Common Share Dividend Increased Eight Per Cent to $2.08 Per Share Annually
CALGARY, ALBERTA–(Marketwired – Feb. 13, 2015) - TransCanada Corporation (TSX:TRP)(NYSE:TRP) (TransCanada) today announced net income attributable to common shares for fourth quarter 2014 of $458 million or $0.65 per share compared to $420 million or $0.59 per share for the same period in 2013. For the year ended December 31, 2014, net income attributable to common shares was $1.7 billion or $2.46 per share compared to $1.7 billion or $2.42 per share in 2013. Comparable earnings for fourth quarter 2014 were $511 million or $0.72 per share compared to $410 million or $0.58 per share for the same period last year. For the year ended December 31, 2014, comparable earnings were $1.7 billion or $2.42 per share compared to $1.6 billion or $2.24 per share in 2013. TransCanada’s Board of Directors also declared a quarterly dividend of $0.52 per common share for the quarter ending March 31, 2015, equivalent to $2.08 per common share on an annualized basis, an increase of eight per cent. This is the fifteenth consecutive year the Board of Directors has raised the dividend.
“Comparable earnings and funds generated from operations in 2014 increased eight per cent and seven per cent, respectively compared to last year,” said Russ Girling, TransCanada’s president and chief executive officer. “Our strong performance reflects the diversity and stability of our complementary businesses and $3.8 billion of new assets that were placed into service in 2014. Looking forward, the resiliency of our business model and a strong balance sheet leaves us well positioned to continue to create shareholder value under various market conditions.
“With an additional $12 billion of small-to-medium sized projects expected to be completed and placed into service by the end of 2017, and the steps we have taken to solidify the long-term returns from existing assets such as the Canadian Mainline and ANR, we are also pleased to announce an eight per cent increase in the common share dividend”, added Girling. “Our financial strength and flexibility provides us with the capacity to raise the dividend and to continue to prudently fund our industry-leading capital program.”
Over the course of 2014, we captured approximately $7 billion of new projects primarily related to our Canadian regulated natural gas pipeline business. With these additions, our capital program now includes $46 billion of commercially secured projects which are backed by long-term contracts or cost of service business models. We continue to advance this unprecedented slate of growth initiatives, with many currently under construction or proceeding through their respective regulatory processes. Over the remainder of the decade, subject to required approvals, this blue-chip portfolio of contracted energy infrastructure is expected to generate significant sustainable growth in earnings, cash flow and dividends.
Fourth Quarter and Year-End Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Fourth quarter financial results:
Net income attributable to common shares of $458 million or $0.65 per share
Comparable earnings of $511 million or $0.72 per share
Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.5 billion
Funds generated from operations of $1.2 billion
For the year ended December 31, 2014:
Net income attributable to common shares of $1.7 billion or $2.46 per share
Comparable earnings of $1.7 billion or $2.42 per share
Comparable EBITDA of $5.5 billion
Funds generated from operations of $4.3 billion
Announced an increase in the quarterly common share dividend of eight per cent to $0.52 per share for the quarter ending March 31, 2015
Received National Energy Board (NEB) approval for our Canadian Mainline 2015-2030 Tolls Application
Filed regulatory applications with the NEB for the $12 billion Energy East Project and the $1.5 billion Eastern Mainline Project on October 30, 2014
Received Environmental Assessment Certificates (EAC) from the B.C. Environmental Assessment Office (BC EAO) for Coastal GasLink and Prince Rupert Gas Transmission
Commenced construction on the $1.5 billion Grand Rapids Pipeline Project and the $1 billion Napanee Power Project
Nebraska State Supreme Court vacated a lower court’s ruling that the law approving the route for the Keystone XL project was unconstitutional. The current route through Nebraska remains valid.
Closed the $60 million purchase of an additional solar facility in Ontario in late December
Closed the sale of our remaining 30 per cent interest in the Bison pipeline and announced our intention to sell our remaining 30 per cent interest in Gas Transmission Northwest LLC (GTN) to TC PipeLines, LP as part of advancing our master limited partnership drop down strategy
Net income attributable to common shares increased by $38 million to $458 million or $0.65 per share for the three months ended December 31, 2014 compared to the same period in 2013. Both years included unrealized gains and losses from changes in certain risk management activities. Fourth quarter 2014 results also included an $8 million after-tax gain from the sale of Gas Pacifico/INNERGY.
Net income attributable to common shares for the year ended December 31, 2014 was $1.7 billion or $2.46 per share compared to $1.7 billion or $2.42 per share in 2013. Results in 2014 included a net after-tax gain of $99 million from the sale of Cancarb and its related power generation facility, an after-tax $32 million expense for terminating a natural gas storage contract and an $8 million after-tax gain from the sale of Gas Pacifico/INNERGY. Results in 2013 included $84 million of net income related to the 2012 impact of the 2013 NEB decision on the Canadian Mainline 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. These amounts, along with unrealized gains and losses on risk management activities, were excluded from comparable earnings.
Comparable earnings for fourth quarter 2014 were $511 million or $0.72 per share compared to $410 million or $0.58 per share for the same period in 2013. Higher earnings from the Keystone Pipeline System, the Canadian Mainline, Mexican Pipelines and U.S. Power were partially offset by higher interest expense.
Comparable earnings for the year ended December 31, 2014 were $1.7 billion or $2.42 per share compared to $1.6 billion or $2.24 per share in 2013. Higher earnings from the Keystone Pipeline System, the Canadian Mainline, Mexican Pipelines, U.S. and International Pipelines, Eastern Power and U.S. Power were partially offset by higher interest expense and lower contributions from Western Power.
Notable recent developments in Liquids Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Liquids Pipelines:
Energy East Pipeline: On October 30, 2014, we filed the necessary regulatory applications for approvals to construct and operate the Energy East Pipeline and terminal facilities with the NEB. 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 by the end of 2018.
The Energy East Pipeline includes a proposed marine terminal near Cacouna, Québec which would be adjacent to a beluga whale habitat. On December 8, 2014, the Committee on the Status of Endangered Wildlife in Canada recommended that beluga whales be placed on the endangered species list. As a result, we have made the decision to halt any further work at Cacouna and we will be analyzing the recommendation, assessing any impacts to the project and reviewing all viable options. We intend to make a decision on how to proceed by the end of first quarter 2015.
The 1.1 million barrel per day (Bbl/d) Energy East Pipeline received approximately one million Bbl/d of firm, long-term contracts to transport crude oil from western Canada that were secured during binding open seasons.
Keystone XL: In February 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Heineman, had the authority to approve an alternative route through Nebraska for the Keystone XL project. Nebraska’s Attorney General filed an appeal which was heard by the Nebraska State Supreme Court on September 5, 2014. On January 9, 2015, the Nebraska State Supreme Court vacated the lower court’s ruling that the law was unconstitutional. As a result, the Governor’s January 2013 approval of the alternate route through Nebraska for Keystone XL remains valid. Landowners have filed lawsuits in two Nebraska counties seeking to enjoin Keystone XL from condemning easements on state constitutional grounds.
In September 2014, we filed a certification petition for Keystone XL with the South Dakota Public Utilities Commission (PUC) which confirms that the conditions under which Keystone XL’s original June 2010 PUC construction permit was granted continue to be satisfied. The formal hearing for the certification is scheduled for May 2015.
On January 16, 2015, the U.S. Department of State (DOS) re-initiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest and to provide their views to the DOS by February 2, 2015.
On February 2, 2015, the U.S. Environmental Protection Agency (EPA) posted a comment letter to its website suggesting that, among other things, the Final Supplemental Environmental Impact Statement issued by the DOS has not fully and completely assessed the environmental impacts of Keystone XL and that, at lower oil prices, Keystone XL may increase the rates of oil sands production and greenhouse gas emissions. On February 10, 2015, we sent a letter to the DOS refuting these and other comments in the EPA letter but also offering to work with the DOS to ensure it has all the relevant information to allow it to reach a decision to approve Keystone XL.
The estimated capital cost for Keystone XL is approximately US$8.0 billion. As of December 31, 2014, we have invested US$2.4 billion in the project and have also recorded capitalized interest in the amount of US$0.4 billion.
Northern Courier: In July 2014, the Alberta Energy Regulator issued a permit approving our application to construct and operate the Northern Courier Pipeline. Construction has started on the $900 million, 90 kilometre (km) (56 mile) pipeline to transport bitumen and diluent between the Fort Hills mine site and Suncor Energy’s terminal located north of Fort McMurray, Alberta. We currently expect the pipeline to be ready for service in 2017.
Grand Rapids Pipeline Project: On October 9, 2014, the Alberta Energy Regulator issued a permit approving our application to construct and operate the Grand Rapids Pipeline. We have a partner through a joint venture, to develop Grand Rapids, a 460 km (287 mile) crude oil and diluent pipeline system connecting the producing area northwest of Fort McMurray, Alberta to terminals in the Edmonton/Heartland, Alberta region. Each partner will own 50 per cent of the $3 billion pipeline project, and we will be the operator. Our partner has also entered into a long-term transportation service contract in support of Grand Rapids. Construction has commenced with initial crude oil transportation planned in 2016.
Upland Pipeline: In November 2014, we completed a successful binding open season for the Upland Pipeline. The $600 million pipeline would provide crude oil transportation between multiple points in North Dakota and interconnect with the Energy East Pipeline at Moosomin, Saskatchewan.
Subject to regulatory approvals, we anticipate the Upland Pipeline to be in service in 2018. The commercial contracts we have executed for Upland Pipeline are conditioned on Energy East Pipeline proceeding.
Natural Gas Pipelines:
NGTL System Expansions: We continue to experience significant growth on the NGTL System 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. This demand for NGTL System services is expected to result in a total of approximately 4.0 billion cubic feet per day (Bcf/d) of incremental firm service contracts. Approximately 3.1 Bcf/d of this volume relates to firm receipt service and 0.9 Bcf/d relates to firm delivery service. Significant new facilities consisting of approximately 540 km (336 miles) of pipeline, seven compressor stations, and 40 meter stations will be required in 2016 and 2017 (2016/17 Facilities) to meet these service requests. We will be seeking regulatory approval in 2015 to construct the new facilities which have an estimated total capital cost of $2.7 billion.
Including the new 2016/17 Facilities, the North Montney Mainline, the Merrick Mainline, and other new supply and demand facilities, the NGTL System has approximately $6.7 billion of projects in development which have been or will be filed with the NEB for approval.
NGTL System Revenue Requirement Settlement: We received NEB approval on February 2, 2015 for our revenue requirement settlement with our shippers for 2015 on the NGTL System. The terms of the one year settlement include no changes to the return on equity of 10.1 per cent on 40 per cent deemed equity, a continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed operating, maintenance and administrative expense amount that is based on an escalation of 2014 actual costs.
Canadian Mainline 2015 – 2030 Tolls and Tariff Application: On November 28, 2014, the NEB approved the Canadian Mainline’s 2015 – 2030 Tolls and Tariff Application. The application reflected components of a settlement between the Canadian Mainline and the three major local distribution companies in Ontario and Québec. The approval of this application provides a long term commercial platform for both the Canadian Mainline and its shippers with a known toll design for 2015 to 2020 and certain parameters for a toll-setting methodology up to 2030. The platform balances the needs of our shippers while at the same time ensuring a reasonable opportunity to recover the capital from our existing facilities and any new facilities required to serve existing and new markets.
Highlights of the approved application include a revenue requirement along with an incentive sharing mechanism that targets a return of 10.1 per cent on a deemed common equity of 40 per cent, with a possible range of outcomes from 8.7 per cent to 11.5 per cent.
Canadian Mainline Expansions: On October 30, 2014, we filed an application seeking NEB approval to build, own and operate new facilities for our existing Canadian Mainline natural gas transmission system in southeastern Ontario. The new facilities are a result of the proposed transfer of a portion of Canadian Mainline capacity to crude oil from natural gas service as part of our Energy East Pipeline and an open season that closed in January 2014. The $1.5 billion Eastern Mainline Project will add 0.6 Bcf/d of new capacity in the Eastern Triangle segment of the Canadian Mainline and will ensure appropriate levels of capacity are available to meet the requirements of existing shippers as well as new firm service commitments. The project is contingent upon the Energy East Project.
In addition to the Eastern Mainline Project, we have executed new short haul arrangements in the Eastern Triangle portion of the Canadian Mainline that require new facilities, or modifications to existing facilities. Subject to regulatory approval, these projects will provide capacity needed to meet customer requirements in Eastern Canada and have a total capital cost estimate of $475 million, with expected in-service dates between November 1, 2015 and November 1, 2016.
Bison and GTN Sales: On October 1, 2014, our remaining 30 per cent interest in the Bison pipeline was sold to our master limited partnership, TC PipeLines, LP (the Partnership) for cash proceeds of US$215 million.
On November 12, 2014, we announced an offer to sell our remaining 30 per cent interest in the GTN Pipeline to the Partnership. Subject to the satisfactory negotiation of terms and Partnership Board approval, the transaction is expected to close in late first quarter 2015.
These transactions advance our previously stated commitment to sell the remainder of TransCanada’s U.S. natural gas pipeline assets to the Partnership to help fund our capital program and enhance the size and diversity of the Partnership’s asset base, positioning it with visible, high quality future growth. Including GTN, the U.S. natural gas pipeline assets that remain directly-held by TransCanada are expected to generate approximately US$480 million of EBITDA in 2016.
At December 31, 2014, we held a 28.3 per cent interest in TC PipeLines, LP.
Tamazunchale Pipeline Extension Project: Construction of the US$600 million extension was completed November 6, 2014. Delays from the original service commencement date of March 9, 2014 were attributed primarily to archeological findings along the pipeline route. Under the terms of the Transportation Service Agreement, these delays were recognized as a force majeure with provisions allowing for collection of revenue as per the original service commencement date.
Coastal GasLink Pipeline Project: In October 2014, the BC EAO issued an EAC for the Coastal GasLink Pipeline Project. In 2014, we also submitted applications to the B.C. Oil and Gas Commission (BC OGC) for the permits required to build and operate Coastal GasLink. Regulatory review of those applications is progressing, with permit decisions anticipated in first quarter 2015. We are currently continuing our engagement with Aboriginal groups and stakeholders along the pipeline route and are advancing detailed engineering and construction planning work to support the regulatory applications and refine the capital cost estimates in advance of a final investment decision (FID), which is expected to be made by LNG Canada in early 2016.
Prince Rupert Gas Transmission Project: On November 25, 2014, we received an EAC from the BC EAO. We have submitted our permit applications to the BC OGC for construction of the pipeline and anticipate receiving these permits in first quarter 2015.
We have made significant changes to the project route since first announced, increasing it by 150 km (90 miles) to 900 km (560 miles), taking into account First Nations and stakeholder input. We continue to work closely with First Nations and stakeholders along the proposed route to create and deliver appropriate benefits to all impacted groups. In October 2014, we concluded a benefits agreement with the Nisga’a First Nation to allow 85 km (52 miles) of the proposed natural gas pipeline to run through Nisga’a Lands.
On December 3, 2014, our customer announced the deferral of a FID. We continue to work with our contractors to refine capital cost estimates for the project. Once the permitting process with the BC OGC is complete and Pacific NorthWest LNG secures the necessary regulatory approvals and proceeds with a positive FID, we will be in a position to begin construction. All costs would be fully recoverable should the project not proceed. The deferral of a FID past the end of 2014 has resulted in a deferral of the expected in-service date for the pipeline. The in-service date will depend on when our customer receives the necessary regulatory approvals and is in a position to make a FID.
Energy:
Napanee Project: In January 2015, we began construction activities on the 900 megawatt (MW) natural gas-fired power plant at Ontario Power Generation’s Lennox site in eastern Ontario in the town of Greater Napanee. We expect to invest approximately $1.0 billion in the Napanee facility during construction and commercial operations are expected to begin in late 2017 or early 2018. Production from the facility is fully contracted for 20 years with the Independent Electricity System Operator (IESO).
Ontario Solar: As part of a purchase agreement with Canadian Solar Solutions Inc., we acquired our eighth facility for $60 million in December 2014. Our total investment in the eight solar facilities is $457 million. All power produced by the solar facilities is sold under 20-year power purchase arrangements with the IESO.
Ravenswood: In late September 2014, the 972 MW Unit 30 at the Ravenswood Generating Station experienced an unplanned outage as a result of a problem with the generator associated with the high pressure turbine. Insurance is expected to cover the repair costs and lost revenues associated with the unplanned outage, which are yet to be finalized. As a result of the expected insurance recoveries, net of deductibles, the Unit 30 unplanned outage is not expected to have a significant impact on our earnings although the recording of earnings may not coincide with lost revenues due to timing of the anticipated insurance proceeds. The unit is expected to be back in service in the first half of 2015.
Corporate:
Common Dividend: Our Board of Directors declared a quarterly dividend of $0.52 per share for the quarter ending March 31, 2015 on TransCanada’s outstanding common shares. The quarterly amount is equivalent to $2.08 per common share on an annualized basis and represents an eight per cent increase over the previous amount.
Preferred Share Rate Reset and Conversion: In December 2014, Series 1 shareholders converted 12.5 million of our 22 million outstanding Series 1 Cumulative Redeemable First Preferred Shares, on a one-for-one basis into Series 2 floating-rate Cumulative Redeemable First Preferred Shares. The rate on the Series 1 Shares was reset and they will pay an annual fixed dividend rate of 3.266 per cent on a quarterly basis for the five-year period which began on December 31, 2014. The Series 2 Shares will pay a floating quarterly dividend for the same five-year period. The quarterly dividend rate for the Series 2 Shares for the first quarterly floating rate period (December 31, 2014 to but excluding March 31, 2015) is 2.815 per cent per annum and will be reset every quarter going forward.
Financing Activity: In January 2015, we issued US$500 million of three-year fixed rate senior notes bearing interest at 1.875 per cent, and US$250 million of three-year LIBOR-based floating rate senior notes, bearing interest at an initial rate of 1.045 per cent, both maturing on January 12, 2018.
The net proceeds of these offerings are intended to be used for general corporate purposes and to reduce short-term indebtedness which was used to fund a portion of our capital program and for general corporate purposes.
Teleconference – Audio and Slide Presentation:
We will hold a teleconference and webcast on Friday, February 13, 2015 to discuss our fourth 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 1:00 p.m. (MT) / 3:00 p.m. (ET).
Analysts, members of the media and other interested parties are invited to participate by calling 800.396.7098 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 atwww.transcanada.com.
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on February 20, 2015. Please call800.408.3053 or 905.694.9451 and enter pass code 2631193.
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.
Fourth quarter 2014 and financial highlights
three months ended
December 31
year ended
December 31
(unaudited – millions of $, except per share amounts)
2014
2013
2014
2013
Income
Revenue
2,616
2,332
10,185
8,797
Net income attributable to common shares
458
420
1,743
1,712
per common share – basic and diluted
$0.65
$0.59
$2.46
$2.42
Comparable EBITDA(1)
1,521
1,291
5,521
4,859
Comparable earnings(1)
511
410
1,715
1,584
per common share(1)
$0.72
$0.58
$2.42
$2.24
Operating cash flow
Funds generated from operations(1)
1,178
1,083
4,268
4,000
Decrease/(increase) in operating working capital
12
(74
)
(189
)
(326
)
Net cash provided by operations
1,190
1,009
4,079
3,674
Investing activities
Capital spending – capital expenditures
1,128
1,311
3,550
4,264
Capital spending – projects under development
330
297
807
488
Equity investments
61
62
256
163
Acquisitions, net of cash acquired
60
62
241
216
Proceeds from sale of assets, net of transaction costs
9
-
196
-
Dividends declared
per common share
$0.48
$0.46
$1.92
$1.84
Basic common shares outstanding (millions)
Average for the period
709
707
708
707
End of period
709
707
709
707
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.
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 likeanticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this news release may include information about the following, among other things:
anticipated business prospects
our financial and operational performance, including the performance of our subsidiaries, and the expected incremental earnings to be realized from our portfolio of growth projects
expectations or projections about strategies and goals for growth and expansion
expected cash flows and future financing options available to us
expected costs for planned projects, including projects under construction and in development
expected schedules for planned projects (including anticipated construction and completion dates)
expected regulatory processes and outcomes
expected impact of regulatory outcomes
expected outcomes with respect to legal proceedings, including arbitration and insurance claims
expected capital expenditures and contractual obligations
expected operating and financial results
the expected impact of future accounting changes, commitments and contingent liabilities
expected industry, market and economic conditions.
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this news release.
Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:
Assumptions
inflation rates, commodity prices and capacity prices
timing of financings and hedging
regulatory decisions and outcomes
foreign exchange rates
interest rates
tax rates
planned and unplanned outages and the use of our pipeline and energy assets
integrity and reliability of our assets
access to capital markets
anticipated construction costs, schedules and completion dates
acquisitions and divestitures.
Risks and uncertainties
our ability to successfully implement our strategic initiatives
whether our strategic initiatives will yield the expected benefits
the operating performance of our pipeline and energy assets
amount of capacity sold and rates achieved in our pipeline businesses
the availability and price of energy commodities
the amount of capacity payments and revenues we receive from our energy business
regulatory decisions and outcomes
outcomes of legal proceedings, including arbitration and insurance claims
performance of our counterparties
changes in market commodity prices
changes in the political environment
changes in environmental and other laws and regulations
competitive factors in the pipeline and energy sectors
construction and completion of capital projects
costs for labour, equipment and materials
access to capital markets
interest 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.
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.
Comparable measures
We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Comparable measure
Original measure
comparable earnings
net income attributable to common shares
comparable earnings per common share
net income per common share
comparable EBITDA
EBITDA
comparable EBIT
segmented earnings
comparable depreciation and amortization
depreciation and amortization
comparable interest expense
interest expense
comparable interest income and other
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 – fourth quarter 2014
three months ended
December 31
year ended
December 31
(unaudited – millions of $, except per share amounts)
2014
2013
2014
2013
Natural Gas Pipelines
621
498
2,187
1,881
Liquids Pipelines
230
160
843
603
Energy
219
301
1,051
1,113
Corporate
(43
)
(35
)
(150
)
(124
)
Total segmented earnings
1,027
924
3,931
3,473
Interest expense
(323
)
(240
)
(1,198
)
(985
)
Interest income and other
28
1
91
34
Income before income taxes
732
685
2,824
2,522
Income tax expense
(206
)
(208
)
(831
)
(611
)
Net income
526
477
1,993
1,911
Net income attributable to non-controlling interests
(43
)
(38
)
(153
)
(125
)
Net income attributable to controlling interests
483
439
1,840
1,786
Preferred share dividends
(25
)
(19
)
(97
)
(74
)
Net income attributable to common shares
458
420
1,743
1,712
Net income per common share – basic and diluted
$0.65
$0.59
$2.46
$2.42
Net income attributable to common shares increased by $38 million for the three months ended December 31, 2014 compared to the same period in 2013 and included an after tax gain on the sale of Gas Pacifico/INNERGY of $8 million as well as unrealized gains and losses from changes in certain risk management activities. Excluding the impact of these items, comparable earnings in the three months ended December 31, 2014 increased over the same period in 2013, as discussed below in Reconciliation of Net Income to Comparable Earnings.
Net income attributable to common shares increased by $31 million for the year ended December 31, 2014 compared to 2013. The following specific items were recognized in net income:
2014
a gain on the 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 $32 million after tax
a gain on the sale of our 30 per cent interest in Gas Pacifico/INNERGY of $8 million after tax
2013
net income of $84 million related to 2012 from the 2013 NEB Decision
a favourable tax adjustment of $25 million due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax.
The items discussed above were 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
December 31
year ended
December 31
(unaudited – millions of $, except per share amounts)
2014
2013
2014
2013
Net income attributable to common shares
458
420
1,743
1,712
Specific items (net of tax):
Cancarb gain on sale
-
-
(99
)
-
Niska contract termination
-
-
32
-
Gas Pacifico/ INNERGY gain on sale
(8
)
-
(8
)
-
2013 NEB decision – 2012
-
-
-
(84
)
Part VI.I income tax adjustment
-
-
-
(25
)
Risk management activities(1)
61
(10
)
47
(19
)
Comparable earnings
511
410
1,715
1,584
Net income per common share
$0.65
$0.59
$2.46
$2.42
Specific items (net of tax):
Cancarb gain on sale
-
-
(0.14
)
-
Niska contract termination
-
-
0.04
-
Gas Pacifico/ INNERGY gain on sale
(0.01
)
-
(0.01
)
-
2013 NEB decision – 2012
-
-
-
(0.12
)
Part VI.I income tax adjustment
-
-
-
(0.04
)
Risk management activities(1)
0.08
(0.01
)
0.07
(0.02
)
Comparable earnings per share
$0.72
$0.58
$2.42
$2.24
(1)
Risk management activities
three months ended
December 31
year ended
December 31
(unaudited – millions of $)
2014
2013
2014
2013
Canadian Power
(11
)
(2
)
(11
)
(4
)
U.S. Power
(85
)
36
(55
)
50
Natural Gas Storage
9
(5
)
13
(2
)
Foreign exchange
(12
)
(9
)
(21
)
(9
)
Income tax attributable to risk management activities
38
(10
)
27
(16
)
Total (losses)/gains from risk management activities
(61
)
10
(47
)
19
Comparable earnings increased by $101 million for the three months ended December 31, 2014 compared to the same period in 2013. This was primarily the net effect of:
incremental earnings from the Gulf Coast extension of the Keystone Pipeline System
higher earnings from Canadian Mainline due to higher incentive earnings recorded in fourth quarter
higher earnings from the Tamazunchale Extension which was placed in service in 2014
higher earnings from Eastern Power due to higher contractual earnings at Bécancour and incremental earnings from solar facilities acquired in December 2013 and the second half of 2014
higher earnings from U.S. Power due to higher generation, higher sales to wholesale, commercial and industrial customers and the impact of higher realized power and capacity prices
higher interest expense from debt issuances and lower capitalized interest on projects placed in service.
The stronger U.S. dollar this quarter compared to the same period in 2013 positively impacted the translated results of our U.S. businesses, however this impact was 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 cash flow.
Our capital program is comprised of $12 billion of small to medium-sized projects and $34 billion of large scale projects. Amounts presented exclude the impact of foreign exchange and capitalized interest.
All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
at December 31, 2014
(unaudited – billions of $)
Segment
Expected
In-Service Date
Estimated
Project Cost
Amount
Spent
Small to medium sized, shorter-term
Houston Lateral and Terminal
Liquids Pipelines
2015
US 0.6
US 0.4
Topolobampo
Natural Gas Pipelines
2016
US 1.0
US 0.7
Mazatlan
Natural Gas Pipelines
2016
US 0.4
US 0.2
Grand Rapids(1)
Liquids Pipelines
2016-2017
1.5
0.2
Heartland and TC Terminals
Liquids Pipelines
2017
0.9
0.1
Northern Courier
Liquids Pipelines
2017
0.9
0.2
Canadian Mainline – Other
Natural Gas Pipelines
2015-2016
0.5
-
NGTL System
- North Montney
Natural Gas Pipelines
2016-2017
1.7
0.1
- 2016/17 Facilities
Natural Gas Pipelines
2016-2017
2.7
-
- Other
Natural Gas Pipelines
2015-2016
0.4
0.1
Napanee
Energy
2017 or 2018
1.0
0.1
11.6
2.1
Large-scale, medium and longer-term
Upland
Liquids Pipelines
2018
0.6
-
Keystone Projects
Keystone XL(2)
Liquids Pipelines
(3)
US 8.0
US 2.4
Keystone Hardisty Terminal
Liquids Pipelines
(3)
0.3
0.1
Energy East projects
Energy East(4)
Liquids Pipelines
2018
12.0
0.5
Eastern Mainline
Natural Gas Pipelines
2017
1.5
-
BC west coast LNG-related projects
Coastal GasLink
Natural Gas Pipelines
2019+
4.8
0.2
Prince Rupert Gas Transmission
Natural Gas Pipelines
2019+
5.0
0.3
NGTL System – Merrick
Natural Gas Pipelines
2020
1.9
-
34.1
3.5
45.7
5.6
(1)
Represents our 50 per cent share.
(2)
Estimated project cost dependent on the timing of the Presidential permit.
(3)
Approximately two years from the date the Keystone XL permit is received.
(4)
Excludes transfer of Canadian Mainline natural gas assets.
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
December 31
year ended
December 31
(unaudited – millions of $)
2014
2013
2014
2013
Comparable EBITDA
884
778
3,241
2,852
Comparable depreciation and amortization(1)
(272
)
(280
)
(1,063
)
(1,013
)
Comparable EBIT
612
498
2,178
1,839
Specific items:
Gas Pacifico/INNERGY gain on sale
9
-
9
-
2013 NEB decision – 2012
-
-
-
42
Segmented earnings
621
498
2,187
1,881
(1)
In 2014, comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization. In 2013, comparable depreciation and amortization was adjusted by $13 million relating to the impact of the 2013 NEB Decision (RH-003-2011).
Natural Gas Pipelines segmented earnings increased by $123 million for the three months ended December 31, 2014 compared to the same period in 2013 and included a $9 million pre-tax gain related to the sale of Gas Pacifico/INNERGY in November 2014. 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 which, along with comparable EBITDA, are discussed below.
three months ended
December 31
year ended
December 31
(unaudited – millions of $)
2014
2013
2014
2013
Canadian Pipelines
Canadian Mainline
396
305
1,334
1,121
NGTL System
219
261
856
846
Foothills
26
28
106
114
Other Canadian pipelines(1)
5
6
22
26
Canadian Pipelines – comparable EBITDA
646
600
2,318
2,107
Comparable depreciation and amortization
(208
)
(225
)
(821
)
(790
)
Canadian Pipelines – comparable EBIT
438
375
1,497
1,317
U.S. and International Pipelines (US$)
ANR
47
33
189
188
TC PipeLines, LP(1,2)
23
21
88
72
Great Lakes(3)
13
10
49
34
Other U.S. pipelines (Bison(4), Iroquois(1), GTN(5), Portland(6))
32
37
132
183
Mexico (Guadalajara, Tamazunchale)
43
23
160
100
International and other(1,7)
(5
)
(1
)
(10
)
(4
)
Non-controlling interests(8)
65
60
241
186<