CALGARY, ALBERTA--(Marketwired - Feb 20, 2014) - TransCanada Corporation ( TRP.TO ) ( TRP ) (TransCanada or the Company) today announced comparable earnings for fourth quarter 2013 of $410 million or $0.58 per share compared to $318 million or $0.45 per share for the same period in 2012. For the year ended December 31, 2013, comparable earnings were $1.6 billion or $2.24 per share compared to $1.3 billion or $1.89 per share in 2012. Net income attributable to common shares for fourth quarter 2013 was $420 million or $0.59 per share compared to $306 million or $0.43 per share in fourth quarter 2012. For the year ended December 31, 2013, net income attributable to common shares was $1.7 billion or $2.42 per share compared to $1.3 billion or $1.84 per share in 2012. TransCanada's Board of Directors also declared a quarterly dividend of $0.48 per common share for the quarter ending March 31, 2014, equivalent to $1.92 per common share on an annualized basis, an increase of four per cent. This is the fourteenth consecutive year the Board of Directors has raised the dividend.
"Our diverse portfolio of critical energy infrastructure assets generated strong earnings and cash flow in 2013," said Russ Girling, TransCanada's president and chief executive officer. "Comparable earnings increased 19 per cent to $1.6 billion and funds generated from operations were up 22 per cent to $4 billion. The strong year over year results reflect a return to an eight unit site at Bruce Power, higher Western Power volumes, an increase in New York capacity prices, growth in our NGTL System, and a higher Canadian Mainline return on equity."
During 2013 we also captured an additional $19 billion of commercially secured growth opportunities. They include the Prince Rupert Gas Transmission project that would move natural gas to Canada's West Coast for liquefaction and shipment to Asian markets, further expansion of the NGTL System, the Heartland and TC Terminals crude oil infrastructure projects in Alberta, and the Energy East Pipeline project which, in addition to new build, would include the conversion of a portion of our existing Canadian Mainline from natural gas to crude oil service and link growing crude oil production in Western Canada to refineries and export terminals in Eastern Canada.
"We now have a $38 billion portfolio of commercially secured projects backed by long-term contracts," added Girling. "Looking forward, we will remain focused on obtaining the necessary approvals and constructing this high-quality portfolio of energy infrastructure assets that are expected to generate significant growth in earnings and cash flow as they are placed into service over the remainder of the decade."
On January 22, 2014, we reached a significant milestone in advancing our unprecedented capital program when the approximate US$2.6 billion Gulf Coast Project began delivering crude oil from Cushing, Oklahoma to refineries on the U.S. Gulf Coast. This vital piece of infrastructure extends our existing Keystone Pipeline System which has safely delivered more than 550 million barrels of oil from Western Canada to key refining markets in the U.S. Midwest since it commenced operations in 2010.
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 $420 million or $0.59 per share
- Comparable earnings of $410 million or $0.58 per share
- Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.3 billion
- Funds generated from operations of $1.1 billion
- For the year ended December 31, 2013
- Net income attributable to common shares of $1.7 billion or $2.42 per share
- Comparable earnings of $1.6 billion or $2.24 per share
- Comparable EBITDA of $4.9 billion
- Funds generated from operations of $4.0 billion
- Announced an increase in the quarterly common share dividend of four per cent to $0.48 per share for the quarter ending March 31, 2014
- Placed the US$2.6 billion Gulf Coast Project into service on January 22, 2014
- Received the U.S. Department of State (DOS) Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL Pipeline on January 31, 2014
- Acquired our fourth Ontario Solar facility for $62 million on December 31, 2013
- Signed a Heads of Agreement (HOA) with the State of Alaska and North Slope producers to advance the proposed Alaska LNG Project in January 2014
- Reached an agreement in January 2014 to sell Cancarb Limited (Cancarb) and its related power generation facility for aggregate gross proceeds of $190 million
Comparable earnings for fourth quarter 2013 were $410 million or $0.58 per share compared to $318 million or $0.45 per share for the same period in 2012. Higher earnings from the Canadian Mainline, the NGTL System, Keystone, and Bruce Power were partially offset by lower contributions from U.S. Natural Gas Pipelines and Western Power.
Comparable earnings for the year ended December 31, 2013 were $1.584 billion or $2.24 per share compared to $1.330 billion or $1.89 per share in 2012. Higher earnings from the Canadian Mainline, the NGTL System, Keystone, Bruce Power, U.S. Power, and Western Power were partially offset by lower contributions from U.S. Natural Gas Pipelines.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Gulf Coast Project
: On January 22, 2014 crude oil transportation service commenced
on the 780 kilometre (km) (485 mile) 36-inch pipeline which
extends from Cushing, Oklahoma to Nederland, Texas. The pipeline,
which is expected to have an average capacity of 520,000 barrels
per day (bbl/d) in its first year of operation, will play a
critical role in connecting growing North American crude oil
production with the continent's largest refining centre in the
U.S. Gulf Coast.
Construction continues on the US$400 million 77 km (48 mile) Houston Lateral pipeline and terminal to transport crude oil to Houston, Texas refineries. We anticipate the capacity of the lateral will be similar to that of the Gulf Coast Project and the terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are expected to be completed in mid-2015.
On January 31, 2014, the DOS released its FSEIS for the Keystone
XL Pipeline. 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
of up to 90 days which involves consultation with other
governmental agencies and provides an opportunity for public
On February 19, 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Dave Heineman, has the authority to approve an alternative route through Nebraska for the Keystone XL Pipeline. We are disappointed and disagree with the decision of the Nebraska district court and will now analyze the judgment and decide what next steps may be taken. Nebraska's Attorney General has filed an appeal.
We anticipate the pipeline, which will extend from Hardisty, Alberta to Steele City, Nebraska, to be in service approximately two years following the receipt of the Presidential Permit. The US$5.4 billion cost estimate will increase depending on the timing and conditions of the permit. As of December 31, 2013, we have invested US$2.2 billion in the project.
Energy East Pipeline:
We have begun 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
mid-2014 for approvals to construct and operate the pipeline
project and terminal facilities.
The 1.1 million bbl/d Energy East Pipeline project received approximately 900,000 bbl/d of firm, long-term contracts during a binding open season to transport crude oil from Western Canada to eastern refineries and export terminals. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets. Subject to regulatory approvals, it is anticipated to commence deliveries to Québec in 2018 with service to New Brunswick expected to follow in late 2018.
Northern Courier Pipeline:
In October 2013, Suncor Energy announced that the Fort Hills
Energy Limited Partnership is proceeding with the Fort Hills oil
sands mining project and expects to begin producing crude oil in
2017. Our Northern Courier Pipeline project, which is expected to
be completed in advance of mine start-up and cost approximately
$800 million, will transport bitumen and diluent between the Fort
Hills mine site and Suncor Energy's terminal located north of
Fort McMurray, Alberta.
We filed a permit application for the project with the Alberta Energy Regulator (AER) after completing the required Aboriginal and stakeholder engagement and associated field work.
Heartland Pipeline and TC Terminals
: In October 2013, we filed a permit application with the AER for
the Heartland Pipeline, after completing the required Aboriginal
and stakeholder engagement and associated field work. In February
2014, the application for the TC Terminals facility was approved
by the AER.
The projects will include a 200 km (125 mile) crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta, and a terminal facility in the Heartland industrial area north of Edmonton. We anticipate the pipeline could transport up to 900,000 bbl/d, while the terminal is expected to have storage capacity for up to 1.9 million barrels of crude oil. These projects together have a combined cost estimated at $900 million and are expected to be in service in 2016.
Natural Gas Pipelines:
In July 2013, we implemented the National Energy Board's (NEB)
decision on our Canadian Mainline Restructuring Proposal
application. The NEB decision introduced several new elements
that were not part of our application, including fixing tolls for
contracted capacity outside the time frame that was applied for
and the ability to price discretionary services at market rates.
Having secured additional firm transportation service contracts
since July 2013, along with the ability to price discretionary
services, allowed us to realize our net revenue requirement in
2013, which included a return on equity of 11.50 per cent on 40
per cent equity.
In December 2013, we filed for NEB approval of a settlement reached with three eastern Canadian local natural gas distribution customers. The settlement is intended to provide a stable, long-term solution to meet demand growth in the Eastern Triangle and address anticipated lower demand for transportation service on the remainder of the system while providing a reasonable opportunity to recover our costs. Under the settlement, the base return on equity would be set at 10.10 per cent on 40 per cent equity. After a $20 million (after tax) annual contribution from 2015 to 2020 and various incentive mechanisms, the return on equity could range from 8.70 to 11.50 per cent.
The Mainline is expected to operate under the current NEB tolling framework in 2014. The settlement, if approved, will address tolls from 2015 through 2020 with certain aspects of tolling to be applied through 2030, and resolve tolls for 2014.
On January 31, 2014, shippers on the Canadian Mainline elected to renew approximately 2.5 billion cubic feet a day of their contracts through November 2016.
NGTL System Expansion:
In addition to completing and placing into service approximately
$730 million of pipeline projects in 2013 to expand and extend
the NGTL System, the NEB approved approximately $290 million of
additional expansions that are currently in various stages of
development or construction, but not yet in-service.
On November 8, 2013, we filed an application with the NEB to construct and operate the 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 British Columbia and underpinned by long-term contracts. The estimated capital cost of the project is $1.7 billion and it consists of approximately 300 km (186 miles) of pipeline.
NGTL System Rate Settlement:
On November 1, 2013, the NEB approved our NGTL System 2013-2014
settlement and final 2013 rates as filed. The settlement fixes
the allowed return on equity at 10.10 per cent on 40 per cent
deemed common equity, establishes an increase in the composite
depreciation rate to 3.05 per cent and 3.12 per cent for 2013 and
2014, respectively, and fixes the operations, maintenance and
administration costs for 2013 at $190 million and 2014 at $198
million with any variance to our account.
Tamazunchale Pipeline Extension Project:
Construction is proceeding on the US$500 million Tamazunchale
Pipeline Extension Project although delays have occurred due to a
significant number of archeological finds along the pipeline
route. It is expected these finds and the related impact on
construction will move the project's scheduled in-service date to
second quarter 2014. As these types of finds are not uncommon in
significant infrastructure projects in Mexico, contractual relief
for such delays is provided. We continue to work with local,
state and federal authorities to minimize and mitigate ground
disturbance at the specific sites as well as to minimize impact
to the scheduled in-service date.
ANR Lebanon Lateral Reversal Project:
Following a successful binding open season which concluded in
October 2013, we have executed firm transportation contracts for
350 million cubic feet per day at maximum tariff rates for 10
years on the ANR Lebanon Lateral Reversal Project, which will
entail modifications to existing facilities. The facility
modifications are expected to be completed in first quarter 2014.
Contracted volumes will increase over the course of 2014
generating incremental earnings. The project will substantially
increase our ability to receive gas on ANR's southeast mainline
from the Utica/Marcellus shale plays.
Great Lakes Rate Settlement
: In November 2013, we received Federal Energy Regulatory
Commission (FERC) approval for a rate settlement with shippers on
Great Lakes Gas Transmission. Commencing November 1, 2013,
maximum recourse rates increased by approximately 21 per cent
resulting in a modest increase in the portion of Great Lakes'
revenue derived from recourse rate contracts. The settlement
includes a 17 month moratorium through March 31, 2015 and
requires Great Lakes to have new rates in effect by January 1,
- Alaska LNG Project: On January 14, 2014, the State of Alaska, TransCanada, the three major Alaska North Slope (ANS) gas producers, and the Alaska Gasline Development Corporation signed a HOA relating to a gas pipeline and liquefied natural gas project to bring ANS natural gas resources to market. Under the HOA and a related Memorandum of Understanding, the State of Alaska and TransCanada have agreed that an LNG export project, rather than a pipeline to Alberta, is currently the best opportunity to commercialize ANS gas resources, and that our license under the Alaska Gasline Inducement Act will be amicably terminated. The HOA seeks to establish a transparent set of principles and a roadmap outlining how all six parties will work together to advance the Alaska LNG Project. It is anticipated that two years of front end engineering will be completed before further commitments to commercialize the project will be made.
Units 1 and 2 returned to service in September and October 2013,
respectively. The operator shut down both units in December 2010
under a claim of force majeure and was ordered by an arbitration
panel in July 2012 to rebuild them. Combined, the units are
capable of generating 560 megawatts (MW).
Capacity prices in the New York City Zone J market, where
Ravenswood operates, are established through a series of forward
auctions and utilize a demand curve administered price for
purposes of setting the monthly spot price. The demand curve,
among other inputs, uses assumptions with respect to the expected
cost of the most likely peaking generation technology applicable
to new entrants into the market. On January 28, 2014, the FERC
accepted a new rate for the demand curve that was filed by the
New York Independent System Operator as part of its triennial
Demand Curve Reset (DCR) process. The filing changed the
generation technology used in the DCR versus that used during the
last reset process. We do not expect this change to impact
capacity prices in 2014, however, this new assumption does have
the potential to negatively affect New York City capacity prices
in 2015 and 2016.
In late 2011, we agreed to buy nine Ontario solar facilities
(combined capacity of 86 MW) from Canadian Solar Solutions Inc.
for approximately $500 million. On December 31, 2013, we
completed the acquisition of our fourth facility for $62 million
which has a capacity of 10 MW. We expect the acquisition of the
remaining five facilities to close in 2014, subject to regulatory
approvals and satisfactory completion of the related construction
activities. All power produced by the facilities is sold under
20-year power purchase arrangements with the Ontario Power
In January 2014, we reached an agreement to sell Cancarb and its
related power generation facility for $190 million, subject to
closing adjustments. The sale is expected to close late in first
- Bruce Power: On January 31, 2014, Cameco announced it had agreed to sell its 31.6 per cent limited partnership interest in Bruce B to BPC Generation Infrastructure Trust. We are considering our option to increase our Bruce B ownership percentage.
Our Board of Directors declared a quarterly dividend of $0.48 per
share for the quarter ending March 31, 2014 on TransCanada's
outstanding common shares. The quarterly amount is equivalent to
$1.92 per common share on an annualized basis and represents a
four per cent increase over the previous amount.
- In October 2013, we redeemed all four million outstanding
TransCanada PipeLines Limited (TCPL) 5.60 per cent Cumulative
Redeemable First Preferred Shares Series U at a price of $50
per share plus $0.5907 of accrued and unpaid dividends. The
total face value of the outstanding Series U Shares was $200
million and they carried an aggregate of $11 million in
- In October 2013, we issued US$625 million of senior notes
maturing on October 16, 2023, bearing interest at 3.75 per
cent, and US$625 million of senior notes maturing on October
16, 2043, bearing interest at 5.00 per cent.
In January 2014, we completed a public offering of 18 million Series 9 Cumulative Redeemable First Preferred Shares. The Series 9 shares were issued at a price of $25 per share, resulting in gross proceeds of $450 million. The initial dividend rate is fixed to October 30, 2019 at $1.0625 per share per annum paid quarterly.
The net proceeds of these offerings will be used for general corporate purposes and to reduce short-term indebtedness, which was used to fund a portion of our capital program and for general corporate purposes.
- Also in January 2014, we announced that we will redeem
all four million outstanding TCPL 5.60 per cent Cumulative
Redeemable First Preferred Shares Series Y at a price of $50
per share plus $0.2455 of accrued and unpaid dividends on
March 5, 2014. The total face value of the outstanding Series
Y Shares is $200 million and they carry an aggregate of $11
million in annualized dividends.
- In October 2013, we redeemed all four million outstanding TransCanada PipeLines Limited (TCPL) 5.60 per cent Cumulative Redeemable First Preferred Shares Series U at a price of $50 per share plus $0.5907 of accrued and unpaid dividends. The total face value of the outstanding Series U Shares was $200 million and they carried an aggregate of $11 million in annualized dividends.
Effective February 28, 2014, Greg Lohnes, Executive
Vice-President, Operations and Major Projects and Sean McMaster,
Executive Vice-President, Stakeholder Relations, General Counsel
and Chief Compliance Officer will retire from the Company.
Effective March 1, 2014, Alex Pourbaix is appointed Executive Vice-President and President, Development; Paul Miller is appointed Executive Vice-President and President, Liquids Pipelines; Bill Taylor is appointed Executive Vice-President and President, Energy; James Baggs is appointed Executive Vice-President, Operations and Engineering; and Kristine Delkus is appointed Executive Vice-President, General Counsel and Chief Compliance Officer.
Teleconference - Audio and Slide Presentation:
We will hold a teleconference and webcast on Thursday, February 20, 2014 to discuss our fourth quarter 2013 financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 12 p.m. (MT) / 2 p.m. (ET).
Analysts, members of the media and other interested parties are invited to participate by calling 866.226.1792 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 February 27, 2014. Please call 800.408.3053 or 905.694.9451 and enter pass code 6573719.
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 2013 AND FINANCIAL HIGHLIGHTS
Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See the non-GAAP measures section for more information.
|three months ended December 31||
|(unaudited - millions of $, except per share amounts)||2013||2012||2013||2012|
|Net income attributable to common shares||420||306||1,712||1,299|
|per common share - basic||$0.59||$0.43||$2.42||$1.84|
|per common share||$0.58||$0.45||$2.24||$1.89|
|Operating cash flow...|
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