TransCanada Reports Increase in Second Quarter Results, Comparable Earnings to $357 Million or $0.51 Per Share, Funds Generated from Operations of $955 Million

CALGARY, ALBERTA--(Marketwired - Jul 26, 2013) - TransCanada Corporation ( TRP.TO ) ( TRP ) (TransCanada or the Company) today announced comparable earnings for second quarter 2013 of $357 million or $0.51 per share, compared to $300 million or $0.43 per share for the same period in 2012. Net income attributable to common shares for second quarter 2013 was $365 million or $0.52 per share. TransCanada's Board of Directors also declared a quarterly dividend of $0.46 per common share for the quarter ending September 30, 2013, equivalent to $1.84 per common share on an annualized basis.

"All three of our business segments generated strong results during the second quarter," said Russ Girling, TransCanada's president and chief executive officer. "Higher power prices in Alberta, an increase in capacity prices in New York, the return to an eight unit site at Bruce Power and a higher Canadian Mainline allowed return on equity all contributed to a significant increase in earnings when compared to the same period last year. We were also pleased by the significant shipper interest in our Energy East Pipeline project, which would transport crude oil from western Canada to eastern Canadian markets and add to our existing $26 billion portfolio of commercially secured projects that are targeted for completion by the end of the decade."

Over the next three years, subject to required approvals, we expect to complete $13 billion of projects that are currently in advanced stages of development. They include the Gulf Coast Project, Keystone XL, the Keystone Hardisty Terminal, the initial phase of the Grand Rapids Pipeline, the Heartland Pipeline and TC Terminals projects, the Tamazunchale Pipeline Extension, the acquisition of nine Ontario Solar projects and ongoing expansion of the NGTL System.

We have also commercially secured an additional $13 billion of long-life, contracted energy infrastructure projects that are expected to be placed into service in 2016 and beyond. They include the Coastal GasLink and Prince Rupert Gas Transmission projects that would move natural gas to Canada's West Coast for liquefaction and shipment to Asian markets, the Topolobampo and Mazatlan Gas Pipeline projects in Mexico, completion of the Grand Rapids and Northern Courier oil pipeline projects in Northern Alberta, and the Napanee Generating Station in Eastern Ontario. TransCanada expects these projects to generate predictable, sustained earnings and cash flow.

Highlights

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

  • Second quarter financial results
    • Net income attributable to common shares of $365 million or $0.52 per share
    • Comparable earnings of $357 million or $0.51 per share
    • Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.1 billion
    • Funds generated from operations of $955 million
  • Net income attributable to common shares of $365 million or $0.52 per share
  • Comparable earnings of $357 million or $0.51 per share
  • Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.1 billion
  • Funds generated from operations of $955 million
  • Declared a quarterly dividend of $0.46 per common share for the quarter ending September 30
  • Construction on the US$2.3 billion Gulf Coast Project, excluding the Houston Lateral, is now 85 per cent complete
  • Comment period on the U.S. Department of State (DOS) Draft Supplemental Environmental Impact Statement for the Keystone XL Pipeline closed on April 22
  • Concluded Energy East open season to obtain firm commitments for a pipeline to transport crude oil from western receipt points to eastern Canadian markets
  • For the first time in two decades, Bruce Power is operating as an eight unit site with the return of Unit 4 on April 13 and the recent restart of Units 1 and 2
  • Acquired the first of nine Ontario Solar projects for $55 million on June 28
  • Sold a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP for US$1.05 billion on July 2

Comparable earnings for second quarter 2013 were $357 million or $0.51 per share compared to $300 million or $0.43 per share for the same period in 2012. Higher earnings from the Canadian Mainline, Western Power, Bruce Power and U.S. Power were partially offset by lower contributions from U.S. Natural Gas Pipelines.

Net income attributable to common shares for second quarter 2013 was $365 million or $0.52 per share compared to $272 million or $0.39 per share in second quarter 2012.

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

Oil Pipelines:

  • Gulf Coast Project : We are constructing a 36-inch pipeline from Cushing, Oklahoma to the U.S. Gulf Coast and expect to begin delivering crude oil to Port Arthur, Texas at the end of 2013. Construction is approximately 85 per cent complete and we estimate the cost of the Cushing to Port Arthur facilities to be US$2.3 billion.

    Construction of the 76 kilometre (km) (47 mile) Houston Lateral pipeline to transport crude oil to Houston refineries is expected to be complete in 2014 at a cost of US$300 million.

    The Gulf Coast Project will have a capacity of up to 700,000 barrels per day (bbl/d).
  • Keystone XL: On March 1, 2013, the DOS released its Draft Supplemental Environmental Impact Statement for the Keystone XL Pipeline. The impact statement reaffirmed that construction of the proposed pipeline from the U.S./Canada border in Montana to Steele City, Nebraska would not result in any significant impact to the environment. The DOS continues to review submissions on the impact statement that it received during a public comment period that ended on April 22, 2013. Once the DOS has completed its review, it is anticipated it will issue a Final Supplemental Environmental Impact Statement and then consult with other government agencies and provide an additional opportunity for the public to comment during a National Interest Determination period of up to 90 days, before making a decision on our Presidential Permit application.

    We anticipate the pipeline to be in service approximately two years following the receipt of the Presidential Permit. The US$5.3 billion cost estimate will increase depending on the timing of the permit. As of June 30, 2013, we had invested US$1.9 billion in the project.
  • Energy East Pipeline: On June 17, 2013, we concluded an open season to obtain firm commitments for a pipeline to transport up to 850,000 bbl/d of crude oil from western receipt points to eastern Canadian markets and are currently reviewing the results.

    The Energy East Pipeline project involves converting natural gas pipeline capacity in approximately 3,000 km (1,870 miles) of our existing Canadian Mainline to crude oil service and constructing up to approximately 1,400 km (870 miles) of new pipeline.

    We have begun Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. If we determine that there is sufficient commercial support for the project, we will apply for regulatory approval to build and operate the facilities, with a potential in-service date of late 2017.
  • Heartland Pipeline and TC Terminals : On May 2, 2013, we announced we had secured binding long-term shipping agreements to build, own and operate the proposed Heartland Pipeline and TC Terminals projects.

    The proposed projects will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton. We anticipate the pipeline could transport up to 900,000 bbl/d, while the terminal is expected to have storage capacity for up to 1.9 million barrels of crude oil. These projects together have a combined cost estimated at $900 million and are expected to come into service during the second half of 2015.

    On May 30, 2013, we filed a permit application for the terminal facility with the Alberta Energy Regulator and we expect to file an application for the pipeline later in 2013.
  • Northern Courier Pipeline: On April 25, 2013, we filed a permit application with the Alberta Energy Regulator after completing the required Aboriginal and stakeholder engagement and associated field work. We continue to work with the Fort Hills Energy Limited Partnership on the development of this project.
  • Grand Rapids Pipeline: On May 23, 2013, we filed a permit application with the Alberta Energy Regulator after completing the required Aboriginal and stakeholder engagement and associated field work. The Grand Rapids Pipeline system will be the first pipeline to connect the growing oil sands region west of the Athabasca River to the Edmonton/Heartland region and will be capable of moving up to 900,000 bbl/d of crude oil and 330,000 bbl/d of diluent.

Natural Gas Pipelines:

  • National Energy Board (NEB) decision on the Canadian Restructuring Proposal: On March 27, 2013, the NEB issued its decision on our application to change the business structure and the terms and conditions of service for the Canadian Mainline. The decision significantly alters the regulatory framework that has formed the basis for more than $10 billion of regulated pipeline investment over the last sixty years.

    On May 1, 2013, we filed an application for a review and variance of the decision and order. The NEB dismissed the review and variance application on June 11, 2013, and released its reasons for dismissal on July 22, 2013. The NEB did, however, recognize that certain changes proposed by TransCanada to the Canadian Mainline's tariff should be considered as a separate application through an oral hearing process that will commence on September 3, 2013.

    We are effectively operating under the new framework set out by the NEB in its decision as of July 1. We have submitted the tariff change application and will manage that process through the oral hearing and await a decision on those changes.
  • NGTL System: We continue to expand the NGTL System and have placed $700 million of new facilities into service in 2013. We have applied and received approval from the NEB for an additional $130 million of new facilities. To date in 2013, we have applied for an additional $145 million of facilities, which remain subject to NEB approval, and are planning regulatory applications for further expansion into British Columbia (B.C.), which we estimate will cost between $1.0 billion and $1.5 billion, to connect and transport new gas supply that will be delivered to the Prince Rupert Gas Transmission Project as well as other markets served by the NGTL System. In third quarter 2013, we expect to begin an open season to provide delivery service through a transportation by others arrangement on Coastal GasLink to Vanderhoof, B.C.
  • Prince Rupert Gas Transmission Project: The B.C. Environmental Assessment Office issued its Section 10 Order in June 2013 indicating that the project is reviewable and requires an environmental assessment certificate. The Canadian Environmental Assessment Agency (CEAA) initiated the public comment period with respect to the project in June 2013.
  • Coastal GasLink: We are currently focused on community, landowner, government and First Nations engagement as the project advances through the regulatory process with the B.C. Environmental Assessment Office and the CEAA.

Energy:

  • Bruce Power: Bruce Power returned Unit 4 to service on April 13, 2013 after completing an expanded life extension outage program which began in August 2012. It is anticipated that this investment will allow Unit 4 to operate until at least 2021. With the return of Unit 4 and the restart of Units 1 and 2, Bruce Power is now operating an eight unit site for the first time in two decades and is capable of generating 6,200 megawatts (MW) of emission-free electricity. No further maintenance outages are planned at Bruce Power for the remainder of 2013.

  • Sundance A: TransAlta previously announced that it expected Sundance A Units 1 and 2 to be returned to service in the fall of 2013. They subsequently reported an earlier return to service for Unit 1 of July 31, 2013. TransAlta has not announced any change in the return to service date for Unit 2. Combined, Units 1 and 2 are capable of generating 560 MW.

  • Ontario Solar: In late 2011, we agreed to buy nine Ontario solar projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc. for approximately $470 million. On June 28, 2013, we acquired the first project for $55 million which has a capacity of 10 MW. We expect to close the acquisition of the remaining projects in 2013 and 2014, subject to satisfactory completion of the related construction activities and regulatory approvals. All power produced will be sold under 20-year power purchase arrangements with the Ontario Power Authority.

  • Bécancour: In June 2013, Hydro-Québec notified us that it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant through 2014. Under the suspension agreement, Hydro-Québec has the option, subject to certain conditions, to extend the suspension every year until regional electricity demand levels recover. We continue to receive capacity payments while generation is suspended.

Corporate:

  • Our Board of Directors declared a quarterly dividend of $0.46 per share for the quarter ending September 30, 2013 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $1.84 per common share on an annual basis.
  • On July 2, 2013, we completed the sale of a 45 per cent interest in each of Gas Transmission Northwest LLC (GTN) and Bison Pipeline LLC (Bison) to our master limited partnership, TC PipeLines, LP, for an aggregate purchase price of US$1.05 billion which includes US$146 million for 45 per cent of GTN's debt. The proceeds from the sale will contribute to funding a portion of our capital program. The transaction demonstrates one of the many financing options available to us as we execute on our unprecedented growth portfolio.

    In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at a price of US$43.85 per unit, resulting in gross proceeds of approximately US$388 million. We invested US$8 million to maintain our two per cent general partnership interest and did not purchase any additional common units. Upon completion of this offering, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent.

    In July 2013, TC PipeLines, LP entered into a five-year, US$500 million term loan, maturing July 2018. The proceeds from the term loan were used to partially finance the acquisition of the 45 per cent interest in GTN and Bison.
  • In July 2013, we issued US$500 million of three-year LIBOR-based floating rate notes maturing on June 30, 2016, bearing interest at an initial annual rate of 0.95 per cent.

    Also in July 2013, we issued $450 million and $300 million of medium term notes maturing on July 19, 2023 and November 15, 2041, respectively, and bearing interest at 3.69 and 4.55 per cent per annum, respectively.

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

Teleconference - Audio and Slide Presentation:

We will hold a teleconference and webcast on Friday, July 26, 2013 to discuss our second quarter 2013 financial results. Russ Girling, TransCanada 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 9:00 a.m. (MDT) / 11:00 a.m. (EDT).

Analysts, members of the media and other interested parties are invited to participate by calling 866.507.1212 or 416.695.6616 (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 (EDT) on August 2, 2013. Please call 800.408.3053 or 905.694.9451 and enter pass code 1924325.

The unaudited interim Consolidated Financial Statements and Management's Discussion and Analysis (MD&A) are available 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 60 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,500 kilometres (42,500 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 more than 400 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 11,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com or check us out on Twitter @TransCanada or http://blog.transcanada.com .

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 July 25, 2013 and 2012 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, 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 July 25, 2013.

Quarterly report to shareholders

Second quarter 2013

Financial highlights

Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See non-GAAP measures section for more information.

three months ended
June 30
six months ended
June 30
(unaudited - millions of $, except per share amounts) 2013 2012 2013 2012
Income
Revenue 2,009 1,847 4,261 3,792
Comparable EBITDA 1,143 997 2,311 2,110
Net income attributable to common shares 365 272 811 624
per common share - basic $0.52 $0.39 $1.15 $0.89
Comparable earnings 357 300 727 663
per common share $0.51 $0.43 $1.03 $0.94
Operating cash flow
Funds generated from operations 955 729 1,871 1,600
(Increase)/decrease in operating working capital (114 ) 14 (324 ) (155 )
Net cash provided by operations 841 743 1,547 1,445
Investing activities
Capital expenditures 1,109 397 2,038 861
Equity investments 39 197 71 413
Acquisition 55 - 55 -
Dividends
Per common share $0.46 $0.44 $0.92 $0.88
Basic common shares outstanding (millions)
Average for the period 707 704 706 704
End of period 707 704 707 704

Management's discussion and analysis

July 25, 2013

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, 2013, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2013 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2012 audited consolidated financial statements and notes and the MD&A in our 2012 Annual Report, which have been prepared in accordance with U.S. GAAP.

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 2012 Annual Report.

All information is as of July 25, 2013 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 required as a result of regulatory outcomes
  • expected outcomes with respect to legal proceedings, including arbitration
  • expected capital expenditures and contractual obligations
  • expected operating and financial results
  • the expected impact of future 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
  • performance of our counterparties
  • 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
  • labour, equipment and material costs
  • access to capital markets
  • interest and foreign exchange rates
  • weather
  • cybersecurity
  • 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 2012 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, unless we are required to by law.

FOR MORE INFORMATION

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

NON-GAAP MEASURES

We use the following non-GAAP measures:

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

These measures 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 entities.

EBITDA and EBIT

We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting interest and other financial charges, income taxes, 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 an effective measure of our performance and an effective tool for evaluating trends in each segment. 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 an effective measure of our consolidated operating cashflow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period. See 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 EBIT
comparable depreciation and amortization depreciation and amortization
comparable interest expense interest expense
comparable interest income and other interest income and other
comparable income taxes income tax expense/(recovery)

Our decision not to include a specific item is subjective and made after careful consideration. These may include:

  • certain fair value adjustments relating to risk management activities
  • income tax refunds and adjustments
  • gains or losses on sales of assets
  • legal and bankruptcy settlements, and
  • write-downs of assets and investments.

In our calculation of comparable earnings, we exclude 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 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.

Reconciliation of non-GAAP measures

three months ended
June 30
six months ended
June 30
(unaudited - millions of $, except per share amounts) 2013 2012 2013 2012
Comparable EBITDA 1,143 997 2,311 2,110
Comparable depreciation and amortization (356 ) (346 ) (710 ) (690 )
Comparable EBIT 787 651 1,601 1,420
Other income statement items
Comparable interest expense (252 ) (239 ) (509 ) (481 )
Comparable interest income and other (2 ) 19 16 44
Comparable income taxes (133 ) (91 ) (292 ) (231 )
Net income attributable to non-controlling interests (23 ) (26 ) (54 ) (61 )
Preferred share dividends (20 ) (14 ) (35 ) (28 )
Comparable earnings 357 300 727 663
Specific items (net of tax):
Canadian restructuring proposal - 2012 - - 84 -
Income tax adjustment 25 - 25 -
Sundance A PPA arbitration decision - 2011 - (15 ) - (15 )
Risk management activities 1 (17 ) (13 ) (25 ) (24 )
Net income attributable to common shares 365 272 811 624
Comparable depreciation and amortization (356 ) (346 ) (710 ) (690 )
Specific item:
Canadian restructuring proposal - 2012 - - (13 ) -
Depreciation and amortization (356 ) (346 ) (723 ) (690 )
Comparable interest expense (252 ) (239 ) (509 ) (481 )
Specific item:
Canadian restructuring proposal - 2012 - - (1 ) -
Interest expense (252 ) (239 ) (510 ) (481 )
Comparable interest income and other (2 ) 19 16 44
Specific items:
Canadian restructuring proposal - 2012 - - 1 -
Risk management activities 1 (9 ) (14 ) (15 ) (8 )
Interest income and other (11 ) 5 2 36
Comparable income taxes (133 ) (91 ) (292 ) (231 )
Specific items:
Canadian restructuring proposal - 2012 - - 42 -
Income tax adjustment 25 - 25 -
Income taxes attributable to Sundance A PPA arbitration decision - 2011 - 5 - 5
Risk management activities 1 10 1 12 12
Income taxes expense (98 ) (85 ) (213 ) (214 )
Comparable earnings per common share $0.51 $0.43 $1.03 $0.94
Specific items (net of tax):
Canadian restructuring proposal - 2012 - - 0.12 -
Income tax adjustment 0.04 - 0.04 -
Sundance A PPA arbitration decision - 2011 - (0.02 ) - (0.02 )
Risk management activities 1 (0.03 ) (0.02 ) (0.04 ) (0.03 )
Net income per common share $0.52 $0.39 $1.15 $0.89
three months ended
June 30
six months ended
June 30
1 (unaudited - millions of $) 2013 2012 2013 2012
Canadian Power (4 ) 1 (6 ) (1 )
U.S. Power (18 ) 16 (17 ) (16 )
Natural Gas Storage 4 (17 ) 1 (11 )
Foreign exchange (9 ) (14 ) (15 ) (8 )
Income taxes attributable to risk management activities 10 1 12 12
Total losses from risk management activities (17 ) (13 ) (25 ) (24 )
EBITDA and EBIT by business segment
three months ended June 30, 2013
(unaudited - millions of $)
Natural Gas Pipelines Oil Pipelines
Energy

Corporate

Total
Comparable EBITDA 644 186 330 (17 ) 1,143
Comparable depreciation and amortization (245 ) (37 ) (69 ) (5 ) (356 )
Comparable EBIT 399 149 261 (22 ) 787
three months ended June 30, 2012
(unaudited - millions of $)
Natural Gas Pipelines Oil Pipelines
Energy

Corporate

Total
Comparable EBITDA 666 176 170 (15 ) 997
Comparable depreciation and amortization (234 ) (36 ) (72 ) (4 ) (346 )
Comparable EBIT 432 140 98 (19 ) 651
six months ended June 30, 2013
(unaudited - millions of $)
Natural Gas Pipelines Oil Pipelines
Energy

Corporate

Total
Comparable EBITDA 1,390 365 607 (51 ) 2,311
Comparable depreciation and amortization (485 ) (74 ) (143 ) (8 ) (710 )
Comparable EBIT 905 291 464 (59 ) 1,601
six months ended June 30, 2012
(unaudited - millions of $)
Natural Gas Pipelines Oil Pipelines
Energy

Corporate

Total
Comparable EBITDA 1,391 349 414 (44 ) 2,110
Comparable depreciation and amortization (466 ) (72 ) (145 ) (7 ) (690 )
Comparable EBIT 925 277 269 (51 ) 1,420

Results - second quarter 2013

Net income attributable to common shares was $365 million this quarter compared to $272 million in second quarter 2012. Second quarter 2013 results included a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax, in June 2013 and was excluded from comparable earnings. Second quarter 2012 included an after-tax charge of $37 million ($50 million pre-tax) related to the impact of the Sundance A PPA arbitration decision. Of this amount, $15 million ($20 million pre-tax) is excluded from 2012 comparable earnings as it related to 2011.

Net income attributable to common shares was $811 million for the six months ended June 30, 2013 compared to $624 million for the same period in 2012. The 2013 results included $84 million of net income related to 2012 from the NEB decision on the Canadian Restructuring Proposal. Also included was the $25 million of net income resulting from the favourable income tax adjustment noted above. These amounts were excluded from comparable earnings. The 2012 results included an after-tax charge of $15 million ($20 million pre-tax) that was excluded from 2012 comparable earnings as it related to 2011.

Comparable earnings this quarter were $357 million and $0.51 per share, $57 million and $0.08 per share higher than second quarter 2012.

This was the result of:

  • higher earnings from Western Power because of higher realized power prices, higher purchased PPA volumes as well as the Sundance A PPA charge recorded in second quarter 2012
  • higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, and the completion of the Unit 3 West Shift Plus planned outage in June 2012, partially offset by higher planned outage days in second quarter 2013
  • higher realized power prices from U.S. Power
  • higher earnings from the Canadian Mainline because of the higher ROE of 11.50 per cent in 2013 compared to 8.08 per cent in 2012.

These increases were partly offset by:

  • lower contribution from U.S. natural gas pipelines
  • higher comparable interest expense reflecting lower capitalized interest primarily as a result of the return to service of Bruce Power Units 1 and 2
  • lower comparable interest income and other because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
  • higher comparable income taxes because of higher pre-tax earnings.

Comparable earnings for the six months ended June 30, 2013 were $727 million and $1.03 per share, $64 million and $0.09 per share higher than the same period in 2012.

This was the result of:

  • higher equity income from Bruce Power because of incremental earnings from Units 1, 2 and 3 and the recognition of an insurance recovery in first quarter 2013 partly offset by an increase in planned outage days
  • higher realized power prices in Western Power and U.S. Power
  • higher earnings from the Canadian Mainline because of the higher ROE of 11.50 per cent in 2013 compared to 8.08 per cent in 2012.

These increases were partly offset by:

  • lower contribution from U.S. natural gas pipelines
  • lower comparable interest income and other because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
  • higher comparable income taxes because of higher pre-tax earnings.

Comparable earnings do not include net unrealized after-tax losses resulting from changes in the fair value of certain risk management activities:

  • $17 million ($27 million before tax) for the three months ended June 30, 2013 compared to $13 million ($14 million before tax) for the same period in 2012
  • $25 million ($37 million before tax) for the six months ended June 30, 2013 compared to $24 million ($36 million before tax) for the same period in 2012.

Outlook

While the NEB's March 27, 2013 decision on the Canadian Restructuring Proposal for tolls and services on the Canadian Mainline may result in increased variability and seasonality of cash flow, we expect it to have a positive impact on the earnings outlook for 2013 previously included in our 2012 Annual Report. The NEB approved an allowed ROE of 11.50 per cent on 40 per cent deemed common equity ratio, multi-year tolls through 2017 and a new incentive mechanism. In addition, we expect the recent increase in 2013 power prices in Western Power to also have a positive impact on our previously disclosed earnings outlook for 2013. See the MD&A in our 2012 Annual Report for further information about our outlook.

Natural Gas Pipelines

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended
June 30
six months ended
June 30
(unaudited - millions of $) 2013 2012 2013 2012
Canadian Pipelines
Canadian Mainline 263 247 543 497
NGTL System 193 183 375 360
Foothills 28 30 57 61
Other Canadian (TQM 1 , Ventures LP) 7 7 13 15
Canadian Pipelines - comparable EBITDA 491 467 988 933
Comparable depreciation and amortization 2 (190 ) (177 ) (374 ) (354 )
Canadian Pipelines - comparable EBIT 301 290 614 579
U.S. and International (US$)
ANR 32 53 122 150
GTN 3 26 26 54 56
Great Lakes 4 8 17 18 35
TC PipeLines, LP 1,5 13 18 30 38
Other U.S. pipelines (Iroquois 1 , Bison 3 , Portland 6 ) 23 23 66 57
International (Gas Pacifico/INNERGY 1 , Guadalajara, Tamazunchale, TransGas 1 ) 25 30 51 58
General, administrative and support costs (3 ) (2 ) (5 ) (4 )
Non-controlling interests 7 31 38 74 83
U.S. Pipelines and International - comparable EBITDA 155 203 410 473
Comparable depreciation and amortization 2 (54 ) (56 ) (109 ) (111 )
U.S. Pipelines and International - comparable EBIT 101 147 301 362
Foreign exchange 2 2 4 2
U.S. Pipelines and International - comparable EBIT (Cdn$) 103 149 305 364
Business Development comparable EBITDA and EBIT (5 ) (7 ) (14 ) (18 )
Natural Gas Pipelines - comparable EBIT 399 432 905 925
Summary
Natural Gas Pipelines - comparable EBITDA 644 666 1,390 1,391
Comparable depreciation and amortization 2 (245 ) (234 ) (485 ) (466 )
Natural Gas Pipelines - comparable EBIT 399 432 905 925
(1) Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments.
(2) Does not include depreciation and amortization from equity investments.
(3) Represents our 75 per cent direct ownership interest.
(4) Represents our 53.6 per cent direct ownership interest.
(5) Effective May 22, 2013, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. Results reflect our 28.9 per cent ownership interest effective May 22, 2013 and 33.3 per cent from January 1 to May 22, 2013. Our effective ownership through TC PipeLines, LP prior to May 22, 2013 was 8.3 per cent of each of GTN and Bison, 16.7 per cent of Northern Border and an additional effective ownership of 15.4 per cent of Great Lakes. Our effective ownership through TC PipeLines, LP effective May 22, 2013 was 7.2 per cent of each of GTN and Bison, 14.4 per cent of Northern Border and an additional effective ownership of 13.4 per cent of Great Lakes.
(6) Represents our 61.7 per cent ownership interest.
(7) Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.
NET INCOME - WHOLLY OWNED CANADIAN PIPELINES
three months ended
June 30
six months ended
June 30
(unaudited - millions of $) 2013 2012 2013 2012
Canadian Mainline - net income 67 46 218 93
Canadian Mainline - comparable earnings 67 46 134 93
NGTL System 58 52 114 100
Foothills 5 4 9 9
OPERATING STATISTICS - WHOLLY OWNED PIPELINES
six months ended June 30 Canadian Mainline 1 NGTL System 2 ANR 3
(unaudited) 2013 2012 2013 2012 2013 2012
Average investment base (millions of $) 5,871 5,775 5,882 5,359 n/a n/a
Delivery volumes (Bcf)
Total 704 804 1,832 1,844 823 844
Average per day 3.9 4.4 10.1 10.1 4.6 4.6
(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 six months ended June 30, 2013 were 397 Bcf (2012 - 455 Bcf). Average per day was 2.2 Bcf (2012 - 2.5 Bcf).
(2) Field receipt volumes for the NGTL System for the six months ended June 30, 2013 were 1,840 Bcf (2012 - 1,856 Bcf). Average per day was 10.2 Bcf (2012 - 10.2 Bcf).
(3) Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.

CANADIAN PIPELINES

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

Canadian Mainline's comparable earnings increased by $21 million for the three months ended June 30, 2013 and $41 million for the six months ended June 30, 2013 compared to the same periods in 2012 because of the impact of the NEB's March 2013 decision (the NEB decision) on the Canadian Restructuring Proposal. Among other items, the NEB approved an ROE of 11.50 per cent on a 40 per cent deemed common equity for the years 2012 through to 2017 compared to the last approved ROE of 8.08 per cent on a deemed common equity of 40 per cent that was used to record earnings in 2012. Net income of $218 million for the six months ended June 30, 2013 included $84 million related to the 2012 impact of the NEB decision.

Net income for the NGTL System (formerly known as the Alberta System) increased by $6 million for the three months ended June 30, 2013 and $14 million for the six months ended June 30, 2013, compared to the same periods in 2012 because of a higher average investment base and termination of the annual fixed OM&A costs component included in the 2010 - 2012 Revenue Requirement Settlement which expired at the end of 2012. Results for 2013 reflect the last approved ROE of 9.70 per cent on deemed common equity of 40 per cent and no incentive earnings.

U.S. PIPELINES AND INTERNATIONAL

EBITDA for our U.S. operations is 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 the U.S. and international pipelines was US$155 million for the three months ended June 30, 2013 and US$410 million for the six months ended June 30, 2013 compared to US$203 million and US$473 million for the same periods in 2012. This was the net effect of:

  • higher costs at ANR relating to services provided by other pipelines as well as lower second quarter revenues
  • lower revenues at Great Lakes because of lower rates and uncontracted capacity
  • lower contributions from TransGas and Gas Pacifico/INNERGY
  • higher short term and interruptible revenues at Portland.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization was $245 million for the three months ended June 30, 2013 and $485 million for the six months ended June 30, 2013 compared to $234 million and $466 million for the same periods in 2012 mainly because of a higher investment base on the NGTL System and the impact of the NEB decision on the Canadian Mainline.

Oil Pipelines

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended
June 30
six months ended
June 30
(unaudited - millions of $) 2013 2012 2013 2012
Keystone Pipeline System 187 178 373 352
Oil Pipelines Business Development (1 ) (2 ) (8 ) (3 )
Oil Pipelines - comparable EBITDA 186 176 365 349
Comparable depreciation and amortization (37 ) (36 ) (74 ) (72 )
Oil Pipelines - comparable EBIT 149 140 291 277
Comparable EBIT denominated as follows:
Canadian dollars 52 51 99 99
U.S. dollars 95 88 189 177
Foreign exchange 2 1 3 1
149 140 291 277

Comparable EBITDA for the Keystone Pipeline System increased by $9 million for the three months ended June 30, 2013 and $21 million for the six months ended June 30, 2013 compared to the same periods in 2012. These increases reflected higher revenues primarily resulting from:

  • higher contracted volumes
  • higher final fixed tolls on committed pipeline capacity to Cushing, Oklahoma, which came into effect in July 2012.

BUSINESS DEVELOPMENT

Business development expenses in the first six months of 2013 were $5 million higher than the same period in 2012 because of increased activity on various development projects.

Energy

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended
June 30
six months ended
June 30
(unaudited - millions of $) 2013 2012 2013 2012
Canadian Power
Western Power 1 123 27 202 158
Eastern Power 1,2 75 73 170 166
Bruce Power 1 59 31 90 18
General, administrative and support costs (12 ) (11 ) (22 ) (22 )
Canadian Power - comparable EBITDA 1 245 120 440 320
Comparable depreciation and amortization 3 (43 ) (39 ) (86 ) (79 )
Canadian Power - comparable EBIT 1 202 81 354 241
U.S. Power (US$)
Northeast Power 92 49 169 95
General, administrative and support costs (12 ) (11 ) (22 ) (21 )
U.S. Power - comparable EBITDA 80 38 147 74
Comparable depreciation and amortization (23 ) (30 ) (51 ) (60 )
U.S. Power - comparable EBIT 57 8 96 14
Foreign exchange 1 1 2 1
U.S. Power - comparable EBIT (Cdn$) 58 9 98 15
Natural Gas Storage
Alberta Storage 11 19 31 34
General, administrative and support costs (2 ) (2 ) (4 ) (4 )
Natural Gas Storage - comparable EBITDA 1 9 17 27 30
Comparable depreciation and amortization 3 (2 ) (3 ) (5 ) (6 )
Natural Gas Storage - comparable EBIT 1 7 14 22 24
Business Development comparable EBITDA and EBIT (6 ) (6 ) (10 ) (11 )
Energy - comparable EBIT 1 261 98 464 269
Summary
Energy - comparable EBITDA 1 330 170 607 414
Comparable depreciation and amortization 3 (69 ) (72 ) (143 ) (145 )
Energy - comparable EBIT 1 261 98 464 269
(1) Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, Portlands Energy, Bruce Power and, in 2012, CrossAlta. In December 2012, we acquired the remaining 40 per cent interest in CrossAlta, bringing our ownership interest to 100 per cent.
(2) Includes phase two of Cartier Wind Gros-Morne starting in November 2012 and the acquisition of the first Ontario Solar project in June 2013.
(3) Does not include depreciation and amortization of equity investments.

Comparable EBITDA for Energy increased by $160 million for the three months ended June 30, 2013 compared to the same period in 2012. The increase was the effect of:

  • higher earnings from Western Power primarily due to higher realized power prices, the Sundance A PPA charge recorded in second quarter 2012 earnings and higher purchased PPA volumes
  • higher earnings from U.S. Power mainly because of higher realized power and capacity prices in New York
  • higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, and higher earnings from Unit 3, due to an outage during first and second quarter 2012, partially offset by lower Bruce B volumes due to higher planned outage days.

Comparable EBITDA for Energy increased by $193 million for the six months ended June 30, 2013 compared to the same period in 2012. The increase was the effect of:

  • higher earnings from U.S. Power mainly because of higher realized power prices and higher capacity prices in New York
  • higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, the recognition of a business interruption insurance recovery in first quarter 2013, and higher earnings from Unit 3 due to the first and second quarter 2012 outage partially offset by the extended outage of Unit 4 in first quarter 2013 and lower Bruce B volumes due to higher planned outage days
  • higher earnings from Western Power primarily due to higher realized power prices and higher purchased PPA volumes.

CANADIAN POWER

Western and Eastern Power 1

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

...
three months ended
June 30
six months ended
June 30
(unaudited - millions of $) 2013 2012 2013 2012
Revenue
Western Power 161 106 303 330
Eastern Power 1 91 98 200 201
Other 2 22 22 53 47
274 226 556 578
Income from equity investments 3 66 (6 ) 88 17
Commodity purchases resold
Western power (82 ) (43 ) (147 ) (137 )
Other 4 (1 ) - (3 ) (2 )
(83 ) (43 ) (150 ) (139 )
Plant operating costs and other (59 ) (47 ) (122 ) (102 )
Sundance A PPA arbitration decision - 2012 - (30 ) -