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TransCanada Reports Third Quarter 2015 Financial Results

CALGARY, ALBERTA--(Marketwired - Nov 3, 2015) - TransCanada Corporation (TRP) (TRP) (TransCanada) today announced net income attributable to common shares for third quarter 2015 of $402 million or $0.57 per share compared to $457 million or $0.64 per share for the same period in 2014 and $1.2 billion or $1.72 per share compared to $1.3 billion or $1.81 per share on a year-to-date basis. Comparable earnings for third quarter 2015 were $440 million or $0.62 per share compared to $450 million or $0.63 per share for the same period last year. For the nine months ended September 30, 2015, comparable earnings were $1.3 billion or $1.84 per share compared to $1.2 billion or $1.70 per share in 2014. TransCanada's Board of Directors also declared a quarterly dividend of $0.52 per common share for the quarter ending December 31, 2015, equivalent to $2.08 per common share on an annualized basis.

"Over the past nine months, our diverse suite of high-quality long-life assets has performed well in a challenging environment with comparable earnings and funds generated from operations up eight and nine per cent, respectively, compared to the same period last year," said Russ Girling, TransCanada's president and chief executive officer. "The resiliency of our base business through various market conditions, combined with $12 billion of visible near-term growth projects, gives us the ability to continue growing the dividend at an annual rate of eight to ten per cent through 2017."

We are also focused on enhancing shareholder value by maximizing the effectiveness and efficiency of our existing operations. As part of those efforts, we recently commenced a business restructuring initiative that is expected to reduce overall costs. The changes will be undertaken in fourth quarter 2015 and continue into 2016.

Over the longer term, our portfolio of low-risk energy infrastructure assets and our financial strength leaves us well positioned to advance a number of other growth initiatives. They include $35 billion of commercially secured projects which would extend and augment future growth in earnings, cash flow and dividends.

Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
  • Third quarter financial results
    • Net income attributable to common shares of $402 million or $0.57 per share
    • Comparable earnings of $440 million or $0.62 per share
    • Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.5 billion
    • Funds generated from operations of $1.1 billion
  • Declared a quarterly dividend of $0.52 per common share for the quarter ending December 31, 2015
  • Received final pipeline and facilities permits for the Prince Rupert Gas Transmission (PRGT) project in September
  • Announced the acquisition of Ironwood, a strategically situated natural gas-fired power plant for US$654 million in October
  • Reached an agreement with eastern Local Distribution Companies (LDCs) on the Energy East and Eastern Mainline Pipeline projects

Net income attributable to common shares decreased by $55 million to $402 million or $0.57 per share for the three months ended September 30, 2015 compared to the same period last year. Third quarter 2015 included a $6 million after-tax restructuring charge related to changes to our organizational structure while both periods included unrealized gains and losses from changes in risk management activities. All of these specific items are excluded from comparable earnings.

Comparable earnings for third quarter 2015 were $440 million or $0.62 per share compared to $450 million or $0.63 per share for the same period in 2014. Lower contributions from Bruce Power and Western Power were partially offset by higher earnings from the Keystone System, U.S. Power, ANR and Eastern Power.

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

Natural Gas Pipelines:
  • NGTL System Expansions: The NGTL System has approximately $6.8 billion of new supply and demand facilities under development. Approximately $2.8 billion of these facilities have received regulatory approval with $800 million currently under construction. In third quarter 2015, we continued to advance several of these capital expansion projects with an additional approximately $500 million of applied for facilities that now await regulatory review for approval. We have also received additional requests for firm receipt service that we anticipate will increase the overall capital spend on the NGTL System beyond the previously announced program and continue to work with our customers to best match their requirements for 2016, 2017 and 2018 in-service dates.

  • LDC Agreement on Eastern Mainline Project and Energy East: On August 24, 2015, we announced an agreement with eastern LDCs that resolves their issues with Energy East and the Eastern Mainline Project. The agreement honours our previously stated commitment to ensure that Energy East and the Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs. As part of the agreement, we will size the Eastern Mainline Project to meet all firm requirements including gas transmission contracts resulting from both 2016 and 2017 new capacity open seasons plus approximately 50 million cubic feet per day of additional capacity.

    The Eastern Mainline Project capital cost is now estimated to be $2.0 billion with an expected in-service date of 2019. This increase resulted from the revised project scope resulting from the LDC agreement and updated cost estimates.

  • PRGT: On June 11, 2015, Pacific North West (PNW) LNG announced a positive Final Investment Decision (FID) for its proposed liquefaction and export facility, subject to two conditions. The first condition, approval by the Legislative Assembly of B.C. of a Project Development Agreement between PNW LNG and the Province of B.C., was satisfied in mid-July 2015. The second condition is a positive regulatory decision on PNW LNG's environmental assessment by the Government of Canada.

    In third quarter 2015, we received the remaining permits from the B.C. Oil and Gas Commission (BC OGC) which completes the 11 permits required to build and operate PRGT. Environmental permits for the project were also received in November 2014 from the B.C. Environmental Assessment Office.

    We also announced in third quarter 2015, the signing of project agreements with Metlakatla First Nation and Blueberry River First Nations. We are continuing our engagement with Aboriginal groups and have now signed project agreements with nine First Nation groups along the pipeline route.

    We remain ready to begin construction following confirmation of a FID by PNW LNG. The in-service date for PRGT is estimated to be 2020 but will be aligned with PNW LNG's liquefaction facility timeline.

    PRGT is a 900 kilometre (km) (559 mile) natural gas pipeline that will deliver gas from the Montney producing region at an expected interconnect on the NGTL System near Fort St. John, B.C. to PNW LNG's proposed LNG facility near Prince Rupert, B.C.

  • Coastal GasLink: We have received eight of ten pipeline and facilities permits from the BC OGC and anticipate receiving the remaining two permits in fourth quarter 2015. We are continuing our engagement with Aboriginal groups and have signed project agreements with eight First Nation groups along the pipeline route.

    Coastal GasLink is a 670 km (416 mile) natural gas pipeline that will deliver gas from the Montney producing region at an expected interconnect on the NGTL System near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C. The project is subject to regulatory approvals and a positive FID.
Liquids Pipelines:
  • Energy East Pipeline: In April 2015, we announced that the marine and associated tank terminal in Cacouna, Québec will not be built as a result of the recommended reclassification of beluga whales as an endangered species. Amendments to the project are expected to be submitted to the National Energy Board (NEB) in fourth quarter 2015. The NEB has continued to process the application in the interim.

    The alteration to the project scope and further refinement of the project schedule is expected to result in an in-service date of 2020. The original $12 billion cost estimate is expected to increase due to further scope refinement as we consult with stakeholders and escalation of construction costs as the project schedule is refined.

  • Keystone XL: In January 2015, the Department of State re-initiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest. All of the agency comments were submitted. The timing and ultimate resolution of Keystone XL's pending application for a Presidential Permit remains uncertain.

    Also in January 2015, Keystone XL initiated eminent domain actions against landowners in Nebraska who had not agreed to grant voluntary easements. These actions were taken under the eminent domain authority provided by the Governor's 2013 approval of the re-route in Nebraska. Several landowners then challenged those actions in Nebraska district court on the grounds that the law authorizing the Governor's approval violated the Nebraska constitution.

    In October 2015, we withdrew the eminent domain actions and moved to dismiss the constitutional court proceedings. The plaintiffs are resisting dismissal of this case; a hearing on that issue was held on October 19. A decision is expected in fourth quarter 2015.

    On October 5, 2015, we filed an application with the Nebraska Public Service Commission (PSC) for route approval through the state of Nebraska. The route we are seeking approval for is the same route previously approved by the Nebraska Department of Environmental Quality in January 2013. After careful review, we believe this would be the most expedient path to approval and expect the PSC to make a decision by third quarter 2016. On November 2, 2015, we sent a letter to U.S. Secretary of State John Kerry asking the Department of State to pause its review of the Presidential Permit application for Keystone XL while we seek Nebraska PSC approval of the route.

    On August 5, 2015, the South Dakota Public Utility Commission (PUC) concluded their hearing on Keystone XL's request to re-certify its existing permit authority in that state. The PUC is expected to make a decision by first quarter 2016.

    As of September 30, 2015, we have invested US$2.4 billion in the project and have also capitalized interest in the amount of US$0.4 billion.

  • Grand Rapids Pipeline: On August 6, 2015, Grand Rapids Pipeline Limited Partnership (Grand Rapids) entered into an agreement to contribute the southernmost portion of the 20-inch diluent Grand Rapids Pipeline into a 50/50 joint venture with Keyera Corp (Keyera). The 45 km (28 mile) pipeline will be constructed by us and will extend from Keyera's Edmonton Terminal to our Heartland Terminal near Fort Saskatchewan. Keyera will also contribute a new pump station at its Edmonton terminal. We expect Grand Rapids' total contribution to the joint venture will be approximately $140 million. Keyera will operate the pipeline once construction is complete and the facilities are in-service. The expected in-service date is the second half of 2017 subject to regulatory approvals.

Energy:
  • Ironwood Acquisition: On October 8, 2015, we reached an agreement to acquire the Ironwood natural gas-fired, combined cycle power plant in Lebanon, Pennsylvania, with a nameplate capacity of 778 megawatts (MW), from Talen Energy Corporation for US$654 million.

    The Ironwood power plant delivers energy into the PJM power market, North America's largest and most liquid energy region which includes a three-year forward capacity market. The facility provides us with a solid platform from which to continue to grow our wholesale, commercial and industrial customer base in this market area. Strategically located in proximity to the Marcellus shale gas play, the facility is well positioned to access competitively priced natural gas in a market that is in the midst of transitioning away from coal-fired power generation to gas.

    The acquisition is expected to be immediately accretive to earnings and cash flow and generate approximately US$90-$110 million in EBITDA annually through a combination of capacity payments and energy sales. The acquisition will be financed with a combination of cash on hand and available debt capacity and is expected to close early in first quarter 2016, subject to certain conditions being satisfied.
  • Becancour: In August 2015, we executed an agreement with Hydro Quebec (HQ) to amend Becancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Becancour facility for a term of 20 years commencing in December 2016. Annual payments received for this new service will be incremental to existing capacity payments earned under the new agreement. In October 2015, the Regie de l'energie approved the amended contract.
Corporate:
  • Our Board of Directors declared a quarterly dividend of $0.52 per share for the quarter ending December 31, 2015 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.08 per common share on an annualized basis.

  • Financing Activities: In July 2015, we issued $750 million of medium-term notes maturing on July 17, 2025 bearing interest at 3.30 per cent and in October 2015, we issued $400 million of medium-term notes maturing on November 15, 2041 bearing interest at 4.55 per cent.

    The net proceeds of these offerings will be used for general corporate purposes and to reduce short-term indebtedness which was used to fund a portion of our capital program and for general corporate purposes.

  • Management Changes and Corporate Restructuring: Effective October 1, 2015, Alex Pourbaix was appointed as Chief Operating Officer. Don Marchand was appointed Executive Vice-President, Corporate Development and Chief Financial Officer and Kristine Delkus was appointed Executive Vice-President, Stakeholder Relations and General Counsel. Jim Baggs, Executive Vice-President, Operations and Engineering, has announced his intention to retire in early 2016.

    In mid-2015, we commenced a business restructuring initiative. While there is no change to our corporate strategy, we have undertaken this initiative to reduce overall costs and maximize the effectiveness and efficiency of our existing operations. We expect the changes to be undertaken in fourth quarter 2015 and continue into 2016.

Teleconference and Webcast:

We will hold a teleconference and webcast on Tuesday, November 3, 2015 to discuss our third quarter 2015 financial results. Russ Girling, TransCanada President and Chief Executive Officer, and Don Marchand, Executive Vice-President, Corporate Development and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 9 a.m. (MT) / 11 a.m. (ET).

Analysts, members of the media and other interested parties are invited to participate by calling 866.225.6564 or 416.340.2218 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on November 10, 2015. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 9292695.

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

With more than 65 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,000 kilometres (42,100 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with 368 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 10,900 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest liquids delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com and our blog to learn more, or connect with us on social media and 3BL Media.

Forward Looking Information

This news release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "believe", "may", "will", "should", "estimate", "intend" or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future plans and financial outlook. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada's Quarterly Report to Shareholders dated November 2, 2015 and 2014 Annual Report on our website at www.transcanada.com or filed under TransCanada's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov.

Non-GAAP Measures

This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, funds generated from operations and comparable earnings per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada's Quarterly Report to Shareholders dated November 2, 2015.

Quarterly report to shareholders
Third quarter 2015
Financial highlights
three months ended
September 30
nine months ended
September 30
(unaudited - millions of $, except per share amounts) 2015 2014 2015 2014
Income
Revenue 2,944 2,451 8,449 7,569
Net income attributable to common shares 402 457 1,218 1,285
per common share - basic and diluted $0.57 $0.64 $1.72 $1.81
Comparable EBITDA1 1,483 1,387 4,381 4,000
Comparable earnings1 440 450 1,302 1,204
per common share1 $0.62 $0.63 $1.84 $1.70
Operating cash flow
Funds generated from operations1 1,140 1,071 3,354 3,090
Decrease/(increase) in operating working capital 107 171 (378 ) 250
Net cash provided by operations 1,247 1,242 2,976 3,340
Investing activities
Capital expenditures 976 744 2,748 2,381
Capital projects under development 130 207 465 504
Equity investments 105 66 303 195
Acquisitions - 181 - 181
Proceeds from sale of assets, net of transaction costs - - - 187
Dividends declared
Per common share $0.52 $0.48 $1.56 $1.44
Basic common shares outstanding (millions)
Average for the period 709 708 709 708
End of period 709 709 709 709
(1) Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See the non-GAAP measures section for more information.

Management's discussion and analysis

November 2, 2015

This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and nine months ended September 30, 2015, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2015 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2014 audited consolidated financial statements and notes and the MD&A in our 2014 Annual Report.

About this document

Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.

Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2014 Annual Report.

All information is as of November 2, 2015 and all amounts are in Canadian dollars, unless noted otherwise.

FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this MD&A may include information about the following, among other things:
  • anticipated business prospects
  • 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 costs for planned projects, including projects under construction and in development
  • expected schedules for planned projects (including anticipated construction and completion dates)
  • expected regulatory processes and outcomes
  • expected impact of regulatory outcomes
  • expected outcomes with respect to legal proceedings, including arbitration and insurance claims
  • expected capital expenditures and contractual obligations
  • expected operating and financial results
  • the expected impact of future accounting changes, commitments and contingent liabilities
  • 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 subject to the following risks and uncertainties:

Assumptions
  • inflation rates, commodity prices and capacity prices
  • timing of financings and hedging
  • regulatory decisions and outcomes
  • foreign exchange rates
  • interest rates
  • tax rates
  • 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
  • acquisitions and divestitures.
Risks and uncertainties
  • our ability to successfully implement our strategic initiatives
  • whether our strategic initiatives 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 we receive from our energy business
  • regulatory decisions and outcomes
  • outcomes of legal proceedings, including arbitration and insurance claims
  • performance of our counterparties
  • changes in market commodity prices
  • 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
  • interest, tax and foreign exchange rates
  • weather
  • cyber security
  • technological developments
  • economic conditions in North America as well as globally.

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

You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, except as required by law.

FOR MORE INFORMATION

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

NON-GAAP MEASURES

We use the following non-GAAP measures:

  • EBITDA
  • EBIT
  • funds generated from operations
  • comparable earnings
  • comparable earnings per common share
  • comparable EBITDA
  • comparable EBIT
  • comparable depreciation and amortization
  • comparable interest expense
  • comparable interest income and other expense
  • comparable income tax expense.

These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures.

EBITDA and EBIT

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

Funds generated from operations

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

Comparable measures

We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

Comparable measure Original measure
comparable earnings net income attributable to common shares
comparable earnings per common share net income per common share
comparable EBITDA EBITDA
comparable EBIT segmented earnings
comparable depreciation and amortization depreciation and amortization
comparable interest expense interest expense
comparable interest income and other expense interest income and other expense
comparable income tax expense income tax expense
Our decision not to include 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 rates
  • gains or losses on sales of assets
  • legal, contractual and bankruptcy settlements
  • impact of regulatory or arbitration decisions relating to prior year earnings
  • restructuring costs
  • write-downs of assets and investments.

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

Consolidated results - third quarter 2015
three months ended
September 30
nine months ended
September 30
(unaudited - millions of $, except per share amounts) 2015 2014 2015 2014
Natural Gas Pipelines 528 484 1,648 1,566
Liquids Pipelines 287 226 783 613
Energy 249 359 730 832
Corporate (45 ) (37 ) (140 ) (107 )
Total segmented earnings 1,019 1,032 3,021 2,904
Interest expense (341 ) (304 ) (990 ) (875 )
Interest income and other expense 16 17 83 63
Income before income taxes 694 745 2,114 2,092
Income tax expense (223 ) (239 ) (680 ) (625 )
Net income 471 506 1,434 1,467
Net income attributable to non-controlling interests (46 ) (25 ) (145 ) (110 )
Net income attributable to controlling interests 425 481 1,289 1,357
Preferred share dividends (23 ) (24 ) (71 ) (72 )
Net income attributable to common shares 402 457 1,218 1,285
Net income per common share - basic and diluted $0.57 $0.64 $1.72 $1.81

Net income attributable to common shares decreased by $55 million and $67 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. The 2015 results included:

  • a charge of $6 million after tax in third quarter and $14 million after tax year-to-date for severance costs as part of a restructuring initiative to maximize the effectiveness and efficiency of our existing operations along with the restructuring of our major projects group in response to delayed timelines on certain of our major projects in second quarter 2015
  • a $34 million adjustment in second quarter 2015 to income tax expense due to the enactment of a two per cent increase in the Alberta corporate income tax rate in June 2015.
The nine-month 2014 results included:
  • a gain on sale of Cancarb Limited and its related power generation business of $99 million after tax
  • a net loss resulting from the termination of a contract with Niska Gas Storage of $32 million after tax.

Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.

Comparable earnings decreased by $10 million for the three months ended September 30, 2015 and increased $98 million for the nine months ended September 30, 2015 compared to the same periods in 2014 as discussed below in the reconciliation of net income to comparable earnings.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
three months ended
September 30
nine months ended
September 30
(unaudited - millions of $, except per share amounts) 2015 2014 2015 2014
Net income attributable to common shares 402 457 1,218 1,285
Specific items (net of tax):
Alberta corporate income tax rate increase - - 34 -
Restructuring costs 6 - 14 -
Cancarb gain on sale - - - (99 )
Niska contract termination - 1 - 32
Risk management activities1 32 (8 ) 36 (14 )
Comparable earnings 440 450 1,302 1,204
Net income per common share $0.57 $0.64 $1.72 $1.81
Specific items (net of tax):
Alberta corporate income tax rate increase - - 0.05 -
Restructuring costs 0.01 - 0.02 -
Cancarb gain on sale - - - (0.14 )
Niska contract termination - - - 0.04
Risk management activities1 0.04 (0.01 ) 0.05 (0.01 )
Comparable earnings per share $0.62 $0.63 $1.84 $1.70
(1) Risk management activities three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Canadian Power (14 ) 2 (7 ) -
U.S. Power (5 ) 41 (22 ) 30
Natural Gas Storage 2 7 2 4
Foreign exchange (26 ) (32 ) (25 ) (9 )
Income tax attributable to risk management activities 11 (10 ) 16 (11 )
Total (losses)/gains from risk management activities (32 ) 8 (36 ) 14
Comparable earnings decreased by $10 million for the three months ended September 30, 2015 compared to the same period in 2014. This was primarily the net effect of:
  • lower earnings from Bruce Power due to lower volumes resulting from higher planned outage days and higher operating expenses at Bruce A, as well as losses from contracting activities and higher operating expenses, partially offset by lower lease expense at Bruce B
  • lower earnings from Western Power as a result of lower realized power prices
  • higher interest expense from new debt issuances
  • higher earnings from Liquids Pipelines due to higher uncontracted volumes on the Keystone Pipeline System
  • higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York
  • higher ANR Southeast mainline transportation revenue, partially offset by increased spending on ANR pipeline integrity work
  • higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in the second half of 2014.
Comparable earnings increased by $98 million for the nine months ended September 30, 2015 compared to the same period in 2014. This was primarily the net effect of:
  • higher earnings from Liquids Pipelines due to higher uncontracted volumes on the Keystone Pipeline System
  • higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in 2014, higher contractual earnings at Bécancour and the sale of unused natural gas transportation
  • higher earnings from U.S. Power mainly due to increased margins and higher sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York and lower earnings on U.S. generating assets as a result of lower realized power prices and reduced generation
  • higher earnings from U.S. and International Pipelines due to higher ANR Southeast transportation revenue and ANR's first quarter 2015 settlement with an owner of adjacent facilities for commercial interruption of ANR's service, partially offset by increased spending on ANR pipeline integrity work, plus increased earnings from the Tamazunchale Extension which was placed in service in 2014
  • lower earnings from Western Power as a result of lower realized power prices
  • higher interest expense from debt issuances.

The stronger U.S. dollar this quarter compared to the same period in 2014 positively impacted the translated results in our U.S. businesses, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our exposure.

CAPITAL PROGRAM

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

Our capital program is comprised of $11 billion of small to medium-sized, shorter-term projects, $35 billion of commercially secured large-scale, medium and longer-term projects and $1 billion of acquisitions. Amounts presented exclude the impact of foreign exchange, AFUDC and capitalized interest.

Estimated project costs are generally based on the last announced project estimates and are subject to adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.

at September 30, 2015
(unaudited - billions of $) Segment Expected
in-service date
Estimated project cost Amount spent
Small to medium sized, shorter-term
Houston Lateral and Terminal Liquids Pipelines 2016 US 0.6 US 0.5
Topolobampo Natural Gas Pipelines 2016 US 1.0 US 0.8
Mazatlan Natural Gas Pipelines 2016 US 0.4 US 0.3
Grand Rapids1 Liquids Pipelines 2016-2017 1.5 0.4
Northern Courier Liquids Pipelines 2017 1.0 0.5
Canadian Mainline Natural Gas Pipelines 2015-2016 0.4 -
NGTL System
- North Montney Natural Gas Pipelines 2017 1.7 0.3
- 2016/17 Facilities Natural Gas Pipelines 2016-2018 2.7 0.2
- Other Natural Gas Pipelines 2015-2017 0.5 0.2
Napanee Energy 2017 or 2018 1.0 0.3
10.8 3.5
Large-scale, medium and longer-term
Heartland and TC Terminals Liquids Pipelines 2 0.9 0.1
Upland Liquids Pipelines 2020 US 0.6 -
Keystone projects
Keystone XL3 Liquids Pipelines 4 US 8.0 US 2.4
Keystone Hardisty Terminal Liquids Pipelines 4 0.3 0.2
Energy East projects
Energy East5 Liquids Pipelines 2020 12.0 0.7
Eastern Mainline Natural Gas Pipelines 2019 2.0 0.1
BC west coast LNG-related projects
Coastal GasLink Natural Gas Pipelines 2019+ 4.8 0.3
Prince Rupert Gas Transmission Natural Gas Pipelines 2020 5.0 0.4
NGTL System - Merrick Natural Gas Pipelines 2020 1.9 -
35.5 4.2
Acquisition
Ironwood 2016 US 0.7 -
47.0 7.7
(1) Represents our 50 per cent share.
(2) In-service date to be aligned with industry requirements.
(3) Estimated project cost dependent on the timing of the Presidential permit.
(4) Approximately two years from the date the Keystone XL permit is received.
(5) Excludes transfer of Canadian Mainline natural gas assets.

Outlook

The earnings outlook for 2015 is expected to be consistent with what was previously included in the 2014 Annual Report. See the MD&A in our 2014 Annual Report for further information about our outlook.

We expect our capital expenditures to be approximately $5 billion for 2015, a decrease of $1 billion from the outlook previously provided in our 2014 Annual Report due to project timing delays.

Natural Gas Pipelines

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

three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Comparable EBITDA 812 750 2,493 2,357
Comparable depreciation and amortization1 (284 ) (266 ) (845 ) (791 )
Comparable EBIT 528 484 1,648 1,566
Specific items2 - - - -
Segmented earnings 528 484 1,648 1,566
(1) Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.
(2) There were no specific items in any of these periods.

Natural Gas Pipelines segmented earnings increased by $44 million and $82 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.

three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Canadian Pipelines
Canadian Mainline 289 311 876 938
NGTL System 226 213 675 637
Foothills 26 26 81 80
Other Canadian pipelines1 7 7 21 17
Canadian Pipelines - comparable EBITDA 548 557 1,653 1,672
Comparable depreciation and amortization (212 ) (206 ) (632 ) (613 )
Canadian Pipelines - comparable EBIT 336 351 1,021 1,059
U.S. and International Pipelines (US$)
ANR 54 31 177 142
TC PipeLines, LP1,2 25 18 76 65
Great Lakes3 8 8 35 36
Other U.S. pipelines (Bison4, Iroquois1, GTN5, Portland6) 13 26 66 100
Mexico (Guadalajara, Tamazunchale) 44 43 138 117
International and other1,7 (2 ) (3 ) 2 (5 )
Non-controlling interests8 68 49 208 176
U.S. and International Pipelines - comparable EBITDA 210 172 702 631
Comparable depreciation and amortization (55 ) (54 ) (169 ) (162 )
U.S. and International Pipelines - comparable EBIT 155 118 533 469
Foreign exchange impact 49 10 138 44
U.S. and International Pipelines - comparable EBIT (Cdn$) 204 128 671 513
Business Development comparable EBITDA and EBIT (12 ) 5 (44 ) (6 )
Natural Gas Pipelines - comparable EBIT 528 484 1,648 1,566
(1) Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments. In November 2014, we sold our interest in Gas Pacifico/INNERGY.
(2) Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program which, when utilized, decreases our ownership interest in TC PipeLines, LP. On October 1, 2014, we sold our remaining 30 per cent direct interest in Bison to TC PipeLines, LP. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Bison and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.
Ownership percentage as of
September 30, 2015 April 1, 2015 October 1, 2014 January 1, 2014
TC PipeLines, LP 28.2 28.3 28.3 28.9
Effective ownership through TC PipeLines, LP:
Bison 28.2 28.3 28.3 20.2
GTN 28.2 28.3 19.8 20.2
Great Lakes 13.1 13.1 13.1 13.4
(3) Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.
(4) Effective October 1, 2014, we have no direct ownership in Bison. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.
(5) Effective April 1, 2015, we have no direct ownership in GTN. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.
(6) Represents our 61.7 per cent ownership interest.
(7) Includes our share of the equity income from Gas Pacifico/INNERGY and TransGas as well as general and administration costs relating to our U.S. and International Pipelines. In November 2014, we sold our interest in Gas Pacifico/INNERGY.
(8) Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

CANADIAN PIPELINES

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

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES
three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Canadian Mainline 47 61 161 185
NGTL System 70 61 200 182
Foothills 3 5 11 13

Net income for the Canadian Mainline decreased by $14 million and $24 million for the three months and nine months ended September 30, 2015 compared to the same periods in 2014. The decrease in net income is primarily due to a lower ROE of 10.10 per cent on deemed equity of 40 per cent in 2015 compared to 11.5 per cent in 2014 and a lower average investment base in 2015, partially offset by higher incentive earnings recorded in 2015 primarily in second quarter.

Net income for the NGTL System increased by $9 million and $18 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly due to a higher average investment base and OM&A incentive losses realized in 2014 under the terms of the 2013-2014 NGTL Settlement.

U.S. AND INTERNATIONAL PIPELINES

Earnings for our U.S. natural gas pipelines operations are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.

Comparable EBITDA for U.S. and International Pipelines increased by US$38 million for the three months ended September 30, 2015 compared to the same period in 2014. This increase was the net effect of higher ANR Southeast mainline transportation revenue, partially offset by increased spending on ANR pipeline integrity work.

Comparable EBITDA for U.S. and International Pipelines increased by US$71 million for the nine months ended September 30, 2015 compared to the same period in 2014. This increase was the net effect of:

  • higher ANR Southeast mainline transportation revenue and ANR's first quarter 2015 settlement with an owner of adjacent facilities for commercial interruption of ANR's service, partially offset by increased spending on ANR pipeline integrity work
  • higher earnings from the Tamazunchale Extension which was placed in service in 2014.

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

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $18 million and $54 million for three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly because of a higher investment base on the NGTL System, depreciation for the completed Tamazunchale Extension, and the effect of a stronger U.S. dollar.

BUSINESS DEVELOPMENT

Business development expenses were higher by $17 million and $38 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly due to increased business development activity as well as the third quarter 2014 recovery of amounts from partners for 2013 Alaska Gasline Inducement Act costs.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES
nine months ended September 30 Canadian Mainline1 NGTL System2 ANR3
(unaudited) 2015 2014 2015 2014 2015 2014
Average investment base (millions of $) 4,840 5,632 6,599 6,205 n/a n/a
Delivery volumes (Bcf)
Total 1,204 1,264 2,871 2,857 1,212 1,202
Average per day 4.4 4.6 10.5 10.5 4.4 4.4
(1) Canadian Mainline's throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2015 were 833 Bcf (2014 - 940 Bcf). Average per day was 3.1 Bcf (2014 - 3.5 Bcf).
(2) Field receipt volumes for the NGTL System for the nine months ended September 30, 2015 were 2,994 Bcf (2014 - 2,857 Bcf). Average per day was 11.0 Bcf (2014 - 10.5 Bcf).
(3) Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.

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
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Comparable EBITDA 355 281 980 771
Comparable depreciation and amortization1 (68 ) (55 ) (197 ) (158 )
Comparable EBIT 287 226 783 613
Specific items2 - - - -
Segmented earnings 287 226 783 613
(1) Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.
(2) There were no specific items in any of these periods.

Liquids Pipelines segmented earnings increased by $61 million and $170 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.

three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Keystone Pipeline System 363 275 997 779
Liquids Pipelines Business Development (8 ) 6 (17 ) (8 )
Liquids Pipelines - comparable EBITDA 355 281 980 771
Comparable depreciation and amortization (68 ) (55 ) (197 ) (158 )
Liquids Pipelines - comparable EBIT 287 226 783 613
Comparable EBIT denominated as follows:
Canadian dollars 58 58 175 157
U.S. dollars 173 155 480 417
Foreign exchange impact 56 13 128 39
287 226 783 613

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

Comparable EBITDA for the Keystone Pipeline System increased by $88 million and $218 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. These increases were primarily due to:

  • higher uncontracted volumes
  • a stronger U.S. dollar and its positive effect on the foreign exchange impact
  • incremental earnings from the Gulf Coast extension which was placed in service in late January 2014.

BUSINESS DEVELOPMENT

Business development expenses increased by $14 million and $9 million for the three and nine months ended September 30, 2015, as a result of increased business development activities.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $13 million and $39 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 due to the Gulf Coast extension being placed in service and the effect of a stronger U.S. dollar.

Energy

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

three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Comparable EBITDA 345 387 1,005 963
Comparable depreciation and amortization1 (79 ) (76 ) (248 ) (230 )
Comparable EBIT 266 311 757 733
Specific items (pre-tax):
Cancarb gain on sale - - - 108
Niska contract termination - (2 ) - (43 )
Risk management activities (17 ) 50 (27 ) 34
Segmented earnings 249 359 730 832
(1) Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

Energy segmented earnings decreased by $110 million and $102 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and included the following unrealized gains and losses from risk management activities:

(1) Risk management activities three months ended
September 30
nine months ended
September 30
(unaudited - millions of $, pre-tax) 2015 2014 2015 2014
Canadian Power (14 ) 2 (7 ) -
U.S. Power (5 ) 41 (22 ) 30
Natural Gas Storage 2 7 2 4
Total (losses)/gains from risk management activities (17 ) 50 (27 ) 34

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

The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with EBITDA, are discussed below.

three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Canadian Power
Western Power 24 75 73 193
Eastern Power 87 76 309 239
Bruce Power 57 111 202 199
Canadian Power- comparable EBITDA1 168 262 584 631
Comparable depreciation and amortization (47 ) (44 ) (141 ) (133 )
Canadian Power-comparable EBIT1 121 218 443 498
U.S. Power (US$)
U.S. Power - comparable EBITDA 141 117 338 291
Comparable depreciation and amortization (23 ) (26 ) (78 ) (80 )
U.S. Power - comparable EBIT 118 91 260 211
Foreign exchange impact 36 8 68 19
U.S. Power-comparable EBIT (Cdn$) 154 99 328 230
Natural Gas Storage and other - comparable EBITDA (1 ) 3 8 32
Comparable depreciation and amortization (3 ) (3 ) (9 ) (9 )
Natural Gas Storage and other - comparable EBIT (4 ) - (1 ) 23
Business Development comparable EBITDA and EBIT (5 ) (6 ) (13 ) (18 )
Energy-comparable EBIT1 266 311 757 733
(1) Includes our share of equity income from our investments in ASTC Power Partnership, Portlands Energy and Bruce Power.
Comparable EBITDA for Energy decreased by $42 million for the three months ended September 30, 2015 compared to the same period in 2014 due to the net effect of:
  • lower earnings from Bruce Power due to lower volumes resulting from higher planned outage days and higher operating expenses at Bruce A, as well as losses from contracting activities and higher operating expenses, partially offset by lower lease expense at Bruce B
  • lower earnings from Western Power as a result of lower realized power prices
  • higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York
  • higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in 2014
  • a stronger U.S. dollar and its positive effect on the foreign exchange impact.
Comparable EBITDA for Energy increased by $42 million for the nine months ended September 30, 2015 compared to the same period in 2014 due to the net effect of:
  • higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in 2014, higher contractual earnings at Bécancour and the sale of unused natural gas transportation
  • higher earnings from U.S. Power mainly due to increased margins and higher sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York and lower earnings on U.S. generating assets as a result of lower realized power prices and generation
  • lower earnings from Western Power as a result of lower realized power prices
  • lower earnings from Natural Gas Storage due to lower realized natural gas price spreads
  • a stronger U.S. dollar and its positive effect on the foreign exchange impact.
CANADIAN POWER
Western and Eastern Power
three months ended
September 30
nine months ended
September 30
(unaudited - millions of $) 2015 2014 2015 2014
Revenue1
Western Power 126 206 412 547
Eastern Power 119 92 358 322
Other2 1 - 49 57
246 298 819 926
(Loss)/income from equity investments3 (2 ) 14 13 42
Commodity purchases resold (83 ) (105 ) (266 ) (296 )
Plant operating costs and other (64 ) (54 ) (191 ) (240 )
Exclude risk management activities1 14 (2 ) 7 -
Comparable EBITDA 111 151 382 432
Comparable depreciation and amortization (47 ) (44 ) (141 ) (133 )
Comparable EBIT 64 107 241 299
Breakdown of comparable EBITDA
Western Power 24 75 73 193
Eastern Power 87 76 309 239
Comparable EBITDA 111 151 382 432
(1) The realized and unrealized gains and losses from financial derivatives used to manage Canadian Power's assets are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives included in revenue are excluded to arrive at Comparable EBITDA.
(2) Includes revenues from the sale of unused natural gas transportation, sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black up to April 15, 2014 when it was sold.
(3) Includes our share of equity (loss) or income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy. Equity (loss)/income does not include any earnings related to our risk management activities.
Sales volumes and plant availability
Includes our share of volumes from our equity investments.
three months ended
September 30
nine months ended
September 30
(unaudited) 2015 2014 2015 2014
Sales volumes (GWh)
Supply
Generation
Western Power 589 637 1,876 1,857
Eastern Power 1,083 563 3,145 2,436
Purchased
Sundance A & B...