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TransCanada Reports First Quarter 2017 Financial Results; Strong Results Build Upon Transformational 2016 – Part 5


DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by US$11 million for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to the commencement of depreciation on Topolobampo and Mazatlan.

Liquids Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.

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three months ended March 31 ------------------------------ (unaudited - millions of $) 2017 2016 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Keystone Pipeline System 306 302 Business development and other 6 (6) ---------------------------------------------------------------------------- Comparable EBITDA 312 296 Depreciation and amortization (77) (72) ---------------------------------------------------------------------------- Comparable EBIT 235 224 Specific items: Keystone XL asset costs (8) (10) Risk management activities - (2) ---------------------------------------------------------------------------- Segmented earnings 227 212 ----------------------------------------------------------------------------
Comparable EBIT denominated as follows: Canadian dollars 55 53 U.S. dollars 135 127 Foreign exchange impact 45 44 ---------------------------------------------------------------------------- 235 224 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

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Liquids Pipelines segmented earnings increased by $15 million for the three months ended March 31, 2017 compared to the same period in 2016 and included pre-tax charges related to Keystone XL costs for the maintenance of project assets which are being expensed pending further advancement of the project as well as unrealized losses from changes in the fair value of derivatives related to our liquids marketing business in 2016.

Keystone Pipeline System earnings are generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings.

Comparable EBITDA for Liquids Pipelines increased by $16 million for the three months ended March 31, 2017 compared to the same period in 2016 and was the net effect of:

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-- higher volumes on Keystone pipeline
-- higher contribution from liquids marketing
-- higher business development activities, including advancement of

Keystone XL.

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DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $5 million for the three months ended March 31, 2017 compared to the same period in 2016 as a result of new facilities being placed in service.

Energy

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 results have been adjusted to reflect this change.

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three months ended March 31 ------------------------------ (unaudited - millions of $) 2017 2016 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Canadian Power Western Power(1) 30 4 Eastern Power 94 102 Bruce Power 91 114 ---------------------------------------------------------------------------- Canadian Power - comparable EBITDA(1,2) 215 220 Depreciation and amortization (37) (47) ---------------------------------------------------------------------------- Canadian Power-comparable EBIT(1,2) 178 173 ---------------------------------------------------------------------------- U.S. Power (US$) U.S. Power - comparable EBITDA 54 75 Depreciation and amortization(3) - (31) ---------------------------------------------------------------------------- U.S. Power - comparable EBIT 54 44 Foreign exchange impact 18 17 ---------------------------------------------------------------------------- U.S. Power-comparable EBIT (Cdn$) 72 61 ---------------------------------------------------------------------------- Natural Gas Storage and other - comparable EBITDA 21 9 Depreciation and amortization (3) (3) ---------------------------------------------------------------------------- Natural Gas Storage and other - comparable EBIT 18 6 ---------------------------------------------------------------------------- Business Development comparable EBITDA and EBIT (3) (3) ---------------------------------------------------------------------------- Energy-comparable EBIT(1,2) 265 237 Specific items: U.S. Northeast power monetization (11) - Alberta PPA terminations - (240) Risk management activities (56) (123) ---------------------------------------------------------------------------- Segmented earnings/(losses)(1,2) 198 (126) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Included losses from the Alberta PPAs up to March 7, 2016 when the PPAs were terminated. (2) Includes our share of equity income from our investments in Portlands Energy and Bruce Power. (3) Depreciation no longer being recorded effective November 1, 2016 on assets held for sale.

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Energy segmented earnings increased by $324 million for the three months ended March 31, 2017 compared to the same period in 2016 and included the following specific items:

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-- in 2017, $11 million of pre-tax costs related to the monetization of our

U.S. Northeast power business. See Recent developments section for more details -- in 2016, a $240 million pre-tax charge, which included a $29 million impairment of our equity investment in ASTC Power Partnership, on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs -- unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks as follows:
------------------------------------------------------------------ ------------------------------------------------------------------ three months ended Risk management activities March 31 -------------------- (unaudited - millions of $, pre-tax) 2017 2016 ------------------------------------------------------------------ ------------------------------------------------------------------ Canadian Power 1 (13) U.S. Power (62) (115) Natural Gas Storage 5 5 ------------------------------------------------------------------ Total unrealized losses from risk management activities (56) (123) ------------------------------------------------------------------ ------------------------------------------------------------------

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The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impacts of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.

The remainder of the Energy segmented earnings are equivalent to comparable EBIT and are discussed in the following sections.

CANADIAN POWER

Western and Eastern Power

The following are the components of comparable EBITDA and comparable EBIT.

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three months ended March 31 ------------------------------ (unaudited - millions of $) 2017 2016 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Revenue(1) Western Power 46 88 Eastern Power 105 95 Other(2) 15 29 ---------------------------------------------------------------------------- 166 212 Income from equity investments(3) 8 - Commodity purchases resold (1) (59) Plant operating costs and other (49) (47) ---------------------------------------------------------------------------- Comparable EBITDA(4) 124 106 Depreciation and amortization (37) (47) ---------------------------------------------------------------------------- Comparable EBIT(4) 87 59 ---------------------------------------------------------------------------- Breakdown of comparable EBITDA Western Power(4) 30 4 Eastern Power 94 102 ---------------------------------------------------------------------------- Comparable EBITDA(4) 124 106 ----------------------------------------------------------------------------
---------------------------------------------------------------------------- Plant availability(5) Western Power 99% 99% Eastern Power(6,7) 99% 86% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes the realized gains and losses from financial derivatives used to manage Canadian Power's assets which are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives have been excluded to arrive at comparable EBITDA. (2) Includes revenues from the sale of unused natural gas transportation and sale of excess natural gas purchased for generation. (3) Includes our share of equity income in Portlands Energy, and ASTC Power Partnership up to March 7, 2016. (4) Included Alberta PPAs up to March 7, 2016 when the PPAs were terminated. (5) The percentage of time the plant was available to generate power, regardless of whether it was running. (6) Does not include Becancour because power generation has been suspended since 2008. (7) Plant availability was higher in the three months ended March 31, 2017 than the same period in 2016 due to an unplanned outage at the Halton Hills facility in 2016.

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Western Power

Comparable EBITDA for Western Power increased by $26 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to the termination of the Alberta PPAs. Results from the Alberta PPAs are included up to March 7, 2016 when we terminated the PPAs for the Sundance A, Sundance B and Sheerness facilities.

Depreciation and amortization decreased by $10 million for the three months ended March 31, 2017 compared to the same period in 2016 following the termination of the Alberta PPAs.

Eastern Power

Comparable EBITDA for Eastern Power decreased by $8 million for the three months ended March 31, 2017 compared to the same period in 2016 mainly due to lower earnings on the sale of unused natural gas transportation.

Bruce Power

Bruce Power results reflect our proportionate share. The following is our proportionate share of the components of comparable EBITDA and comparable EBIT.

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three months ended March 31 ----------------------------- (unaudited - millions of $, unless noted otherwise) 2017 2016 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Equity income included in comparable EBITDA and EBIT comprised of: Revenues 401 415 Operating expenses (224) (225) Depreciation and other (86) (76) ---------------------------------------------------------------------------- Comparable EBITDA and EBIT(1) 91 114 ---------------------------------------------------------------------------- Bruce Power - other information Plant availability(2) 89% 88% Planned outage days 56 76 Unplanned outage days 17 8 Sales volumes (GWh)(1) 5,983 5,834 Realized sales price per MWh(3) $67 $66 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Represents our 48.4 per cent (2016 - 48.5 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation. (2) The percentage of time the plant was available to generate power, regardless of whether it was running. (3) Calculation based on actual and deemed generation. Realized sales prices per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues.

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