TransCanada Reports Solid Second Quarter Results

CALGARY, ALBERTA--(Marketwired - Jul 31, 2014) - TransCanada Corporation (TRP.TO) (TRP) (TransCanada) today announced net income attributable to common shares for second quarter 2014 of $416 million or $0.59 per share compared to $365 million or $0.52 per share for the same period in 2013. Comparable earnings for second quarter 2014 were $332 million or $0.47 per share compared to $357 million or $0.51 per share for the same period last year. TransCanada's Board of Directors also declared a quarterly dividend of $0.48 per common share for the quarter ending September 30, 2014, equivalent to $1.92 per common share on an annualized basis.

"The majority of our business segments performed well over the course of the second quarter and demonstrate the benefits of a diversified and growing portfolio of critical energy infrastructure assets," said Russ Girling, TransCanada's president and chief executive officer. "Although weak Alberta power prices and maintenance outages at Bruce Power weighed on second quarter results, both businesses are expected to produce stronger results in the future due to positive Alberta power market fundamentals and higher plant availability at Bruce Power."

With the recent addition of the Merrick Mainline Pipeline Project, our capital program now includes $38 billion of commercially secured projects that are backed by long-term contracts or cost of service business models. Our portfolio is comprised of $21 billion of liquids pipelines, $15 billion of natural gas pipelines, and $2 billion of power generation facilities. We continue to advance this unprecedented slate of growth initiatives, with many currently proceeding through their regulatory processes. Over the remainder of the decade, subject to required approvals, this blue-chip portfolio of contracted energy infrastructure projects is expected to generate significant long-term shareholder value from growth in 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 $416 million or $0.59 per share
    • Comparable earnings of $332 million or $0.47 per share
    • Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.2 billion
    • Funds generated from operations of $917 million
  • Net income attributable to common shares of $416 million or $0.59 per share
  • Comparable earnings of $332 million or $0.47 per share
  • Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.2 billion
  • Funds generated from operations of $917 million
  • Declared a quarterly dividend of $0.48 per common share for the quarter ending September 30, 2014
  • Secured commercial support for the $1.9 billion Merrick Mainline Pipeline Project, an extension of the NGTL System
  • Received regulatory approval for the $800 million Northern Courier Pipeline Project
  • Closed the $190 million sale of Cancarb and its related power generation facility on April 15, 2014
  • Filed a Project Description with the National Energy Board (NEB) for the Eastern Mainline Project
  • Continue to progress regulatory applications for several of our major capital projects including Coastal GasLink, Prince Rupert Gas Transmission, Energy East, Grand Rapids, Heartland, the North Montney Mainline and Napanee

Net income attributable to common shares for second quarter 2014 was $416 million or $0.59 per share compared to $365 million or $0.52 per share in second quarter 2013. Second quarter 2014 results included a net after-tax gain of $99 million from the sale of Cancarb and its related power generation facility and an after-tax $31 million termination expense for restructuring a natural gas storage contract. These amounts were excluded from comparable earnings.

Comparable earnings for second quarter 2014 were $332 million or $0.47 per share compared to $357 million or $0.51 per share for the same period in 2013. Higher earnings from Keystone and Mexican Pipelines were more than offset by lower contributions from Western Power and Bruce Power.

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

Liquids Pipelines:

  • Energy East Pipeline: In March 2014, we filed a Project Description with the NEB. This is the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.

    Subject to regulatory approvals, the pipeline is anticipated to commence deliveries to Québec in 2018, with service to New Brunswick to follow in late 2018. We continue to participate in Aboriginal and stakeholder engagement and associated field work as part of our initial design and planning. We intend to file the necessary regulatory applications in third quarter 2014 for approvals to construct and operate the pipeline project and terminal facilities.
  • Keystone XL: On January 31, 2014, the Department of State (DOS) released its Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL project. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is "unlikely to significantly impact the rate of extraction in the oil sands" and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more greenhouse gas emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period that was to last up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment. The 30-day public comment period has concluded. On April 18, 2014, the DOS announced that the National Interest Determination period has been extended indefinitely to allow them to consider the potential impact of the case discussed below on the Nebraska portion of the pipeline route.

    In February 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Heineman, has the authority to approve an alternative route through Nebraska for the Keystone XL project. Nebraska's Attorney General has filed an appeal and the Nebraska Supreme Court is expected to hear the appeal in September 2014.

    As of June 30, 2014, we have invested US$2.4 billion in the Keystone XL project.
  • Northern Courier Pipeline Project: In October 2013, Suncor Energy announced that Fort Hills Energy LP is proceeding with the Fort Hills oil sands mining project. Our $800 million Northern Courier Pipeline Project will transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's East Tank Farm located north of Fort McMurray, Alberta, and is fully contracted under a long-term agreement.

    On July 18, 2014, the Alberta Energy Regulator issued a permit approving our application to construct and operate the Northern Courier Pipeline. We currently expect construction on Northern Courier to begin in third quarter 2014, with it being ready for service in 2017.

Natural Gas Pipelines:

  • NGTL System Expansions: The NGTL System is currently experiencing a significant amount of growth as a result of growing natural gas supply in northwestern Alberta and northeastern B.C. from unconventional gas plays and substantive growth in intra-basin delivery markets driven primarily by oil sands development and demand for gas-fired electric power generation. Approximately $250 million of capital projects have been placed into service in 2014. Another $3.8 billion of projects are either under construction, or have or will be filed with the NEB for approval. These projects include the North Montney Mainline and the Merrick Mainline Pipeline, along with other new supply and demand facilities. We continue to receive requests for new services and expect that this will lead to additional growth opportunities in the future.

    On June 4, 2014, we announced the signing of agreements for approximately 1.9 billion cubic feet per day (Bcf/d) of firm natural gas transportation services for the proposed Merrick Mainline Pipeline Project, a major extension of our NGTL System. The project will transport natural gas through the NGTL System to the inlet of the proposed Pacific Trail Pipeline that will terminate at the Kitimat LNG Terminal at Bish Cove near Kitimat, B.C. The proposed project will be an extension from the existing Groundbirch Mainline section of the NGTL System beginning near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C. The $1.9 billion project consists of approximately 260 kilometres (km) (161 miles) of 48-inch diameter pipe. We anticipate filing an application for approvals to build and operate the system with the NEB in fourth quarter 2014. Subject to the necessary regulatory approvals and a positive final investment decision for Kitimat LNG, we expect the Merrick Mainline to be in service in first quarter 2020.

    The NEB issued a Hearing Order in February 2014 for the $1.7 billion North Montney project, which is an extension and expansion of the NGTL System to receive and transport natural gas from the North Montney area of B.C. The proposed project consists of approximately 300 km (186 miles) of pipeline and is expected to be placed in service in two sections, Aitken Creek in second quarter 2016 and Kahta in second quarter 2017. On June 17, 2014, the NEB revised the procedural schedule, which has resulted in the oral portion of the hearing being rescheduled to mid-October 2014 for the Calgary phase, and mid-November for the Fort St. John phase. We now anticipate an NEB decision on the application in first quarter 2015.
  • Canadian Mainline - LDC Settlement: In March 2014, the NEB responded to the LDC Settlement application we filed on December 20, 2013. The NEB did not approve the application as a settlement but allowed us the option to continue with the application as a contested tolls application, amend the application or terminate the processing of the application. We amended the application with additional information. On May 9, 2014, the NEB released a Hearing Order that sets out the process and schedule for the 2015 - 2030 Mainline Tolls application that incorporates the LDC Settlement, with the oral portion set to begin September 9, 2014.
  • Canadian Mainline - Eastern Mainline Project: On May 8, 2014, we filed a Project Description with the NEB for the Eastern Mainline Project. The proposed project will add new facilities to our existing Canadian Mainline natural gas transmission system in southeastern Ontario as a result of the proposed transfer of a portion of the Canadian Mainline capacity to crude oil from natural gas service as part of our proposed Energy East Pipeline and an open season that closed in January 2014. The proposed scope of the project will add 0.6 Bcf/d of new capacity and will ensure appropriate levels of capacity are available to meet the requirements of existing shippers as well as new firm service commitments contracted for in the Eastern Triangle segment of the Canadian Mainline. Subject to regulatory approvals, the project is expected to be in service in second quarter 2017.
  • Tamazunchale Pipeline Extension Project: Construction of the US$600 million extension is currently expected to be completed by the end of September 2014 with delays attributed to archeological findings along the pipeline route. Under the terms of the Transportation Service Agreement, these delays are recognized as a force majeure with provisions allowing for collection of revenue as per the original service commencement date of March 9, 2014.
  • Prince Rupert Gas Transmission Project: The Environmental Assessment application submitted to the B.C. Environmental Assessment Office (EAO) in April 2014 was deemed complete. The EAO initiated a 180-day review period which included a 45-day public comment period that was completed on July 10, 2014. A facilities application was also filed with the B.C. Oil and Gas Commission in April 2014. Regulatory approval for the pipeline is expected in fourth quarter 2014 and a final investment decision from Pacific Northwest LNG is expected to follow at the end of 2014.
  • Alaska LNG Project: In April 2014, the State of Alaska passed new legislation that will transition from the Alaska Gasline Inducement Act (AGIA) and enable a new commercial arrangement to be established with us, the three major Alaska North Slope producers, and the Alaska Gasline Development Corp. It was also agreed that a Liquefied Natural Gas (LNG) export project, rather than a pipeline to Alberta, is currently the best opportunity to commercialize Alaska North Slope gas resources in current market conditions.

    On June 9, 2014, we executed an agreement with the State of Alaska to abandon the AGIA license and executed a Precedent Agreement, where we will act as the transporter of the State's portion of natural gas under a long-term shipping contract in the Alaska LNG Project. On June 30, 2014, the Alaska LNG Project entered the pre-front end engineering and design (pre-FEED) phase following the execution of a Joint Venture Agreement among ourselves, the three major Alaska North Slope producers and Alaska Gasline Development Corp. The pre-FEED work is anticipated to take two years to complete with our share of the cost to be approximately US$100 million. The Precedent Agreement also provides us with full recovery of development costs in the event the project does not proceed.

Energy:

  • Cancarb: In January 2014, we reached an agreement to sell Cancarb and its related power generation facility for gross proceeds of $190 million. The sale closed on April 15, 2014 and we recognized an after-tax gain of $99 million in second quarter 2014.
  • Natural Gas Storage: Effective April 30, 2014, we terminated a 38 billion cubic feet long-term natural gas storage contract in Alberta with Niska Gas Storage. As a result, we recorded a $31 million after-tax charge in second quarter 2014. We have re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six year period at a reduced average volume.

Corporate:

  • Our Board of Directors declared a quarterly dividend of $0.48 per share for the quarter ending September 30, 2014 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $1.92 per common share on an annualized basis.

Teleconference - Audio and Slide Presentation:

We will hold a teleconference and webcast on Thursday, July 31, 2014 to discuss our second quarter 2014 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 2 p.m. (MT) / 4 p.m. (ET).

Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.2216 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on August 7, 2014. Please call 800.408.3053 or 905.694.9451 and enter pass code 5722299.

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

With more than 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 31, 2014 and 2013 Annual Report on our website at www.transcanada.com or filed under TransCanada's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov.

Non-GAAP Measures

This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, funds generated from operations and comparable earnings per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada's Quarterly Report to Shareholders dated July 31, 2014.

Quarterly report to shareholders

Second quarter 2014

Financial highlights

three months ended June 30 six months ended June 30
(unaudited - millions of $, except per share amounts) 2014 2013 2014 2013
Income
Revenue 2,234 2,009 5,118 4,261
Net income attributable to common shares 416 365 828 811
per common share - basic and diluted $0.59 $0.52 $1.17 $1.15
Comparable EBITDA1 1,217 1,143 2,613 2,311
Comparable earnings1 332 357 754 727
per common share1 $0.47 $0.51 $1.07 $1.03
Operating cash flow
Funds generated from operations1 917 955 2,019 1,871
Decrease/(increase) in operating working capital 202 (114 ) 79 (324 )
Net cash provided by operations 1,119 841 2,098 1,547
Investing activities
Capital expenditures (967 ) (1,109 ) (1,745 ) (2,038 )
Equity investments (40 ) (39 ) (129 ) (71 )
Acquisitions - (55 ) - (55 )
Proceeds from sale of assets, net of transaction costs 187 - 187 -
Dividends paid
Per common share $0.48 $0.46 $0.96 $0.92
Basic common shares outstanding (millions)
Average for the period 708 707 708 706
End of period 708 707 708 707
1 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.

Management's discussion and analysis

July 31, 2014

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, 2014, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and six months ended June 30, 2014 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2013 audited consolidated financial statements and notes and the MD&A in our 2013 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 2013 Annual Report.

All information is as of July 31, 2014 and all amounts are in Canadian dollars, unless noted otherwise.

FORWARD-LOOKING INFORMATION

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

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

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

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

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

  • inflation rates, commodity prices and capacity prices
  • timing of financings and hedging
  • regulatory decisions and outcomes
  • foreign exchange rates
  • interest rates
  • tax rates
  • planned and unplanned outages and the use of our pipeline and energy assets
  • integrity and reliability of our assets
  • access to capital markets
  • anticipated construction costs, schedules and completion dates
  • acquisitions and divestitures.

Risks and uncertainties

  • our ability to successfully implement our strategic initiatives
  • whether our strategic initiatives will yield the expected benefits
  • the operating performance of our pipeline and energy assets
  • amount of capacity sold and rates achieved in our pipeline businesses
  • the availability and price of energy commodities
  • the amount of capacity payments and revenues we receive from our energy business
  • regulatory decisions and outcomes
  • outcomes of legal proceedings, including arbitration
  • 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
  • costs for labour, equipment and materials
  • access to capital markets
  • interest and foreign exchange rates
  • weather
  • cyber security
  • technological developments
  • economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2013 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
  • funds generated from operations
  • comparable earnings
  • comparable earnings per common share
  • comparable EBITDA
  • comparable EBIT
  • comparable depreciation and amortization
  • comparable interest expense
  • comparable interest income and other
  • comparable income tax expense.

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

EBITDA and EBIT

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

Funds generated from operations

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

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

  • certain fair value adjustments relating to risk management activities
  • income tax refunds and adjustments
  • gains or losses on sales of assets
  • legal, contractual and bankruptcy settlements
  • impact of regulatory or arbitration decisions relating to prior year earnings
  • 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.

Consolidated results - second quarter 2014

three months ended June 30 six months ended June 30
(unaudited - millions of $, except per share amounts) 2014 2013 2014 2013
Natural gas pipelines 496 399 1,082 947
Liquids pipelines1 195 149 387 291
Energy 216 243 473 442
Corporate (27 ) (22 ) (70 ) (59 )
Total segmented earnings 880 769 1,872 1,621
Interest expense (297 ) (252 ) (571 ) (510 )
Interest income and other 54 (11 ) 46 2
Income before income taxes 637 506 1,347 1,113
Income tax expense (165 ) (98 ) (386 ) (213 )
Net income 472 408 961 900
Net income attributable to non-controlling interests (31 ) (23 ) (85 ) (54 )
Net income attributable to controlling interests 441 385 876 846
Preferred share dividends (25 ) (20 ) (48 ) (35 )
Net income attributable to common shares 416 365 828 811
Net income per common share - basic and diluted $0.59 $0.52 $1.17 $1.15
1 Previously Oil Pipelines.

Net income attributable to common shares increased by $51 million for the three months ended June 30, 2014 compared to the same period in 2013. Second quarter 2014 results included:

  • a gain on sale of Cancarb Limited and its related power generation business of $99 million after tax
  • a net loss resulting from the termination of a contract with Niska Gas Storage of $31 million after tax.

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.

Net income attributable to common shares increased by $17 million for the six months ended June 30, 2014 compared to the same period in 2013. The 2014 results included:

  • a gain on sale of Cancarb Limited and its related power generation business of $99 million after tax
  • a net loss resulting from a termination payment to Niska Gas Storage for contract restructuring of $31 million after tax.

The results for the first six months of 2013 included $84 million of Canadian Mainline net income related to 2012 from the NEB decision (RH-003-2011) as well as 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.

The items discussed above are excluded from comparable earnings for the relevant periods. Certain unrealized fair value adjustments relating to risk management activities are also excluded from comparable earnings. The remainder of net income is equivalent to comparable earnings. A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS

three months ended June 30 six months ended June 30
(unaudited - millions of $, except per share amounts) 2014 2013 2014 2013
Net income attributable to common shares 416 365 828 811
Specific items (net of tax):
Energy - Cancarb gain on sale (99 ) - (99 ) -
Energy - Niska contract termination 31 - 31 -
Risk management activities1 (16 ) 17 (6 ) 25
Natural gas pipelines - NEB decision - 2012 - - - (84 )
Part VI.I income tax adjustment - (25 ) - (25 )
Comparable earnings 332 357 754 727
Net income per common share $0.59 $0.52 $1.17 $1.15
Specific items (net of tax):
Energy - Cancarb gain on sale (0.14 ) - (0.14 ) -
Energy - Niska contract termination 0.04 - 0.04 -
Risk management activities1 (0.02 ) 0.03 - 0.04
Natural gas pipeline - NEB decision - 2012 - - - (0.12 )
Part VI.I income tax adjustment - (0.04 ) - (0.04 )
Comparable earnings per share $0.47 $0.51 $1.07 $1.03
1 Risk management activities three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Canadian Power (2 ) (4 ) (2 ) (6 )
U.S. Power (9 ) (18 ) (11 ) (17 )
Natural gas Storage 6 4 (3 ) 1
Foreign exchange 25 (9 ) 23 (15 )
Income tax attributable to risk management activities (4 ) 10 (1 ) 12
Total gains/(losses) from risk management activities 16 (17 ) 6 (25 )

Comparable earnings decreased by $25 million for the three months ended June 30, 2014 compared to the same period in 2013, a decrease of $0.04 per share.

This was primarily the net effect of the following:

  • incremental earnings from the Gulf Coast extension of the Keystone Pipeline System
  • lower earnings from Western Power as a result of lower realized power prices
  • lower equity income from Bruce Power mainly due to increased planned and unplanned outage days at Bruce A, partially offset by fewer outage days at Bruce B
  • higher earnings from Mexico pipelines resulting from contract revenues recognized from the Tamazunchale Extension.

Comparable earnings increased by $27 million for the six months ended June 30, 2014 compared to the same period in 2013, an increase of $0.04 per share.

This was primarily the net effect of:

  • incremental earnings from the Gulf Coast extension of the Keystone Pipeline System
  • lower earnings from Western Power as a result of lower realized power prices
  • higher earnings from U.S. Power mainly because of higher realized capacity and power prices
  • higher earnings from Mexico pipelines resulting from contract revenues recognized from the Tamazunchale Extension
  • higher earnings from U.S. natural gas pipelines due to higher transportation revenues at Great Lakes and higher contributions from TC PipeLines, LP reflecting colder winter weather and increased demand.

The stronger U.S. dollar this quarter compared to the same period in 2013 positively impacted the results in our U.S. businesses, which were mostly offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our net exposure through our hedging program.

CAPITAL PROGRAM

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

Our capital program is comprised of $12 billion of small to medium-sized projects and $26 billion of large scale projects. Amounts presented exclude the impact of foreign exchange and capitalized interest.

at June 30, 2014
(unaudited - billions of $)

Segment Expected In-Service Date
Estimated Project Cost
Amount Spent
Small to medium-sized projects
Tamazunchale Extension1 Natural Gas Pipelines 2014 US 0.6 US 0.5
Ontario Solar Energy 2014-2015 0.5 0.2
Houston Lateral and Terminal Liquids Pipelines 2015 US 0.4 US 0.3
Heartland and TC Terminals Liquids Pipelines 2016 0.9 0.1
Keystone Hardisty Terminal Liquids Pipelines Approximately 2 years from date Keystone XL permit received 0.3 0.1
Topolobampo Natural Gas Pipelines 2016 US 1.0 US 0.5
Mazatlan Natural Gas Pipelines 2016 US 0.4 US 0.1
Grand Rapids2 Liquids Pipelines 2015-2017 1.5 0.1
Northern Courier Liquids Pipelines 2017 0.8 0.1
NGTL System - North Montney Natural Gas Pipelines 2016-2017 1.7 0.1
- Merrick Natural Gas Pipelines 2020 1.9 -
- Other Natural Gas Pipelines 2014-2016 0.5 0.2
Napanee Energy 2017 or 2018 1.0 -
11.5 2.3
Large scale projects3
Keystone XL4 Liquids Pipelines Approximately 2 years from date permit received US 5.4 US 2.4
Energy East5 Liquids Pipelines 2018 12.0 0.3
Prince Rupert Gas Transmission Natural Gas Pipelines 2018 5.0 0.2
Coastal GasLink Natural Gas Pipelines 2018+ 4.0 0.2
26.4 3.1
37.9 5.4
1 A force majeure has delayed completion of construction, however, revenue has been recorded in second quarter 2014 as per the terms of the Transportation Service Agreement.
2 Represents our 50 per cent share.
3 Subject to cost adjustments due to market conditions, route refinement, permitting conditions and scheduling.
4 Estimated project cost will increase depending on the timing of the Presidential permit.
5 Excludes transfer of Canadian Mainline natural gas assets.

Outlook

The earnings outlook previously included in the 2013 Annual Report is expected to be impacted by:

  • the gain on sale of Cancarb Limited and its related power generation facility
  • the termination payment to Niksa Gas Storage for the contract restructuring
  • increased outage days at Bruce A.

See the MD&A in our 2013 Annual Report for further information about our outlook.

Natural Gas Pipelines

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

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Comparable EBITDA 759 644 1,607 1,390
Comparable depreciation and amortization1 (263 ) (245 ) (525 ) (485 )
Comparable EBIT 496 399 1,082 905
Specific item:
NEB decision - 2012 - - - 42
Segmented earnings 496 399 1,082 947
1 In 2014, comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization. In 2013, comparable depreciation is adjusted by $13 million relating to the impact from the NEB decision (RH-003-2011).

Our Natural Gas Pipelines segmented earnings increased by $97 million for the three months ended June 30, 2014 and by $135 million for the six months ended June 30, 2014 compared to the same periods in 2013. Natural gas segmented earnings for the six months ended June 30, 2013 included $42 million related to the 2012 impact of the NEB decision (RH-003-2011). This amount has been excluded in our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT and comparable EBITDA and are discussed below.

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Canadian Pipelines
Canadian Mainline 312 263 627 543
NGTL System 205 193 424 375
Foothills 27 28 54 57
Other Canadian pipelines (TQM1, Ventures LP) 5 7 10 13
Canadian Pipelines - comparable EBITDA 549 491 1,115 988
Comparable depreciation and amortization (204 ) (190 ) (407 ) (374 )
Canadian Pipelines - comparable EBIT 345 301 708 614
U.S. and International Pipelines (US$)
ANR 33 32 111 122
TC PipeLines, LP1,2 21 13 47 30
Great Lakes3 9 8 28 18
Other U.S. pipelines (Bison4, Iroquois1, GTN4, Portland5) 29 49 74 120
Mexico (Guadalajara, Tamazunchale) 49 26 74 52
International and other6 (1 ) (4 ) (2 ) (6 )
Non-controlling interests7 54 31 127 74
U.S. and International Pipelines - comparable EBITDA 194 155 459 410
Comparable depreciation and amortization (54 ) (54 ) (108 ) (109 )
U.S. and International Pipelines - comparable EBIT 140 101 351 301
Foreign exchange impact 13 2 34 4
U.S. and International Pipelines - comparable EBIT(Cdn$) 153 103 385 305
Business Development comparable EBITDA and EBIT (2 ) (5 ) (11 ) (14 )
Natural Gas Pipelines - comparable EBIT 496 399 1,082 905
1 Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments.
2 Effective May 22, 2013, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold 45 per cent of GTN and Bison to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership of GTN, Bison, and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.
Ownership percentage as of
July 1, 2013 May 22, 2013 January 1, 2013
TC PipeLines, LP 28.9 28.9 33.3
Effective ownership through TC PipeLines, LP:
GTN/Bison 20.2 7.2 8.3
Great Lakes 13.4 13.4 15.5
3 Represents our 53.6 per cent direct ownership interest.
4 Effective July 1, 2013, represents our 30 per cent direct ownership interest. Prior to July 1, 2013, our direct ownership interest was 75 per cent.
5 Represents our 61.7 per cent ownership interest.
6 Includes our share of the equity income from Gas Pacifico/INNERGY and TransGas as well as general and administration costs relating to our U.S. and International pipelines.
7 Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

CANADIAN PIPELINES

Net income and comparable EBITDA for our rate-regulated Canadian Pipelines are 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 comparable EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Canadian Mainline - net income 58 67 124 218
Canadian Mainline - comparable earnings 58 67 124 134
NGTL System 58 58 121 114
Foothills 4 5 8 9

Canadian Mainline's net income decreased by $9 million and $94 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 as net income in first quarter 2013 included $84 million related to the 2012 impact of the NEB decision (RH-003-2011), which was excluded from comparable earnings. Comparable earnings in both years reflect an ROE of 11.50 per cent on deemed common equity of 40 per cent and have decreased by $9 million and $10 million for the three and six months ended June 30, 2014 compared to the same periods in 2013 because of a lower average investment base as well as carrying charges owed to shippers on the Tolls Stabilization Account.

Net income for the NGTL System was unchanged for the three months ended June 30, 2014 and increased by $7 million for the six months ended June 30, 2014 compared to the same periods in 2013. A higher average investment base as well as an increase in the ROE had a positive impact on earnings. These increases were partially offset by increased OM&A costs at risk under the terms of the 2013-2014 NGTL Settlement approved by the NEB in November 2013. The Settlement included an ROE of 10.10 per cent on deemed common equity of 40 per cent and included annual fixed amounts for certain OM&A costs. Results for the three and six months ended June 30, 2013 reflect the previously approved ROE of 9.70 per cent on deemed common equity of 40 per cent.

U.S. AND INTERNATIONAL PIPELINES

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

Comparable EBITDA for the U.S. and international pipelines increased by US$39 million and US$49 million for the three and six months ended June 30, 2014 compared to the same periods in 2013. This was the net effect of:

  • contract revenues recognized from the Tamazunchale Extension in the three months ended June 30, 2014. The Tamazunchale Extension project has experienced delays in completing the construction due to archeological findings along the pipeline route. The CFE agreed that, under the terms of the TSA, these delays constitute force majeure and, as a result, collection and recognition of revenue commenced on March 9, 2014.
  • higher transportation revenues at Great Lakes and higher contributions from TC PipeLines, LP reflecting colder winter weather and increased demand
  • higher OM&A costs at ANR as well as lower storage revenues in first quarter 2014.

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

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $18 million and $40 million for the three and six months ended June 30, 2014 compared to the same periods in 2013, mainly because of a higher investment base and higher depreciation rates on the NGTL System.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES

six months ended June 30 Canadian Mainline1 NGTL System2 ANR3
(unaudited) 2014 2013 2014 2013 2014 2013
Average investment base (millions of $) 5,667 5,871 6,179 5,882 n/a n/a
Delivery volumes (Bcf)
Total 842 704 1,996 1,832 863 823
Average per day 4.7 3.9 11.0 10.1 4.8 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, 2014 were 599 Bcf (2013 - 397 Bcf). Average per day was 3.3 Bcf (2013 - 2.2 Bcf).
2 Field receipt volumes for the NGTL System for the six months ended June 30, 2014 were 1,879 Bcf (2013 - 1,840 Bcf). Average per day was 10.4 Bcf (2013 - 10.2 Bcf).
3 Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.

Liquids Pipelines1

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

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Comparable EBITDA 249 186 490 365
Comparable depreciation and amortization2 (54 ) (37 ) (103 ) (74 )
Comparable EBIT 195 149 387 291
Specific items - - - -
Segmented earnings 195 149 387 291
1 Previously Oil Pipelines.
2 Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

Liquids Pipelines segmented earnings increased by $46 million for the three months ended June 30, 2014 and increased by $96 million for the six months ended June 30, 2014 compared to the same periods in 2013. Liquids Pipelines segmented earnings are equivalent to comparable EBIT and comparable EBITDA and are discussed below.

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Keystone Pipeline System 256 187 504 373
Liquids Pipelines Business Development (7 ) (1 ) (14 ) (8 )
Liquids Pipelines - comparable EBITDA 249 186 490 365
Comparable depreciation and amortization (54 ) (37 ) (103 ) (74 )
Liquids Pipelines - comparable EBIT 195 149 387 291
Comparable EBIT denominated as follows:
Canadian dollars 50 52 99 99
U.S. dollars 133 95 262 189
Foreign exchange impact 12 2 26 3
195 149 387 291

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

Comparable EBITDA for the Keystone Pipeline System increased by $69 million for the three months ended June 30, 2014 and increased by $131 million for the six months ended June 30, 2014 compared to the same periods in 2013. These increases were primarily due to:

  • incremental earnings from the Gulf Coast extension which was placed in service in January 2014
  • a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.

BUSINESS DEVELOPMENT

Business development expenses for the three and six months ended June 30, 2014 were $6 million higher than the same periods in 2013 primarily due to lower capitalization of business development costs in 2014.

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $17 million for the three months ended June 30, 2014 and by $29 million for the six months ended June 30, 2014 compared to the same periods in 2013 due to the Gulf Coast extension being placed in service.

Energy

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

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Comparable EBITDA 231 330 576 607
Comparable depreciation and amortization1 (77 ) (69 ) (154 ) (143 )
Comparable EBIT 154 261 422 464
Specific items (pre-tax):
Cancarb gain on sale 108 - 108 -
Niska contract termination (41 ) - (41 ) -
Risk management activities (5 ) (18 ) (16 ) (22 )
Segmented earnings 216 243 473 442
1 Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

Our Energy segmented earnings decreased by $27 million for the three months ended June 30, 2014 and increased by $31 million for the six months ended June 30, 2014 compared to the same periods in 2013.

Energy segmented earnings included the following specific items for the three and six months ended June 30, 2014:

  • a gain of $108 million ($99 million after tax) on the sale of Cancarb Limited and its related power generation business, which closed on April 15, 2014
  • a net loss resulting from the contract termination payment to Niska Gas Storage of $41 million ($31 million after-tax) effective April 30, 2014
  • unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks as follows:
Risk management activities three months ended June 30 six months ended June 30
(unaudited - millions of $, pre-tax) 2014 2013 2014 2013
Canadian Power (2 ) (4 ) (2 ) (6 )
U.S. Power (9 ) (18 ) (11 ) (17 )
Natural Gas Storage 6 4 (3 ) 1
Total losses from risk management activities (5 ) (18 ) (16 ) (22 )

The remainder of the Energy segmented earnings are equivalent to comparable EBITDA and comparable EBIT and are discussed below.

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Canadian Power
Western Power 46 117 118 191
Eastern Power1 70 69 163 159
Bruce Power 24 59 88 90
Canadian Power - comparable EBITDA2 140 245 369 440
Comparable depreciation and amortization (45 ) (43 ) (89 ) (86 )
Canadian Power - comparable EBIT2 95 202 280 354
U.S. Power (US$)
U.S. Power - comparable EBITDA 88 80 174 147
Comparable depreciation and amortization (27 ) (23 ) (54 ) (51 )
U.S. Power - comparable EBIT 61 57 120 96
Foreign exchange impact 6 1 11 2
U.S. Power - comparable EBIT (Cdn$) 67 58 131 98
Natural Gas Storage and other
Natural Gas Storage and other - comparable EBITDA 2 9 29 27
Comparable depreciation and amortization (3 ) (2 ) (6 ) (5 )
Natural Gas Storage and other - comparable EBIT (1 ) 7 23 22
Business Development comparable EBITDA and EBIT (7 ) (6 ) (12 ) (10 )
Energy - comparable EBIT2 154 261 422 464
1 Includes four Ontario solar facilities acquired between June and December 2013.
2 Includes our share of equity income from our investments in ASTC Power Partnership, Portlands Energy and Bruce Power.

Comparable EBITDA for Energy decreased by $99 million for the three months ended June 30, 2014 compared to the same period in 2013. The decrease was the net effect of:

  • lower earnings from Western Power as a result of lower realized power prices
  • lower equity income from Bruce Power mainly due to increased planned and unplanned outage days at Bruce A, partially offset by fewer outage days at Bruce B
  • higher earnings from U.S. Power mainly because of higher realized capacity prices
  • lower earnings from Natural Gas Storage due to lower realized natural gas storage spreads.

Comparable EBITDA for Energy decreased by $31 million for the six months ended June 30, 2014 compared to the same period in 2013. The decrease was the net effect of:

  • lower earnings from Western Power as a result of lower realized power prices
  • higher earnings from U.S. Power mainly because of higher realized capacity and power prices
  • higher earnings from Eastern Power due to the incremental earnings from the Ontario solar facilities acquired in 2013.

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

CANADIAN POWER

Western and Eastern Power

three months ended June 30 six months ended June 30
(unaudited - millions of $) 2014 2013 2014 2013
Revenue
Western Power 160 157 341 297
Eastern Power1 88 91 230 200
Other2 6 22 57 53
254 270 628 550
Income from equity investments3 8 66 28 88
Commodity purchases resold (90 ) (83 ) (191 ) (150 )
Plant operating costs and other (58 ) (71 ) (186 ) (144 )
Exclude risk management activities 2 4 2 6
Comparable EBITDA 116 186 281 350
Comparable depreciation and amortization (45 ) (43 ) (89 ) (86 )
Comparable EBIT 71 143 192 264
Breakdown of comparable EBITDA
Western Power 46 117 118 191
Eastern Power 70 69 163 159
Comparable EBITDA 116 186 281 350
1 Includes four Ontario solar facilities acquired between June and December 2013.
2 Includes sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black. Sale of Cancarb closed April 15, 2014.
3 Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy.

Sales volumes and plant availability

Includes our share of volumes from our equity investments.

three months ended June 30 six months ended June 30
(unaudited) 2014 2013 2014 2013
Sales volumes (GWh)
Supply
Generation
Western Power 611 687 1,220 1,357
Eastern Power1 596 750 1,873 2,096
Purchased
Sundance A & B and Sheerness PPAs2 2,598 1,788 5,398 3,495
Other purchases 2 - 7 -
3,807 3,225 8,498 6,948
Sales
Contracted
Western Power 2,434 1,939 4,895 3,646
Eastern Power1 596 750 1,873 2,...