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TransCanada Reports First Quarter Results, Continues to Advance $25 Billion Portfolio of Projects

CALGARY, ALBERTA--(Marketwired - Apr 26, 2013) - TransCanada Corporation (TRP.TO) (TRP) (TransCanada or the Company) today announced net income attributable to common shares for first quarter 2013 of $446 million or $0.63 per share. The first quarter financial results include the impact of the National Energy Board (NEB) decision received in the period on our Canadian Restructuring Proposal. In the decision, among other items, the NEB approved a return on equity for the Canadian Mainline of 11.50 per cent for the years 2012 to 2017 compared to the last approved return on equity of 8.08 per cent. As a result, net income includes $84 million or $0.12 per share related to 2012. Excluding this and certain other minor amounts, comparable earnings were $370 million or $0.52 per share. Our Board of Directors also declared a quarterly dividend of $0.46 per common share for the quarter ending June 30, 2013, equivalent to $1.84 per share on an annualized basis.

"Our three business segments performed well during the first quarter," said Russ Girling, TransCanada's president and chief executive officer. "The restart of Bruce Power Units 1 and 2, the completion of the Bruce Power Unit 4 life extension outage in April, the return to service of Sundance A this fall and a higher Canadian Mainline return on equity are all expected to have a positive impact on earnings in 2013. At the same time, we continue to progress our $25 billion portfolio of commercially secured projects and advance other value creating opportunities including the Energy East Pipeline Project which would transport crude oil from western receipt points to eastern Canadian markets."

Over the next three years, subject to required approvals, we expect to complete $12 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 Tamazunchale Pipeline Extension, the acquisition of nine Ontario Solar projects, and the 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)

  • First quarter financial results
    • Net income attributable to common shares of $446 million or $0.63 per share
    • Comparable earnings of $370 million or $0.52 per share
    • Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.2 billion
    • Funds generated from operations of $916 million
  • Declared a quarterly dividend of $0.46 per common share for the quarter ending June 30
  • Received NEB decision on our Canadian Restructuring Proposal
  • Bruce Power Units 1 and 2 now able to operate at full power and Unit 4 returned to service on April 13, 2013
  • Continued to advance several growth initiatives in the Oil Pipelines business
    • Construction on the US$2.3 billion Gulf Coast Project, excluding the Houston Lateral, is now 70 per cent complete
    • Received the Draft Supplemental Environmental Impact Statement for the Keystone XL Pipeline from the U.S. Department of State (DOS)
    • Announced the launch of an open season for the Energy East Pipeline project to obtain firm commitments to transport crude oil from western receipt points to eastern Canadian markets

Comparable earnings for first quarter 2013 were $370 million or $0.52 per share compared to $363 million or $0.52 per share for the same period in 2012. Higher earnings contributions from the Canadian Mainline in the first quarter 2013 as a result of the NEB decision on its Restructuring Proposal, Bruce Power and U.S. Power, were offset by lower contributions from U.S. Natural Gas Pipelines and Western Power.

Net income attributable to common shares for first quarter 2013 was $446 million or $0.63 per share compared to $352 million or $0.50 per share in first 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 70 per cent complete and we estimate the total cost of the facilities to be US$2.3 billion.

    Construction of the 76 kilometre (km) (47 mile) Houston Lateral to transport crude oil to Houston refineries is expected to begin in mid 2013 and be complete by mid 2014 at a total cost of approximately US$300 million.

    The Gulf Coast Project will have an initial capacity of up to 700,000 barrels per day (bbl/d).
  • Keystone XL: In January 2013, the Governor of Nebraska approved our proposed re-route after the Nebraska Department of Environmental Quality issued its final evaluation report noting that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska.

    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 is in the process of reviewing comments on the impact statement that it received during a 45 day public comment period that ended on April 22, 2013. Once the DOS has completed its review, it is anticipated that it will issue a Final Supplemental Environmental Impact Statement and then consult with other governmental agencies during a National Interest Determination period of up to 90 days, before making a decision on our Presidential Permit application.

    Due to ongoing delays in the issuance of a Presidential Permit for Keystone XL, we now expect the pipeline to be in service in the second half of 2015 and, based on our pipeline construction experience, the US$5.3 billion cost estimate will increase depending on the timing of the permit. As of March 31, 2013, we had invested US$1.8 billion in the project.
  • Energy East Pipeline: We announced in April 2013 that we are holding an open season to obtain firm commitments for a pipeline to transport crude oil from western receipt points to eastern Canadian markets. The open season, which follows a successful expression of interest phase and discussions with prospective shippers, began on April 15, 2013 and closes on June 17, 2013.

    The Energy East Pipeline project involves converting natural gas pipeline capacity in approximately 3,000 km (1,864 miles) of our existing Canadian Mainline to crude oil service and constructing up to approximately 1,400 km (870 miles) of new pipeline. Subject to the results of the open season, the project will have the capacity to transport as much as 850,000 bbl/d, increasing access to eastern Canadian markets.

    We have begun Aboriginal and stakeholder engagement and field work as part of our initial design and planning. If the open season is successful, we will apply for regulatory approval to build and operate the facilities, with a potential in service date of late 2017.
  • Northern Courier Pipeline: The Fort Hills Energy Limited Partnership has not indicated that their recent decision to cancel the Voyageur upgrader project has changed their current plans for Northern Courier. We have nearly completed the field work and Aboriginal and stakeholder engagement necessary to allow us to file the permit application with the Energy Resources Conservation Board and expect to file the application in second quarter 2013.

Natural Gas Pipelines:

  • 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, including tolls for 2012 and 2013.

    The NEB approved several of our proposed changes, including the Canadian Mainline's revenue requirement for 2011 and 2012. At the same time, the NEB agreed with us that the Canadian Mainline has been significantly affected by market forces with the result that throughput has decreased significantly, and as a result, the Canadian Mainline tolls have increased over a short period of time eroding the Canadian Mainline's competitiveness. The response of the NEB was to adopt a multi-year fixed tolls approach which it believes will provide shippers with greater toll certainty and stability. Under the decision, long-term firm tolls are fixed through 2017 (subject to being re-opened under certain circumstances) at what the NEB determined is a competitive level. Although long-term firm tolls are fixed, the Canadian Mainline has been given pricing discretion for interruptible and short-term firm services. The NEB concluded in the decision that this framework will provide us with reasonable opportunity to recover our costs, over a reasonable period of time. Under or over collection variances to the revenue requirement inclusive of the return on and of capital will be carried over in deferral accounts to be dealt with in future NEB proceedings in 2017 (or earlier under certain circumstances). At that time, the NEB will determine how any variances contained in the deferral accounts will be addressed and the extent of cost disallowances, if any. As a result of the multi-year fixed tolls and increased risk associated with fluctuations in cash flow, the NEB increased the allowed return to 11.50 per cent on a 40 per cent equity ratio.

    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. We have determined that we will seek regulatory and potentially legal review and variance of certain aspects of the decision.
  • NGTL System: The Alberta System is now known as the NGTL System to better reflect the service provided and continued growth in British Columbia (B.C.).

    We have been continuing our expansion of the NGTL System and have placed approximately $340 million of new facilities into service to date in 2013. We have applied and received approval from the NEB for an additional $300 million of facilities with in service dates planned for later in 2013. The NEB has also recommended approval of the Chinchaga lateral, an approximate $100 million project that is planned to be placed in service in early 2014. To date in 2013, we have applied for an additional $60 million of facilities and are planning regulatory applications for further expansion into B.C., which we estimate will cost between $1.0 billion and $1.5 billion to accommodate the Prince Rupert Gas Transmission Project.
  • Prince Rupert Gas Transmission Project: We signed the project development agreement for the Prince Rupert Gas Transmission Project with Progress Energy Canada Ltd. in February 2013 and are now working to initiate the environmental assessment process, including developing and filing the project description that we plan to submit to the B.C. Environmental Assessment Office and the Canadian Environmental Assessment Agency (CEAA) in second quarter 2013.
  • Coastal GasLink: We are currently focused on community, landowner, government and First Nations engagement as the Coastal GasLink pipeline project advances through the regulatory process with the B.C. Environmental Assessment Office and the CEAA. We expect to begin an NGTL open season to provide delivery service to Vanderhoof, B.C. on Coastal GasLink in second quarter 2013.
  • Tamazunchale Pipeline Extension Project: A variety of construction activities are underway and the project remains on schedule to meet the planned in service date of first quarter 2014.

Energy:

  • Bruce Power: The availability percentage for Units 1 and 2 increased through first quarter 2013. These units are now able to operate at full power. As Units 1 and 2 have not operated for an extended period of time they may experience slightly higher forced outage rates and reduced availability percentages in 2013.

    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.

    The overall plant availability percentage in 2013 is expected to be in the mid 80 per cent range for Bruce A and the high 80 per cent range for Bruce B. Planned maintenance outages on two of the Bruce B units and one of the Bruce A units are expected to be completed in second quarter 2013.

    On April 5, 2013, Bruce Power announced that it had reached an agreement with the Ontario Power Authority (OPA) to extend the Bruce B floor price through to the end of the decade which is expected to coincide with the 2019 and 2020 end of life dates for the Bruce B units.
  • Ontario Solar: In late 2011, we agreed to buy nine Ontario solar projects with a combined capacity of 86 megawatts (MW) from Canadian Solar Solutions Inc. We expect to close the acquisition of the first three projects (combined capacity of 29 MW) by mid 2013 for a total cost of approximately $175 million. We expect to acquire the remaining six projects later in 2013 and 2014, subject to regulatory approvals.

Corporate:

  • Our Board of Directors declared a quarterly dividend of $0.46 per share for the quarter ending June 30, 2013 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $1.84 per common share on an annual basis.
  • In March 2013, we completed a public offering of 24 million Series 7 cumulative redeemable first preferred shares. The Series 7 shares were issued at a price of $25 per share, resulting in gross proceeds of $600 million. The initial dividend rate is fixed to April 30, 2019 at $1.00 per share per annum paid quarterly.

    In January 2013, we issued US$750 million of senior notes maturing on January 15, 2016, bearing interest at an annual rate of 0.75 per cent.

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

Teleconference - Audio and Slide Presentation:

We will hold a teleconference and webcast on Friday, April 26, 2013 to discuss our first 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 1:00 p.m. (MDT) / 3:00 p.m. (EDT).

Analysts, members of the media and other interested parties are invited to participate by calling 866.226.1793 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 (EDT) May 3, 2013. Please call 800.408.3053 or 905.694.9451 and enter pass code 6260206.

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", "would", "believe", "may", "will", "plan", "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 financial and operational plans and 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 April 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 may therefore not 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 April 25, 2013.

Quarterly report to shareholders

First quarter 2013

Financial highlights

Comparable EBITDA, 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 March 31
(unaudited - millions of $, except per share amounts)

2013

2012
Income
Revenue 2,252 1,945
Comparable EBITDA 1,168 1,113
Net income attributable to common shares 446 352
per common share - basic $0.63 $0.50
Comparable earnings 370 363
per common share $0.52 $0.52
Operating cash flow
Funds generated from operations 916 871
Increase in working capital (210 ) (169 )
Net cash provided by operations 706 702
Investing activities
Capital expenditures 929 464
Equity investments 32 216
Dividends
Per common share $0.46 $0.44
Basic common shares outstanding (millions)
Average for the period 706 704
End of period 706 704

Management's discussion and analysis

April 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 quarter ended March 31, 2013, and should be read with the accompanying unaudited condensed consolidated financial statements for the quarter ended March 31, 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 comparative 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 April 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
  • 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 and changes 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 U.S. Securities and Exchange Commission (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 may not 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.

We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives 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 March 31
(unaudited - millions of $, except per share amounts)
2013 2012
Comparable EBITDA 1,168 1,113
Comparable depreciation and amortization (354 ) (344 )
Comparable EBIT 814 769
Other income statement items
Comparable interest expense (257 ) (242 )
Comparable interest income and other 18 25
Comparable income taxes (159 ) (140 )
Net income attributable to non-controlling interests (31 ) (35 )
Preferred share dividends (15 ) (14 )
Comparable earnings 370 363
Specific items (net of tax):
Canadian restructuring proposal - 2012 84 -
Risk management activities1 (8 ) (11 )
Net income attributable to common shares 446 352
Comparable depreciation and amortization (354 ) (344 )
Specific item:
Canadian restructuring proposal - 2012 (13 ) -
Depreciation and amortization (367 ) (344 )
Comparable interest expense (257 ) (242 )
Specific item:
Canadian restructuring proposal - 2012 (1 ) -
Interest expense (258 ) (242 )
Comparable interest income and other 18 25
Specific items:
Canadian restructuring proposal - 2012 1 -
Risk management activities1 (6 ) 6
Interest income and other 13 31
Comparable income taxes (159 ) (140 )
Specific items:
Canadian restructuring proposal - 2012 42 -
Risk management activities1 2 11
Income taxes expense (115 ) (129 )
Comparable earnings per common share $0.52 $0.52
Specific items (net of tax):
Canadian restructuring proposal - 2012 0.12 -
Risk management activities1 (0.01 ) (0.02 )
Net income per common share $0.63 $0.50
1 three months ended March 31
(unaudited - millions of $)

2013
2012
Canadian Power (2 ) (2 )
U.S. Power 1 (32 )
Natural Gas Storage (3 ) 6
Foreign exchange (6 ) 6
Income taxes attributable to risk management activities 2 11
Total losses from risk management activities (8 ) (11 )
EBITDA and EBIT by business segment
three months ended March 31, 2013
(unaudited - millions of $)
Natural Gas Pipelines Oil Pipelines
Energy

Corporate

Total
Comparable EBITDA 746 179 277 (34 ) 1,168
Comparable depreciation and amortization (240 ) (37 ) (74 ) (3 ) (354 )
Comparable EBIT 506 142 203 (37 ) 814
three months ended March 31, 2012
(unaudited - millions of $)
Natural Gas Pipelines Oil Pipelines
Energy

Corporate

Total
Comparable EBITDA 725 173 244 (29 ) 1,113
Comparable depreciation and amortization (232 ) (36 ) (73 ) (3 ) (344 )
Comparable EBIT 493 137 171 (32 ) 769

Results - first quarter 2013

Net income attributable to common shares was $446 million this quarter compared to $352 million in first quarter 2012. This included $104 million of net income resulting from the National Energy Board's (NEB) decision on the Canadian Mainline Business and Services Restructuring Proposal and 2012 and 2013 Mainline Final Tolls Application (Canadian Restructuring Proposal). Of this amount, $84 million is excluded from comparable earnings as it relates to 2012.

Comparable earnings this quarter were $370 million or $0.52 per share, $7 million higher than first quarter 2012.

This was the result of:
  • higher net income from the Canadian Mainline because of the first quarter 2013 impact of the NEB's decision on the Canadian Restructuring Proposal
  • higher equity income from Bruce Power because of incremental earnings from Units 1 and 2 and the recognition of an insurance recovery partly offset by an increase in outage days
  • higher realized power prices from U.S. Power.
These were partly offset by:
  • lower contributions from U.S. natural gas pipelines
  • lower earnings from Western Power because of the Sundance A PPA force majeure and lower realized prices
  • 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.
Comparable earnings do not include net unrealized after-tax losses resulting from changes in the fair value of certain risk management activities:
  • $8 million ($10 million before tax) in first quarter 2013
  • $11 million ($22 million before tax) in first quarter 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 we included in our 2012 Annual Report. The NEB approved a return on equity (ROE) of 11.50 per cent on 40 per cent deemed common equity ratio, multi year tolls until 2017 and a new incentive mechanism. 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 March 31
(unaudited - millions of $)

2013

2012
Canadian Pipelines
Canadian Mainline 280 250
NGTL System 182 177
Foothills 29 31
Other Canadian (TQM1, Ventures LP) 6 8
Canadian Pipelines - comparable EBITDA 497 466
Comparable depreciation and amortization2 (184 ) (177 )
Canadian Pipelines - comparable EBIT 313 289
U.S. and International (in US$)
ANR 90 97
GTN3 28 30
Great Lakes4 10 18
TC PipeLines, LP1,5 17 20
Other U.S. pipelines (Iroquois1, Bison3, Portland6) 43 34
International (Gas Pacifico/INNERGY1, Guadalajara, Tamazunchale, TransGas1)
26
28
General, administrative and support costs (2 ) (2 )
Non-controlling interests7 43 45
U.S. Pipelines and International - comparable EBITDA 255 270
Comparable depreciation and amortization2 (55 ) (55 )
U.S. Pipelines and International - comparable EBIT 200 215
Foreign exchange 2 -
U.S. Pipelines and International - comparable EBIT(Cdn$) 202 215
Business Development comparable EBITDA and EBIT (9 ) (11 )
Natural Gas Pipelines - comparable EBIT 506 493
Summary
Natural Gas Pipelines - comparable EBITDA 746 725
Comparable depreciation and amortization2 (240 ) (232 )
Natural Gas Pipelines - comparable EBIT 506 493
(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) Represents our 33.3 per cent direct ownership interest of TC PipeLines, LP and our effective ownership through TC PipeLines, LP of 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.
(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 March 31
(millions of $)

2013

2012
Canadian Mainline - net income 151 47
Canadian Mainline - comparable earnings 67 47
NGTL System 56 48
Foothills 4 5
OPERATING STATISTICS - WHOLLY OWNED CANADIAN PIPELINES
Canadian Mainline1 NGTL System2 ANR3
three months ended March 31
(unaudited)
2013 2012 2013 2012 2013 2012
Average investment base (millions of dollars) 5,870 5,812 5,824 5,282 n/a n/a
Delivery volumes (Bcf)
Total 426 430 994 998 465 482
Average per day 4.7 4.7 11.0 11.0 5.2 5.3
(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 three months ended March 31, 2013 were 231 Bcf (2012 - 247 Bcf). Average per day was 2.6 Bcf (2012 - 2.7 Bcf).
(2) Field receipt volumes for the NGTL System for the three months ended March 31, 2013 were 916 Bcf (2012 - 948 Bcf). Average per day was 10.2 Bcf (2012 - 10.4 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.

Net income for the Canadian Mainline this quarter was $104 million higher than first quarter 2012 because of the impact of the NEB's March 27, 2013 decision on the Canadian Restructuring Proposal. Among other things, the NEB approved an ROE of 11.50 per cent on a 40 per cent deemed common equity effective for the years 2012 to 2017 compared to the last approved ROE of 8.08 per cent on a 40 per cent deemed common equity which was used to record earnings in 2012. Comparable earnings in first quarter 2013 excludes $84 million related to the 2012 impact of the NEB decision.

Net income for the NGTL System (formerly known as the Alberta System) was $8 million higher than first quarter 2012 because of a higher average investment base and termination of the annual fixed operating, maintenance and administration (OM&A) costs component included in the 2010 - 2012 Revenue Requirement which expired at the end of 2012. The NGTL System's results this quarter reflected 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$255 million this quarter, or US$15 million lower than first quarter 2012. This was the net effect of:
  • lower revenue at Great Lakes because of lower rates and uncontracted capacity
  • higher costs at ANR relating to services provided by other pipelines
  • higher short term and interruptible revenues at Portland.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization was $8 million higher this quarter than in first quarter 2012 mainly because of the higher rate base on the NGTL System.

Oil Pipelines

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

three months ended March 31
(unaudited - millions of $)

2013

2012
Keystone Pipeline System 186 174
Oil Pipeline Business Development (7 ) (1 )
Oil Pipelines - comparable EBITDA 179 173
Comparable depreciation and amortization (37 ) (36 )
Oil Pipelines - comparable EBIT 142 137
Comparable EBIT denominated as follows:
Canadian dollars 47 48
U.S. dollars 94 89
Foreign exchange 1 -
142 137
Comparable EBITDA for the Keystone Pipeline System was $12 million higher this quarter than in first quarter 2012. This increase 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 this quarter were $6 million higher than in first quarter 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 March 31
(unaudited - millions of $)

2013

2012
Canadian Power
Western Power1 79 131
Eastern Power1,2 95 93
Bruce Power1 31 (13 )
General, administrative and support costs (10 ) (11 )
Canadian Power - comparable EBITDA1 195 200
Comparable depreciation and amortization3 (43 ) (40 )
Canadian Power - comparable EBIT1 152 160
U.S. Power (US$)
Northeast Power 77 46
General, administrative and support costs (10 ) (10 )
U.S. Power - comparable EBITDA 67 36
Comparable depreciation and amortization (28 ) (30 )
U.S. Power - comparable EBIT 39 6
Foreign exchange 1 -
U.S. Power - comparable EBIT(Cdn$) 40 6
Natural Gas Storage
Alberta Storage 20 15
General, administrative and support costs (2 ) (2 )
Natural Gas Storage - comparable EBITDA1 18 13
Comparable depreciation and amortization3 (3 ) (3 )
Natural Gas Storage - comparable EBIT1 15 10
Business Development comparable EBITDA and EBIT (4 ) (5 )
Energy - comparable EBIT1 203 171
Summary
Energy - comparable EBITDA1 277 244
Comparable depreciation and amortization3 (74 ) (73 )
Energy - comparable EBIT1 203 171
(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 Cartier phase two of Gros-Morne starting in November 2012.
(3) Does not include depreciation and amortization of equity investments.
Comparable EBITDA for Energy was $277 million this quarter, or $33 million higher than first quarter 2012. This was the net effect of:
  • 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 and a Unit 3 outage in first quarter 2012 partially offset by the extended outage of Unit 4 in first quarter 2013
  • higher earnings from U.S. Power mainly because of higher realized power prices
  • lower earnings from Western Power because of the Sundance A PPA force majeure and lower realized power prices.

CANADIAN POWER

Western and Eastern Power1

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

three months ended March 31
(unaudited - millions of $)

2013

2012
Revenue
Western power 142 224
Eastern power1 109 103
Other2 31 25
282 352
Income from equity investments3 22 23
Commodity purchases resold
Western power (65 ) (94 )
Other4 (2 ) (2 )
(67 ) (96 )
Plant operating costs and other (63 ) (55 )
General, administrative and support costs (10 ) (11 )
Comparable EBITDA 164 213
Comparable depreciation and amortization5 (43 ) (40 )
Comparable EBIT 121 173
(1) Includes Cartier phase two of Gros-Morne starting in November 2012.
(2) Includes sale of excess natural gas purchased for generation and sales of thermal carbon black.
(3) Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy.
(4) Includes the cost of excess natural gas not used in operations.
(5) Does not include depreciation and amortization of equity investments.

Sales volumes and plant availability

Includes our share of volumes from our equity investments.

three months ended March 31
(unaudited)

2013

2012
Sales volumes (GWh)
Supply
Generation
Western Power 670 671
Eastern Power1 1,346 1,143
Purchased
Sundance A & B and Sheerness PPAs2 1,707 2,039
Other purchases - 45
3,723 3,898
Sales
Contracted
Western Power 1,707 2,295
Eastern Power1 1,346 1,143
Spot
Western Power 670 460
3,723 3,898
Plant availability3
Western Power4 97 % 99 %
Eastern Power1,5 96 % 93 %
(1) Includes Cartier phase two of Gros-Morne starting in November 2012.
(2) Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership. No volumes were delivered under the Sundance A PPA in 2012 and 2013.
(3) The percentage of time the plant was available to generate power, regardless of whether it was running.
(4) Does not include facilities that provide power to TransCanada under PPAs.
(5) Does not include Bécancour because power generation has been suspended since 2008.
Western Power's comparable EBITDA was $79 million this quarter, or $52 million lower than first quarter 2012. Revenue also decreased by $82 million this quarter to $142 million. These decreases were mainly due to:
  • the Sundance A PPA force majeure
  • lower realized power prices and
  • lower purchased PPA volumes during periods of lower spot prices.

In first quarter 2012, we recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply in accordance with the terms of the PPA. In July 2012, we received the Sundance A PPA arbitration decision which determined the units were in force majeure in first quarter 2012. In response, we recorded a charge of $30 million in second quarter 2012 equivalent to the pre-tax income we had recorded in first quarter 2012. Because the plant continues to be in force majeure, we will not record further revenues and costs until the units are returned to service. See Energy - Significant Events in the MD&A in our 2012 Annual Report for more information about the Sundance A PPA arbitration decision.

Average spot market power prices in Alberta were $64 per MWh this quarter, compared to $60 per MWh in first quarter 2012. This increase was mainly the result of high spot market prices in the month of March driven by plant outages and increased demand. Western Power's average realized power price this quarter was lower than first quarter 2012 because of contracting activities. Purchased volumes were lower than first quarter 2012 mainly because of lower utilization of the Sheerness and Sundance B PPAs and higher Sundance B plant outage days.

Western Power's commodity purchases resold were $65 million this quarter, or $29 million lower than first quarter 2012, because of the Sundance A PPA force majeure and lower purchased volumes during periods of lower spot prices.

Eastern Power's comparable EBITDA of $95 million was $2 million higher than first quarter 2012 because of the start up of phase two of Cartier Gros-Morne in November 2012, partially offset by lower contractual earnings at Bécancour.

Plant operating costs and other, which includes natural gas fuel consumed in power generation, were $63 million this quarter, or $8 million higher than first quarter 2012, mainly due to higher natural gas fuel prices in 2013.

Approximately 72 per cent of Western Power sales volumes were sold under contract this quarter, compared to 83 per cent in first quarter 2012. To reduce exposure to spot market prices in Alberta, Western Power has entered into fixed-price power sales contracts to sell approximately 5,300 GWh for the remainder of 2013 and approximately 5,200 GWh in 2014.

BRUCE POWER

Our proportionate share

...
three months ended March 31
(unaudited - millions of $ unless noted otherwise)

2013

2012
Income/(loss) from equity investments1
Bruce A 36 (33 )
Bruce B (5 ) 20
31 (13 )
Comprised of:
Revenues 287 162
Operating expenses (173 ) (135 )
Depreciation and other (83 ) (40 )
31 (13 )
Bruce Power - Other information
Plant availability2
Bruce A3 66 % 48 %
Bruce B 78 % 86 %
Combined Bruce Power 72 % 62 %
Planned outage days
Bruce A 90 91
Bruce B 70 46
Unplanned outage days
Bruce A 8 -
Bruce B 9 4
Sales volumes (GWh)1
Bruce A3 2,097 747
Bruce B 1,735 1,909
3,832 2,656