fuelled by unharvested local plantation forest. “Both renewable energy supply options could actually cost Kangaroo Islanders less than the new cable over a 25-year period when indirect costs like savings in local network charges are included.” (As an example, the central “balanced” renewables scenario includes an extra 6MW of solar power for the island, 8MW of wind, 5MW of biomass, and around 8MW of diesel, although this would be used sparingly and only produce around 62MWh a year, compared to 41,000MWh from the wind, solar and biomass resources). Dunstan says it would make sense to use the current cable as long as it lasts. That would mean less diesel use and even offer the opportunity to export excess wind or solar power. 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.

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