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TransCanada Reports Fourth Quarter and Year-End 2015 Financial Results
Marketwired
Common Share Dividend Increased Nine Per Cent to $2.26 Per Share Annually

TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada) today announced a net loss attributable to common shares for fourth quarter 2015 of $2.5 billion or $3.47 per share compared to net income of $458 million or $0.65 per share for the same period in 2014. For the year ended December 31, 2015, the net loss attributable to common shares was $1.2 billion or $1.75 per share compared to net income of $1.7 billion or $2.46 per share in 2014. Comparable earnings for fourth quarter 2015 were $453 million or $0.64 per share compared to $511 million or $0.72 per share for the same period last year. For the year ended December 31, 2015, comparable earnings were $1.8 billion or $2.48 per share compared to $1.7 billion or $2.42 per share in 2014. TransCanada's Board of Directors also declared a quarterly dividend of $0.565 per common share for the quarter ending March 31, 2016, equivalent to $2.26 per common share on an annualized basis, an increase of nine per cent. This is the sixteenth consecutive year the Board of Directors has raised the dividend.

"Although 2015 was a very challenging year for the energy industry, our $64 billion portfolio of high-quality energy infrastructure assets performed well," said Russ Girling, TransCanada's president and chief executive officer. "Excluding specific items, comparable earnings and funds generated from operations reached record levels while we continued to safely and reliably meet the needs of our customers across North America."

While we were extremely disappointed by the denial of a Presidential Permit for Keystone XL and the resulting $2.9 billion after-tax non-cash impairment charge, we are well positioned to continue to grow earnings and cash flow in the years ahead. Our assets are largely underpinned by cost of service regulated business models or long-term contracts with solid counterparties resulting in highly predictable cash flow streams with minimal commodity or volume throughput risk. In addition, we are proceeding with $13 billion of near-term growth opportunities that are expected to be in-service by 2018. Over the medium to longer-term we are advancing $45 billion of commercially secured, large-scale projects and various other initiatives that will create significant additional shareholder value.

"Based on the confidence we have in our future outlook, we recently repurchased 7.1 million common shares and are pleased to announce a nine per cent increase in the common share dividend," added Girling. "Building upon the resiliency of our base business, our visible, near-term growth and our financial strength, our common share dividend is expected to rise at an average annual rate of eight to ten per cent through 2020. Success in advancing additional initiatives could further extend and augment future dividend growth."

Net income attributable to common shares decreased by $2.9 billion to a net loss of $2.5 billion or $3.47 per share for the three months ended December 31, 2015 compared to the same period last year. Fourth quarter 2015 included a net loss of $2.9 billion related to specific items including a $2.9 billion after-tax impairment charge related to Keystone XL, an $86 million after-tax loss provision related to the sale of TC Offshore, a $43 million after-tax charge related to an impairment of turbine equipment held for future use in Energy, a debt retirement charge of $27 million after-tax related to the merger of Bruce A and Bruce B, a $60 million after-tax charge for our business restructuring and transformation initiative and a positive $199 million adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes. Fourth quarter 2014 included an $8 million after-tax gain from the sale of Gas Pacifico/INNERGY. Both periods included unrealized gains and losses from changes in risk management activities. All of these specific items are excluded from comparable earnings.

Net loss attributable to common shares for the year ended December 31, 2015 was $1.2 billion or $1.75 per share compared to net income of $1.7 billion or $2.46 per share in 2014. Results in 2015 included a net loss of $3.0 billion related to specific items including those noted above for the fourth quarter as well as an Alberta corporate income tax rate increase of $34 million. Results in 2014 included a net after-tax gain of $99 million from the sale of Cancarb and its related power generation facility, an after-tax $32 million expense for terminating a natural gas storage contract and an $8 million after-tax gain from the sale of Gas Pacifico/ INNERGY. These amounts, along with unrealized gains and losses on risk management activities, were excluded from comparable earnings.

Comparable earnings for fourth quarter 2015 were $453 million or $0.64 per share compared to $511 million or $0.72 per share for the same period in 2014. Lower contributions from Canadian Power and the Canadian Mainline were partially offset by higher earnings from the Keystone System.

Comparable earnings for the year ended December 31, 2015 were $1.8 billion or $2.48 per share compared to $1.7 billion or $2.42 per share in 2014. Higher earnings from the Keystone System, U.S. Power, ANR, Eastern Power and Mexico were partially offset by lower contributions from Western Power and Bruce Power.

Notable recent developments in Natural Gas Pipelines, Liquids Pipelines, Energy and Corporate include:

Natural Gas Pipelines:

Liquids Pipelines:

Energy:

Corporate:

Teleconference and Webcast:

We will hold a teleconference and webcast on Thursday, February 11, 2016 to discuss our fourth 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 1 p.m. (MT) / 3 p.m. (ET).

Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.2216 (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 18, 2016. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 9573850.

The audited annual 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 67,000 kilometres (42,000 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 13,100 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

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 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 news release.

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

Risks and uncertainties

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2014 Annual Report.

As actual results could vary significantly from 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.

FOR MORE INFORMATION

You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).

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 news release for a reconciliation of the GAAP measures to the non-GAAP measures.

EBITDA and EBIT

We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings. It is calculated in the same way as EBITDA, less depreciation and amortization.

Funds generated from operations

Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period and is used to provide a consistent measure of the cash generating performance of our assets. See the Financial condition section for a reconciliation to net cash provided by operations.

Distributable cash flow

Distributable cash flow is defined as funds generated from operations plus distributions in excess of equity earnings less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures represent costs which are necessary to preserve the operating ability of our assets and investments. We believe it is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. See the Reconciliation of non-GAAP measures 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.

Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:

In calculating comparable earnings and other comparable measures 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 unrealized changes in fair value 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 $2,916 million to a net loss of $2,458 million for the three months ended December 31, 2015 compared to the same period in 2014. The 2015 results included:

The 2014 results included:

Net income in both 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 $58 million for the three months ended December 31, 2015 compared to the same period in 2014 as discussed below in the reconciliation of net income to comparable earnings.

Comparable earnings decreased by $58 million for the three months ended December 31, 2015 compared to the same period in 2014. This was primarily the net effect of:

The stronger U.S. dollar in 2015 compared to 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 consists of $13 billion of near-term projects and $45 billion of commercially secured medium and longer-term projects. Amounts presented exclude the impact of foreign exchange, capitalized interest and AFUDC.

All project costs are subject to adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.

Medium to Longer-term projects

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 disclosed. These projects have all been commercially secured but are subject to approvals that include sponsor FID and/or complex regulatory processes.

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). See the non-GAAP measures section for more information on the non-GAAP measures we use as well as the reconciliation of non-GAAP measures section for reconciliations to their GAAP equivalents.

Natural Gas Pipelines segmented earnings decreased by $49 million for the three months ended December 31, 2015 compared to the same period in 2014 and included a $125 million pre-tax loss provision recorded as a result of a December 2015 agreement to sell TC Offshore, which is expected to close in early 2016. Segmented earnings in 2014 included a $9 million pre-tax gain related to the sale of Gas Pacifico/INNERGY in November 2014. These amounts have been excluded from our calculation of comparable EBIT. Comparable EBIT and 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, if material, carrying charges on revenue and cost variances that are recovered in revenue on a flow-through basis. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and comparable EBIT but do not have a significant impact in net income as they are almost entirely recovered in revenue on a flow-through basis.

Net income for the Canadian Mainline decreased by $63 million for the three months ended December 31, 2015 compared to the same period in 2014 primarily due to a lower average investment base in 2015 and a lower ROE of 10.1 per cent in 2015 compared to 11.5 per cent in 2014. Incentive earnings of $59 million for 2014 were recorded in the fourth quarter 2014 contributing to the higher net income in that period.

Net income for the NGTL System increased by $10 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to a higher average investment base and OM&A incentive losses realized in 2014.

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$42 million for the three months ended December 31, 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.

A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $15 million for the three months ended December 31, 2015 compared to the same period 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.

Liquids Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). See the non-GAAP measures section for more information on the non-GAAP measures we use as well as the reconciliation of non-GAAP measures section for reconciliations to their GAAP equivalents.

Liquids Pipelines segmented earnings decreased by $3,643 million to a segmented loss of $3,413 million for the three months ended December 31, 2015 compared to the same period in 2014. 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. This amount has 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 increased by $54 million for the three months ended December 31, 2015 compared to the same period in 2014 and was primarily due to:

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $11 million for the three months ended December 31, 2015 compared to the same period in 2014 primarily due to 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). See the non-GAAP measures section for more information on the non-GAAP measures we use as well as the reconciliation of non-GAAP measures section for reconciliations to their GAAP equivalents.

Energy segmented earnings decreased by $137 million for the three months ended December 31, 2015 compared to the same period in 2014 and included the following specific items:

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 particular 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 representative of our underlying operations.

The specific items noted above have been excluded in our calculation of comparable EBIT. The remainder of the Energy segmented earnings are equivalent to comparable EBIT, which, along with EBITDA, are discussed below.

Comparable EBITDA for Energy decreased by $110 million for the three months ended December 31, 2015 compared to the same period in 2014 due to the net effect of:

Western Power

Comparable EBITDA for Western Power decreased by $60 million for the three months ended December 31, 2015 compared to the same period in 2014. The decrease was due to lower realized power prices and lower PPA volumes.

Average spot market power prices in Alberta decreased by 32 per cent from $31/MWh to $21/MWh for the three months ended December 31, 2015 compared to the same period in 2014. The addition of new natural gas-fired power plants in 2015 have contributed to a well supplied market and few higher priced hours were observed. 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 $8 million decrease in equity earnings for the three months ended December 31, 2015 compared to the same period 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 do not include the impact of related contracting activities.

Fifty-nine per cent of Western Power sales volumes were sold under contract in fourth quarter 2015 compared to 76 per cent in fourth quarter 2014.

Eastern Power

Comparable EBITDA for Eastern Power decreased by $26 million for the three months ended December 31, 2015 compared to the same period in 2014 due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour.

BRUCE POWER

Results reflect our proportionate share. Beginning in 2016, results from Bruce Power will be reported on a combined basis to reflect the merged entity. Comparable income from equity investments is a non-GAAP measure. See the non-GAAP measures section for more information on the non-GAAP measures we use.

Comparable income from equity investments from Bruce A decreased by $58 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to lower volumes resulting from higher planned outage days and higher operating expenses.

Comparable income from equity investments from Bruce B increased by $26 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to higher volumes resulting from lower planned outage days and lower lease expense based on the terms of the lease agreement with Ontario Power Generation.

On December 3, 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the Bruce Power facility to 2064. This new agreement represents an extension and material amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site.

The amended agreement, which took economic effect on January 1, 2016, allows Bruce Power to immediately invest in life extension activities for Units 3 through 8 to support the long-term refurbishment program. This early investment in the Asset Management program will result in near-term life extension, allowing later investment in the Major Component Replacement work that is expected to begin in 2020.

As part of the life extension and refurbishment agreement, Bruce Power began receiving a uniform price of $65.73 per MWh for all units in January 2016. 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.

Our estimated share of investment related to the Asset Management program to be completed over the life of the agreement is approximately $2.5 billion (2014 dollars). Our estimated share of investment in the Major Component Replacement work for Units 3 through 8 over the 2020 to 2033 timeframe is approximately a further $4 billion (2014 dollars).

Under certain conditions, Bruce Power and the IESO can elect to not proceed with the remaining Major Component Replacement investments should the cost exceed certain thresholds or prove to not provide sufficient economic benefits. The agreement has been structured to account for changing cost inputs over time, including ongoing operating costs and larger capital investments.

On December 3, 2015, we exercised our option to acquire an additional 14.89 per cent ownership interest in Bruce B for $236 million from the Ontario Municipal Employees Retirement System. On December 4, 2015, Bruce B and Bruce A were merged to form a single partnership structure through Bruce Power LP with us now owning a 48.5 per cent ownership interest. Prior to the acquisition of additional Bruce B ownership and the merger, we owned 48.9 per cent of Bruce A and 31.6 per cent of Bruce B.

Prior to the amended agreement with the IESO, all of the output from Bruce A 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. Bruce A also recovered fuel costs from the IESO.

Prior to the amended agreement with the IESO, all output from Bruce B Units 5 to 8 was subject to a floor price adjusted annually for inflation on April 1.

Amounts received under the Bruce B Units 5 - 8 floor price mechanism within a calendar year were subject to repayment if the average spot price in a month exceeded the floor price. The average spot power price in each month of 2015 was less than the floor price and therefore no amounts received under the floor price mechanism in 2015 are subject to repayment.

Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.

The contract 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 contract price.

Comparable EBITDA for U.S. Power decreased US$5 million for the three months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

Average New York Zone J spot capacity prices were approximately 23 per cent lower for the three months ended December 31, 2015 compared to the same period in 2014. The decrease in spot prices and the impact of hedging activities resulted in lower realized capacity prices in New York in 2015. This was primarily due to increased available operational supply in New York City's Zone J market.

Capacity revenues were also negatively impacted by an outage from September 2014 to May 2015 at Ravenswood. The calculation used by the NYISO to determine the capacity volume for which a generator is compensated utilizes a rolling average forced outage rate. As a result of this methodology, outages impact capacity volumes and associated revenues on a lagged basis. Accordingly, capacity revenues for the three months ended December 31, 2015 were negatively impacted compared to the same period in 2014. The outage continues to be included in the rolling average forced outage rate.

Wholesale electricity prices in New York and New England were lower for the three months ended December 31, 2015 compared to the same period in 2014. In New England, spot power prices for the three months ended December 31, 2015 were 27 per cent lower compared to the same period in 2014. In New York City, spot power prices were 33 per cent lower for the three months ended December 31, 2015 compared to the same period in 2014. Both markets have experienced lower natural gas commodity prices throughout 2015 compared to 2014.

Physical sales volumes and purchased volumes sold to wholesale, commercial and industrial customers were higher for the three months ended December 31, 2015 than the same period in 2014 as we have expanded our customer base in both the PJM and New England markets.

As at December 31, 2015, approximately 6,600 GWh or 70 per cent of U.S. Power's planned generation is contracted for 2016, and 3,000 GWh or 33 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.

NATURAL GAS STORAGE AND OTHER

Comparable EBITDA for Natural Gas Storage and Other decreased by $5 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to decreased proprietary revenue as a result of lower realized natural gas storage price spreads.

Corporate

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). See the non-GAAP measures section for more information on the non-GAAP measures we use as well as the reconciliation of non-GAAP measures section for reconciliations to their GAAP equivalent.

Corporate segmented losses for the three months ended December 31, 2015 increased by $118 million compared to the same period in 2014 and included a charge of $79 million before tax for restructuring charges comprised of $36 million related to 2015 severance costs and a provision of $43 million for 2016 planned severance costs and expected future losses under lease commitments. This amount has been excluded from our calculation of comparable EBIT and EBITDA.

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. See the non-GAAP measures section for more information on the non- GAAP measures we use.

Comparable interest expense increased by $57 million for the three months ended December 31, 2015 compared to the same period in 2014 due to the net effect of:

Comparable interest income and other increased by $36 million for the three months ended December 31, 2015 compared to the same period in 2014 due to the net effect of:

Comparable income tax expense decreased by $8 million for the three months ended December 31, 2015 compared to the same period in 2014 and was mainly the result of lower pre-tax earnings and changes in the proportion of income earned between Canadian and foreign jurisdictions.

Net income attributable to non-controlling interests decreased by $182 million for the three months ended December 31, 2015 compared to the same period in 2014 due to an impairment charge recorded by TC PipeLines, LP related to their equity investment goodwill in Great Lakes. At December 31, 2015, TC PipeLines, LP recorded an impairment of US$199 million. On consolidation, we recorded the non-controlling interest's 72 per cent of this TC PipeLines, LP impairment charge which was US$143 million or $199 million (in Canadian dollars). The TC PipeLines, LP impairment charge is not recognized at the TransCanada consolidation level as a result of our lower carrying value of Great Lakes. This $199 million positive impact to net income attributable to non-controlling interests is excluded from comparable net income attributable to non-controlling interests.

Comparable net income attributable to non-controlling interests increased by $17 million for the three months ended December 31, 2015 compared to the same period in 2014 primarily due to higher earnings resulting from the sale of our remaining 30 per cent direct interests in GTN in April 2015 to TC PipeLines, LP along with the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.

Preferred share dividends were $23 million for the three months and $94 million for the year ended December 31, 2015 (2014 - $25 million and $97 million, respectively).

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