TransCanada Reports Strong Second Quarter 2018 Financial Results

CALGARY, Alberta, Aug. 02, 2018 (GLOBE NEWSWIRE) — TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced net income attributable to common shares for second quarter 2018 of 5 million or {$content}.88 per share compared to net income of 1 million or .01 per share for the same period in 2017. Comparable earnings for second quarter 2018 were 8 million or {$content}.86 per share compared to 9 million or {$content}.76 per share for the same period in 2017. TransCanada’s Board of Directors also declared a quarterly dividend of {$content}.69 per common share for the quarter ending September 30, 2018, equivalent to .76 per common share on an annualized basis.

“During the second quarter of 2018 our diversified portfolio of critical energy infrastructure assets continued to perform very well,” said Russ Girling, TransCanada’s president and chief executive officer. “Comparable earnings of 86 cents per share increased 13 per cent compared to the same period last year reflecting the strong performance of our legacy assets, contributions from approximately billion of growth projects that entered service over the last twelve months and the positive impact of U.S. Tax Reform. For the six months ended June 30, 2018, comparable earnings were .83 per share, an increase of 17 per cent over the same period last year despite the sale of our U.S. Northeast power generation and Ontario solar assets in 2017.”

“With our existing asset portfolio benefiting from strong underlying market fundamentals and billion of near-term growth projects including maintenance capital expenditures advancing as planned, earnings and cash flow are forecast to continue to rise. This is expected to support annual dividend growth at the upper end of an eight to ten per cent range through 2020 and an additional eight to ten per cent in 2021,” added Girling. “We have invested approximately billion in these projects to date and are well positioned to fund the remainder through our strong and growing internally generated cash flow along with a broad spectrum of financing levers including access to capital markets and further portfolio management activities. In second quarter we placed approximately .3 billion of long-term debt on compelling terms and year-to-date have raised approximately .2 billion of common equity through our dividend reinvestment plan and at-the-market program. Earlier today we also announced the sale of our interests in the Cartier Wind power facilities for approximately 0 million. Collectively through these initiatives, we have raised .1 billion which represents a sizable component of our 2018 funding requirements.”

“In addition, we continue to methodically advance more than billion of medium to longer-term projects including Keystone XL, Coastal GasLink and the Bruce Power life extension agreement. Success in advancing these and/or other growth initiatives associated with our vast North American footprint could extend our growth outlook beyond 2021,” concluded Girling.

Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)

  • Second quarter 2018 financial results
    • Net income attributable to common shares of 5 million or {$content}.88 per common share
    • Comparable earnings of 8 million or {$content}.86 per common share
    • Comparable earnings before interest, taxes, depreciation and amortization of .0 billion
    • Net cash provided by operations of .8 billion
    • Comparable funds generated from operations of .5 billion
    • Comparable distributable cash flow of .3 billion or .46 per common share reflecting only non-recoverable maintenance capital expenditures
  • Declared a quarterly dividend of {$content}.69 per common share for the quarter ending September 30, 2018
  • Received National Energy Board (NEB) approval for the NGTL System’s 2018-2019 Settlement with customers
  • Received approval from the Federal government for the .6 billion North Montney project
  • Raised US.5 billion in 10, 20 and 30-year fixed-rate senior debt in May 2018
  • Issued billion of 10 and 30-year fixed-rate medium-term notes in July 2018
  • Replenished the capacity available under the Corporate ATM program by billion
  • Announced the sale of our interests in Cartier Wind for approximately 0 million in August 2018.

Net income attributable to common shares decreased by million to 5 million or {$content}.88 per share for the three months ended June 30, 2018 compared to the same period last year. Net income per common share in 2018 reflects the dilutive effect of common shares issued in 2017 and 2018 under our DRP and Corporate ATM program. Second quarter 2018 results included an million after-tax loss related to our U.S. Northeast power marketing contracts which were excluded from comparable earnings as we do not consider their wind-down part of our underlying operations. Second quarter 2017 results included a 5 million after-tax net gain related to the monetization of our U.S. Northeast power business, an after-tax charge of million for integration-related costs associated with the acquisition of Columbia and an after-tax charge of million related to the maintenance of Keystone XL assets. All of these specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings.

Comparable earnings for second quarter 2018 were 8 million or {$content}.86 per common share compared to 9 million or {$content}.76 per common share for the same period in 2017, an increase of 9 million or {$content}.10 per share. Comparable earnings per share for the three months ended June 30, 2018 include the effect of common shares issued in 2017 and 2018 under our DRP and Corporate ATM program. The increase in second quarter 2018 comparable earnings over the same period in 2017 was primarily due to the net effect of:

  • higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and the amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform
  • higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities
  • lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform
  • higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities, and lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017
  • lower earnings from U.S. Power mainly due to the sale of the U.S. Northeast power generation assets in second quarter 2017
  • lower earnings from Bruce Power primarily due to lower volumes resulting from increased outage days
  • lower Eastern Power results mainly due to the sale of our Ontario solar assets in December 2017.

Notable recent developments include:

Canadian Natural Gas Pipelines:

  • NGTL System: On June 19, 2018, the NEB approved the 2018-2019 Settlement, as filed, for final 2018 tolls and revised interim 2018 tolls. The 2018-2019 Settlement fixes return on equity (ROE) at 10.1 per cent on 40 per cent deemed equity and increases the composite depreciation rate from 3.18 per cent to 3.45 per cent. OM&A costs are fixed at 5 million for 2018 and 0 million for 2019 with a 50/50 sharing mechanism for any variances between the fixed amounts and actual OM&A costs. All other costs are treated as flow-through expenses.

    On June 20, 2018, we filed an application with the NEB for approval to construct and operate the 2021 Expansion Project. The project, with an estimated capital cost of .3 billion, consists of approximately 344 km (214 miles) of new pipeline, three compressors and a control valve. The expansion is required to accept increasing supply from the west side of the system and deliver gas to increasing market demand on the east side of the system. The anticipated in-service date for the expansion is the first half of 2021.

  • North Montney: On May 23, 2018, the NEB issued a report recommending the Federal government approve a variance to the existing North Montney project approvals to remove the condition requiring a positive Final Investment Decision (FID) for the Pacific Northwest LNG project prior to commencement of construction.  The Federal government approved the recommendation on June 22, 2018 and on July 2, 2018 the NEB issued an amending order for the project.

    The North Montney project consists of approximately 206 km (128 miles) of new pipeline, three compressor units and 14 meter stations. The current estimated project cost increased by {$content}.2 billion to .6 billion mainly due to construction schedule delays and an increase in market-dependent construction costs.

    The first phase of the project is anticipated to be in service by fourth quarter 2019 and the second phase is expected to be in service by second quarter 2020.

U.S. Natural Gas Pipelines:

  • Nixon Ridge: On June 7, 2018, a natural gas pipeline rupture on Columbia Gas occurred on Nixon Ridge in Marshall County, West Virginia. Emergency response procedures were enacted and the segment of impacted pipeline was isolated shortly after. There were no injuries and no material damage to surrounding structures. The pipeline was placed back in service on July 15, 2018. The preliminary investigation, as noted in the PHMSA Proposed Safety Order, suggests that the rupture was a result of land subsidence. The investigation remains ongoing and we are fully cooperating with PHMSA to determine the root cause of the incident. We do not expect this event to have a significant impact on our financial results.

Mexico Natural Gas Pipelines:

  • Topolobampo: On June 29, 2018, the Topolobampo pipeline was placed in service. The 560 km (348 miles) pipeline provides capacity of 720 TJ/d (670 MMcf/d), receiving natural gas from upstream pipelines near El Encino, in the state of Chihuahua, and delivering it to points along the pipeline route including our Mazatlán pipeline at El Oro, in the state of Sinaloa. Under the force majeure terms of the TSA, we began collecting and recognizing revenue from the original TSA service commencement date of July 2016.

  • Sur de Texas: Offshore construction was completed in May 2018 and the project continues to progress toward an anticipated in-service date of late 2018.
  • Tula and Villa de Reyes: We continue to work toward finalizing amending agreements for both of these pipelines with the Comisión Federal de Electricidad (CFE) to formalize the schedule and payments resulting from their respective force majeure events. The CFE has commenced payments on both pipelines in accordance with the TSAs.

Liquids Pipelines:

  • Keystone XL: In December 2017, an appeal to Nebraska’s Court of Appeals was filed by intervenors after the Nebraska Public Service Commission (PSC) issued an approval of an alternative route for the Keystone XL project in November 2017. In March 2018, the Nebraska Supreme Court, on its own motion, agreed to bypass the Court of Appeals and hear the appeal case against the PSC’s alternative route itself. We expect the Nebraska Supreme Court, as the final arbiter, could reach a decision by late 2018 or first quarter 2019.

    On May 15, 2018, the U.S. Department of State filed a notice of its intent to prepare an environmental assessment for the Keystone XL mainline alternative route in Nebraska. Public comments were due in June 2018. On July 30, 2018, the U.S. Department of State issued a draft environmental assessment. Comments on the draft are to be filed by August 29, 2018. We expect the U.S. Department of State will have completed the supplemental environmental review by third or fourth quarter 2018.

    The Keystone XL Presidential Permit, issued in March 2017, has been challenged in two separate lawsuits commenced in Montana. Together with the U.S. Department of Justice, we are actively participating in these lawsuits to defend both the issuance of the permit and the exhaustive environmental assessments that support the U.S. President’s actions. Legal arguments addressing the merits of these lawsuits were heard in May 2018 and we believe the court’s decisions may be issued by year-end 2018.

    The South Dakota Public Utilities Commission permit for the Keystone XL project was issued in June 2010 and recertified in January 2016. An appeal of that recertification was denied in June 2017 and that decision was further appealed to the South Dakota Supreme Court. On June 13, 2018, the Supreme Court dismissed the appeal, finding that the lower court lacked jurisdiction to hear the case. This decision is final as there can be no further appeals from this decision by the Supreme Court.

Energy:

  • Cartier Wind: On August 1, 2018, we entered into an agreement to sell our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for gross proceeds of 0 million before closing adjustments. The sale is expected to be completed in fourth quarter 2018 subject to certain regulatory and other approvals and result in an estimated gain of 5 million (0 million after tax) which will be recorded upon closing of the transaction.

Corporate:

  • Common Share Dividend: Our Board of Directors declared a quarterly dividend of {$content}.69 per share for the quarter ending September 30, 2018 on TransCanada’s outstanding common shares. The quarterly amount is equivalent to .76 per common share on an annualized basis.

  • Issuance of Long-term Debt:  In second quarter 2018, TCPL issued US billion of Senior Unsecured Notes due in May 2028 bearing interest at a fixed rate of 4.25 per cent, US0 million of Senior Unsecured Notes due in May 2038 bearing interest at a fixed rate of 4.75 per cent and US billion of Senior Unsecured Notes due in May 2048 bearing interest at a fixed rate of 4.875 per cent.

    In July 2018, TCPL issued 0 million of Medium Term Notes due in July 2048 bearing interest at a fixed rate of 4.182 per cent and 0 million of Medium Term Notes due in March 2028 bearing interest at a fixed rate of 3.39 per cent.

    The net proceeds of the above debt issuances were used for general corporate purposes and to fund our capital program.

  • Dividend Reinvestment Plan: In second quarter 2018, the DRP participation rate amongst common shareholders was approximately 33 per cent, resulting in 8 million reinvested in common equity under the program. Year-to-date in 2018, the participation rate amongst common shareholders has been approximately 36 per cent, resulting in 2 million of dividends reinvested.

  • ATM Equity Issuance Program: In second quarter 2018, 8.1 million common shares were issued under our Corporate ATM program at an average price of .63 per common share for gross proceeds of 3 million. In the six months ended June 30, 2018, 13.9 million common shares have been issued under the program at an average price of .42 per common share for gross proceeds of 2 million.

    In June 2018, we announced that the Company replenished the capacity available under our existing Corporate ATM program. This will allow us to issue additional common shares from treasury having an aggregate gross sales price of up to .0 billion, for a revised total of .0 billion or its U.S. dollar equivalent (Amended Corporate ATM program), to the public from time to time at the prevailing market price when sold through the TSX, the NYSE or on any other existing trading market for the common shares in Canada or the United States. The Amended Corporate ATM program, which is effective to July 23, 2019, will be activated at our discretion if and as required based on the spend profile of our capital program and relative cost of other funding options.

  • Comparable Distributable Cash Flow: Beginning in second quarter 2018, our determination of comparable distributable cash flow has been revised to exclude the deduction of maintenance capital expenditures for assets for which we have the ability to recover costs in pipeline tolls. We believe that including only non-recoverable maintenance capital expenditures in the calculation of distributable cash flow presents the best depiction of the cash available for reinvestment or distribution to shareholders. For our rate-regulated Canadian and U.S. natural gas pipelines, we have the opportunity to recover and earn a return on maintenance capital expenditures through current and future tolls. Tolling arrangements in our liquids pipelines provide for the recovery of maintenance capital expenditures. Therefore, we have not deducted the recoverable maintenance capital expenditures for these businesses in the calculation of comparable distributable cash flow.

  • 2018 FERC Actions: In December 2016, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) seeking comment on how to address the issue of whether its existing policies resulted in a ‘double recovery’ of income taxes in a pass-through entity such as a master limited partnership (MLP). This NOI was in response to a decision by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in United Airlines, Inc., et al. v. FERC (the United case), directing FERC to address the issue.

    On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act (U.S. Tax Reform), was signed resulting in significant changes to U.S. tax law including a decrease in the U.S. federal corporate income tax rate from 35 per cent to 21 per cent effective January 1, 2018. As a result of this change, deferred income tax assets and deferred income tax liabilities related to our U.S. businesses, including amounts related to our proportionate share of assets held in TC PipeLines, LP, were remeasured as at December 31, 2017 to reflect the new lower U.S. federal corporate income tax rate. With respect to our U.S. rate-regulated natural gas pipelines, the impact of this remeasurement was recorded as a net regulatory liability.

    On March 15, 2018, FERC issued (1) a Revised Policy Statement to address the treatment of income taxes for rate-making purposes for MLPs; (2) a Notice of Proposed Rulemaking (NOPR) proposing interstate pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the Revised Policy Statement on each pipeline’s ROE assuming a single-issue adjustment to a pipeline’s rates; and (3) a NOI seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation. On July 18, 2018, FERC issued (1) an Order on Rehearing of the Revised Policy Statement dismissing rehearing requests and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR (collectively, the “2018 FERC Actions”). The Final Rule will become effective September 13, 2018, and is subject to requests for further rehearing and clarification.

    For more information on these developments and their implications for TransCanada and TC PipeLines, LP, please refer to our management’s discussion and analysis.

Teleconference and Webcast:

We will hold a teleconference and webcast on Thursday, August 2, 2018 to discuss our second quarter 2018 financial results. Russ Girling, President and Chief Executive Officer, and Don Marchand, Executive Vice-President and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 9 a.m. (MT) / 11 a.m. (ET).

Members of the investment community and other interested parties are invited to participate by calling 800.377.0758 or 416.340.2218 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com or via the following URL: www.gowebcasting.com/9341

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on August 9, 2018. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 1845117#.

The unaudited interim Condensed consolidated financial statements and Management’s Discussion and Analysis (MD&A) are available under TransCanada’s profile on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com.

With more than 65 years’ experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates one of the largest natural gas transmission networks that extends more than 91,900 kilometres (57,100 miles), tapping into virtually all major gas supply basins in North America. TransCanada is a leading provider of gas storage and related services with 653 billion cubic feet of storage capacity. A large independent power producer, TransCanada owns or has interests in approximately 6,100 megawatts of power generation in Canada and the United States. TransCanada is also the developer and operator of one of North America’s leading liquids pipeline systems that extends approximately 4,900 kilometres (3,000 miles), connecting growing continental oil supplies to key markets and refineries. TransCanada’s common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit www.transcanada.com to learn more, or connect with us on social media.

Forward Looking Information
This release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as “anticipate”, “expect”, “believe”, “may”, “will”, “should”, “estimate”, “intend” or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management’s assessment of TransCanada’s and its subsidiaries’ future plans and financial outlook. All forward-looking statements reflect TransCanada’s beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to the Quarterly Report to Shareholders dated August 1, 2018 and the 2017 Annual Report filed under TransCanada’s profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov.

Non-GAAP Measures
This news release contains references to non-GAAP measures, including comparable earnings, comparable earnings per common share, comparable EBITDA, comparable distributable cash flow, comparable distributable cash flow per common share and comparable funds generated from operations, 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 except as otherwise described in the Condensed consolidated financial statements and MD&A. For more information on non-GAAP measures, refer to TransCanada’s Quarterly Report to Shareholders dated August 1, 2018.

Media Enquiries:
Grady Semmens
403.920.7859 or 800.608.7859

Investor & Analyst Enquiries:   
David Moneta / Duane Alexander
403.920.7911 or 800.361.6522

Quarterly report to shareholders

Second quarter 2018

Financial highlights

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Income                
Revenues     3,195       3,230       6,619       6,637  
Net income attributable to common shares     785       881       1,519       1,524  
per common share – basic   $0.88     .01     $1.70     .76  
                                   – diluted   $0.88     .01     $1.70     .75  
Comparable EBITDA1     1,991       1,830       4,054       3,807  
Comparable earnings1     768       659       1,632       1,357  
per common share1   $0.86     {$content}.76     $1.83     .56  
                 
Cash flows                
Net cash provided by operations     1,805       1,353       3,217       2,655  
Comparable funds generated from operations1     1,459       1,367       3,070       2,875  
Comparable distributable cash flow1     1,306       1,181       2,745       2,521  
per common share1   $1.46     .36     $3.08     .90  
Capital spending2     2,597       2,321       4,693       4,115  
                 
Dividends declared                
Per common share   $0.69     {$content}.625     $1.38     .25  
Basic common shares outstanding (millions)                
– weighted average for the period     896       870       892       868  
– issued and outstanding at end of period     904       871       904       871  

1 Comparable EBITDA, comparable earnings, comparable earnings per common share, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share are all non-GAAP measures. See the Non-GAAP measures section for more information.
2 Includes capital expenditures, capital projects in development and contributions to equity investments.

Management’s discussion and analysis

August 1, 2018

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 six months ended June 30, 2018, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2018, which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2017 audited consolidated financial statements and notes and the MD&A in our 2017 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in our 2017 Annual Report. Certain comparative figures have been adjusted to reflect the current period’s presentation.

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. These statements generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this MD&A include information about the following, among other things:

  • planned changes in our business
  • our financial and operational performance, including the performance of our subsidiaries
  • expectations or projections about strategies and goals for growth and expansion
  • expected cash flows and future financing options available to us
  • expected dividend growth
  • expected costs for planned projects, including projects under construction, permitting and in development
  • expected schedules for planned projects (including anticipated construction and completion dates)
  • expected regulatory processes and outcomes, including the expected impact of the 2018 FERC Actions
  • expected outcomes with respect to legal proceedings, including arbitration and insurance claims
  • expected capital expenditures and contractual obligations
  • expected operating and financial results
  • expected impact of future accounting changes, commitments and contingent liabilities
  • expected impact of U.S. Tax Reform
  • expected industry, market and economic conditions.

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 is subject to the following risks and uncertainties:

Assumptions

  • continued wind-down of our U.S. Northeast power marketing business
  • inflation rates and commodity prices
  • nature and scope of hedging activities
  • regulatory decisions and outcomes, including those related to the 2018 FERC Actions
  • interest, tax and foreign exchange rates, including the impact of U.S. Tax Reform
  • planned and unplanned outages and the use of our pipeline and energy assets
  • integrity and reliability of our assets
  • access to capital markets
  • anticipated construction costs, schedules and completion dates.

Risks and uncertainties

  • our ability to successfully implement our strategic priorities and whether they will yield the expected benefits
  • the operating performance of our pipeline and energy assets
  • amount of capacity sold and rates achieved in our pipeline businesses
  • the availability and price of energy commodities
  • the amount of capacity payments and revenues from our energy business
  • regulatory decisions and outcomes, including those related to the 2018 FERC Actions
  • outcomes of legal proceedings, including arbitration and insurance claims
  • performance and credit risk of our counterparties
  • changes in market commodity prices
  • changes in the regulatory environment
  • changes in the political environment
  • changes in environmental and other laws and regulations
  • competitive factors in the pipeline and energy sectors
  • construction and completion of capital projects
  • costs for labour, equipment and materials
  • access to capital markets, including the economic benefit of asset drop downs to TC PipeLines, LP
  • interest, tax and foreign exchange rates, including the impact of U.S. Tax Reform
  • weather
  • cyber security
  • technological developments
  • economic conditions in North America as well as globally.

You can read more about these factors and others in this MD&A and in other disclosure documents we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2017 Annual Report.

As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.

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
This MD&A references the following non-GAAP measures:

  • comparable earnings
  • comparable earnings per common share
  • comparable EBITDA
  • comparable EBIT
  • funds generated from operations
  • comparable funds generated from operations
  • comparable distributable cash flow
  • comparable distributable cash flow per common share.

These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be similar to measures presented by other entities.

Comparable measures
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, 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:

  • certain fair value adjustments relating to risk management activities
  • income tax refunds and adjustments and changes to enacted tax rates
  • gains or losses on sales of assets or assets held for sale
  • legal, contractual and bankruptcy settlements
  • impact of regulatory or arbitration decisions relating to prior year earnings
  • restructuring costs
  • impairment of property, plant and equipment, goodwill, investments and other assets including certain ongoing maintenance and liquidation costs
  • acquisition and integration costs.

We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.

The following table identifies our non-GAAP measures against their equivalent GAAP measures.

Comparable measure   Original measure
     
comparable earnings   net income attributable to common shares
comparable earnings per common share   net income per common share
comparable EBITDA   segmented earnings
comparable EBIT   segmented earnings
comparable funds generated from operations   net cash provided by operations
comparable distributable cash flow   net cash provided by operations

Comparable earnings and comparable earnings per common share
Comparable earnings represents earnings or loss attributable to common shareholders on a consolidated basis, adjusted for specific items. Comparable earnings is comprised of segmented earnings, interest expense, AFUDC, interest income and other, income taxes and non-controlling interests, adjusted for specific items. See the Consolidated results section for reconciliations to net income attributable to common shares and net income per common share.

Comparable EBIT and comparable EBITDA
Comparable EBIT represents segmented earnings, adjusted for specific items. We use comparable EBIT as a measure of our earnings from ongoing operations as it is a useful measure of our performance and an effective tool for evaluating trends in each segment. Comparable EBITDA is calculated the same way as comparable EBIT but excludes the non-cash charges for depreciation and amortization. See the Reconciliation of non-GAAP measures section for a reconciliation to segmented earnings.

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

Comparable distributable cash flow and comparable distributable cash flow per common share
We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. Comparable distributable cash flow is defined as comparable funds generated from operations less preferred share dividends, distributions to non-controlling interests and non-recoverable maintenance capital expenditures.

Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability, and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. We have the opportunity to recover effectively all of our pipeline maintenance capital expenditures in Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines through tolls. Canadian natural gas pipelines maintenance capital expenditures are reflected in rate bases, on which we earn a regulated return and subsequently recover in tolls. Our U.S. natural gas pipelines can recover maintenance capital expenditures through tolls under current rate settlements, or have the ability to recover such expenditures through tolls established in future rate cases or settlements. Tolling arrangements in our liquids pipelines provide for the recovery of maintenance capital expenditures. As such, beginning in second quarter 2018, our presentation of comparable distributable cash flow and comparable distributable cash flow per common share only includes a reduction for non-recoverable maintenance capital expenditures in their respective calculations. Comparative figures have been adjusted to reflect this presentation.

See the Financial condition section for a reconciliation to net cash provided by operations.

Consolidated results – second quarter 2018

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Canadian Natural Gas Pipelines     280       305       533       587  
U.S. Natural Gas Pipelines     541       401       1,189       962  
Mexico Natural Gas Pipelines     118       120       255       238  
Liquids Pipelines     390       251       731       478  
Energy     191       645       241       843  
Corporate     72       (40 )     (9 )     (73 )
Total segmented earnings     1,592       1,682       2,940       3,035  
Interest expense     (558 )     (524 )     (1,085 )     (1,024 )
Allowance for funds used during construction     113       121       218       222  
Interest income and other     (92 )     89       (29 )     109  
Income before income taxes     1,055       1,368       2,044       2,342  
Income tax expense     (153 )     (393 )     (274 )     (593 )
Net income     902       975       1,770       1,749  
Net income attributable to non-controlling interests     (76 )     (55 )     (170 )     (145 )
Net income attributable to controlling interests     826       920       1,600       1,604  
Preferred share dividends     (41 )     (39 )     (81 )     (80 )
Net income attributable to common shares     785       881       1,519       1,524  
Net income per common share — basic   $0.88     .01     $1.70     .76  
                                                    — diluted   $0.88     .01     $1.70     .75  

Net income attributable to common shares decreased by million and million, or {$content}.13 and {$content}.06 per common share, for the three and six months ended June 30, 2018 compared to the same periods in 2017. Net income per common share in 2018 reflects the effect of common shares issued in 2017 and 2018 under our DRP and Corporate ATM program.

Net income in both periods included unrealized gains and losses from changes in risk management activities, which we exclude, along with other specific items as noted below to arrive at comparable earnings.

2018 results included:

  • an after-tax loss of million year-to-date related to our U.S. Northeast power marketing contracts which included an after-tax loss of million in second quarter and an after-tax gain of million in first quarter primarily due to income recognized on the sale of our retail contracts. These amounts have been excluded from Energy’s comparable earnings effective January 1, 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio will continue to run-off through to mid-2020.

2017 results included:

  • a 5 million after-tax net gain related to the monetization of our U.S. Northeast power business, which included a 1 million after-tax gain on the sale of TC Hydro in second quarter, an incremental loss of 6 million after tax recorded in second quarter on the sale of the thermal and wind package and million year-to-date of after-tax disposition costs
  • an after-tax charge of million in second quarter and million year-to-date for integration-related costs associated with the acquisition of Columbia
  • an after-tax charge of million in second quarter and million year-to-date related to the maintenance of Keystone XL assets which was expensed in 2017 pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized
  • a million income tax recovery in first quarter related to the realized loss on a third-party sale of Keystone XL project assets.

A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Net income attributable to common shares     785       881       1,519       1,524  
Specific items (net of tax):                
U.S. Northeast power marketing contracts     11             5        
Net gain on sales of U.S. Northeast power generation assets           (265 )           (255 )
Integration and acquisition related costs – Columbia           15             39  
Keystone XL asset costs           4             11  
Keystone XL income tax recoveries                       (7 )
Risk management activities1     (28 )     24       108       45  
Comparable earnings     768       659       1,632       1,357  
Net income per common share — basic   $0.88     .01     $1.70     .76  
Specific items (net of tax):                
U.S. Northeast power marketing contracts     0.01             0.01        
Net gain on sales of U.S. Northeast power generation assets           (0.30 )           (0.29 )
Integration and acquisition related costs – Columbia           0.02             0.04  
Keystone XL asset costs                       0.01  
Keystone XL income tax recoveries                       (0.01 )
Risk management activities     (0.03 )     0.03       0.12       0.05  
Comparable earnings per common share     $0.86     {$content}.76     $1.83     .56  

1   Risk management activities   three months ended
June 30
  six months ended
June 30
    (unaudited – millions of $)   2018     2017     2018     2017  
                     
    Canadian Power   1     3     3     4  
    U.S. Power   39     (94 )   (62 )   (156 )
    Liquids marketing   62     4     55     4  
    Natural Gas Storage   (3 )   (4 )   (6 )   1  
    Foreign exchange   (60 )   41     (139 )   56  
    Income tax attributable to risk management activities   (11 )   26     41     46  
    Total unrealized gains/(losses) from risk management activities   28     (24 )   (108 )   (45 )

Comparable earnings increased by 9 million or {$content}.10 per common share for the three months ended June 30, 2018 compared to the same period in 2017 and was primarily the net effect of:

  • higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and the amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform
  • higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities
  • lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform
  • higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities, and lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017
  • lower earnings from U.S. Power mainly due to the sale of the U.S. Northeast power generation assets in second quarter 2017
  • lower earnings from Bruce Power primarily due to lower volumes resulting from increased outage days
  • lower Eastern Power results mainly due to the sale of our Ontario solar assets in December 2017.

Comparable earnings increased by 5 million or {$content}.27 per common share for the six months ended June 30, 2018 compared to the same period in 2017 and was primarily the net effect of:

  • higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform
  • higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities
  • lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform
  • higher interest income and other primarily resulting from realized gains in 2018 compared to realized losses in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
  • lower earnings from U.S. Power mainly due to the sale of the U.S. Northeast power generation assets in second quarter 2017
  • higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities, and lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017
  • lower earnings from Bruce Power primarily due to lower volumes resulting from increased outage days
  • lower Eastern Power results mainly due to the sale of our Ontario solar assets in December 2017.

Comparable earnings per common share for the three and six months ended June 30, 2018 also reflect the effect of common shares issued in 2017 and 2018 under our DRP and our Corporate ATM program.

2018 FERC Actions

BACKGROUND
In December 2016, FERC issued a Notice of Inquiry (NOI) seeking comment on how to address the issue of whether its existing policies resulted in a ‘double recovery’ of income taxes in a pass-through entity such as a master limited partnership (MLP). This NOI was in response to a decision by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in United Airlines, Inc., et al. v. FERC (the United case), directing FERC to address the issue.

On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act (U.S. Tax Reform), was signed resulting in significant changes to U.S. tax law including a decrease in the U.S. federal corporate income tax rate from 35 per cent to 21 per cent effective January 1, 2018. As a result of this change, deferred income tax assets and deferred income tax liabilities related to our U.S. businesses, including amounts related to our proportionate share of assets held in TC PipeLines, LP, were remeasured as at December 31, 2017 to reflect the new lower U.S. federal corporate income tax rate. With respect to our U.S. rate-regulated natural gas pipelines, the impact of this remeasurement was recorded as a net regulatory liability.

On March 15, 2018, FERC issued (1) a Revised Policy Statement to address the treatment of income taxes for rate-making purposes for MLPs; (2) a Notice of Proposed Rulemaking (NOPR) proposing interstate pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the Revised Policy Statement on each pipeline’s return on equity (ROE) assuming a single-issue adjustment to a pipeline’s rates; and (3) a NOI seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation. On July 18, 2018, FERC issued (1) an Order on Rehearing of the Revised Policy Statement dismissing rehearing requests; and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR (collectively, the “2018 FERC Actions”). The Final Rule will become effective September 13, 2018, and is subject to requests for further rehearing and clarification. Each is described below.

FERC Revised Policy Statement on Treatment of Income Taxes for MLPs
The Revised Policy Statement changes FERC’s long-standing policy allowing income tax amounts to be included in rates subject to cost-of-service rate regulation for pipelines owned by an MLP. The Revised Policy Statement creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates. On July 18, 2018, FERC dismissed requests for rehearing and provided clarification of the Revised Policy Statement. In this Order on Rehearing, FERC noted that an MLP is not automatically precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance in its cost-of-service rates. Additionally, FERC provided guidance with regard to accumulated deferred income taxes for MLP pipelines and other pass-through entities. FERC found that to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing accumulated deferred income tax balance from its rate base. As a result, the Revised Policy Statement also precludes the recognition and subsequent amortization of any related regulatory assets or liabilities that might have otherwise impacted rates charged to customers as a refund or collection of excess or deficient deferred income tax assets or liabilities.

Final Rule on Tax Law Changes for Interstate Natural Gas Pipelines
The Final Rule established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantifies the isolated rate impact of U.S. Tax Reform on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by MLPs. Pipelines filing the FERC Form No. 501-G will have four options:

  • make a limited Natural Gas Act Section 4 filing to reduce its rates by the reduction in its cost-of-service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on Natural Gas Act Section 5 rate investigations if the pipeline’s FERC Form 501-G shows the pipeline’s estimated ROE as being 12 per cent or less. Under the Final Rule, and notwithstanding the Revised Policy Statement discussed above, a pipeline organized as an MLP is not required to eliminate its income tax allowance, but instead can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance along with its accumulated deferred income tax balance used for rate-making purposes. In situations where the accumulated deferred income tax balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base for rate-making purposes;  
  • commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Section 5 investigation of its rates prior to that date; 
  • file a statement explaining its rationale for why it does not believe the pipeline’s rates must change; or 
  • take no other action. FERC will consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case. 

We are evaluating this Final Rule and our next courses of action, however, we do not expect an immediate or a retroactive impact from the Final Rule or the Revised Policy Statement described above.

NOI Regarding the Effect of U.S. Tax Reform on Commission-Jurisdictional Rates
In the NOI, FERC sought comment on the effects of U.S. Tax Reform to determine additional action, if any, required by FERC related to accumulated deferred income taxes that were reserved in anticipation of being paid to or refunded by the Internal Revenue Service, but which no longer accurately reflect the future income tax liability or asset. The NOI also sought comment on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of U.S. Tax Reform on regulated rates or earnings.

As noted above, FERC’s Order on Rehearing of the Revised Policy Statement provided guidance with regard to accumulated deferred income taxes for MLP pipelines, finding that if an MLP pipeline’s income tax allowance is eliminated from its cost-of-service rates, then its existing accumulated deferred income tax balance used for rate-making purposes should also be eliminated from its rate base.

IMPACT OF 2018 FERC ACTIONS ON TRANSCANADA
Our U.S. natural gas pipelines are held through a number of different ownership structures. We do not anticipate that the earnings and cash flows from our directly-held U.S. natural gas pipelines, including ANR, Columbia Gas and Columbia Gulf, will be materially impacted by the Revised Policy Statement as they are held through wholly-owned taxable corporations and, in addition, a significant proportion of their revenues are earned under non-recourse rates. Columbia Gas is required under existing settlements to adjust certain of its recourse rates for the decrease in the U.S. federal corporate income tax rate enacted December 22, 2017, with the changes implemented January 1, 2018. As ANR, Columbia Gas, Columbia Gulf and other wholly-owned regulated assets undergo future rate proceedings, some of which may be accelerated by the Final Rule, future rates may be impacted prospectively as a result of U.S. Tax Reform, but the impact is expected to be largely mitigated by lower corporate income tax rates. Therefore, the impact on earnings and cash flows resulting from the 2018 FERC Actions on our wholly-owned U.S. natural gas pipelines is expected to be limited in comparison to pre-U.S. Tax Reform.

The Revised Policy Statement also prohibits an income tax allowance for liquids pipelines held in MLP structures. We do not expect an impact on our U.S. liquids pipelines as they are not held in MLP form.

Financing
At the time and as a result of the 2018 FERC Actions initially proposed in March 2018, further drop downs of assets into TC PipeLines, LP were considered to no longer be a viable funding lever. In addition, the TC PipeLines, LP ATM program ceased to be utilized. Pursuant to the 2018 FERC Actions issued on July 18, 2018, it is yet to be determined if and when in the future these might be restored as competitive financing options. Regardless, we believe we have the financial capacity to fund our existing capital program through predictable and growing cash flow generated from operations, access to capital markets including through our Amended Corporate ATM program and our DRP, portfolio management, cash on hand and substantial committed credit facilities.

Impact of 2018 FERC Actions on TC PipeLines, LP
We are analyzing the impact of the 2018 FERC Actions on our TC PipeLines, LP assets, particularly considering the changes noted above and alternatives now available under the Final Rule. While a number of uncertainties exist with respect to the changes, TC PipeLines, LP’s earnings, cash flows and financial position could be materially adversely impacted. Should we or TC PipeLines, LP choose to proactively address the issues contemplated by the 2018 FERC Actions, prospective changes in certain pipeline systems’ rates could occur as early as late 2018. However, the impact in 2018 is expected to be limited, while subsequent periods for TC PipeLines, LP could be more significantly affected. Mitigating this impact, approximately half of TC PipeLines, LP’s revenues, including those of equity investments, are earned under non-recourse rates which are not expected to be impacted by the 2018 FERC Actions. As our ownership in TC PipeLines, LP is approximately 25 per cent, the impact of the 2018 FERC Actions related to TC PipeLines, LP is not expected to be significant to our consolidated earnings or cash flow.

Individual pipelines owned by TC PipeLines, LP do not currently have a requirement to file for new rates until 2022, however, that timing may be accelerated by the Final Rule, except where moratoria exist. As noted above, the change in the Final Rule to allow MLPs to remove the accumulated deferred income tax liability from rate base, thus increasing rate base in general, may further mitigate the loss of the tax allowance in cost-of-service based rates.

As a result of the 2018 FERC Actions initially proposed in March 2018, and in order to retain cash in anticipation of a possible reduction of revenues, TC PipeLines, LP reduced its quarterly distribution to common unitholders by 35 per cent to US{$content}.65 per unit beginning with its first quarter 2018 distribution.

Impairment Considerations
We review plant, property and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.

Goodwill is tested for impairment on an annual basis, or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, then an impairment test is not performed.

Until the 2018 FERC Actions are implemented through individual rate proceedings or settlements and we and TC PipeLines, LP have fully evaluated our respective alternatives to minimize any negative impact, we believe that it is not more likely than not that the fair value of any of the reporting units is less than its respective carrying value. Therefore, a goodwill impairment test has not been performed in 2018 to date. We also determined there is no indication that the carrying values of plant, property and equipment and equity investments potentially impacted by the 2018 FERC Actions are not recoverable. We will continue to monitor developments and assess our goodwill for impairment as well as review our property, plant and equipment and equity investments for recoverability as new information becomes available.

At December 31, 2017, the estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. There is a risk that the 2018 FERC Actions, once finalized, could result in a goodwill impairment charge. The goodwill balance for Great Lakes is US3 million at June 30, 2018 (December 31, 2017 – US3 million). There is also a risk that the goodwill balance of US million at June 30, 2018 (December 31, 2017 – US million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions.

U.S. Tax Reform

Pursuant to the enactment of U.S. Tax Reform, we recorded net regulatory liabilities and a corresponding reduction in net deferred income tax liabilities in the amount of ,686 million at December 31, 2017 related to our U.S. natural gas pipelines subject to rate-regulated accounting (RRA). Amounts recorded to adjust income taxes remain provisional as our interpretation, assessment and presentation of the impact of U.S. Tax Reform may be further clarified with additional guidance from regulatory, tax and accounting authorities as well as through our elections of specific treatments allowed under the Final Rule described above. Should additional guidance be provided by these authorities or other sources during the one-year measurement period permitted by the SEC, we will review the provisional amounts and adjust as appropriate. Other than the amortizations discussed below and the foreign exchange impacts, no adjustments were made to these amounts during second quarter 2018. Once the final impact of the 2018 FERC Actions is determined there may be prospective adjustments to our net regulatory liabilities.

Commencing January 1, 2018, we have amortized the net regulatory liabilities using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine amortization based on their composite depreciation rate and immediately begin recording amortization. For the three and six months ended June 30, 2018, amortization of the net regulatory liabilities in the amount of million and million, respectively, was recorded and included in Revenues.

Capital Program

We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow.

Our capital program consists of approximately billion of near-term investments and approximately billion of commercially-supported medium to longer-term projects. Amounts presented exclude capitalized interest and AFUDC.

Beginning in second quarter 2018, we have included three years of maintenance capital expenditures for all of our businesses in the following table. Maintenance capital expenditures on our regulated Canadian and U.S. natural gas pipelines are added to rate base on which we have the opportunity to earn a return and recover these expenditures through current or future tolls, which is similar to our capacity capital projects on these pipelines. Tolling arrangements in Liquids Pipelines provide for the recovery of maintenance capital expenditures.

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

Near-term projects

    Expected in-service   Estimated project     Carrying value  
(unaudited – billions of $)   date   cost1     at June 30, 2018  
Canadian Natural Gas Pipelines            
Canadian Mainline   2018-2021   0.2      
NGTL System   2018   0.6     0.4  
    2019   2.6     0.5  
    2020   1.7     0.1  
    2021+   2.5      
Regulated maintenance capital expenditures   2018-2020   2.5     0.2  
U.S. Natural Gas Pipelines            
Columbia Gas            
Mountaineer XPress   2018   US 3.0     US 1.4  
WB XPress   2018   US 0.9     US 0.6  
Modernization II   2018-2020   US 1.1     US 0.3  
Buckeye XPress   2020   US 0.2      
Columbia Gulf            
Gulf XPress   2018   US 0.6     US 0.4  
Other   2018-2020   US 0.3     US 0.1  
Regulated maintenance capital expenditures   2018-2020   US 1.9     US 0.2  
Mexico Natural Gas Pipelines            
Sur de Texas   2018   US 1.3     US 1.2  
Villa de Reyes   2019   US 0.8     US 0.6  
Tula   2020   US 0.7     US 0.5  
Liquids Pipelines            
White Spruce   2019   0.2     0.1  
Recoverable maintenance capital expenditures   2018-2020   0.1      
Energy            
Napanee2   2018   1.5     1.3  
Bruce Power – life extension3   up to 2020   0.9     0.3  
Other            
Non-recoverable maintenance capital expenditures4   2018-2020   0.7     0.1  
        24.3     8.3  
Foreign exchange impact on near-term projects5       3.3     1.6  
Total near-term projects (Cdn$)       27.6     9.9  

1 Amounts reflect our proportionate share of joint venture costs where applicable and 100% of costs related to wholly-owned assets and assets held through TC PipeLines, LP.
2 Reflects increased costs required to bring facility into service in fourth quarter 2018.
3 Reflects our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of the Unit 6 major refurbishment outage which is expected to begin in 2020.
4 Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of Bruce Power cash calls and other Energy amounts.
5 Reflects U.S./Canada foreign exchange rate of 1.31 at June 30, 2018.

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 post-2020, and costs provided in the schedule below reflect the most recent costs for each project as filed with the various regulatory authorities or otherwise determined. These projects are subject to approvals that include FID and/or complex regulatory processes, however, each project has commercial support except where noted.

    Estimated project     Carrying value  
(unaudited – billions of $)   cost1     at June 30, 2018  
         
Canadian Natural Gas Pipelines        
Canadian west coast LNG-related projects        
Coastal GasLink2   4.8     0.5  
NGTL System – Merrick   1.9      
Liquids Pipelines        
Heartland and TC Terminals2,3   0.9     0.1  
Grand Rapids Phase 2   0.7      
Keystone XL4   US 8.0     US 0.3  
Keystone Hardisty Terminal2,3,4   0.3     0.1  
Energy        
Bruce Power – life extension   5.3      
    21.9     1.0  
Foreign exchange impact on medium to longer-term projects5   2.5     0.1  
Total medium to longer-term projects (Cdn$)   24.4     1.1  

1 Amounts reflect our proportionate share of joint venture costs where applicable and 100% of costs related to wholly-owned assets and assets held through TC PipeLines, LP.
2 Regulatory approvals have been obtained.
3 Additional commercial support is being pursued.
4 Carrying value reflects amount remaining after impairment charge recorded in 2015, along with additional amounts capitalized from January 1, 2018.
5 Reflects U.S./Canada foreign exchange rate of 1.31 at June 30, 2018.

Outlook

Consolidated comparable earnings
We expect consolidated comparable earnings on a per common share basis for the second half of 2018 to be similar to the results achieved in the first half of the year. Our overall comparable earnings outlook for 2018 has increased compared to what was included in the 2017 Annual Report primarily due to:

  • improved earnings from additional contract sales and lower expenses in U.S. Natural Gas Pipelines
  • higher contracted and uncontracted volumes on the Keystone Pipeline System as well as higher contributions from liquids marketing activities
  • increased revenues in Mexico Natural Gas Pipelines
  • increased benefit from and better visibility into the impacts of U.S. Tax Reform.

2018 FERC Actions are not anticipated to have a significant impact on our earnings or cash flows in 2018. Refer to the 2018 FERC Actions section for additional details.

Consolidated capital spending
We expect to spend approximately billion in 2018 on growth projects, maintenance capital expenditures and contributions to equity investments. The increase from the amount included in the 2017 Annual Report primarily reflects incremental spending required to complete construction of our near-term capital program in 2018, as well as the capitalization of costs to further advance our medium to longer-term projects.

Canadian 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).

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
NGTL System   311     236     582     466  
Canadian Mainline   204     264     397     511  
Other1   30     27     60     54  
Comparable EBITDA   545     527     1,039     1,031  
Depreciation and amortization   (265 )   (222 )   (506 )   (444 )
Comparable EBIT and segmented earnings   280     305     533     587  

1 Includes results from Foothills, Ventures LP, Great Lakes Canada, our share of equity income from our investment in TQM, general and administrative and business development costs related to our Canadian Natural Gas Pipelines.

Canadian Natural Gas Pipelines segmented earnings decreased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and are equivalent to comparable EBIT.

Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.

NET INCOME AND AVERAGE INVESTMENT BASE

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018   2017   2018   2017
                 
Net Income                
NGTL System   96   87   188   169
Canadian Mainline   44   48   81   100
Average investment base                
NGTL System           9,250   8,043
Canadian Mainline           3,829   4,131

Net income for the NGTL System increased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 mainly due to a higher average investment base as a result of continued system expansions, partially offset by lower incentive earnings. On June 19, 2018, the NEB approved NGTL’s 2018-2019 Revenue Requirement Settlement Application (the 2018-2019 Settlement). The 2018-2019 Settlement, which is effective from January 1, 2018 to December 31, 2019, includes an ROE of 10.1 per cent on 40 per cent deemed equity, a mechanism for sharing variances above and below a fixed annual OM&A amount, flow-through treatment of all other costs and an increase in depreciation rates. See the Recent developments section for additional details.

Net income for the Canadian Mainline decreased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 primarily because no incentive earnings have been recorded in 2018 pending an NEB decision on the 2018 – 2020 Tolls Review. As a result, the Canadian Mainline earnings to date reflect the last approved ROE of 10.1 per cent on 40 per cent deemed equity.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 mainly due to facilities that were placed in service for the NGTL System and an increase in the approved depreciation rates in the 2018-2019 Settlement.

U.S. 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).

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of US$, unless noted otherwise)   2018     2017     2018     2017  
                 
Columbia Gas   202     136     433     321  
ANR   118     93     259     215  
TC PipeLines, LP1,2,3   33     27     72     59  
Great Lakes4   21     13     56     40  
Midstream   29     20     59     43  
Columbia Gulf   30     21     56     39  
Other U.S. pipelines3,5   16     22     31     50  
Non-controlling interests6   97     78     215     186  
Comparable EBITDA   546     410     1,181     953  
Depreciation and amortization   (128 )   (112 )   (250 )   (224 )
Comparable EBIT   418     298     931     729  
Foreign exchange impact   123     103     258     243  
Comparable EBIT (Cdn$)   541     401     1,189     972  
Specific items:                
Integration and acquisition related costs – Columbia               (10 )
Segmented earnings (Cdn$)   541     401     1,189     962  

1 Results reflect our earnings from TC PipeLines, LP’s ownership interests in GTN, Great Lakes, Iroquois, Northern Border, Bison, PNGTS, North Baja and Tuscarora, as well as general and administrative costs related to TC PipeLines, LP.
2 TC PipeLines, LP periodically conducts ATM equity issuances which decrease our ownership in TC PipeLines, LP. For the three months ended June 30, 2018, our ownership interest in TC PipeLines, LP was 25.5 per cent compared to 26.3 per cent for the same period in 2017. Our ownership interest for the six months ended June 30, 2018 ranged from 25.7 to 25.5 per cent compared to a range of 26.5 to 26.3 per cent for the same period in 2017.
3 TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois and our remaining 11.81 per cent interest in PNGTS on June 1, 2017.
4 Results reflect our 53.55 per cent direct interest in Great Lakes. The remaining 46.45 per cent is held by TC PipeLines, LP.
5 Results reflect earnings from our direct ownership interests in Crossroads, as well as Iroquois and PNGTS until June 1, 2017, and our effective ownership in Millennium and Hardy Storage, as well as general and administrative and business development costs related to our U.S. natural gas pipelines.
6 Results reflect earnings attributable to portions of TC PipeLines, LP, PNGTS (until June 1, 2017) and CPPL (until February 17, 2017) that we do not own.

U.S. Natural Gas Pipelines segmented earnings increased by 0 million and 7 million for the three and six months ended June 30, 2018 compared to the same periods in 2017.

Segmented earnings for the six months ended June 30, 2017 included a million pre-tax charge for integration and acquisition related costs associated with the Columbia acquisition. This amount has been excluded from our calculation of comparable EBIT. As well, a weaker U.S. dollar in 2018 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same period in 2017.

Earnings from 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. Columbia and ANR results are also affected by the contracting and pricing of their storage capacity and commodity sales.

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US6 million and US8 million for the three and six months ended June 30, 2018 compared to the same periods in 2017. This was primarily the net effect of:

  • increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and improved commodity prices and throughput in Midstream
  • increased earnings due to the amortization of the net regulatory liabilities recognized in 2017 as a result of U.S. Tax Reform.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US million and US million for the three and six months ended June 30, 2018 compared to the same periods in 2017 mainly due to new projects placed in service.

Mexico 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).

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of US$, unless noted otherwise)   2018     2017     2018     2017  
                 
Topolobampo   42     40     86     80  
Tamazunchale   32     27     63     56  
Mazatlán   19     17     39     33  
Guadalajara   16     17     35     34  
Sur de Texas1   1     7     10     11  
Other           4      
Comparable EBITDA   110     108     237     214  
Depreciation and amortization   (18 )   (19 )   (37 )   (36 )
Comparable EBIT   92     89     200     178  
Foreign exchange impact   26     31     55     60  
Comparable EBIT and segmented earnings (Cdn$)   118     120     255     238  

1 Represents equity income from our 60 per cent interest.

Mexico Natural Gas Pipelines segmented earnings decreased by million and increased by million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and are equivalent to comparable EBIT. Earnings from our Mexico operations are underpinned by long-term, stable, primarily U.S. dollar-denominated revenue contracts, and are affected by the cost of providing service. A weaker U.S. dollar in 2018 had a negative impact on Canadian dollar equivalent segmented earnings from our Mexico operations compared to the same period in 2017.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US million and US million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and was primarily due to higher revenues from operations as a result of changes in timing of revenue recognition, partially offset by lower equity earnings from our investment in our Sur de Texas pipeline due to higher interest expense from an inter-affiliate loan with TransCanada. The interest expense on the inter-affiliate loan is fully offset in Interest income and other.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization remained largely consistent for the three and six months ended June 30, 2018 compared to the same periods in 2017.

Liquids Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Keystone Pipeline System   352     329     692     635  
Intra-Alberta pipelines   37         76      
Other1   24     3     76     9  
Comparable EBITDA   413     332     844     644  
Depreciation and amortization   (85 )   (80 )   (168 )   (157 )
Comparable EBIT   328     252     676     487  
Specific items:                
Keystone XL asset costs       (5 )       (13 )
Risk management activities   62     4     55     4  
Segmented earnings   390     251     731     478  
                 
Comparable EBIT denominated as follows:                
Canadian dollars   89     57     182     112  
U.S. dollars   185     146     387     281  
Foreign exchange impact   54     49     107     94  
    328     252     676     487  

1 Includes primarily liquids marketing and business development activities.

Liquids Pipelines segmented earnings increased by 9 million and 3 million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and included:

  • pre-tax charges related to the maintenance of Keystone XL assets which were expensed in 2017 pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized

  • unrealized gains in 2018 from changes in the fair value of derivatives related to our liquids marketing business.

Liquids Pipelines earnings are generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. The Keystone Pipeline System also offers uncontracted capacity to the market on a spot basis which provides opportunities to generate incremental earnings.

Comparable EBITDA for Liquids Pipelines increased by million and 0 million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and was the net effect of:

  • contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017
  • higher contracted and spot volumes on the Keystone Pipeline System
  • a higher contribution from liquids marketing activities
  • lower business development costs as a result of capitalizing Keystone XL expenditures
  • a weaker U.S. dollar which had a negative impact on the Canadian dollar equivalent earnings from our U.S. operations.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 as a result of new facilities being placed in service, partially offset by the effect of a weaker 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).

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of Canadian $, unless noted otherwise)   2018     2017     2018     2017  
                 
Canadian Power                
Western Power   34     23     71     53  
Eastern Power1   70     83     152     177  
Bruce Power1   91     132     145     223  
U.S. Power (US$)2       32         86  
Foreign exchange impact on U.S. Power       9         27  
Natural Gas Storage and other   10     11     17     32  
Business Development   (3 )   (3 )   (7 )   (6 )
Comparable EBITDA   202     287     378     592  
Depreciation and amortization   (33 )   (39 )   (65 )   (79 )
Comparable EBIT   169     248     313     513  
Specific items:                
U.S. Northeast power marketing contracts   (15 )       (7 )    
Net gain on sales of U.S. Northeast power generation assets       492         481  
Risk management activities   37     (95 )   (65 )   (151 )
Segmented earnings   191     645     241     843  

1 Includes our share of equity income from our investments in Portlands Energy and Bruce Power.
2 In second quarter 2017, we completed the sales of our U.S. Northeast power generation assets.

Energy segmented earnings decreased by 4 million and 2 million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and included the following specific items:

  • a loss of million year-to-date related to our U.S. Northeast power marketing contracts which included a loss of million in second quarter and a gain of million in first quarter primarily due to income recognized on the sale of our retail contracts. These amounts have been excluded from Energy’s comparable earnings effective January 1, 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio will continue to run-off through to mid-2020
  • a net gain of 2 million and 1 million before tax for the three and six months ended June 30, 2017, related to the monetization of our U.S. Northeast power generation assets
  • unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, as noted in the table below.
Risk management activities   three months ended
June 30
  six months ended
June 30
(unaudited – millions of $, pre-tax)   2018     2017     2018     2017  
                 
Canadian Power   1     3     3     4  
U.S. Power   39     (94 )   (62 )   (156 )
Natural Gas Storage and Other   (3 )   (4 )   (6 )   1  
Total unrealized gains/(losses) from risk management activities   37     (95 )   (65 )   (151 )

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.

Comparable EBITDA for Energy decreased by million and 4 million for the three and six months ended June 30, 2018 compared to the same periods in 2017 primarily due to the net effect of:

  • lower earnings from U.S. Power mainly due to the sale of the U.S. Northeast power generation assets in second quarter 2017
  • decreased Bruce Power earnings primarily due to lower volumes resulting from increased outage days and lower results from contracting activities. Additional financial and operating information on Bruce Power is provided below
  • lower Eastern Power results mainly due to the sale of our Ontario solar assets in December 2017
  • decreased Natural Gas Storage year-to-date results primarily due to lower realized natural gas storage price spreads
  • increased Western Power results due to higher realized margins on higher generation volumes.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 following the sale of our Ontario solar assets in December 2017.

BRUCE POWER
The following reflects our proportionate share of the components of comparable EBITDA and comparable EBIT.

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $, unless noted otherwise)     2018       2017       2018       2017  
                 
Equity income included in comparable EBITDA and EBIT comprised of:                
Revenues     385       428       756       829  
Operating expenses     (209 )     (209 )     (436 )     (433 )
Depreciation and other     (85 )     (87 )     (175 )     (173 )
Comparable EBITDA and EBIT1     91       132       145       223  
Bruce Power other information                
Plant availability2     89 %     92 %     87 %     91 %
Planned outage days     76       41       150       97  
Unplanned outage days     3       3       34       20  
Sales volumes (GWh)1     6,027       6,309       11,723       12,292  
Realized sales price per MWh3   $67         $67      

1 Represents our 48.3 per cent (2017 – 48.4 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.

Planned outage work on Unit 1 and Unit 4 was completed in the first half of 2018. Planned maintenance is expected to occur on Units 3 and 8 in the second half of 2018. The overall average plant availability percentage in 2018 is expected to be in the high 80 per cent range.

Corporate

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure).

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Comparable EBITDA and EBIT   (15 )   (12 )   (17 )   (16 )
Specific items:                
Foreign exchange gain/(loss) – inter-affiliate loan1   87     (8 )   8     (8 )
Integration and acquisition related costs – Columbia       (20 )       (49 )
Segmented earnings/(losses)   72     (40 )   (9 )   (73 )

1 Reported in Income from equity investments in our Corporate segment.

Corporate segmented earnings increased by 2 million for the three months ended June 30, 2018 compared to the same period in 2017. For the six months ended June 30, 2018, Corporate segmented loss decreased by million compared to the same period in 2017. These results included the following specific items that have been excluded from comparable EBIT:

  • foreign exchange gains and losses on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the affiliate’s project financing. There are corresponding foreign exchange losses and gains included in Interest income and other on the inter-affiliate loan receivable which fully offset these amounts
  • in 2017, pre-tax integration and acquisition costs associated with the acquisition of Columbia.

OTHER INCOME STATEMENT ITEMS

Interest expense

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Interest on long-term debt and junior subordinated notes                
Canadian dollar-denominated   (131 )   (118 )   (265 )   (226 )
U.S. dollar-denominated   (332 )   (323 )   (646 )   (640 )
Foreign exchange impact   (97 )   (111 )   (180 )   (214 )
    (560 )   (552 )   (1,091 )   (1,080 )
Other interest and amortization expense   (28 )   (28 )   (50 )   (45 )
Capitalized interest   30     56     56     101  
Interest expense   (558 )   (524 )   (1,085 )   (1,024 )

Interest expense increased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and primarily reflects the net effect of:

  • long-term debt and junior subordinated notes issuances, net of maturities
  • lower capitalized interest primarily due to the completion of construction of Grand Rapids and Northern Courier in 2017
  • final repayment of the Columbia acquisition bridge facilities in June 2017 resulting in lower interest expense and debt amortization expense
  • the positive impact of a weaker U.S. dollar in translating U.S. dollar denominated interest.

Allowance for funds used during construction

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Canadian dollar-denominated   21     55     41     105  
U.S. dollar-denominated   72     49     139     87  
Foreign exchange impact   20     17     38     30  
Allowance for funds used during construction   113     121     218     222  

AFUDC decreased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017.

The decrease in Canadian dollar-denominated AFUDC is primarily due to the October 2017 decision not to proceed with the Energy East pipeline project and completion of the NGTL 2017 Expansion Program.

The increase in U.S. dollar-denominated AFUDC is primarily due to additional investment in and higher AFUDC rates on Columbia Gas growth projects and continued investment in Mexico projects.

Interest income and other

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Interest income and other included in comparable earnings   55     40     118     45  
Specific items:                
Foreign exchange (loss)/gain – inter-affiliate loan   (87 )   8     (8 )   8  
Risk management activities   (60 )   41     (139 )   56  
Interest income and other   (92 )   89     (29 )   109  

Interest income and other decreased by 1 million and 8 million for the three and six months ended June 30, 2018 compared to the same periods in 2017 and was primarily the net effect of:

  • interest income partially offset by the foreign exchange loss related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange gain are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related amounts are excluded from comparable earnings
  • unrealized losses on risk management activities in 2018 compared to unrealized gains in 2017. These amounts have been excluded from comparable earnings
  • foreign exchange impact on the translation of foreign currency denominated working capital balances
  • realized gains in 2018 compared to realized losses in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
  • income of million related to reimbursement of Coastal GasLink project costs recorded in 2017.

Income tax expense

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Income tax expense included in comparable earnings   (146 )   (198 )   (317 )   (442 )
Specific items:                
U.S. Northeast power marketing contracts   4         2      
Integration and acquisition related costs – Columbia       5         20  
Keystone XL asset costs       1         2  
Net gain on sales of U.S. Northeast power generation assets       (227 )       (226 )
Keystone XL income tax recoveries               7  
Risk management activities   (11 )   26     41     46  
Income tax expense   (153 )   (393 )   (274 )   (593 )

Income tax expense included in comparable earnings decreased by million and 5 million for the three and six months ended June 30, 2018 compared to the same periods in 2017 mainly due to lower income tax rates as a result of U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines, partially offset by higher comparable earnings before income taxes.

Net income attributable to non-controlling interests

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Net income attributable to non-controlling interests   (76 )   (55 )   (170 )   (145 )

Net income attributable to non-controlling interests increased by million and million for the three and six months ended June 30, 2018 compared to the same periods in 2017 primarily due to higher earnings in TC PipeLines, LP. Higher net income attributable to non-controlling interests for the six months ended June 30, 2018 was partially offset by our acquisition of the remaining outstanding publicly held common units of CPPL in February 2017.

Preferred share dividends

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Preferred share dividends   (41 )   (39 )   (81 )   (80 )

Preferred share dividends remained largely consistent for the three and six months ended June 30, 2018 compared to the same periods in 2017.

Recent developments

CANADIAN NATURAL GAS PIPELINES

NGTL System
On April 2, 2018, we announced that the Northwest Mainline Loop-Boundary Lake project was placed in service. The 0 million project added approximately 230 km (143 miles) of new pipeline along with compression facilities and increased the NGTL System capacity by approximately 535 TJ/d (500 MMcf/d).

On March 20, 2018, we announced the successful completion of an open season for additional expansion capacity at the Empress / McNeill Export Delivery Point for service expected to commence in November 2021. The offering of 300 TJ/d (280 MMcf/d) was oversubscribed, with an average awarded contract term of approximately 22 years. The facilities and capital requirements for the expansion are still being finalized and are currently anticipated to increase NGTL’s capital program by approximately {$content}.1 billion, to .4 billion, excluding maintenance capital expenditures.

North Montney Project Approval
On May 23, 2018, the NEB issued a report recommending the Federal government approve the application for a variance to the existing North Montney project approvals to remove the condition requiring a positive FID for the Pacific Northwest LNG project prior to commencement of construction. The Federal government approved the recommendation on June 22, 2018 and on July 2, 2018 the NEB issued an amending order for the project.

The North Montney project consists of approximately 206 km (128 miles) of new pipeline, three compressor units and 14 meter stations. The current estimated project cost increased by {$content}.2 billion to .6 billion mainly due to construction schedule delays and an increase in market-dependent construction costs.

The NEB directed NGTL to seek approval for a revised tolling methodology for the project following a provisional period defined as one year after the receipt of the Federal government decision, or otherwise impose stand-alone tolling as a default. NGTL is working with its shippers to address this requirement and is confident an appropriate tolling mechanism can be achieved.

The first phase of the project is anticipated to be in service by fourth quarter 2019 and the second phase is anticipated to be in service by second quarter 2020.

NGTL 2018-2019 Revenue Requirement Settlement Approval
On June 19, 2018, the NEB approved the 2018-2019 Settlement, as filed, for final 2018 tolls and revised interim 2018 tolls. The 2018-2019 Settlement fixes ROE at 10.1 per cent on 40 per cent deemed equity and increases the composite depreciation rate from 3.18 per cent to 3.45 per cent. OM&A costs are fixed at 5 million for 2018 and 0 million for 2019 with a 50/50 sharing mechanism for any variances between the fixed amounts and actual OM&A costs. All other costs, including pipeline integrity expenses and emissions costs, are treated as flow-through expenses.

2021 NGTL System Expansion Project Application
On June 20, 2018, we filed an application with the NEB for approval to construct and operate the 2021 Expansion Project. The project, with an estimated capital cost of .3 billion, consists of approximately 344 km (214 miles) of new pipeline, three compressors and a control valve. The expansion is required to accept increasing supply from the west side of the system and deliver gas to increasing market demand on the east side of the system. The anticipated in-service date for the expansion is the first half of 2021.

Sundre Crossover Project
On April 9, 2018, we announced that the Sundre Crossover project was placed in service. The 0 million pipeline project increases NGTL System capacity at our Alberta / B.C. export delivery point by approximately 245 TJ/d (228 MMcf/d), enhancing connectivity to key downstream markets in the Pacific Northwest and California.

Canadian Mainline

Canadian Mainline 2018 – 2020 Toll Review
On March 16, 2018, the NEB provided its Notice of Public Hearing for our Supplemental Agreement with the Eastern LDCs filed on December 18, 2017. Our reply evidence is due September 18, 2018. The NEB will provide further details regarding an oral or written hearing process to consider the written submissions of the interested parties.

Maple Compressor Expansion Project
We continue to await an NEB decision on our application seeking project approval and are reviewing project plans to continue to meet our in-service timelines.

U.S. NATURAL GAS PIPELINES

Nixon Ridge
On June 7, 2018, a natural gas pipeline rupture on Columbia Gas occurred on Nixon Ridge in Marshall County, West Virginia. Emergency response procedures were enacted and the segment of impacted pipeline was isolated shortly after. There were no injuries involved with this incident and no material damage to surrounding structures. The pipeline was placed back in service on July 15, 2018. The preliminary investigation, as noted in the PHMSA Proposed Safety Order, suggests that the rupture was a result of land subsidence. The investigation remains ongoing and we are fully cooperating with PHMSA to determine the root cause of the incident. We do not expect this event to have a significant impact on our financial results.

TC PipeLines, LP
As a result of the 2018 FERC Actions initially proposed in March 2018, and in order to retain cash in anticipation of a possible reduction of revenues, TC PipeLines, LP reduced its quarterly distribution to common unitholders by 35 per cent to US{$content}.65 per unit beginning with its first quarter 2018 distribution. A number of uncertainties exist with respect to the changes resulting from the 2018 FERC Actions, which could materially adversely impact the earnings, cash flows and financial position of TC PipeLines, LP. Cash retained by TC PipeLines, LP is being used to fund its ongoing capital expenditures as well as the repayment of debt to prudently manage its financial metrics in anticipation of a reduction in revenues should its pipeline systems’ rates be reset in response to the 2018 FERC Actions. As our ownership interest in TC PipeLines, LP is approximately 25 per cent, the impact of the 2018 FERC Actions related to TC PipeLines, LP is not expected to be significant to our consolidated earnings or cash flows.

Cameron Access
The Cameron Access project, a Columbia Gulf project designed to transport approximately 0.9 PJ/d (0.8 Bcf/d) of gas supply to the Cameron LNG export terminal in Louisiana, was placed in service on March 13, 2018.

Mountaineer XPress and WB XPress
In first quarter 2018, estimated project costs were revised upwards to US.0 billion for Mountaineer XPress and US{$content}.9 billion for WB XPress, representing increases of US{$content}.4 billion and US{$content}.1 billion, respectively. These increases primarily reflect the impact of delays of various regulatory approvals from FERC and other agencies, increased contractor construction costs due to unusually high demand for construction resources in the region, and modifications to contractor work plans and resources to maintain our projected in-service dates.

Great Lakes and Northern Border Rate Settlements
In February 2018, FERC approved the 2017 Great Lakes Rate Settlement and the 2017 Northern Border Rate Settlement, both of which were uncontested.

MEXICO NATURAL GAS PIPELINES

Topolobampo
On June 29, 2018, the Topolobampo pipeline was placed in service. The 560 km (348 miles) pipeline provides capacity of 720 TJ/d (670 MMcf/d), receiving natural gas from upstream pipelines near El Encino, in the state of Chihuahua, and delivering it to points along the pipeline route including our Mazatlán pipeline at El Oro, in the state of Sinaloa. Under the force majeure terms of the TSA, we began collecting and recognizing revenue from the original TSA service commencement date of July 2016.

Sur de Texas
Offshore construction was completed in May 2018 and the project continues to progress toward an anticipated in-service date of late 2018.

Tula and Villa de Reyes
We continue to work toward finalizing amending agreements for both of these pipelines with the CFE to formalize the schedule and payments resulting from their respective force majeure events. The CFE has commenced payments on both pipelines in accordance with the TSAs.

LIQUIDS PIPELINES

Keystone XL
In December 2017, an appeal to Nebraska’s Court of Appeals was filed by intervenors after the Nebraska Public Service Commission (PSC) issued an approval of an alternative route for the Keystone XL project in November 2017. In March 2018, the Nebraska Supreme Court, on its own motion, agreed to bypass the Court of Appeals and hear the appeal case against the PSC’s alternative route itself. We expect the Nebraska Supreme Court, as the final arbiter, could reach a decision by late 2018 or first quarter 2019.

On May 15, 2018, the U.S. Department of State filed a notice of its intent to prepare an environmental assessment for the Keystone XL mainline alternative route in Nebraska. Public comments were due in June 2018. On July 30, 2018, the U.S. Department of State issued a draft environmental assessment. Comments on the draft are to be filed by August 29, 2018. We expect the U.S. Department of State will have completed the supplemental environmental review by third or fourth quarter 2018.

The Keystone XL Presidential Permit, issued in March 2017, has been challenged in two separate lawsuits commenced in Montana. Together with the U.S. Department of Justice, we are actively participating in these lawsuits to defend both the issuance of the permit and the exhaustive environmental assessments that support the U.S. President’s actions. Legal arguments addressing the merits of these lawsuits were heard in May 2018 and we believe the court’s decisions may be issued by year-end 2018.

The South Dakota Public Utilities Commission permit for the Keystone XL project was issued in June 2010 and recertified in January 2016. An appeal of that recertification was denied in June 2017 and that decision was further appealed to the South Dakota Supreme Court. On June 13, 2018, the Supreme Court dismissed the appeal against the recertification of the Keystone XL project finding that the lower court lacked jurisdiction to hear the case. This decision is final as there can be no further appeals from this decision by the Supreme Court.

White Spruce
In February 2018, the AER issued a permit for the construction of the White Spruce pipeline. Construction has commenced with an anticipated in-service date in second quarter 2019.

ENERGY

Cartier Wind
On August 1, 2018, we entered into an agreement to sell our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for gross proceeds of 0 million before closing adjustments. The sale is expected to be completed in fourth quarter 2018 subject to certain regulatory and other approvals and result in an estimated gain of 5 million (0 million after tax) which will be recorded upon closing of the transaction.

Monetization of U.S. Northeast power marketing business
On March 1, 2018, as part of the continued wind-down of our U.S. Northeast power marketing contracts, we closed the sale of our U.S. power retail contracts for proceeds of approximately US million and recognized income of US million (US million after tax).

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 and growing cash flow from operations, access to capital markets, including through our Corporate ATM program and our DRP, portfolio management, cash on hand and substantial committed credit facilities. In light of the 2018 FERC Actions initially proposed in March 2018, further drop downs of assets into TC PipeLines, LP were considered to no longer be a viable funding lever. In addition, the TC PipeLines, LP ATM program ceased to be utilized. Pursuant to the 2018 FERC Actions issued on July 18, 2018, it is yet to be determined if and when in the future these might be restored as competitive financing options. See the 2018 FERC Actions section for further information.

At June 30, 2018, our current assets totaled .4 billion and current liabilities amounted to .4 billion, leaving us with a working capital deficit of .0 billion compared to a working capital deficit of .2 billion at December 31, 2017. Our working capital deficit is considered to be in the normal course of business and is managed through:

  • our ability to generate cash flow from operations
  • our access to capital markets
  • approximately .3 billion of unutilized, unsecured credit facilities.

CASH PROVIDED BY OPERATING ACTIVITIES

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Net cash provided by operations     1,805       1,353       3,217       2,655  
(Decrease)/increase in operating working capital     (361 )     (17 )     (154 )     138  
Funds generated from operations1     1,444       1,336       3,063       2,793  
Specific items:                
U.S. Northeast power marketing contracts     15             7        
Integration and acquisition related costs – Columbia           20             52  
Keystone XL asset costs           5             13  
Net loss on sales of U.S. Northeast power generation assets           6             17  
Comparable funds generated from operations1     1,459       1,367       3,070       2,875  
Dividends on preferred shares     (39 )     (38 )     (78 )     (77 )
Distributions paid to non-controlling interests     (48 )     (69 )     (117 )     (149 )
Non-recoverable maintenance capital expenditures2     (66 )     (79 )     (130 )     (128 )
Comparable distributable cash flow1     1,306       1,181       2,745       2,521  
Comparable distributable cash flow per common share1   $1.46     .36     $3.08     .90  

1 See the Non-GAAP measures section of this MD&A for further discussion of funds generated from operations, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share.
2 Includes non-recoverable maintenance capital expenditures from all segments including cash contributions to fund maintenance capital expenditures for our equity investments. Expenditures are primarily related to contributions to Bruce Power to fund our proportionate share of their maintenance capital expenditures.

COMPARABLE FUNDS GENERATED FROM OPERATIONS
Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our operations by excluding the timing effects of working capital changes.

Despite the sales of our U.S. Northeast power generation assets in second quarter 2017 and the continued wind-down of our U.S. Northeast power marketing contracts, comparable funds generated from operations increased by million and 5 million for the three and six months ended June 30, 2018 compared to the same periods in 2017. These increases are primarily due to higher comparable earnings.

COMPARABLE DISTRIBUTABLE CASH FLOW
Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation.

The increase in comparable distributable cash flow for the three and six months ended June 30, 2018 compared to the same periods in 2017 reflects higher comparable funds generated from operations, as described above. Comparable distributable cash flow per common share for the three and six months ended June 30, 2018 also reflects the effect of common shares issued under the Corporate ATM program and DRP in 2017 and 2018.

Beginning in second quarter 2018, our determination of comparable distributable cash flow has been revised to exclude the deduction of maintenance capital expenditures for assets for which we have the ability to recover these costs in pipeline tolls. Comparative periods presented in the table below have been adjusted accordingly. We believe that including only non-recoverable maintenance capital expenditures in the calculation of distributable cash flow presents the best depiction of the cash available for reinvestment or distribution to shareholders. For our rate-regulated Canadian and U.S. natural gas pipelines, we have the opportunity to recover and earn a return on maintenance capital expenditures through current and future tolls. Tolling arrangements in our liquids pipelines provide for the recovery of maintenance capital expenditures. Therefore, we have not deducted the recoverable maintenance capital expenditures for these businesses in the calculation of comparable distributable cash flow.

CASH (USED IN)/PROVIDED BY INVESTING ACTIVITIES

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Capital spending                
Capital expenditures   (2,337 )   (1,792 )   (4,039 )   (3,352 )
Capital projects in development   (76 )   (56 )   (112 )   (98 )
Contributions to equity investments   (184 )   (473 )   (542 )   (665 )
    (2,597 )   (2,321 )   (4,693 )   (4,115 )
Proceeds from sales of assets, net of transaction costs       4,147         4,147  
Other distributions from equity investments       1     121     364  
Deferred amounts and other   (16 )   (169 )   94     (254 )
Net cash (used in)/provided by investing activities   (2,613 )   1,658     (4,478 )   142  

Capital expenditures in 2018 were incurred primarily for the expansion of the Columbia Gas, Columbia Gulf and NGTL System natural gas pipelines, the construction of Mexico natural gas pipelines and the Napanee power generating facility.

Costs incurred on capital projects in development in 2018 were predominantly related to spending on Keystone XL.

Contributions to equity investments decreased in 2018 compared to 2017 primarily due to lower contributions to our proportionate share of Sur de Texas debt financing and Grand Rapids, which went into service in August 2017. This was partially offset by increased contributions to our Bruce Power and Millennium investments.

Other distributions from equity investments primarily reflect our proportionate share of Bruce Power financings undertaken to fund its capital program and to make distributions to its partners. In first quarter 2018, Bruce Power issued senior notes in capital markets which resulted in distributions totaling 1 million to us.

In second quarter 2017, we closed the sale of our U.S. Northeast power generation assets for net proceeds of ,147 million.

CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Notes payable (repaid)/issued, net   (1,327 )   111     485     781  
Long-term debt issued, net of issue costs1   3,240     817     3,333     817  
Long-term debt repaid1   (808 )   (4,418 )   (2,034 )   (5,469 )
Junior subordinated notes issued, net of issue costs       1,489         3,471  
Dividends and distributions paid   (467 )   (435 )   (933 )   (854 )
Common shares issued, net of issue costs   445     18     785     36  
Partnership units of TC PipeLines, LP issued, net of issue costs       27     49     119  
Common units of Columbia Pipeline Partners LP acquired               (1,205 )
Net cash provided by/(used in) financing activities   1,083     (2,391 )   1,685     (2,304 )

1 Includes draws and repayments on unsecured loan facility by TC PipeLines, LP.

LONG-TERM DEBT ISSUED
In second quarter 2018, TCPL issued US billion of Senior Unsecured Notes due in May 2028 bearing interest at a fixed rate of 4.25 per cent, US0 million of Senior Unsecured Notes due in May 2038 bearing interest at a fixed rate of 4.75 per cent as well as an additional US billion of Senior Unsecured Notes due in May 2048 bearing interest at a fixed rate of 4.875 per cent.

In July 2018, TCPL issued 0 million of Medium Term Notes due in July 2048 bearing interest at a fixed rate of 4.182 per cent and 0 million of Medium Term Notes due in March 2028 bearing interest at a fixed rate of 3.39 per cent.

The net proceeds of the above debt issuances were used for general corporate purposes and to fund our capital program.

LONG-TERM DEBT REPAID
In second quarter 2018, long-term debt repaid included the retirement of US0 million by Columbia Pipeline Group, Inc. of Senior Unsecured Notes bearing interest at a fixed rate of 2.45 per cent.

In first quarter 2018, long-term debt repaid included retirements by TCPL of US0 million of Senior Unsecured Notes bearing interest at a fixed rate of 1.875 per cent, US0 million of Senior Unsecured Notes bearing interest at a floating rate and 0 million of Debentures bearing interest at a fixed rate of 9.45 per cent.

DIVIDEND REINVESTMENT PLAN
With respect to dividends declared on April 27, 2018, the DRP participation rate amongst common shareholders was approximately 33 per cent, resulting in 8 million reinvested in common equity under the program. Year-to-date in 2018, the participation rate amongst common shareholders has been approximately 36 per cent, resulting in 2 million of dividends reinvested.

TRANSCANADA CORPORATION ATM EQUITY ISSUANCE PROGRAM
In the three months ended June 30, 2018, 8.1 million common shares were issued under our Corporate ATM program at an average price of .63 per common share for gross proceeds of 3 million. Related commissions and fees totaled approximately million, resulting in net proceeds of 9 million. In the six months ended June 30, 2018, 13.9 million common shares have been issued under our Corporate ATM program at an average price of .42 per common share for gross proceeds of 2 million. Related commissions and fees totaled approximately million, resulting in net proceeds of 5 million.

In June 2018, we announced that the Company replenished the capacity available under our existing Corporate ATM program. This will allow us to issue additional common shares from treasury having an aggregate gross sales price of up to .0 billion, for a revised total of .0 billion or its U.S. dollar equivalent, (Amended Corporate ATM program), to the public from time to time at the prevailing market price when sold through the TSX, the NYSE or on any other existing trading market for the common shares in Canada or the United States. The Amended Corporate ATM program, which is effective to July 23, 2019, will be activated at our discretion if and as required based on the spend profile of our capital program and relative cost of other funding options.

TC PIPELINES, LP ATM EQUITY ISSUANCE PROGRAM
In the six months ended June 30, 2018, 0.7 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US million. At June 30, 2018, our ownership interest in TC PipeLines, LP was 25.5 per cent giving effect to issuances under the ATM program resulting in dilution of our ownership interest.

In light of the 2018 FERC Actions initially proposed in March 2018, the TC PipeLines, LP ATM program ceased to be utilized. As a result of uncertainties that remain after the 2018 FERC Actions were finalized in July 2018, it is yet to be determined if and when in the future the program will be reactivated.

DIVIDENDS
On August 1, 2018, we declared quarterly dividends as follows:

Quarterly dividend on our common shares
{$content}.69 per share
Payable on October 31, 2018 to shareholders of record at the close of business on September 28, 2018.

Quarterly dividends on our preferred shares
 
Series 1               {$content}.204125 
Series 2               {$content}.20069863 
Series 3               {$content}.1345 
Series 4               {$content}.16080822 
Payable on September 28, 2018 to shareholders of record at the close of business on August 31, 2018.
Series 5               {$content}.1414375 
Series 6               {$content}.17561918 
Series 7               {$content}.25 
Series 9               {$content}.265625 
Payable on October 30, 2018 to shareholders of record at the close of business on October 1, 2018.
Series 11             {$content}.2375 
Series 13             {$content}.34375 
Series 15             {$content}.30625 
Payable on August 31, 2018 to shareholders of record at the close of business on August 15, 2018.

SHARE INFORMATION

as at July 31, 2018    
     
Common shares Issued and outstanding  
  907 million  
Preferred shares Issued and outstanding Convertible to
Series 1 9.5 million Series 2 preferred shares
Series 2 12.5 million Series 1 preferred shares
Series 3 8.5 million Series 4 preferred shares
Series 4 5.5 million Series 3 preferred shares
Series 5 12.7 million Series 6 preferred shares
Series 6 1.3 million Series 5 preferred shares
Series 7 24 million Series 8 preferred shares
Series 9 18 million Series 10 preferred shares
Series 11 10 million Series 12 preferred shares
Series 13 20 million Series 14 preferred shares
Series 15 40 million Series 16 preferred shares
     
Options to buy common shares Outstanding Exercisable
  13 million 8 million

CREDIT FACILITIES
We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for general corporate purposes. In addition, we have demand credit facilities that are also used for general corporate purposes, including issuing letters of credit and providing additional liquidity.

At July 31, 2018, we had a total of .3 billion of committed revolving and demand credit facilities, including:

Amount   Unused
capacity
  Borrower   Description   Matures
                 
Committed, syndicated, revolving, extendible, senior unsecured credit facilities
.0 billion   .0 billion   TCPL   Supports TCPL’s Canadian dollar commercial paper program and for general corporate purposes   December 2022
US.0 billion   US.0 billion   TCPL   Supports TCPL’s U.S. dollar commercial paper program and for general corporate purposes   December 2018
US.0 billion   US{$content}.7 billion   TCPL USA   Used for TCPL USA general corporate purposes, guaranteed by TCPL   December 2018
US.0 billion   US{$content}.4 billion   Columbia   Used for Columbia general corporate purposes, guaranteed by TCPL   December 2018
US{$content}.5 billion   US{$content}.5 billion   TAIL   Supports TAIL’s U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL   December 2018
Demand senior unsecured revolving credit facilities
.1 billion   {$content}.9 billion   TCPL/TCPL USA   Supports the issuance of letters of credit and provides additional liquidity, TCPL USA facility guaranteed by TCPL   Demand
MXN.0
billion
  MXN.5
billion
  Mexican
subsidiary
  Used for Mexico general corporate purposes, guaranteed by TCPL   Demand

At July 31, 2018, our operated affiliates had an additional {$content}.7 billion of undrawn capacity on committed credit facilities.

See Financial risks and financial instruments for more information about liquidity, market and other risks.

CONTRACTUAL OBLIGATIONS
Our capital expenditure commitments have risen by approximately {$content}.8 billion since December 31, 2017 as a result of the net effect of increased commitments for Columbia Gas growth projects, NGTL and Keystone XL, partially offset by decreased commitments for the Sur de Texas natural gas pipeline and the Napanee power generating facility.

There were no other material changes to our contractual obligations in second quarter 2018 or to payments due in the next five years or after. See the MD&A in our 2017 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 2017 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2017, other than as described below.

On March 1, 2018, as part of the continued wind-down of our U.S. Northeast power marketing contracts, we closed the sale of our U.S. Northeast power retail contracts for proceeds of approximately US million and recognized income of US million (US million after tax). We expect to realize the value of the remaining marketing contracts and working capital over time. As a result, our exposure to commodity risk has been reduced.

LIQUIDITY RISK
We manage our liquidity risk by continuously forecasting our cash flow for a 12-month period to ensure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

COUNTERPARTY CREDIT RISK
We have exposure to counterparty credit risk in the following areas:

  • cash and cash equivalents
  • accounts receivable
  • available for sale assets
  • the fair value of derivative assets
  • loans receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At June 30, 2018, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired.

We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

LOAN RECEIVABLE FROM AFFILIATE
We hold a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. We account for the joint venture as an equity investment.

In 2017, we entered into a MXN.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. Draws on the credit facility result in a loan receivable from the joint venture representing our proportionate share of the debt financing requirements advanced to the joint venture. At June 30, 2018, the balance of our loan receivable from the joint venture totaled MXN.5 billion or .2 billion (December 31, 2017 – MXN.4 billion or 9 million) and Interest income and other included million and million of interest income on this loan receivable for the three and six months ended June 30, 2018 (2017 – million and million). Amounts recognized in Interest income and other are offset by a corresponding proportionate share of interest expense recorded in Income from equity investments in our Mexico Natural Gas Pipelines segment.

INTEREST RATE RISK
We utilize short-term and long-term debt to finance our operations which subjects us to interest rate risk. We typically pay fixed rates of interest on our long-term debt and floating rates on our commercial paper programs and amounts drawn on our credit facilities. A small portion of our long-term debt is at floating interest rates. In addition, we are exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. We mitigate our interest rate risk using a combination of interest rate swaps and option derivatives.

FOREIGN EXCHANGE
We generate revenues and incur expenses that are denominated in currencies other than Canadian dollars. As a result, our earnings and cash flows are exposed to currency fluctuations.

A portion of our businesses generate earnings in U.S. dollars, but since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. The vast majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.

Average exchange rate – U.S. to Canadian dollars
The average exchange rate for one U.S. dollar converted into Canadian dollars was as follows:

three months ended June 30, 2018 1.29  
three months ended June 30, 2017 1.34  

six months ended June 30, 2018 1.28  
six months ended June 30, 2017 1.33  

The impact of changes in the value of the U.S. dollar on our U.S. operations is partially offset by interest on U.S. dollar-denominated long-term debt, as set out in the table below. Comparable EBIT is a non-GAAP measure. See our Reconciliation of non-GAAP measures section for more information.

Significant U.S. dollar-denominated amounts

    three months ended June 30   six months ended June 30
(unaudited – millions of US $)   2018     2017     2018     2017  
                 
U.S. Natural Gas Pipelines comparable EBIT   418     298     931     729  
Mexico Natural Gas Pipelines comparable EBIT1   114     89     244     178  
U.S. Liquids Pipelines comparable EBIT   185     146     387     281  
U.S. Power comparable EBIT2       32         86  
AFUDC on U.S. dollar-denominated projects   72     49     139     87  
Interest on U.S. dollar-denominated long-term debt   (332 )   (323 )   (646 )   (640 )
Capitalized interest on U.S. dollar-denominated capital expenditures   3     1     6     1  
U.S. dollar non-controlling interests and other   (65 )   (44 )   (145 )   (114 )
    395     248     916     608  

1 Excludes interest expense on our inter-affiliate loan with Sur de Texas which is offset in Interest income and other.
2 Effective January 1, 2018, U.S. Power is no longer included in comparable EBIT.

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, foreign exchange forward contracts and foreign exchange options.

The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

    June 30, 2018   December 31, 2017
(unaudited – millions of Canadian $, unless noted otherwise)   Fair value1,2     Notional amount   Fair value1,2     Notional amount
                 
U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019)3   (80 )   US 500   (199 )   US 1,200
U.S. dollar foreign exchange options (maturing 2018 to 2019)   (16 )   US 2,000   5     US 500
    (96 )   US 2,500   (194 )   US 1,700

1 Fair values equal carrying values.
2 No amounts have been excluded from the assessment of hedge effectiveness.
3 In the three and six months ended June 30, 2018, Net income includes net realized gains of nil and million, respectively (2017 – million and million, respectively) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

(unaudited – millions of Canadian $, unless noted otherwise)   June 30, 2018   December 31, 2017
         
Notional amount   29,000 (US 22,000)   25,400 (US 20,200)
Fair value   30,800 (US 23,400)   28,900 (US 23,100)

FINANCIAL INSTRUMENTS
With the exception of Long-term debt and Junior subordinated notes, our derivative and non-derivative financial 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.

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 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.

Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of derivative instruments is as follows:

(unaudited – millions of $)   June 30, 2018     December 31, 2017  
         
Other current assets   246     332  
Intangible and other assets   63     73  
Accounts payable and other   (355 )   (387 )
Other long-term liabilities   (52 )   (72 )
    (98 )   (54 )

Unrealized and realized gains/(losses) of derivative instruments
The following summary does not include hedges of our net investment in foreign operations.

    three months ended June 30   six months ended June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Derivative instruments held for trading1                
Amount of unrealized gains/(losses) in the period                
Commodities2   99     (91 )   (10 )   (147 )
Foreign exchange   (60 )   41     (139 )   56  
Amount of realized gains/(losses) in the period                
Commodities   19     (37 )   129     (85 )
Foreign exchange   4     (5 )   19     (9 )
Derivative instruments in hedging relationships                
Amount of realized (losses)/gains in the period                
Commodities   (4 )   7     (1 )   13  
Foreign exchange               5  
Interest rate           1     1  

1 Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively.
2 In the three and six months ended June 30, 2018 and 2017, there were no gains or losses included in Net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Derivatives in cash flow hedging relationships
The components of the Condensed consolidated statement of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests is as follows:

    three months ended June 30   six months ended June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Change in fair value of derivative instruments recognized in OCI (effective portion)1                
Commodities   (3 )   (2 )   (6 )   3  
Interest rate           9     1  
    (3 )   (2 )   3     4  
Reclassification of gains/(losses) on derivative instruments from AOCI to net income1                
Commodities2   2     (7 )   1     (11 )
Interest rate3   7     5     12     9  
    9     (2 )   13     (2 )

1 Amounts presented are pre-tax. No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI.
2 Reported within Revenues on the Condensed consolidated statement of income.
3 Reported within Interest expense on the Condensed consolidated statement of income.

Credit risk related contingent features of derivative instruments
Derivatives often contain financial assurance provisions that may require us to provide collateral if a credit risk related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits.

Based on contracts in place and market prices at June 30, 2018, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was million (December 31, 2017 – million), with no collateral provided in the normal course of business at June 30, 2018 and December 31, 2017. If the credit-risk-related contingent features in these agreements were triggered on June 30, 2018, we would have been required to provide collateral of million (December 31, 2017 – 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 June 30, 2018, 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 second quarter 2018 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 amounts we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. A summary of our critical accounting estimates is included in our 2017 Annual Report.

Our significant accounting policies have remained unchanged since December 31, 2017 other than described below. A summary of our significant accounting policies is included in our 2017 Annual Report.

Changes in accounting policies for 2018

Revenue from contracts with customers
In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as our “performance obligations.” The total consideration to which we expect to be entitled can include fixed and variable amounts. We have variable revenue that is subject to factors outside of our influence, such as market prices, actions of third parties and weather conditions. We consider this variable revenue to be “constrained” as it cannot be reliably estimated, and therefore recognize variable revenue when the service is provided.

The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and related cash flows.

In the application of the new guidance, significant estimates and judgments are used to determine the following:

  • pattern of revenue recognition within a contract, based on whether the performance obligation is satisfied at a point in time versus over time
  • term of the contract
  • amount of variable consideration associated with a contract and timing of the associated revenue recognition.

The new guidance was effective January 1, 2018, was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition.

Financial instruments
In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance changes the income statement effect of equity investments and the recognition of changes in the fair value of financial liabilities when the fair value option is elected. The new guidance also requires us to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance was effective January 1, 2018 and did not have a material impact on our consolidated financial statements.

Income taxes
In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and did not have a material impact on our consolidated financial statements.

Restricted cash
In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. This new guidance was effective January 1, 2018, was applied retrospectively, and did not have an impact on our consolidated financial statements.

Employee post-retirement benefits
In March 2017, the FASB issued new guidance that requires entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance was effective January 1, 2018 and did not have a material impact on our consolidated financial statements.

Hedge accounting
In August 2017, the FASB issued new guidance making more financial and non-financial hedging strategies eligible for hedge accounting. The new guidance also amends the presentation requirements relating to the change in fair value of a derivative and requires additional disclosures including cumulative basis adjustments for fair value hedges and the effect of hedging on individual line items in the consolidated statement of income. This new guidance is effective January 1, 2019 with early adoption permitted. This new guidance, which we elected to adopt effective January 1, 2018, was applied prospectively and did not have a material impact on our consolidated financial statements.

Future accounting changes

Leases
In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessor is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statement of income. The new guidance does not make extensive changes to lessor accounting.

In January 2018, the FASB issued an optional practical expedient, to be applied upon transition, to omit the evaluation of land easements not previously accounted for as leases that existed or expired prior to the entity’s adoption of the new lease guidance. An entity that elects this practical expedient is required to apply the practical expedient consistently to all of its existing or expired land easements not previously accounted for as leases. We continue to monitor and analyze additional guidance and clarifications provided by the FASB.

The new guidance is effective January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We have developed a preliminary inventory of existing lease agreements and have substantially completed our analysis on these leases but continue to evaluate the financial impact on our consolidated financial statements. We have also selected a system solution and are in the testing stage of implementation. We continue to assess process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance and to analyze new contracts that may contain leases.

Measurement of credit losses on financial instruments
In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Goodwill impairment
In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. We are currently evaluating the timing and impact of the adoption of this guidance.

Amortization on purchased callable debt securities
In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Income taxes
In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from the U.S. Tax Reform. This new guidance is effective January 1, 2019, however, early adoption is permitted. This guidance can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change is recognized. We are currently evaluating this guidance in conjunction with our analysis of the overall impact of U.S. Tax Reform.

Reconciliation of non-GAAP measures

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of $)   2018     2017     2018     2017  
                 
Comparable EBITDA                
Canadian Natural Gas Pipelines   545     527     1,039     1,031  
U.S. Natural Gas Pipelines   704     551     1,508     1,271  
Mexico Natural Gas Pipelines   142     145     302     285  
Liquids Pipelines   413     332     844     644  
Energy   202     287     378     592  
Corporate   (15 )   (12 )   (17 )   (16 )
Comparable EBITDA   1,991     1,830     4,054     3,807  
Depreciation and amortization   (570 )   (516 )   (1,105 )   (1,026 )
Comparable EBIT   1,421     1,314     2,949     2,781  
Specific items:                
Foreign exchange gain/(loss) – inter-affiliate loan   87     (8 )   8     (8 )
U.S. Northeast power marketing contracts   (15 )       (7 )    
Net gain on sales of U.S. Northeast power generation assets       492         481  
Integration and acquisition related costs – Columbia       (20 )       (59 )
Keystone XL asset costs       (5 )       (13 )
Risk management activities1   99     (91 )   (10 )   (147 )
Segmented earnings   1,592     1,682     2,940     3,035  

1   Risk management activities   three months ended
June 30
  six months ended
June 30
    (unaudited – millions of $)   2018     2017     2018     2017  
                     
    Canadian Power   1     3     3     4  
    U.S. Power   39     (94 )   (62 )   (156 )
    Liquids marketing   62     4     55     4  
    Natural Gas Storage   (3 )   (4 )   (6 )   1  
    Total unrealized gains/(losses) from risk management activities   99     (91 )   (10 )   (147 )

Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA

  2018
  2017
   2016
(unaudited – millions of $, except
per share amounts)
  Second     First     Fourth     Third     Second       First     Fourth     Third  
                                 
Revenues   3,195     3,424     3,617     3,195     3,230       3,407     3,635     3,642  
Net income/(loss) attributable to common shares   785     734     861     612     881       643     (358 )   (135 )
Comparable earnings   768     864     719     614     659       698     626     622  
Per share statistics                                
Net income/(loss) per common share – basic and diluted   $0.88     {$content}.83     {$content}.98     {$content}.70     .01     {$content}.74     ({$content}.43 )   ({$content}.17 )
Comparable earnings per
common share
  $0.86     {$content}.98     {$content}.82     {$content}.70     {$content}.76     {$content}.81     {$content}.75     {$content}.78  
Dividends declared per common share   $0.69     {$content}.69     {$content}.625     {$content}.625     {$content}.625     {$content}.625     {$content}.565     {$content}.565  

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT
Quarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments.

In our Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines segments, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

  • regulators’ decisions
  • negotiated settlements with shippers
  • acquisitions and divestitures
  • developments outside of the normal course of operations
  • newly constructed assets being placed in service.

In Liquids Pipelines, annual revenues and net income are based on contracted and uncommitted spot transportation and liquids marketing activities. Quarter-over-quarter revenues and net income are affected by:

  • regulatory decisions
  • developments outside of the normal course of operations
  • newly constructed assets being placed in service
  • demand for uncontracted transportation services
  • liquids marketing activities
  • certain fair value adjustments.

In Energy, quarter-over-quarter revenues and net income are affected by:

  • weather
  • customer demand
  • market prices for natural gas and power
  • capacity prices and payments
  • planned and unplanned plant outages
  • acquisitions and divestitures
  • certain fair value adjustments
  • developments outside of the normal course of operations
  • newly constructed assets being placed in service.

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.

Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.

In second quarter 2018, comparable earnings also excluded:

  • an after-tax loss of million related to our U.S. Northeast power marketing contracts. These were excluded from Energy’s comparable earnings effective January 1, 2018 as the wind-down of these contracts is not considered part of our underlying operations.

In the first quarter 2018, comparable earnings also excluded:

  • an after-tax gain of million related to our U.S. Northeast power marketing contracts, primarily due to income recognized on the sale of our retail contracts. These were excluded from Energy’s comparable earnings effective January 1, 2018 as the wind-down of these contracts is not considered part of our underlying operations.

In fourth quarter 2017, comparable earnings also excluded:

  • an 4 million recovery of deferred income taxes as a result of U.S. Tax Reform
  • a 6 million after-tax gain related to the sale of our Ontario solar assets
  • a million net after-tax gain related to the monetization of our U.S. Northeast power business, which included an incremental after-tax loss of million recorded on the sale of the thermal and wind package, million of after-tax third-party insurance proceeds related to a 2017 Ravenswood outage and income tax adjustments
  • a 4 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications
     
  • a million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were expensed pending further advancement of the project.

In third quarter 2017, comparable earnings also excluded:

  • an incremental net loss of million related to the monetization of our U.S. Northeast power business which included an incremental loss of million after tax on the sale of the thermal and wind package and million of after-tax disposition costs and income tax adjustments
  • an after-tax charge of million for integration-related costs associated with the acquisition of Columbia
  • an after-tax charge of million related to the maintenance of Keystone XL assets which were being expensed pending further advancement of the project.

In second quarter 2017, comparable earnings also excluded:

  • a 5 million net after-tax gain related to the monetization of our U.S. Northeast power business which included a 1 million after-tax gain on the sale of TC Hydro and an additional loss of 6 million after tax on the sale of the thermal and wind package
  • an after-tax charge of million for integration-related costs associated with the acquisition of Columbia
  • an after-tax charge of million related to the maintenance of Keystone XL assets which were being expensed pending further advancement of the project.

In first quarter 2017, comparable earnings also excluded:

  • a charge of million after tax for integration-related costs associated with the acquisition of Columbia
  • a charge of million after tax for costs related to the monetization of our U.S. Northeast power generation business
  • a charge of million after tax related to the maintenance of Keystone XL assets which were being expensed pending further advancement of the project
  • a million income tax recovery related to the realized loss on a third-party sale of Keystone XL project assets.     A provision for the expected pre-tax loss on these assets was included in our 2015 impairment charge but the related income tax recoveries could not be recorded until realized.

In fourth quarter 2016, comparable earnings also excluded:

  • an 0 million after-tax charge related to the loss on U.S. Northeast power assets held for sale which included an 3 million after-tax loss on the thermal and wind package held for sale and million of after-tax costs related to the monetization
  • an additional million after-tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the Alberta PPA terminations
  • an after-tax charge of million for costs associated with the acquisition of Columbia which included a million deferred tax adjustment upon acquisition and million of retention, severance and integration costs
  • an after-tax charge of million related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project
  • an after-tax restructuring charge of million for additional expected future losses under lease commitments. These charges formed part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs.

In third quarter 2016, comparable earnings also excluded:

  • a 6 million after-tax impairment on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value
  • costs associated with the acquisition of Columbia including a charge of million after tax primarily relating to retention, severance and integration expenses
  • million of income tax recoveries related to the realized loss on a third-party sale of Keystone XL plant and equipment. A provision for the expected loss on these assets was included in our fourth quarter 2015 impairment charge but the related tax recoveries could not be recorded until realized
  • a charge of million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project
  • a million after-tax charge related to the monetization of our U.S. Northeast power business.

 

Condensed consolidated statement of income

    three months ended
June 30
  six months ended
June 30
(unaudited – millions of Canadian $, except per share amounts)     2018       2017       2018       2017  
                 
Revenues                
Canadian Natural Gas Pipelines     954       922       1,838       1,804  
U.S. Natural Gas Pipelines     930       879       2,021       1,873  
Mexico Natural Gas Pipelines     153       150       304       293  
Liquids Pipelines     644       501       1,267       973  
Energy     514       778       1,189       1,694  
      3,195       3,230       6,619       6,637  
Income from Equity Investments     265       197       345       371  
Operating and Other Expenses                
Plant operating costs and other     822       1,027       1,696       2,033  
Commodity purchases resold     324       547       921       1,090  
Property taxes     152       153       302       315  
Depreciation and amortization     570       516       1,105       1,033  
      1,868       2,243       4,024       4,471  
Gain on Sale of Assets           498             498  
Financial Charges                
Interest expense     558       524       1,085       1,024  
Allowance for funds used during construction     (113 )     (121 )     (218 )     (222 )
Interest income and other     92       (89 )     29       (109 )
      537       314       896       693  
Income before Income Taxes     1,055       1,368       2,044       2,342  
Income Tax Expense                
Current     89       55       139       122  
Deferred     64       338       135       471  
      153       393       274       593  
Net Income     902       975       1,770       1,749  
Net income attributable to non-controlling interests     76       55       170       145  
Net Income Attributable to Controlling Interests     826       920       1,600       1,604  
Preferred share dividends     41       39       81       80  
Net Income Attributable to Common Shares     785       881       1,519       1,524  
Net Income per Common Share                
Basic   $0.88     .01     $1.70     .76  
Diluted   $0.88     .01     $1.70     .75  
Dividends Declared per Common Share   $0.69     {$content}.625     $1.38     .25  
Weighted Average Number of Common Shares (millions)                
Basic     896       870       892       868  
Diluted     896       872       893       870  

See accompanying notes to the Condensed consolidated financial statements.

Condensed consolidated statement of comprehensive income

    three months ended June 30   six months ended June 30
(unaudited – millions of Canadian $)   2018     2017     2018     2017  
                 
Net Income   902     975     1,770     1,749  
Other Comprehensive Income/(Loss), Net of Income Taxes                
Foreign currency translation gains and losses on net investment in foreign operations   259     (269 )   691     (351 )
Reclassification of foreign currency translation gains on net investment on disposal of foreign operations       (77 )       (77 )
Change in fair value of net investment hedges   (13 )   (1 )   (15 )   (2 )
Change in fair value of cash flow hedges   (2 )   (2 )   5     3  
Reclassification to net income of gains and losses on cash flow hedges   7     (1 )   10     (1 )
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans   2     4         7  
Other comprehensive income on equity investments   6         12     3  
Other comprehensive income/(loss)   259     (346 )   703     (418 )
Comprehensive Income   1,161     629     2,473     1,331  
Comprehensive income attributable to non-controlling interests   116     6     276     56  
Comprehensive Income Attributable to Controlling Interests   1,045     623     2,197     1,275  
Preferred share dividends   41     39     81     80  
Comprehensive Income Attributable to Common Shares   1,004     584     2,116     1,195  

See accompanying notes to the Condensed consolidated financial statements.

Condensed consolidated statement of cash flows

    three months ended June 30   six months ended June 30
(unaudited – millions of Canadian $)   2018     2017     2018     2017  
                 
Cash Generated from Operations                
Net income   902     975     1,770     1,749  
Depreciation and amortization   570     516     1,105     1,033  
Deferred income taxes   64     338     135     471  
Income from equity investments   (265 )   (197 )   (345 )   (371 )
Distributions received from operating activities of equity investments   231     228     465     447  
Employee post-retirement benefits funding, net of expense   (3 )   6         9  
Gain on sale of assets       (498 )       (498 )
Equity allowance for funds used during construction   (79 )   (78 )   (157 )   (142 )
Unrealized (gains)/losses on financial instruments   (39 )   50     149     91  
Other   63     (4 )   (59 )   4  
Decrease/(increase) in operating working capital   361     17     154     (138 )
Net cash provided by operations   1,805     1,353     3,217     2,655  
Investing Activities                
Capital expenditures   (2,337 )   (1,792 )   (4,039 )   (3,352 )
Capital projects in development   (76 )   (56 )   (112 )   (98 )
Contributions to equity investments   (184 )   (473 )   (542 )   (665 )
Proceeds from sales of assets, net of transaction costs       4,147         4,147  
Other distributions from equity investments       1     121     364  
Deferred amounts and other   (16 )   (169 )   94     (254 )
Net cash (used in)/provided by investing activities   (2,613 )   1,658     (4,478 )   142  
Financing Activities                
Notes payable (repaid)/issued, net   (1,327 )   111     485     781  
Long-term debt issued, net of issue costs   3,240     817     3,333     817  
Long-term debt repaid   (808 )   (4,418 )   (2,034 )   (5,469 )
Junior subordinated notes issued, net of issue costs       1,489         3,471  
Dividends on common shares   (380 )   (328 )   (738 )   (628 )
Dividends on preferred shares   (39 )   (38 )   (78 )   (77 )
Distributions paid to non-controlling interests   (48 )   (69 )   (117 )   (149 )
Common shares issued, net of issue costs   445     18     785     36  
Partnership units of TC PipeLines, LP issued, net of issue costs       27     49     119  
Common units of Columbia Pipeline Partners LP acquired               (1,205 )
Net cash provided by/(used in) financing activities   1,083     (2,391 )   1,685     (2,304 )
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents   28     (24 )   57     (19 )
Increase in Cash and Cash Equivalents   303     596     481     474  
Cash and Cash Equivalents                
Beginning of period   1,267     894     1,089     1,016  
Cash and Cash Equivalents                
End of period   1,570     1,490     1,570     1,490  

See accompanying notes to the Condensed consolidated financial statements.

Condensed consolidated balance sheet

    June 30,     December 31,  
(unaudited – millions of Canadian $)   2018     2017  
         
ASSETS        
Current Assets        
Cash and cash equivalents   1,570     1,089  
Accounts receivable   2,111     2,522  
Inventories   403     378  
Assets held for sale   458      
Other   888     691  
    5,430     4,680  
Plant, Property and Equipment net of accumulated depreciation of ,822 and ,734, respectively   61,446     57,277  
Equity Investments   6,628     6,366  
Regulatory Assets   1,361     1,376  
Goodwill   13,734     13,084  
Loan Receivable from Affiliate   1,173     919  
Intangible and Other Assets   1,749     1,484  
Restricted Investments   1,062     915  
    92,583     86,101  
LIABILITIES        
Current Liabilities        
Notes payable   2,359     1,763  
Accounts payable and other   3,982     4,057  
Dividends payable   636     586  
Accrued interest   642     605  
Current portion of long-term debt   2,812     2,866  
    10,431     9,877  
Regulatory Liabilities   4,603     4,321  
Other Long-Term Liabilities   666     727  
Deferred Income Tax Liabilities   5,700     5,403  
Long-Term Debt   34,583     31,875  
Junior Subordinated Notes   7,284     7,007  
    63,267     59,210  
EQUITY        
Common shares, no par value   22,385     21,167  
Issued and outstanding: June 30, 2018 – 904 million shares        
  December 31, 2017 – 881 million shares        
Preferred shares   3,980     3,980  
Additional paid-in capital   12      
Retained earnings   2,020     1,623  
Accumulated other comprehensive loss   (1,134 )   (1,731 )
Controlling Interests   27,263     25,039  
Non-controlling interests   2,053     1,852  
    29,316     26,891  
    92,583     86,101  

Contingencies and Guarantees (Note 13)
Variable Interest Entities (Note 14)
Subsequent Event (Note 15)

See accompanying notes to the Condensed consolidated financial statements.

Condensed consolidated statement of equity

  six months ended June 30
(unaudited – millions of Canadian $) 2018     2017  
       
Common Shares      
Balance at beginning of period 21,167     20,099  
Shares issued:      
Under at-the-market equity issuance program, net of issue costs 766      
Under dividend reinvestment and share purchase plan 431     406  
On exercise of stock options 21     39  
Balance at end of period 22,385     20,544  
Preferred Shares      
Balance at beginning and end of period 3,980     3,980  
Additional Paid-In Capital      
Balance at beginning of period      
Issuance of stock options, net of exercises 5     2  
Dilution from TC PipeLines, LP units issued 7     13  
Asset drop downs to TC PipeLines, LP     (202 )
Columbia Pipeline Partners LP acquisition     (171 )
Reclassification of additional paid-in capital deficit to retained earnings     358  
Balance at end of period 12      
Retained Earnings      
Balance at beginning of period 1,623     1,138  
Net income attributable to controlling interests 1,600     1,604  
Common share dividends (1,238 )   (1,087 )
Preferred share dividends (60 )   (58 )
Adjustment related to income tax effects of asset drop downs to TC PipeLines, LP 95      
Adjustment related to employee share-based payments     12  
Reclassification of additional paid-in capital deficit to retained earnings     (358 )
Balance at end of period 2,020     1,251  
Accumulated Other Comprehensive Loss      
Balance at beginning of period (1,731 )   (960 )
Other comprehensive income/(loss) attributable to controlling interests 597     (329 )
Balance at end of period (1,134 )   (1,289 )
Equity Attributable to Controlling Interests 27,263     24,486  
Equity Attributable to Non-Controlling Interests      
Balance at beginning of period 1,852     1,726  
Net income attributable to non-controlling interests 170     145  
Other comprehensive income/(loss) attributable to non-controlling interests 106     (89 )
Issuance of TC PipeLines, LP units      
Proceeds, net of issue costs 49     119  
Decrease in TransCanada’s ownership of TC PipeLines, LP (9 )   (21 )
Distributions declared to non-controlling interests (115 )   (147 )
Reclassification from common units of TC PipeLines, LP subject to rescission     106  
Impact of Columbia Pipeline Partners LP acquisition     33  
Balance at end of period 2,053     1,872  
Total Equity 29,316     26,358  

See accompanying notes to the Condensed consolidated financial statements.

Notes to Condensed consolidated financial statements

(unaudited)

1. Basis of presentation

These Condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada’s annual audited consolidated financial statements for the year ended December 31, 2017, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada’s 2017 Annual Report.

These Condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These Condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2017 audited consolidated financial statements included in TransCanada’s 2017 Annual Report. Certain comparative figures have been reclassified to conform with the current period’s presentation.

Earnings for interim periods may not be indicative of results for the fiscal year in the Company’s natural gas pipelines segments due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company’s Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company’s investments in electrical power generation plants and non-regulated gas storage facilities.

USE OF ESTIMATES AND JUDGEMENTS
In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these Condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies included in the annual audited consolidated financial statements for the year ended December 31, 2017, except as described in Note 2, Accounting changes.

2. Accounting changes

CHANGES IN ACCOUNTING POLICIES FOR 2018

Revenue from contracts with customers
In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Company’s “performance obligations.” The total consideration to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company’s influence, such as market prices, actions of third parties and weather conditions. The Company considers this variable revenue to be “constrained” as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided.

The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and related cash flows.

In the application of the new guidance, significant estimates and judgments are used to determine the following:

  • pattern of revenue recognition within a contract, based on whether the performance obligation is satisfied at a point in time versus over time
  • term of the contract
  • amount of variable consideration associated with a contract and timing of the associated revenue recognition.

The new guidance was effective January 1, 2018, was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 4, Revenues, for further information related to the impact of adopting the new guidance and the Company’s updated accounting policies related to revenue recognition from contracts with customers.

Financial instruments
In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance changes the income statement effect of equity investments and the recognition of changes in the fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance was effective January 1, 2018 and did not have a material impact on the Company’s consolidated financial statements.

Income taxes
In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for an intra-entity asset transfer when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and did not have a material impact on the Company’s consolidated financial statements.

Restricted cash
In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. This new guidance was effective January 1, 2018, was applied retrospectively, and did not have an impact on the Company’s consolidated financial statements.

Employee post-retirement benefits
In March 2017, the FASB issued new guidance that requires entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance was effective January 1, 2018 and did not have a material impact on the Company’s consolidated financial statements.

Hedge accounting
In August 2017, the FASB issued new guidance making more financial and non-financial hedging strategies eligible for hedge accounting. The new guidance also amends the presentation requirements relating to the change in fair value of a derivative and requires additional disclosures including cumulative basis adjustments for fair value hedges and the effect of hedging on individual line items in the consolidated statement of income. This new guidance is effective January 1, 2019 with early adoption permitted. This new guidance, which the Company elected to adopt effective January 1, 2018, was applied prospectively and did not have a material impact on the Company’s consolidated financial statements.

FUTURE ACCOUNTING CHANGES

Leases
In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessor is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statement of income. The new guidance does not make extensive changes to lessor accounting.

In January 2018, the FASB issued an optional practical expedient, to be applied upon transition, to omit the evaluation of land easements not previously accounted for as leases that existed or expired prior to the entity’s adoption of the new lease guidance. An entity that elects this practical expedient is required to apply the practical expedient consistently to all of its existing or expired land easements not previously accounted for as leases. The Company continues to monitor and analyze additional guidance and clarifications provided by the FASB.

The new guidance is effective January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company has developed a preliminary inventory of existing lease agreements and has substantially completed its analysis on these leases but continues to evaluate the financial impact on its consolidated financial statements. The Company has also selected a system solution and is in the testing stage of implementation. The Company continues to assess process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance and to analyze new contracts that may contain leases.

Measurement of credit losses on financial instruments
In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Goodwill impairment
In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 and will be applied prospectively, however, early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance.

Amortization on purchased callable debt securities
In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Income taxes
In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from the U.S. Tax Reform. This new guidance is effective January 1, 2019, however, early adoption is permitted. This guidance can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change is recognized. The Company is currently evaluating this guidance in conjunction with its analysis of the overall impact of U.S. Tax Reform.

3. Segmented information

three months ended June 30, 2018
(unaudited – millions of Canadian $)
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural
Gas
Pipelines
    Liquids
Pipelines
     Energy     Corporate
1  Total  
                           
Revenues   954     930     153     644     514       3,195  
Intersegment revenues       56             5     (61 )2  
    954     986     153     644     519     (61 ) 3,195  
Income from equity investments   3     59     1     13     102     87  3 265  
Plant operating costs and other   (341 )   (288 )   (12 )   (155 )   (72 )   46  2 (822 )
Commodity purchases resold                   (324 )     (324 )
Property taxes   (71 )   (53 )       (27 )   (1 )     (152 )
Depreciation and amortization   (265 )   (163 )   (24 )   (85 )   (33 )     (570 )
Segmented Earnings   280     541     118     390     191     72   1,592  
Interest expense (558 )
Allowance for funds used during construction 113  
Interest income and other (92 )
Income before income taxes 1,055  
Income tax expense (153 )
Net Income 902  
Net income attributable to non-controlling interests (76 )
Net Income Attributable to Controlling Interests 826  
Preferred share dividends (41 )
Net Income Attributable to Common Shares 785  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income from equity investments includes foreign exchange gains on the Company’s inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of debt financing for this joint venture.

three months ended June 30, 2017
(unaudited – millions of Canadian $)
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural
Gas
Pipelines
    Liquids
Pipelines
    Energy     Corporate 1 Total  
                           
Revenues   922     879     150     501     778       3,230  
Intersegment revenues       10                 (10 )2  
    922     889     150     501     778     (10 ) 3,230  
Income/(loss) from equity investments   2     57     5     (1 )   142     (8 )3 197  
Plant operating costs and other   (328 )   (347 )   (10 )   (147 )   (173 )   (22 )2 (1,027 )
Commodity purchases resold                   (547 )     (547 )
Property taxes   (69 )   (48 )       (22 )   (14 )     (153 )
Depreciation and amortization   (222 )   (150 )   (25 )   (80 )   (39 )     (516 )
Gain on sale of assets                   498       498  
Segmented Earnings/(Loss)   305     401     120     251     645     (40 ) 1,682  
Interest expense (524 )
Allowance for funds used during construction 121  
Interest income and other 89  
Income before income taxes 1,368  
Income tax expense (393 )
Net Income 975  
Net income attributable to non-controlling interests (55 )
Net Income Attributable to Controlling Interests 920  
Preferred share dividends (39 )
Net Income Attributable to Common Shares 881  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign exchange losses on the Company’s inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of debt financing for this joint venture.

six months ended June 30, 2018
(unaudited – millions of Canadian $)
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural
Gas
Pipelines
    Liquids
Pipelines
    Energy     Corporate 1 Total  
                           
Revenues   1,838     2,021     304     1,267     1,189       6,619  
Intersegment revenues       81             47     (128 )2  
    1,838     2,102     304     1,267     1,236     (128 ) 6,619  
Income from equity investments   6     126     12     28     165     8  3 345  
Plant operating costs and other   (664 )   (612 )   (14 )   (346 )   (171 )   111  2 (1,696 )
Commodity purchases resold                   (921 )     (921 )
Property taxes   (141 )   (108 )       (50 )   (3 )     (302 )
Depreciation and amortization   (506 )   (319 )   (47 )   (168 )   (65 )     (1,105 )
Segmented Earnings/(Loss)   533     1,189     255     731     241     (9 ) 2,940  
Interest expense (1,085 )
Allowance for funds used during construction 218  
Interest income and other (29 )
Income before income taxes 2,044  
Income tax expense (274 )
Net Income 1,770  
Net income attributable to non-controlling interests (170 )
Net Income Attributable to Controlling Interests 1,600  
Preferred share dividends (81 )
Net Income Attributable to Common Shares 1,519  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income from equity investments includes foreign exchange gains on the Company’s inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of debt financing for this joint venture.

six months ended June 30, 2017
(unaudited – millions of Canadian $)
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural
Gas
Pipelines
    Liquids
Pipelines
    Energy     Corporate 1 Total  
                           
Revenues   1,804     1,873     293     973     1,694       6,637  
Intersegment revenues       21                 (21 )2  
    1,804     1,894     293     973     1,694     (21 ) 6,637  
Income/(loss) from equity investments   5     122     11     (1 )   242     (8 )3 371  
Plant operating costs and other   (640 )   (653 )   (19 )   (292 )   (385 )   (44 )2 (2,033 )
Commodity purchases resold                   (1,090 )     (1,090 )
Property taxes   (138 )   (95 )       (45 )   (37 )     (315 )
Depreciation and amortization   (444 )   (306 )   (47 )   (157 )   (79 )     (1,033 )
Gain on sale of assets                   498       498  
Segmented Earnings/(Loss)   587     962     238     478     843     (73 ) 3,035  
Interest expense (1,024 )
Allowance for funds used during construction 222  
Interest income and other 109  
Income before income taxes 2,342  
Income tax expense (593 )
Net Income 1,749  
Net income attributable to non-controlling interests (145 )
Net Income Attributable to Controlling Interests 1,604  
Preferred share dividends (80 )
Net Income Attributable to Common Shares 1,524  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign exchange losses on the Company’s inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of debt financing for this joint venture.

TOTAL ASSETS

(unaudited – millions of Canadian $)   June 30, 2018   December 31, 2017  
       
Canadian Natural Gas Pipelines   17,447   16,904  
U.S. Natural Gas Pipelines   39,786   35,898  
Mexico Natural Gas Pipelines   6,268   5,716  
Liquids Pipelines   16,291   15,438  
Energy   8,368   8,503  
Corporate   4,423   3,642  
    92,583   86,101  

4. Revenues

In 2014, the FASB issued new guidance on revenue from contracts with customers. The Company adopted the new guidance on January 1, 2018 using the modified retrospective transition method for all contracts that were in effect on the date of adoption. Results reported for 2018 reflect the application of the new guidance, while the 2017 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as “legacy U.S. GAAP.”

DISAGGREGATION OF REVENUES
The following tables summarizes total Revenues for the three and six months ended June 30, 2018:

three months ended June 30, 2018
(unaudited – millions of Canadian $)
Canadian
Natural
Gas
Pipelines
  U.S.
Natural
Gas
Pipelines
  Mexico
Natural
Gas
Pipelines
  Liquids
Pipelines
  Energy   Total  
             
Revenues from contracts with customers            
  Capacity arrangements and transportation 954   785   152   513     2,404  
  Power generation         415   415  
  Natural gas storage and other   118   1     31   150  
  954   903   153   513   446   2,969  
Other revenues1,2   27     131   68   226  
  954   930   153   644   514   3,195  

1 Other revenues include income from the Company’s financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 12, Risk management and financial instruments, for further information on income from financial instruments.
2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 7, Income taxes, for further information.

six months ended June 30, 2018
(unaudited – millions of Canadian $)
Canadian
Natural
Gas
Pipelines
  U.S.
Natural
Gas
Pipelines
  Mexico
Natural
Gas
Pipelines
  Liquids
Pipelines
  Energy   Total  
             
Revenues from contracts with customers            
  Capacity arrangements and transportation 1,838   1,669   302   1,047     4,856  
  Power generation         1,005   1,005  
  Natural gas storage and other   310   2   1   61   374  
  1,838   1,979   304   1,048   1,066   6,235  
Other revenues1,2   42     219   123   384  
  1,838   2,021   304   1,267   1,189   6,619  

1 Other revenues include income from the Company’s financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 12, Risk management and financial instruments, for further information on income from financial instruments.
2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to  Note 7, Income taxes, for further information.

Revenues from contracts with customers are recognized net of any taxes collected from customers which are subsequently remitted to governmental authorities. The Company’s contracts with customers include natural gas and liquids pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts.

Canadian Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from the Company’s Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed.

Revenues from the Company’s Canadian natural gas pipelines are subject to regulatory decisions by the NEB. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and return on capital, as approved by the NEB. The Company’s Canadian natural gas pipelines are generally not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future tolls. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB’s last approved rate of return on common equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. Canadian natural gas pipelines’ revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

U.S. Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from the Company’s U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company has elected to utilize the practical expedient to recognize revenues from its U.S. natural gas pipelines as invoiced.

The Company’s U.S. natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management’s best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. U.S. natural gas pipelines’ revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

Natural Gas Storage and Other
Revenues from the Company’s regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regards to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers.

Revenues from the Company’s midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, are generated from contractual arrangements and are recognized ratably over the term of the contract. The Company also owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas is produced. Midstream natural gas service revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas for which it provides midstream services.

Mexico Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from the Company’s Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. For certain firm capacity arrangements, the Company has elected to utilize the practical expedient to recognize revenues as invoiced. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Other volumes shipped on these pipelines are subject to CRE-approved tariffs and revenues are recognized when the Company has performed the transportation services. Mexico natural gas pipelines’ revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

Liquids Pipelines
Capacity Arrangements and Transportation
Revenues from the Company’s liquids pipelines are generated mainly from providing customers with firm capacity arrangements to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or volumetric-based services are recognized when the service is performed. Liquids pipelines’ revenues are invoiced and received on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers.

Energy
Power Generation
Revenues from the Company’s Energy business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market, and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis.

Natural Gas Storage and Other
Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Park and loan contracts allow for fixed injection or withdrawal volumes on specified dates for a specified price. Term storage contracts allow for a maximum amount of gas to be stored over a set period of time. Revenues from park and loan contracts are recognized and invoiced as the injection and withdrawal services are provided and revenues from term storage contracts are recognized ratably over the term of the contract. Term storage revenues are invoiced and received on a monthly basis. Revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. Revenues from ancillary services are recognized as the service is provided. The Company does not take ownership of the natural gas that it stores for customers.

FINANCIAL STATEMENT IMPACT OF ADOPTING REVENUE FROM CONTRACTS WITH CUSTOMERS
The Company adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Company is not required to analyze completed contracts at the date of adoption. As a result, the Company made the following adjustments on January 1, 2018.

Capacity Arrangements and Transportation
For certain natural gas pipelines capacity contracts, amounts are invoiced to the customer in accordance with the terms of the contract, however, the related revenues are recognized when the Company satisfies its performance obligation to provide committed capacity ratably over the term of the contract. This difference in timing between revenue recognition and amounts invoiced creates a contract asset or contract liability under the new revenue recognition guidance. Under legacy U.S. GAAP, this difference was recorded as Accounts receivable. Under the new guidance, contract assets are included in Other current assets and contract liabilities are included in Accounts payable and other.

Impact of New Revenue Recognition Guidance on Date of Adoption
The following table illustrates the impact of the adoption of the new revenue recognition guidance on the Company’s previously reported consolidated balance sheet line items:

  As reported          
(unaudited – millions of Canadian $) December 31, 2017   Adjustment   January 1, 2018  
       
Current Assets      
Accounts receivable 2,522   (62 ) 2,460  
Other1 691   79   770  
Current Liabilities      
Accounts payable and other2 4,057   17   4,074  

1 Adjustment relates to contract assets previously included in Accounts receivable.
2 Adjustment relates to contract liabilities previously included in Accounts receivable.

Pro-forma Financial Statements under Legacy U.S. GAAP
As required by the new revenue recognition guidance, the following tables illustrate the pro-forma impact on the affected line items on the Condensed consolidated balance sheet, as at June 30, 2018, had legacy U.S. GAAP been applied:

  June 30, 2018
 (unaudited – millions of Canadian $) As reported   Pro-forma
using legacy U.S.
GAAP
     
Current Assets    
Accounts receivable 2,111   2,353
Other 888   646

CONTRACT BALANCES

(unaudited – millions of Canadian $) June 30, 2018   January 1, 2018
       
Receivables from contracts with customers 1,225   1,736
Contract assets1 242   79
Contract liabilities2 24   17
Long-term contract liabilities3 17  

1 Recorded as part of Other current assets on the Condensed consolidated balance sheet.
2 Comprised of deferred revenue recorded in Accounts payable and other on the Condensed consolidated balance sheet. During the six months ended June 30, 2018, million of revenue was recognized that was included in the contract liability at the beginning of the period.
3 Comprised of deferred revenue recorded in Other long-term liabilities on the Condensed consolidated balance sheet. 

Contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced as well as the recognition of additional revenues that remains to be invoiced.

FUTURE REVENUES FROM REMAINING PERFORMANCE OBLIGATIONS
As required by the new revenue recognition guidance, the following provides disclosure on future revenues allocated to remaining performance obligations representing contracted revenues that have not yet been recognized. Certain contracts that qualify for the use of one of the following practical expedients are excluded from the future revenues disclosures:

  1. The original expected duration of the contract is one year or less.

  2. The Company recognizes revenue from the contract that is equal to the amount invoiced, where the amount invoiced represents the value to the customer of the service performed to date. This is referred to as the “right to invoice” practical expedient.
  3. The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.

The following provides a discussion of the transaction price allocated to future performance obligations as well as practical expedients used by the Company.

Capacity Arrangements and Transportation
As at June 30, 2018, future revenues from long-term capacity arrangements and transportation contracts extending through 2043 are approximately .4 billion, of which approximately .8 billion is expected to be recognized during the remainder of 2018.

Future revenues from long-term capacity arrangements and transportation contracts do not include constrained variable revenues or arrangements to which the right to invoice practical expedient has been applied. As a result, these amounts are not representative of potential total future revenues expected from these contracts.

Future revenues from the Company’s Canadian natural gas pipelines’ regulated firm capacity contracts include fixed revenues for the time periods that tolls under current rate settlements are in effect, which is approximately one to three years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations that extend beyond the current rate settlement term are considered to be fully constrained since future tolls remain unknown. Revenues from these contracts will be recognized once the performance obligation to provide capacity has been satisfied and the regulator has approved the applicable tolls. In addition, the Company considers interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Company satisfies the performance obligation and have been excluded from the future revenues disclosure as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts are allocated entirely to unsatisfied performance obligations at June 30, 2018.

The Company also applies the right to invoice practical expedient to all of its U.S. and certain of its Mexico regulated natural gas pipeline capacity arrangements and flow-through revenues. Revenues from regulated capacity arrangements are recognized based on current rates and flow-through revenues are earned from the recovery of operating expenses. These revenues are recognized on a monthly basis as the Company performs the services and are excluded from future revenues disclosures.

Revenues from liquids pipelines capacity arrangements have a variable component based on volumes transported. As a result, these variable revenues are excluded from the future revenues disclosures as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts is allocated entirely to unsatisfied performance obligations at June 30, 2018.

Power Generation
The Company has long-term power generation contracts extending through 2032. Revenues from power generation have a variable component related to market prices that are subject to factors outside the Company’s influence. These revenues are considered to be fully constrained and are recognized on a monthly basis when the Company satisfies the performance obligation. The Company applies the practical expedient related to variable revenues to these contracts. As a result, future revenues from these contracts are excluded from the disclosures.

Natural Gas Storage and Other
As at June 30, 2018, future revenues from long-term natural gas storage and other contracts extending through 2033 are approximately .3 billion, of which approximately 0 million is expected to be recognized during the remainder of 2018. The Company applies the practical expedients related to contracts that are for a duration of one year or less and where it recognizes variable consideration, and therefore excludes the related revenues from the future revenues disclosure. As a result, this amount is lower than the potential total future revenues from these contracts.

5. Assets held for sale

Cartier Wind
On August 1, 2018, we entered into an agreement to sell our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for gross proceeds of 0 million before closing adjustments. The sale is expected to be completed in fourth quarter 2018, subject to certain regulatory and other approvals, and result in an estimated gain of 5 million (0 million after tax) which will be recorded upon closing of the transaction.

At June 30, 2018, the related assets and liabilities in the Energy segment were classified as held for sale as follows:

     
(unaudited – millions of Canadian $)    
     
Assets held for sale    
Plant, property and equipment   458  
Total assets held for sale   458  
Liabilities related to assets held for sale    
Other long-term liabilities   14  
Total liabilities related to assets held for sale1   14  

1 Included in Accounts payable and other on the Condensed consolidated balance sheet.

6. Plant, Property and Equipment, Equity Investments and Goodwill

The Company reviews plant, property and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.

Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. The Company can initially make this assessment based on qualitative factors. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, then an impairment test is not performed.

In March 2018, FERC proposed changes related to U.S. Tax Reform and income taxes for rate-making purposes in a master limited partnership (MLP) that may have an impact on the future earnings and cash flows of FERC-regulated pipelines. On July 18, 2018, FERC issued final rulings with respect to these changes. Until these pronouncements are implemented through individual rate proceedings or settlements, and the Company and TC PipeLines, LP have fully evaluated their respective alternatives to minimize any negative impact of the proposed FERC changes, the Company believes that it is not more likely than not that the fair value of any of its reporting units is less than its respective carrying value. Therefore, a goodwill impairment test has not been performed during the six months ended June 30, 2018. The Company also determined there is no indication that the carrying values of plant, property and equipment and equity investments potentially impacted by FERC’s changes are not recoverable. The Company will continue to monitor developments and assess its goodwill for impairment as well as review its plant, property and equipment and equity investments for recoverability as new information becomes available.

At December 31, 2017, the estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. There is a risk that the FERC developments, once finalized, could result in a goodwill impairment charge. The goodwill balance related to Great Lakes is US3 million at June 30, 2018 (December 31, 2017 – US3 million). There is also a risk that the goodwill balance related to Tuscarora of US million at June 30, 2018 (December 31, 2017 – US million) could be negatively impacted by the FERC developments.

7. Income taxes

U.S. Tax Reform
Pursuant to the enactment of U.S. Tax Reform, the Company recorded net regulatory liabilities and a corresponding reduction in net deferred income tax liabilities in the amount of ,686 million at December 31, 2017 related to the Company’s U.S. natural gas pipelines subject to rate-regulated accounting. Amounts recorded to adjust income taxes remain provisional as the Company’s interpretation, assessment and presentation of the impact of U.S. Tax Reform may be further clarified with additional guidance from regulatory, tax and accounting authorities. Should additional guidance be provided by these authorities or other sources during the one-year measurement period permitted by the SEC, the Company will review the provisional amounts and adjust as appropriate. Other than the amortizations discussed below and the foreign exchange impacts, no adjustments were made to these amounts during the six months ended June 30, 2018. There may be prospective adjustments to the Company’s net regulatory liabilities once the final impact of these changes is determined.

Commencing January 1, 2018, the Company has amortized the net regulatory liabilities using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine amortization based on their composite depreciation rate and immediately begin recording amortization. Amortization of the net regulatory liabilities in the amount of million and million was recorded for the three and six months ended June 30, 2018 respectively and included in Revenues in the Condensed consolidated statement of income.

Effective Tax Rates
The effective income tax rates for the six-month periods ended June 30, 2018 and 2017 were 13 per cent and 25 per cent, respectively. The lower effective tax rate in 2018 was primarily the result of the rate change resulting from U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines.

8. Long-term debt

LONG-TERM DEBT ISSUED
The Company issued long-term debt in the six months ended June 30, 2018 as follows:

(unaudited – millions of Canadian $, unless noted otherwise)                    
Company   Issue date   Type   Maturity Date   Amount   Interest rate
                     
TRANSCANADA PIPELINES LIMITED
    May 2018   Senior Unsecured Notes   May 2028   US 1,000   4.25%
    May 2018   Senior Unsecured Notes   May 2038   US 500   4.75%
    May 2018   Senior Unsecured Notes   May 2048   US 1,000   4.875%

LONG-TERM DEBT RETIRED
The Company retired long-term debt in the six months ended June 30, 2018 as follows:

(unaudited – millions of Canadian $, unless noted otherwise)                
Company   Retirement date   Type   Amount   Interest rate
                 
COLUMBIA PIPELINE GROUP, INC.            
    June 2018   Senior Unsecured Notes   US 500   2.45%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM            
    May 2018   Senior Secured Notes   US 18   5.9%
TRANSCANADA PIPELINES LIMITED            
    March 2018   Debentures   150   9.45%
    January 2018   Senior Unsecured Notes   US 500   1.875%
    January 2018   Senior Unsecured Notes   US 250   Floating
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP        
    March 2018   Senior Unsecured Notes   US 9   6.73%

CAPITALIZED INTEREST
In the three and six months ended June 30, 2018, TransCanada capitalized interest related to capital projects of million and million, respectively (2017 – million and 1 million, respectively).

9. Common shares

TRANSCANADA CORPORATION ATM EQUITY ISSUANCE PROGRAM
In the three months ended June 30, 2018, the Company issued 8.1 million common shares under the TransCanada ATM program at an average price of .63 per common share for gross proceeds of 3 million. Related commissions and fees totaled approximately million resulting in net proceeds of 9 million. In the six months ended June 30, 2018, the Company issued 13.9 million common shares at an average price of .42 per common share for gross proceeds of 2 million. Related commissions and fees totaled approximately million resulting in net proceeds of 5 million.

In June 2018, the Company announced that it has replenished the capacity available under its existing Corporate ATM program. This allows for the issuance of additional common shares from treasury for an aggregate gross sales price of up to .0 billion, for a revised total of .0 billion or its U.S. dollar equivalent (Amended Corporate ATM program). The Amended Corporate ATM program is effective to July 23, 2019.

10. Other comprehensive income/(loss) and accumulated other comprehensive loss

Components of other comprehensive income/(loss), including the portion attributable to non-controlling interests and related tax effects, are as follows:

three months ended June 30, 2018            
(unaudited – millions of Canadian $)   Before Tax
Amount
    Income Tax
Recovery/
(Expense)
    Net of Tax
Amount
 
             
Foreign currency translation gains on net investment in foreign operations   254     5     259  
Change in fair value of net investment hedges   (17 )   4     (13 )
Change in fair value of cash flow hedges   (3 )   1     (2 )
Reclassification to net income of gains and losses on cash flow hedges   9     (2 )   7  
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans   4     (2 )   2  
Other comprehensive income on equity investments   6         6  
Other comprehensive income   253     6     259  

three months ended June 30, 2017            
(unaudited – millions of Canadian $)   Before Tax
Amount
    Income Tax
Recovery/
(Expense)
    Net of Tax
Amount
 
             
Foreign currency translation losses on net investment in foreign operations   (265 )   (4 )   (269 )
Reclassification of foreign currency translation gains on net investment on disposal of foreign operations   (77 )       (77 )
Change in fair value of net investment hedges   (1 )       (1 )
Change in fair value of cash flow hedges   (2 )       (2 )
Reclassification to net income of gains and losses on cash flow hedges   (2 )   1     (1 )
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans   5     (1 )   4  
Other comprehensive loss   (342 )   (4 )   (346 )

six months ended June 30, 2018            
(unaudited – millions of Canadian $)   Before Tax
Amount
    Income Tax
Recovery/
(Expense)
    Net of Tax
Amount
 
             
Foreign currency translation gains on net investment in foreign operations   670     21     691  
Change in fair value of net investment hedges   (20 )   5     (15 )
Change in fair value of cash flow hedges   3     2     5  
Reclassification to net income of gains and losses on cash flow hedges   13     (3 )   10  
Reclassification of actuarial gains and losses on pension and other  post-retirement benefit plans   8     (8 )    
Other comprehensive income on equity investments   13     (1 )   12  
Other comprehensive income   687     16     703  

six months ended June 30, 2017            
(unaudited – millions of Canadian $)   Before Tax
Amount
    Income Tax
Recovery/
(Expense)
    Net of Tax
Amount
 
             
Foreign currency translation losses on net investment in foreign operations   (353 )   2     (351 )
Reclassification of foreign currency translation gains on net investment on disposal of foreign operations   (77 )       (77 )
Change in fair value of net investment hedges   (3 )   1     (2 )
Change in fair value of cash flow hedges   4     (1 )   3  
Reclassification to net income of gains and losses on cash flow hedges   (2 )   1     (1 )
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans   10     (3 )   7  
Other comprehensive income on equity investments   4     (1 )   3  
Other comprehensive loss   (417 )   (1 )   (418 )

The changes in AOCI by component are as follows:

three months ended June 30, 2018                    
(unaudited – millions of Canadian $)   Currency
Translation
Adjustments
    Cash Flow
Hedges
    Pension and
OPEB Plan
Adjustments
    Equity
Investments
    Total1  
                     
AOCI balance at April 1, 2018   (670 )   (29 )   (205 )   (449 )   (1,353 )
Other comprehensive income/(loss) before reclassifications2   208     (2 )           206  
Amounts reclassified from accumulated other comprehensive loss3       5     2     6     13  
Net current period other comprehensive
income
  208     3     2     6     219  
AOCI balance at June 30, 2018   (462 )   (26 )   (203 )   (443 )   (1,134 )

1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.
2 Other comprehensive income/(loss) before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest gains of million and nil, respectively.
3 Amounts reclassified from AOCI on cash flow hedges and equity investments is net of non-controlling interest gains of million and nil, respectively.

six months ended June 30, 2018   Currency           Pension and              
(unaudited – millions of Canadian $)   Translation
Adjustments
    Cash Flow
Hedges
    OPEB Plan
Adjustments
    Equity
Investments
    Total1  
                     
AOCI balance at January 1, 2018   (1,043 )   (31 )   (203 )   (454 )   (1,731 )
Other comprehensive income/(loss) before reclassifications2,3   581     (2 )           579  
Amounts reclassified from accumulated other comprehensive loss 4       7         11     18  
Net current period other comprehensive
income
  581     5         11     597  
AOCI balance at June 30, 2018   (462 )   (26 )   (203 )   (443 )   (1,134 )

1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.
2 Other comprehensive income/(loss) before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest gains of million and million, respectively.
3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be million ( million, net of tax) at June 30, 2018. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.
4 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of million and million, respectively.

Details about reclassifications out of AOCI into the Condensed consolidated statement of income are as follows:

    Amounts Reclassified From
AOCI
  Affected line item
in the Condensed
consolidated statement of
income
    three months ended
June 30
  six months ended
June 30
 
(unaudited – millions of Canadian $)   2018     2017     2018   2017    
                   
Cash flow hedges                  
Commodities   (2 )   7     (1 ) 11     Revenues (Energy)
Interest   (5 )   (5 )   (9 ) (9 )   Interest expense
    (7 )   2     (10 ) 2     Total before tax
    2     (1 )   3   (1 )   Income tax expense
    (5 )   1     (7 ) 1     Net of tax1,3
Pension and other post-retirement benefit plan adjustments                  
Amortization of actuarial gains and losses   (4 )   (4 )   (8 ) (8 )   Plant operating costs and other2
    2     1     8   3     Income tax expense
    (2 )   (3 )     (5 )   Net of tax1
Equity investments                  
  Equity income   (6 )       (13 ) (4 )   Income from equity investments
            2   1     Income tax expense
    (6 )       (11 ) (3 )   Net of tax1,3
Currency translation adjustments                  
Realization of foreign currency translation gain on disposal of foreign operations       77       77     Gain on sale of assets
                  Income tax expense
        77       77     Net of tax1

1 All amounts in parentheses indicate expenses to the Condensed consolidated statement of income.
2 These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 11, Employee post-retirement benefits, for further information.
3 Amounts reclassified from AOCI on cash flow hedges and equity investments is net of non-controlling interest gains of million and nil, respectively for the three months ended June 30, 2018 (2017 – nil and nil) and million and million, respectively for the six months ended June 30, 2018 (2017 – nil and nil).

11. Employee post-retirement benefits

The net benefit cost recognized for the Company’s benefit pension plans and other post-retirement benefit plans is as follows:

    three months ended June 30   six months ended June 30
    Pension benefit
plans
  Other post-
retirement
benefit plans
  Pension benefit
plans
  Other post-
retirement
benefit plans
(unaudited – millions of Canadian $)   2018   2017   2018   2017   2018   2017   2018   2017
                                 
Service cost1   31     27     1     1     61     56     2     2  
Other components of net benefit cost1                                
Interest cost   34     28     4     3     67     62     7     7  
Expected return on plan assets   (55 )   (39 )   (4 )   (6 )   (110 )   (89 )   (8 )   (11 )
Amortization of actuarial loss   3     4     1         7     8     1      
Amortization of regulatory asset   4     1         1     9     7         1  
    (14 )   (6 )   1     (2 )   (27 )   (12 )       (3 )
Net Benefit Cost   17     21     2     (1 )   34     44     2     (1 )

1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Condensed consolidated statement of income.

12. Risk management and financial instruments

RISK MANAGEMENT OVERVIEW
TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings and cash flow.

COUNTERPARTY CREDIT RISK
TransCanada’s maximum counterparty credit exposure with respect to financial instruments at June 30, 2018, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets, derivative assets and loans receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At June 30, 2018, there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the period.

LOAN RECEIVABLE FROM AFFILIATE
Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

The Company holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. The Company accounts for the joint venture as an equity investment. In 2017, the Company entered into a MXN.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. Draws on the credit facility result in a loan receivable from the joint venture representing the Company’s proportionate share of the debt financing requirements advanced to the joint venture. At June 30, 2018, the balance of the Company’s loan receivable from the joint venture totaled MXN.5 billion or .2 billion (December 31, 2017 – MXN.4 billion or 9 million) and Interest income and other included million and million of interest income on this loan receivable for the three and six months ended June 30, 2018 (2017 – million and million). Amounts recognized in Interest income and other are offset by a corresponding proportionate share of interest expense recorded in Income from equity investments.

NET INVESTMENT IN FOREIGN OPERATIONS
The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts and options.

The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

    June 30, 2018   December 31, 2017
(unaudited – millions of Canadian $, unless noted otherwise)   Fair value1,2     Notional amount   Fair value1,2     Notional amount
                 
U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019)3   (80 )   US 500   (199 )   US 1,200
U.S. dollar foreign exchange options (maturing 2018 to 2019)   (16 )   US 2,000   5     US 500
    (96 )   US 2,500   (194 )   US 1,700

1 Fair value equals carrying value.
2 No amounts have been excluded from the assessment of hedge effectiveness.
3 In the three and six months ended June 30, 2018, Net income includes net realized gains of nil and million, respectively (2017 – million and million, respectively) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

(unaudited – millions of Canadian $, unless noted otherwise)   June 30, 2018   December 31, 2017
         
Notional amount   29,000 (US 22,000)   25,400 (US 20,200)
Fair value   30,800 (US 23,400)   28,900 (US 23,100)

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments
Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Intangible and other assets, Notes payable, Accounts payable and other, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. Each of these instruments are classified in Level II of the fair value hierarchy.

Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Balance sheet presentation of non-derivative financial instruments
The following table details the fair value of the Company’s non-derivative financial instruments, excluding those where carrying amounts approximate fair value, which are classified in Level II of the fair value hierarchy:

    June 30, 2018   December 31, 2017
(unaudited – millions of Canadian $)   Carrying
amount
    Fair
value
    Carrying
amount
    Fair
value
 
                 
Long-term debt including current portion1,2   (37,395 )   (40,762 )   (34,741 )   (40,180 )
Junior subordinated notes   (7,284 )   (7,101 )   (7,007 )   (7,233 )
    (44,679 )   (47,863 )   (41,748 )   (47,413 )

1 Long-term debt is recorded at amortized cost except for US.3 billion (December 31, 2017 – US.1 billion) that is attributed to hedged risk and recorded at fair value.
2 Net income for the three and six months ended June 30, 2018 includes unrealized losses of million and unrealized gains of million, respectively, (2017 – losses of million and gains of million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US.3 billion of long-term debt at June 30, 2018 (December 31, 2017 – US.1 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Available for sale assets summary
The following tables summarize additional information about the Company’s restricted investments that are classified as available for sale assets:

  June 30, 2018   December 31, 2017
(unaudited – millions of Canadian $) LMCI restricted
investments
    Other restricted
investments
1
    LMCI restricted
investments
    Other restricted
investments
1
 
               
Fair values of fixed income securities2              
Maturing within 1 year     24         23  
Maturing within 1-5 years     105         107  
Maturing within 5-10 years 85         14      
Maturing after 10 years 857         790      
  942     129     804     130