TransCanada Reports Third Quarter 2015 Financial Results
Solid Performance Demonstrates Quality of Diversified Asset Base
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 11/03/15 -- TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada) today announced net income attributable to common shares for third quarter 2015 of $402 million or $0.57 per share compared to $457 million or $0.64 per share for the same period in 2014 and $1.2 billion or $1.72 per share compared to $1.3 billion or $1.81 per share on a year-to-date basis. Comparable earnings for third quarter 2015 were $440 million or $0.62 per share compared to $450 million or $0.63 per share for the same period last year. For the nine months ended September 30, 2015, comparable earnings were $1.3 billion or $1.84 per share compared to $1.2 billion or $1.70 per share in 2014. TransCanada''s Board of Directors also declared a quarterly dividend of $0.52 per common share for the quarter ending December 31, 2015, equivalent to $2.08 per common share on an annualized basis.
"Over the past nine months, our diverse suite of high-quality long-life assets has performed well in a challenging environment with comparable earnings and funds generated from operations up eight and nine per cent, respectively, compared to the same period last year," said Russ Girling, TransCanada''s president and chief executive officer. "The resiliency of our base business through various market conditions, combined with $12 billion of visible near-term growth projects, gives us the ability to continue growing the dividend at an annual rate of eight to ten per cent through 2017."
We are also focused on enhancing shareholder value by maximizing the effectiveness and efficiency of our existing operations. As part of those efforts, we recently commenced a business restructuring initiative that is expected to reduce overall costs. The changes will be undertaken in fourth quarter 2015 and continue into 2016.
Over the longer term, our portfolio of low-risk energy infrastructure assets and our financial strength leaves us well positioned to advance a number of other growth initiatives. They include $35 billion of commercially secured projects which would extend and augment future growth in earnings, cash flow and dividends.
Net income attributable to common shares decreased by $55 million to $402 million or $0.57 per share for the three months ended September 30, 2015 compared to the same period last year. Third quarter 2015 included a $6 million after-tax restructuring charge related to changes to our organizational structure while both periods included unrealized gains and losses from changes in risk management activities. All of these specific items are excluded from comparable earnings.
Comparable earnings for third quarter 2015 were $440 million or $0.62 per share compared to $450 million or $0.63 per share for the same period in 2014. Lower contributions from Bruce Power and Western Power were partially offset by higher earnings from the Keystone System, U.S. Power, ANR and Eastern Power.
Notable recent developments in Natural Gas Pipelines, Liquids Pipelines, Energy and Corporate include:
Teleconference and Webcast:
We will hold a teleconference and webcast on Tuesday, November 3, 2015 to discuss our third quarter 2015 financial results. Russ Girling, TransCanada President and Chief Executive Officer, and Don Marchand, Executive Vice-President, Corporate Development and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 9 a.m. (MT) / 11 a.m. (ET).
Analysts, members of the media and other interested parties are invited to participate by calling 866.225.6564 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 .
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on November 10, 2015. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 9292695.
The unaudited interim Consolidated Financial Statements and Management''s Discussion and Analysis (MD&A) are available under TransCanada''s profile on SEDAR at , with the U.S. Securities and Exchange Commission on EDGAR at and on the TransCanada website at .
With more than 65 years'' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,000 kilometres (42,100 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent''s largest providers of gas storage and related services with 368 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 10,900 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America''s largest liquids delivery systems. TransCanada''s common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com and our blog to learn more, or connect with us on social media and 3BL Media.
Forward Looking Information
This news 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 2, 2015 and 2014 Annual Report on our website at or filed under TransCanada''s profile on SEDAR at and with the U.S. Securities and Exchange Commission at .
Non-GAAP Measures
This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, funds generated from operations and comparable earnings 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 2, 2015.
Management''s discussion and analysis
November 2, 2015
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, 2015, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2015 which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2014 audited consolidated financial statements and notes and the MD&A in our 2014 Annual Report.
About this document
Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.
Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2014 Annual Report.
All information is as of November 2, 2015 and all amounts are in Canadian dollars, unless noted otherwise.
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management''s assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements 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 2014 Annual Report.
You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, except as required by law.
FOR MORE INFORMATION
You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR ().
NON-GAAP MEASURES
We use the following non-GAAP measures:
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures.
EBITDA and EBIT
We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings. It is calculated in the same way as EBITDA, less depreciation and amortization.
Funds generated from operations
Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. See the Financial condition section for a reconciliation to net cash provided by operations.
Comparable measures
We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
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.
Net income attributable to common shares decreased by $55 million and $67 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. The 2015 results included:
Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.
Comparable earnings decreased by $10 million for the three months ended September 30, 2015 and increased $98 million for the nine months ended September 30, 2015 compared to the same periods in 2014 as discussed below in the reconciliation of net income to comparable earnings.
The stronger U.S. dollar this quarter compared to the same period in 2014 positively impacted the translated results in our U.S. businesses, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our exposure.
CAPITAL PROGRAM
We are developing quality projects under our long-term capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow.
Our capital program is comprised of $11 billion of small to medium-sized, shorter-term projects, $35 billion of commercially secured large-scale, medium and longer-term projects and $1 billion of acquisitions. Amounts presented exclude the impact of foreign exchange, AFUDC and capitalized interest.
Estimated project costs are generally based on the last announced project estimates and are subject to adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
Outlook
The earnings outlook for 2015 is expected to be consistent with what was previously included in the 2014 Annual Report. See the MD&A in our 2014 Annual Report for further information about our outlook.
We expect our capital expenditures to be approximately $5 billion for 2015, a decrease of $1 billion from the outlook previously provided in our 2014 Annual Report due to project timing delays.
Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).
Natural Gas Pipelines segmented earnings increased by $44 million and $82 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.
CANADIAN PIPELINES
Net income and comparable EBITDA for our rate-regulated Canadian pipelines are generally affected by the approved ROE, investment base, level of deemed common equity, incentive earnings or losses and certain carrying charges. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and comparable EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.
Net income for the Canadian Mainline decreased by $14 million and $24 million for the three months and nine months ended September 30, 2015 compared to the same periods in 2014. The decrease in net income is primarily due to a lower ROE of 10.10 per cent on deemed equity of 40 per cent in 2015 compared to 11.5 per cent in 2014 and a lower average investment base in 2015, partially offset by higher incentive earnings recorded in 2015 primarily in second quarter.
Net income for the NGTL System increased by $9 million and $18 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly due to a higher average investment base and OM&A incentive losses realized in 2014 under the terms of the 2013-2014 NGTL Settlement.
U.S. AND INTERNATIONAL PIPELINES
Earnings for our U.S. natural gas pipelines operations are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.
Comparable EBITDA for U.S. and International Pipelines increased by US$38 million for the three months ended September 30, 2015 compared to the same period in 2014. This increase was the net effect of higher ANR Southeast mainline transportation revenue, partially offset by increased spending on ANR pipeline integrity work.
Comparable EBITDA for U.S. and International Pipelines increased by US$71 million for the nine months ended September 30, 2015 compared to the same period in 2014. This increase was the net effect of:
A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.
COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization increased by $18 million and $54 million for three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly because of a higher investment base on the NGTL System, depreciation for the completed Tamazunchale Extension, and the effect of a stronger U.S. dollar.
BUSINESS DEVELOPMENT
Business development expenses were higher by $17 million and $38 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly due to increased business development activity as well as the third quarter 2014 recovery of amounts from partners for 2013 Alaska Gasline Inducement Act costs.
Liquids Pipelines
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).
Liquids Pipelines segmented earnings increased by $61 million and $170 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and 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 increased by $88 million and $218 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. These increases were primarily due to:
BUSINESS DEVELOPMENT
Business development expenses increased by $14 million and $9 million for the three and nine months ended September 30, 2015, as a result of increased business development activities.
COMPARABLE DEPRECIATION AND AMORTIZATION
Comparable depreciation and amortization increased by $13 million and $39 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 due to the Gulf Coast extension being placed in service and the effect of a stronger U.S. dollar.
Energy
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).
Energy segmented earnings decreased by $110 million and $102 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and included the following unrealized gains and losses from risk management activities:
The period-over-period variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impact of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.
The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with EBITDA, are discussed below.
Western Power
Comparable EBITDA for Western Power decreased by $51 million and $120 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. The decreases were due to lower realized power prices.
Average spot market power prices in Alberta decreased by 59 per cent from $64/MWh to $26/MWh for the three months ended September 30, 2015 and decreased 34 per cent from $56/MWh to $37/MWh for the nine months ended September 30, 2015, compared to the same periods in 2014. The addition of new natural gas-fired and wind plants over the last 12 months have contributed to a well supplied market and very few higher priced hours were observed in spite of seasonally higher summer energy consumption levels. 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.
The decrease in equity earnings for the three and nine months ended September 30, 2015 of $16 million and $29 million compared to the same periods in 2014 is primarily due to the impact of lower Alberta spot market prices on earnings from the ASTC Power Partnership which holds our 50 per cent ownership interest in the Sundance B PPA. Equity earnings does not include the impact of related contracting activities.
Lower Alberta spot power prices are expected to continue in the near term and 2015 Western Power earnings are anticipated to be significantly lower compared to 2014 and lower than our original Outlook in the MD&A in our 2014 Annual Report due to a longer than expected period of over-supply in the Alberta power market.
Sixty-one per cent of Western Power sales volumes were sold under contract in third quarter 2015 compared to 75 per cent in third quarter 2014.
Eastern Power
Comparable EBITDA for Eastern Power increased by $11 million for the three months ended September 30, 2015 compared to the same period in 2014 mainly due to incremental earnings from solar facilities acquired in 2014.
Comparable EBITDA for Eastern Power increased by $70 million for the nine months ended September 30, 2015 compared to the same period in 2014 mainly due to incremental earnings from solar facilities acquired in 2014, higher contractual earnings at Becancour, the sale of unused natural gas transportation and higher earnings at Halton Hills.
BRUCE POWER
Our proportionate share
Equity income from Bruce A decreased by $46 million for the three months ended September 30, 2015 compared to the same period in 2014, mainly due to lower volumes resulting from higher planned outage days and higher operating expenses.
Equity income from Bruce A increased by $54 million for the nine months ended September 30, 2015 compared to the same period in 2014, mainly due to higher volumes resulting from fewer unplanned outage days partially offset by higher operating expenses.
Equity income from Bruce B decreased by $8 million for the three months ended September 30, 2015 compared to the same period in 2014, mainly due to losses from contracting activities and higher operating expenses partially offset by lower lease expense based on the terms of the lease agreement with Ontario Power Generation (OPG).
Equity income from Bruce B decreased by $51 million for the nine months ended September 30, 2015 compared to the same period in 2014, mainly due to lower volumes resulting from higher planned outage days, losses from contracting activities and higher operating expenses, partially offset by lower lease expense based on the terms of the lease agreement with OPG. All Bruce B units were removed from service in April 2015 to allow for inspection of the Bruce B vacuum building as mandated by the Canadian Nuclear Safety Commission to occur approximately once every decade. The outage, along with additional planned maintenance on Unit 6, was completed successfully during second quarter 2015.
Under a contract with the IESO, all of the output from Bruce A is sold at a fixed price per MWh which is adjusted annually on April 1 for inflation.
Under the same contract, all output from Bruce B is subject to a floor price adjusted annually for inflation on April 1.
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the average spot price in a month exceeds the floor price. We expect 2015 spot power prices to be less than the floor price throughout 2015 and therefore no amounts received under the floor price mechanism in 2015 are expected to be repaid. Amounts received above the floor price in first quarter 2014 were repaid to the IESO in January 2015.
The contract with the IESO also 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 fixed price, floor price or spot price as applicable under the contract.
Bruce B also enters into fixed-price contracting activities under which it receives or pays the difference between the contract price and the spot price.
Overall plant availability percentages in 2015 are expected to be in the mid 80s for Bruce A and Bruce B. In July 2015, planned outage work commenced on Bruce A Unit 4 and is expected to be completed in early November 2015.
Wholesale electricity prices in New York and New England were lower for the three and nine months ended September 30, 2015 compared to the same periods in 2014. In New England, spot power prices for the three and nine months ended September 30, 2015 were 15 per cent and 36 per cent lower compared to the same periods in 2014. In New York City, spot power prices were 11 per cent and 37 per cent lower for the three and nine months ended September 30, 2015 compared to the same periods in 2014. Both markets have experienced lower natural gas commodity prices throughout 2015 compared to 2014. Reductions in fuel oil prices and increased availability of liquefied natural gas in winter 2015 helped to mitigate the impact of pipeline constraints and keep peak price excursions limited compared to winter 2014.
Spot capacity prices in New York City were, on average, 17 per cent lower for both the three and nine months ended September 30, 2015 compared to the same periods in 2014, primarily due to increased available operational supply in New York City''s Zone J market.
Physical sales volumes and purchased volumes sold to wholesale, commercial and industrial customers were higher than the same periods in 2014 as we have expanded our customer base in both the PJM and New England markets. Lower commodity prices and reduced price volatility contributed to higher margins on sales to wholesale, commercial and industrial customers by reducing the costs on volumes purchased to fulfill power sales commitments to these customers.
As at September 30, 2015, approximately 1,500 GWh or 72 per cent of U.S. Power''s planned generation was contracted for the remainder of 2015 and 4,800 GWh or 52 per cent for 2016. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.
NATURAL GAS STORAGE AND OTHER
Comparable EBITDA decreased by $4 million and $24 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and were primarily due to decreased proprietary and third party storage revenues as a result of lower realized natural gas price spreads as well as extreme natural gas price volatility experienced in first quarter 2014.
Recent developments
NATURAL GAS PIPELINES
Canadian Regulated Pipelines
NGTL System
The NGTL System has approximately $6.8 billion of new supply and demand facilities under development. Approximately $2.8 billion of these facilities have received regulatory approval with $800 million currently under construction. In third quarter 2015, we continued to advance several of these capital expansion projects with an additional approximately $500 million of applied for facilities that now await regulatory review for approval. We have also received additional requests for firm receipt service that we anticipate will increase the overall capital spend on the NGTL System beyond the previously announced program and continue to work with our customers to best match their requirements for 2016, 2017 and 2018 in-service dates.
North Montney Mainline
In April 2015, the NEB issued its report recommending the federal government approve the $1.7 billion North Montney Mainline project which will provide substantial new capacity on the NGTL System to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The project will connect Montney and other Western Canada Sedimentary Basin supply to both existing and new natural gas markets, including LNG markets.
The North Montney Mainline project will consist of two large diameter 42-inch pipeline sections, Aitken Creek and Kahta, totaling approximately 301 km (187 miles) in length, and associated metering facilities, valve sites and compression facilities. The project will also include an interconnection with our proposed Prince Rupert Gas Transmission Project (PRGT) to provide natural gas supply to the proposed Pacific NorthWest (PNW) LNG liquefaction and export facility near Prince Rupert, B.C. We expect to have the Aitken Creek section and the Kahta section in service in 2017.
The NEB also approved the applied-for rolled-in tolling design for the North Montney Mainline project costs during a transition period, subject to certain conditions which we are reviewing. Following the transition period, we will have the option of applying to the NEB for a revised tolling methodology or the ability to implement stand-alone tolling on the project. We are engaging with shippers to determine an appropriate approach that best meets market requirements.
The Federal Government approved the recommendations of the report from the NEB and, in June 2015, the NEB issued a Certificate of Public Convenience and Necessity to proceed with the project, subject to certain terms and conditions. Under one of these conditions, construction on the North Montney Mainline project can only begin after a confirmation of a Final Investment Decision (FID) has been made on the proposed PNW LNG project and we are proceeding with construction on PRGT.
Canadian Mainline
Agreement Reached with Eastern LDCs on Energy East and Eastern Mainline Project
On August 24, 2015, we announced an agreement with eastern local distribution companies (LDCs) that resolves the LDCs'' issues with Energy East and the Eastern Mainline Project. The agreement honours our previously stated commitment to ensure that Energy East and the Eastern Mainline Project will provide gas consumers in eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs. As part of the agreement, we will size the Eastern Mainline Project to meet all firm requirements including gas transmission contracts resulting from both 2016 and 2017 new capacity open seasons plus approximately 50 million cubic feet per day additional capacity.
Eastern Mainline Project
The Eastern Mainline Project capital cost is now estimated to be $2.0 billion with an expected in-service date of 2019. This increase is due to the revised project scope resulting from the LDC agreement and updated cost estimates.
Canadian Mainline 2015-2020 Mainline Transportation Tolls Compliance Filing
In March 2015, we submitted a compliance toll filing in response to direction from the NEB''s RH-001-2014 Decision issued in November 2014. In June 2015, the NEB approved the applied-for compliance tolls, as filed, which allowed, among other things, the recording of incentive earnings as approved by the NEB. These final tolls became effective on July 1, 2015.
Kings North Connection Project
In June 2015, the NEB approved construction of the King''s North Connection project to expand gas transmission capacity in the greater Toronto area and provide shippers with the flexibility to source growing supplies of Marcellus gas from the U.S. Northeast. The project is expected to cost approximately $220 million and is anticipated to be in service by fourth quarter 2016.
U.S. Pipelines
Sale of GTN Pipeline to TC PipeLines, LP
In April 2015, we closed the sale of our remaining 30 per cent interest in GTN to our master limited partnership, TC PipeLines, LP, for an aggregate purchase price of US$446 million plus a purchase price adjustment of US$11 million. Proceeds for the US$457 million sale were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TC PipeLines, LP. The Class B units entitle us to a cash distribution based on 30 per cent of GTN''s annual cash distribution after certain thresholds are achieved, namely 100 per cent of distributions above US$20 million in the first five years and 25 per cent of distributions above US$20 million in subsequent years.
LNG Pipeline Projects
Prince Rupert Gas Transmission
In June 2015, PNW LNG announced a positive FID for its proposed liquefaction and export facility, subject to two conditions. The first condition, approval by the Legislative Assembly of B.C. of a Project Development Agreement between PNW LNG and the Province of B.C., was satisfied in July 2015. The second condition is a positive regulatory decision on PNW LNG''s environmental assessment by the Government of Canada.
In third quarter 2015, we received the remaining permits from the B.C. Oil and Gas Commission (BC OGC) which completes the 11 permits required to build and operate PRGT. Environmental permits for the project were received in November 2014 from the B.C. Environmental Assessment Office.
We also announced in third quarter 2015, the signing of project agreements with Metlakatla First Nation and Blueberry River First Nations. We are continuing our engagement with Aboriginal groups and have now signed project agreements with nine First Nation groups along the pipeline route.
We remain on target to begin construction following confirmation of a FID by PNW LNG. The in-service date for PRGT is estimated to be 2020 but will be aligned with PNW LNG''s liquefaction facility timeline.
Coastal GasLink
We have received eight of ten pipeline and facilities permits from the BC OGC and anticipate receiving the remaining two permits in fourth quarter 2015. We are continuing our engagement with Aboriginal groups and have signed project agreements with eight First Nation groups along the pipeline route.
LIQUIDS PIPELINES
Houston Lateral and Terminal
Construction continues on the 77 km (48 mile) Houston Lateral pipeline and tank terminal which will extend the Keystone Pipeline System to Houston, Texas refineries. The terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are now expected to be completed in second quarter 2016.
On April 14, 2015, we, along with Magellan Midstream Partners L.P. (Magellan), announced a joint development agreement to connect our Houston Terminal to Magellan''s East Houston Terminal. We will own 50 per cent of this US$50 million pipeline project which will enhance connections to the Houston market for our Keystone Pipeline System. Subject to definitive agreements and receipt of necessary permits and approvals, the pipeline is expected to be operational in early 2017.
Keystone XL
In January 2015, the DOS re-initiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest. All of the agency comments were submitted.
On February 2, 2015, the U.S. Environmental Protection Agency (EPA) posted a comment letter to its website suggesting that, among other things, the FSEIS issued by the DOS had not fully and completely assessed the environmental impacts of Keystone XL and that, at lower crude oil prices, Keystone XL may increase the rates of oil sands production and greenhouse gas emissions. On February 10, 2015, we sent a letter to the DOS refuting these and other comments in the EPA letter and offered to work with the DOS to ensure it has all the relevant information to allow it to reach a decision to approve Keystone XL.
On February 24, 2015, U.S. President Obama vetoed Congressional legislation that would have granted us authority to construct Keystone XL across the international border. The U.S. President stated that the legislation circumvented the process established for making a final decision on the permit application. The timing and ultimate resolution of Keystone XL''s pending application for a Presidential Permit remains uncertain.
On June 29, 2015, we sent a letter to the DOS updating relevant developments since the 2014 FSEIS, including additional evidence demonstrating that Canada is taking strong steps toward managing carbon emissions.
On August 5, 2015, the South Dakota Public Utility Commission (PUC) concluded its hearing on Keystone XL''s request to re-certify its existing permit authority in that state. The PUC is expected to make a decision by first quarter 2016.
In January 2015, Keystone XL initiated eminent domain actions against landowners in Nebraska who had not agreed to grant voluntary easements. These actions were taken under the eminent domain authority provided by the Governor''s 2013 approval of the reroute in Nebraska. Several landowners then challenged those actions in Nebraska district court on the grounds that the law authorizing the Governor''s approval violated the Nebraska constitution. In October 2015, we withdrew the eminent domain actions and moved to dismiss the constitutional court proceedings. The plaintiffs are resisting dismissal of this case. A hearing on that issue was held on October 19, 2015 and a decision is expected in fourth quarter 2015.
On October 5, 2015, we filed an application with the Nebraska Public Service Commission (PSC) for route approval through the state of Nebraska. The route we are seeking approval for is the same route previously approved by the Nebraska Department of Environmental Quality in January 2013. After careful review, we believe this would be the most expedient path to approval and expect the PSC to make a decision by third quarter 2016.
On November 2, 2015, we sent a letter to U.S. Secretary of State John Kerry asking the Department of State to pause its review of the Presidential Permit application for Keystone XL while we seek Nebraska PSC approval of the route.
As of September 30, 2015, we have invested US$2.4 billion in the project and have also capitalized interest in the amount of US$0.4 billion.
Energy East Pipeline
In April 2015, we announced that the marine and associated tank terminal in Cacouna, Quebec will not be built as a result of the recommended reclassification of beluga whales as an endangered species. Amendments to the project are expected to be submitted to the NEB in fourth quarter 2015. The NEB has continued to process the application in the interim.
The alteration to the project scope and further refinement of the project schedule is expected to result in an in-service date of 2020. The original $12 billion cost estimate is expected to increase due to further scope refinement as we consult with stakeholders and escalation of construction costs as the project schedule is refined.
Heartland Pipeline and TC Terminals
In May 2015, the Alberta Energy Regulator issued a permit for construction of the Heartland Pipeline. The in-service date of the project will be aligned to meet market requirements for incremental capacity between the Heartland region near Edmonton, Alberta and Hardisty, Alberta.
Crude oil prices continue to remain low, prompting many producers to cut capital spending and delay oil sands projects in western Canada. In its 2015 Crude Oil Forecast, Markets and Transportation report, the Canadian Association of Petroleum Producers estimated WCSB crude oil production will continue to grow but at a slower pace than previously anticipated. Our liquids pipelines projects are supported by long-term contracts. However, with the slowing in growth of crude oil production, our intra-Alberta projects may experience a similar slowing pace of growth to align with the market.
Grand Rapids Pipeline
On August 6, 2015, Grand Rapids Pipeline Limited Partnership (Grand Rapids) entered into an agreement to contribute the southernmost portion of the 20-inch diluent Grand Rapids Pipeline into a 50/50 joint venture with Keyera Corp. (Keyera). The 45-kilometre (28-mile) pipeline will be constructed by us and will extend from Keyera''s Edmonton Terminal to our Heartland Terminal near Fort Saskatchewan. Keyera will also contribute a new pump station at its Edmonton terminal. We expect Grand Rapid''s total contribution to the joint venture will be approximately $140 million. Keyera will operate the pipeline once construction is complete and the facilities are in service. The expected in-service date is the second half of 2017 subject to regulatory approvals.
Upland Pipeline
In April 2015, we filed an application to obtain a U.S. Presidential Permit for the Upland Pipeline. The US$600 million Upland Pipeline is a 400 km (240 mile) crude oil pipeline which will provide transportation from, and between, multiple points in North Dakota and interconnect with the Energy East Pipeline at Moosomin, Saskatchewan. Subject to regulatory approvals, we anticipate the Upland Pipeline to be in service in 2020. The commercial contracts we have executed for Upland Pipeline are conditioned on the Energy East pipeline project proceeding.
ENERGY
Ironwood Power Plant
On October 8, 2015, we reached an agreement to acquire the 778 MW Ironwood natural gas fired, combined cycle power plant located in Lebanon, Pennsylvania from Talen Energy Corporation for US$654 million. At closing, US$42 million in debt will be assumed and repaid within 45 days of closing using funds placed into escrow by the seller.
The Ironwood power plant delivers energy into the PJM power market and will provide us with a solid platform from which to continue to grow our wholesale, commercial and industrial customer base in this market area. The acquisition will be financed with a combination of cash on hand and available debt capacity. The transaction is expected to close early in first quarter 2016, subject to certain conditions being satisfied.
Becancour Power Plant
In August 2015, we executed an agreement with Hydro Quebec (HQ) to amend Becancour''s electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Becancour facility for a term of 20 years commencing in December 2016. Annual payments for this new service will be incremental to existing capacity payments earned under the agreement. In October 2015, the Regie de l''energie approved the amended contract.
Ravenswood
In late May 2015, the 972 MW Unit 30 at the Ravenswood Generating Station returned to service after a September 2014 unplanned outage which resulted from a problem with the generator associated with the high pressure turbine.
Alberta Greenhouse Gas Emissions
In June 2015, the Alberta government announced a renewal and change to the Specified Gas Emitters Regulations (SGER) in Alberta. Since 2007, under the SGER, established industrial facilities with GHG emissions above a certain threshold are required to reduce their emissions by 12 per cent below an average intensity baseline and a carbon levy of $15 per tonne is placed on emissions above this target. The changed regulations include an increase in the emissions reductions target to 15 per cent in 2016 and 20 per cent in 2017, along with an increase in the carbon levy to $20 per tonne in 2016 and $30 per tonne in 2017. While our Sundance and Sheerness PPAs are subject to this regulation, our significant inventory of carbon offset credits is expected to mitigate the majority of these increased costs. The remaining compliance costs are expected to be recovered through increased market pricing and contract flow through provisions.
CORPORATE
Restructuring
In mid-2015, we commenced a business restructuring and transformation initiative. While there is no change to our corporate strategy, we have undertaken this initiative to reduce overall costs and maximize the effectiveness and efficiency of our existing operations. At September 30, 2015, we had incurred $36 million before tax, mainly related to severance costs, of which $20 million before tax was included in plant operating costs and other on the income statement, $8 million was capitalized to projects impacted by the restructuring and $8 million is recoverable through regulatory and tolling structures. The total restructuring charges will be determined once the scope of the expected changes is known, which is anticipated to occur in fourth quarter 2015. We expect further restructuring initiatives to be undertaken in fourth quarter 2015 and to continue into 2016.
Other income statement items
The following are reconciliations and related analyses of our non-GAAP measures to the equivalent GAAP measures for other income statement items.
Comparable interest income and other expense decreased by $7 million for the three months ended September 30, 2015 and increased by $36 million for the nine months ended September 30, 2015 compared to the same periods in 2014. The increase for the nine months ended is the net result of:
Comparable income tax expense increased by $6 million and $52 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. The increases were mainly the result of higher pre-tax earnings in 2015 compared to 2014 and changes in the proportion of income earned between Canadian and foreign jurisdictions, partially offset by lower flow-through taxes in 2015 on Canadian regulated pipelines.
Net income attributable to non-controlling interests increased by $21 million and $35 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 primarily due to the sale of our remaining 30 per cent direct interests in GTN in April 2015 and Bison in October 2014 to TC PipeLines, LP and the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.
Financial condition
We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.
We believe we have the financial capacity to fund our existing capital program through our predictable cash flow from our operations, access to capital markets, proceeds from the sale of U.S. natural gas pipeline assets to TC PipeLines, LP, cash on hand and substantial committed credit facilities.
At September 30, 2015, our current assets were $3.8 billion and current liabilities were $6.9 billion, leaving us with a working capital deficit of $3.1 billion compared to $4.0 billion at December 31, 2014. This working capital deficiency is considered to be in the normal course of business and is managed through:
Costs incurred on capital projects under development primarily relate to the Energy East Pipeline and LNG pipeline projects.
Equity investments have increased in 2015 compared to 2014 primarily due to our investment in Grand Rapids.
Deferred amounts and other has increased in 2015 compared to 2014 primarily due to the change in our long-term regulatory assets and liabilities.
TransCanada Trust (the Trust), our 100 per cent owned financing trust subsidiary of TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors with a fixed interest rate of 5.625 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 us in US$750 million junior subordinated notes of TCPL at a rate of 5.875 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 our financial statements as 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. Further details regarding the terms of the Trust Notes and the related agreements entered into by TransCanada and TCPL can be found in the prospectus in respect of the Trust Notes and other documents filed under the Trust''s profile on SEDAR at .
PREFERRED SHARE ISSUANCE AND CONVERSION
In June 2015, holders of 5.5 million Series 3 cumulative redeemable first preferred shares exercised their option to convert to Series 4 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 1.28 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 3 preferred shares was reset for five years at 2.152 per cent per annum.
In March 2015, we completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $250 million. The Series 11 preferred shareholders will have the right to convert their Series 11 preferred shares into Series 12 cumulative redeemable first preferred shares on November 30, 2020 and on November 30 of every fifth year thereafter. The holders of Series 12 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 2.96 per cent.
The net proceeds of the above debt and Series 11 preferred share offerings were used for general corporate purposes and to reduce short-term indebtedness.
TC PIPELINES, LP AT-THE-MARKET (ATM) EQUITY ISSUANCE PROGRAM
From January 1 to September 30, 2015, 0.4 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$25 million. Our ownership interest in TC PipeLines, LP will decrease as a result of issuances under the ATM program.
DIVIDENDS
On November 2, 2015, we declared quarterly dividends as follows:
CREDIT FACILITIES
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 as well as providing additional liquidity.
At September 30, 2015, we had approximately $7 billion in unsecured credit facilities, including:
At September 30, 2015, our operated affiliates had an additional $0.6 billion of undrawn capacity on committed credit facilities.
We are currently in the process of renewing the committed, syndicated, revolving, extendible credit facilities.
See Financial risks and financial instruments for more information about liquidity, market and other risks.
CONTRACTUAL OBLIGATIONS
Our capital commitments are consistent with the amounts reported at December 31, 2014 as a result of the completion or advancement of capital projects partially offset by new commitments for the Napanee generating facility. Our other purchase obligations have increased by approximately $0.1 billion since December 31, 2014 primarily due to an increase in commodity purchase obligations and information technology and communication contracts. There were no other material changes to our contractual obligations in third quarter 2015 or to payments due in the next five years or after. See the MD&A in our 2014 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 2014 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2014.
LIQUIDITY RISK
We manage our liquidity risk by continuously forecasting our cash requirements for a rolling twelve month period and making sure 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.
COUNTERPARTY CREDIT RISK
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, 2015, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration due from a counterparty of $248 million (US$185 million) and $258 million (US$222 million) at September 30, 2015 and December 31, 2014. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty''s investment grade parent company.
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.
FOREIGN EXCHANGE AND INTEREST RATE RISK
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 by using foreign exchange derivatives.
We have floating interest rate debt and floating rate preferred shares (Series 2 and Series 4) which subject us to interest rate cash flow risk. We use interest rate swaps to help manage this risk.
Derivatives designated as a net investment hedge
We hedge our 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. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:
FINANCIAL INSTRUMENTS
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.
Non-derivative financial instruments
Fair value of non-derivative financial instruments
The fair value of our 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 has been estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data providers.
Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments including 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 financial instruments.
Derivative instruments
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 effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in OCI in the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other expense and interest expense.
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 recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered or refunded through the tolls charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.
Fair value of derivative instruments
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 power and natural gas 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.
Derivatives in cash flow hedging relationships
The components of other comprehensive income related to derivatives in cash flow hedging relationships are as follows:
Credit risk related contingent features of derivative instruments
Derivative contracts 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).
Based on contracts in place and market prices at September 30, 2015, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $15 million (December 31, 2014 - $15 million), with collateral provided in the normal course of business of nil (December 31, 2014 - nil). If the credit-risk-related contingent features in these agreements had been triggered on September 30, 2015, we would have been required to provide collateral of $15 million (December 31, 2014 - $15 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.
Other information
CONTROLS AND PROCEDURES
Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at September 30, 2015, 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 third quarter 2015 that had or are likely to have a material impact on our internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES
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 jud
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