TC Energy Corp (TRP) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2013 fourth-quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, sir.

Thanks very much. Good afternoon, everyone. I would like to welcome you to TransCanada's 2013 fourth-quarter conference call.

With me today, are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of Energy and Oil Pipelines; Karl Johannson, Executive Vice President and President Natural Gas Pipelines; and Glenn Menuz, our Vice President and Controller.

Russ and Don will begin today with some opening comments on our financial results and certain other Company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com. It can be found in the Investor section under the heading Events and Presentations.

Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question-and-answer period, we will take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions please reenter the queue.

Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have more detailed questions relating to some of our smaller operations, or your detailed financial models, Lee and I would be pleased to discuss them with you following the call.

Before Russ begins, I would like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the US Securities Exchange Commission.

Finally, I would also like to point out that during the presentation we will refer to measure such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA, and funds generated from operations. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures.

As a result they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations.

With that, I'll now turn the call over to Russ.

Thank you, David. Good afternoon, everyone. Thank you for joining us today.

2013 was a very successful year for TransCanada. We resolved many of the headwinds at Bruce, at Sundance, at Ravenswood and on our Canadian Mainline, headwinds that were constraining our financial performance. In addition, we secured an unprecedented CAD19 billion of new, high-quality infrastructure projects. That will position the Company for growth well into the next decade.

Our portfolio of blue-chip assets continue to deliver stable and growing cash flow in earnings. All three of our core businesses gas pipelines, oil pipelines and energy generated strong earnings and cash flow in 2013.

Net income attributable to common shares was CAD1.7 billion, or CAD2.42 a share. Comparable earnings increased 19% to CAD1.6 billion, or CAD2.24 per share. Funds generated from operations were up 22% to CAD4 billion.

The strong, year-over-year growth in cash flow and earnings were primarily due to the return to an eight unit operational nuclear site at Bruce Power, the first time all eight reactors have run for a couple of decades; higher western power volumes, due to the return of service of Sundance A; an increase in New York capacity prices; growth in our NGTL; a natural gas pipeline system rate base; and a higher Canadian mainline return on equity, due to the entity's restructuring decision made in March, 2013, all contributed to the growth.

After adding approximately CAD8 billion of new projects in 2012, we continue to build our portfolio of commercially secured projects by adding an additional CAD19 billion in 2013, including the Prince Rupert gas transmission project to transport natural gas to the BC coast, further NGTL expansions, and the largest project in our Company history, the Energy East pipeline, which is a combination of a new build and conversion of existing, natural gas pipeline for crude oil transportation to Eastern Canadian refineries and for export.

As you can see on this slide, our overall portfolio projects is diverse and they are all backed by either long-term contracts or cost of service regulation. The portfolio includes CAD23 billion of crude oil pipelines, CAD13 billion of the natural gas pipelines and CAD2 billion of power generation facilities.

If the required approvals are received, and I can tell you we are very hard at work trying to get those done, and we expect that to occur. We expect that these projects will generate predictable growth in earnings and cash flow through the remainder of the decade. By any measure, I would say 2013 was a very good year for our Company.

Turning quickly to the fourth quarter, TransCanada reported net income of CAD420 million or CAD0.59 a share. Comparable earnings for the quarter were CAD410 million, CAD0.58 a share versus CAD318 million, or CAD0.45 a share, in Q4 of 2012 which is a 29% increase. Comparable EBITDA was CAD1.3 billion. Funds generated from operations were CAD1.1 billion.

The Board of Directors also declared a quarterly dividend of CAD0.48 per common share for the quarter ending March 31, 2014, a 4% increase over the previous quarterly amount of CAD0.46 per share. This results in a per-share annual increase from CAD1.84 to CAD1.92. This is the 14th consecutive year the TransCanada Board has raised the dividend.

A strong quarter that was followed by the release of the Final Environmental Impact Statement for Keystone XL and our announcement in late January that the Gulf Coast project began delivering crude oil. Don Marchand, will speak in a few minutes and provide more details on the financial results.

Now, I would like to provide you with an update on the main initiatives that we continue to advance, starting with the Keystone XL project. First, as I mentioned, the Final Supplemental Environmental Impact Statement for Keystone XL was released on January 31. There has been a lot of rhetoric from those who oppose our project about what the FDIS actually says.

For those of you who that have not had the time yet to read all 11 volumes, I'll let you know what it actually says. First, the report, once again, concludes that this pipeline would have minimal impact on the environment. The project is also unlikely to significantly affect the rate of oil sands extraction or the volume of oil refined in the US. Hence, the project were not have a significant impact on GHG emissions.

It also says that the alternative to shipping oil to the Gulf Coast would produce higher GHGs as compared to the Keystone XL alternative. In fact, the report states that under any scenarios where the project is denied, GHG emissions from the movement of oil would actually increase, 28% more GHGs if all the oil is railed to the Gulf Coast. The report said that during construction, Keystone XL with support 42,000 direct and indirect jobs and contribute $3.4 billion to America's gross domestic product.

We have said that Keystone XL will enhance energy security, and with the growth in domestic production in the US and in Canada. Connecting the third largest resource of oil in the world to the largest refining center in the world with a 36-inch high-tech steal pipeline, that can do nothing but increase energy security.

The FDIS points out that demand will persist for imported heavy crude oil for US refiners. The report states that once the Western Canadian sedimentary basin crude arrives at the Gulf Coast, refiners in the Gulf Coast will have a significant competitive advantage in processing it compared to foreign refiners because foreign refiners would have to incur additional transportation charges to have that crude oil delivered from the Gulf Coast to their location. Hence, all of this oil is going to stay in the United States.

The report also state the US Department of State, in consultation with the Pipeline and Hazardous Materials Safety Administration, has determined that the incorporation of 59 special conditions would result in a project that would have a degree of safety over any other typically constructed domestic oil pipeline system under current code.

We are now in the midst of a 90-day National Interest Determination period for the project. Included in those 90 days is a 30-day, public comment period.

The criteria spelled out, in the executive order for national interest, considers many factors including such things as energy security, trade, foreign relations and economic impacts. Clearly, by any of these criteria, Keystone will be determined to be in the natural interest of the United States.

Yesterday, a Nebraska court ruled that the Public Service Commission, rather than the governor, has the authority to approve an alternative route for Keystone XL through Nebraska. Later in the day, the Nebraska Attorney General filed an appeal. While we're clearly disappointed and disagree with the decision, we will now analyze the judgment and determine what our next steps maybe.

First, let me say this is a solvable problem. We are undeterred. The Nebraska Department of Environmental Quality has reviewed the route. As well, the Department of State has completed its own independent review.

We have dealt with many issues on Keystone XL in the past. We have many options to deal with this latest hurtle.

It is our view that the current 90-day National Interest Determination process that is now underway with the Department of State should not be impacted by this ruling. We will work to minimize any potential impact on the project schedule.

We continue to remain fully committed to completing the Keystone XL project and delivering the benefits it will provide to Americans, thousands of jobs and a secure supply of crude oil from a trusted neighbor. Our shippers and refiners are 100% behind the project. Over one dozen polled since 2011 demonstrate that over 65% of Americans continue to support Keystone XL.

As I've said previously, the cost estimate will increase depending on the timing of the permits. As of December 31, 2013 we had invested approximately CAD2.2 billion in the project. We anticipate the pipe would be operational approximately two years after we receive the Presidential Permit.

Now, turning to the Gulf Coast part of that project. On January 22, 2014 oil began flowing in the southern extension of the Keystone Pipeline, which is our Gulf Coast project, to refineries in Texas. This pipeline is an important step in helping the United States update and enhance its energy infrastructure network.

An efficient and safe pipeline network is something that I believe all Americans support and expect. The CAD2.6 billion Gulf Coast project was designed to connect US oil production to markets that need it, growing energy production in Oklahoma, Texas, North Dakota, Montana, and in Canada, created in places like Cushing. The Gulf Coast refineries couldn't access that domestic production, forcing them to pay a premium to import crude oil from foreign producers.

This project allowed us to create close to 5,000 jobs in America. We are proud to partner with more than 50 US manufacturers and companies in building the pipeline and who supply all of the equipment.

We expect the pipeline will have the capacity to deliver an average of 520,000 barrels a day in its first year of operation, as we ramp up to full delivery capability of 700,000 barrels a day. Since 2010, our Keystone Pipeline system has safely delivered over 550,000 barrels of oil to US refiners.

Moving over to Canada, onto Energy East. Last quarter I talked about the fact that TransCanada had announced it was moving forward with this large-scale energy infrastructure project. We informed stakeholders that we had signed firm binding contracts for 900,000 barrels a day on the 1.1 million barrel per day crude oil pipeline system. Energy East will transport oil from Western Canada to Eastern Canadian refineries and to export terminals creating tax revenue, creating jobs and energy security for all Canadians.

In Canada, we import 700,000 barrels a day of oil from foreign countries. Energy East will allow us to push out this foreign supply, creating the opportunity for Canada to use and refine its own resources, something that benefits all Canadians from coast to coast to coast.

The benefits include CAD35 billion in additional gross domestic product for Canada, more than 10,000 full-time jobs during development and construction, 1,000 jobs once the pipeline is operating, and CAD10 billion in tax revenues for all levels of government over the lifetime of the project. Right now, our focus is on Aboriginal and stakeholder consultation in preparation of a regulatory application to the National Energy Board, which we intend to file in mid 2014.

Moving back to Alberta, last October we filed a permit application with the Alberta Energy Regulator for our Heartland Pipeline and Terminal project after completing our initial consultations with Aboriginal groups and other key stakeholders. This follows our application for the Terminals that was filed in early 2013.

The 200 kilometer crude oil pipeline will connect Edmonton to facilities in Hardisty along with an oil storage terminal in the Heartland industrial area north of Edmonton. The pipeline would transport 900,000 barrels a day, and up to 1.9 million barrels a day of crude oil could be stored in the terminal. Together these projects have a combined cost of CAD900 million and are expected to be operational in 2016.

In addition, last October we received some very positive news from Suncor with the announcement that Fort Hills oil sands mining project would proceed. It is expected to begin producing oil in 2017.

Our Northern Courier pipeline project is also expected to be completed in 2017. We'll transport crude oil and diluents from the Fort Hills mine site to Suncor's tank facilities north of Fort McMurray.

Moving over to our gas business, in December of 2013 would filed for NEB approval of a settlement reached with Canada's three largest local distribution companies. The settlement is designed to provide consumers with greater access to growing natural gas supplies while allowing TransCanada to recover its costs over the long term.

The Mainline is expected to operate under the NEB decision in 2014, and the settlement addresses tolls from 2015 to 2020, and provides a tolling framework through 2030. Don will provide a few comments on the Mainline's performance in 2013 and on our outlook for 2014.

Moving to the NGTL System, where we continue to expand this critical network of pipe, CAD730 million of new facilities became operational in 2013. The National Energy Board also approved CAD290 million of additional expansion facilities that are in various stages of development.

In November of 2013, we filed an application with the National Energy Board for our North Montney project. This CAD1.7 billion, 300 kilometer pipeline would interconnect with our Prince Rupert Gas Transmission project and provide gas to the proposed Pacific Northwest LNG export facility on the West Coast.

Moving over to energy, in 2011 we agreed to buy nine Ontario solar projects from Canadian Solar Solutions. We acquired one in July, two in September, and the fourth in late December. The combined capacity of the nine projects is 86 megawatt's at a total cost of CAD500 million.

We anticipate the remaining five projects will come into service by the end of 2014. They will complement TransCanada's existing operations in Ontario. The renewable energy produced from these projects will be sold to the Ontario Power Authority under 20-year power purchase agreements.

One-third of the power that we provide to North America comes from carbon-free energy sources. TransCanada has invested over CAD5 billion in emission-free energy sources including the largest wind farm in New England, hydro facilities in the US Northeast, our solar investments, Canada's largest wind farm in Quebec, and our interests in Bruce Power.

In conclusion, our diverse portfolio of energy infrastructure assets generated strong earnings and cash flow in 2013. Comparable earnings increased 19% to CAD1.6 billion. Funds generated from operations were up 22% to CAD4 billion.

We captured CAD19 billion in additional projects last year, growing our current portfolio of commercially secured capital projects to CAD38 billion. We expect this high quality portfolio of contracted projects to generate significant growth in earnings and cash flow well into the next decade.

Before I turn the call over to Don, I would like to acknowledge the hard work and dedication of two members of our executive leadership team that are retiring at the end of February. Sean McMaster and Greg Lohnes have provided TransCanada with many years of wisdom, counsel and contributing greatly to our success in building enduring shareholders value. As a result of those retirements, the growth in each of our core businesses, and the development of the contractually secured CAD38 billion portfolio of high-quality growth opportunities, effective March 1, we have reorganized our senior leadership team to ensure focus on both the expansion of our existing systems and projects and the safe, reliable and profitable operation of all of our assets.

Firstly, Alex Pourbaix has been appointed Executive Vice President and President of Development, accountable for leading our growth initiatives including the successful completion of our CAD38 billion portfolio of projects, new initiatives, portfolio management and corporate development. Paul Miller is appointed Executive Vice President and President of Liquids Pipelines. Paul will have accountability for our oil pipeline business.

Bill Taylor is appointed Executive Vice President and President of Energy. Bill will have accountability for our energy business, including power and our non-regulated gas storage businesses.

Jim Baggs is appointed Executive Vice President Operations and Engineering. Jim has continued accountability for safety and operating, maintaining and optimizing all of our infrastructure assets.

Kristine Delkus is appointed Executive Vice President and General Counsel. Kristine will have accountability for all of our legal and regulatory functions and will assume the role of Chief Compliance Officer.

Each of these executives has many decades of experience in their area of responsibility. I am extremely confident in their ability to deliver on our plans, grow cash flow, earnings and dividends, and increase shareholder value for many years to come.

With that I'll turn the conference call back to Don.

Thanks, Russ. Good afternoon, everyone. Before I review the fourth-quarter results in detail, I would just like to reiterate if you have Russ's key messages.

Earlier today we announced a 4% increase in the common share dividend. This marks the 14th consecutive year the Board of Directors has raised the dividend.

Our fourth-quarter and overall 2013 financial results were strong and reflect our diverse portfolio of high-quality energy infrastructure assets including CAD3.5 billion of new assets that were placed into service over the past 15 months. This solid momentum is expected to continue heading into 2014 as approximately CAD4 billion of new assets are expected to be brought into service this year, including the Gulf Coast project, Tamazunchale pipeline extension, the acquisition of the remaining five Ontario solar facilities, and ongoing expansions of the NGTL System, all of which are expected to positively contribute to future results.

We remain focused on advancing the remainder of our CAD38 billion portfolio of high-quality, long-life energy infrastructure growth opportunities. All of these projects are underpinned by long-term contracts or cost-of-service business models and are expected to contribute to significant growth in earnings, cash flow and dividends over the remainder of the decade.

Finally, we remain well positioned to fund our current capital program. In 2013, we raised CAD4.8 billion on attractive terms, clear evidence of our ability to access varying sources in capital in order to finance our growth plans.

Now, moving to our consolidated results shown on the next slide. Comparable earnings in the fourth quarter of CAD410 million, or CAD0.58 per share, increased CAD92 million, or CAD0.13 per share, compared to the same period in 2012. This 29% increase in comparable EPS was primarily due to a higher allowed return on equity for the Canadian Mainline, a higher allowed return on equity and a higher average investment base on the NGTL System, increased volumes on our Keystone Pipeline system, and higher equity income from Bruce Power due to the return to service of Units 1 and 2 and fewer planned outage days Unit 4. This was partially offset by a decreased contribution from US national gas pipelines and lower realized power prices in Western Power.

Turning to our business segment results at the EBITDA level, our national gas pipelines business generated comparable EBITDA of CAD778 million in fourth-quarter 2013, compared to CAD690 million for the same period last year. Canadian gas pipelines EBITDA of CAD600 million, increased CAD118 million compared to 2012. Improved results were due to a higher allowed return on equity of 11.5% and some incentive earnings on the Canadian Mainline.

In 2013 the Mainline was able to realize its net revenue requirement as a result of significant additional firm transportation contracts along with its pricing discretion over other services following the NEB decision on our restructuring proposal. Heading into 2014, the Mainline is again expected to realize its revenue requirement, in part due to shippers recently electing to renew approximately 2.5 billion cubic feet a day of a firm contracts through November 2016.

A higher return on equity, incentive earnings, and a higher average investment based on the NGTL System also contributed to the positive results in Canadian gas pipelines.

If you recall, the NEB approved our 2013 2014 NGTL settlement with shippers as filed on November 1. A positive retroactive after-tax earnings adjustment to January 1, 2013 was recorded in the fourth quarter to reflect an increase in the allowed return on equity to 10.1% along with incentive earnings.

Partially offsetting improved results in Canadian gas pipelines was a $20 million decline in EBITDA at US and international natural gas pipelines and our experience lower transportation and storage revenues, as well as higher cost related to services provided by other pipelines. Contributions from GTN and Bison were also lower due to the reduction in our direct ownership interests from 75% to the 30% effective July 1, 2013 following their partial sale to TC PipeLines LP.

Turning to oil pipelines, Keystone generated CAD200 million of EBITDA in the fourth quarter. The CAD20 million year-over-year increase was primarily a result of higher volumes.

In energy, comparable EBITDA was CAD346 million in the fourth quarter, compared to CAD222 million for the same period last year. The CAD124 million increase was the result of a combination of positive factors, which included Bruce Power's equity income rising CAD123 million, reflecting the restart of Units 1 and 2; as well as increased volumes in Unit 4, which was undergoing a planned life extension outage in the year-ago period.

US Power EBITDA also increased $20 million in the fourth quarter compared to the same period last year. This was primarily due to higher realized capacity prices in New York and higher realized power prices in New England partially offset by higher fuel costs and lower generation at Ravenswood.

National gas storage results rose CAD7 million year over year, driven by increased volumes at higher realized storage spreads and incremental earnings in the acquisition of the remaining 40% interest in CrossAlta in December 2012. This was partially offset by a CAD24 million decline in Western Power's EBITDA in fourth-quarter 2013 compared to the same period last year. The decrease was primarily due to lower realized power prices, partially offset by the return of Sundance A Units 1 and 2 in September and October 2013 respectively.

Now, turning to the other income statement items on slide 26. Comparable interest expense was CAD240 million in the fourth quarter, a CAD6 million decrease compared to the same period last year. This was principally due to increased capitalized interests as well as Canadian and US dollar debt maturities, partially offset by interest charges on recent debt issues, and higher foreign exchange on translating interest denominated in US dollars.

In the fourth quarter, CAD92 million of interest was capitalized to assets under construction compared to CAD76 million from for the same period in 2012. This reflects higher capitalized interest for the Gulf Coast project and Mexican pipelines partially offset by completion of the restart of the Bruce A units. Comparable income tax for fourth-quarter 2013 increased CAD75 million, compared to the same period last year, due to higher pretax earnings combined with changes in the proportion of income earned in higher tax jurisdictions.

Now, moving onto cash flow and investing activities on slide 27. Cash flow was once again very strong in the quarter primarily due to higher earnings in the period. Funds generated from operations exceeded CAD1 billion for the second consecutive quarter, and totaled a record CAD4 billion in 2013 representing a 22% increase over 2012.

Turning to investing activities, capital expenditures were CAD1.4 billion in the fourth quarter driven principally by the Gulf Coast project and construction of our Mexican pipelines. Equity investments of CAD62 million decreased CAD33 million versus the year-ago quarter, primarily due to lower investment in Bruce Power partially offset by increased investment in the Grand Rapids pipeline.

Acquisitions of CAD62 million in the quarter reflect the purchase of our fourth Ontario Solar facility, which closed at the end of December. The acquisition of the five remaining projects is expected to occur in 2014 as they are satisfactorily completed and brought online.

Now, turning to slide 28, our liquidity and access to capital markets remains solid. At the end of the fourth quarter, our consolidated capital structure consisted of 40% common equity, 5% preferred shares, 2% junior subordinated notes, and 53% debt net of cash.

At December 31, we had CAD927 million of cash on hand. We also recently increased our committed credit lines by CAD1 billion and at year end had approximately CAD4.7 billion of committed and undrawn revolving bank lines available with our high-quality bank group.

Our two commercial paper programs, one in Canada and one in the US, remain well supported and provide flexible and very attractive sources of short-term funds. In October, we issued $1.25 billion of senior notes, split evenly between 10- and 30-year maturities, baring interest at 3.75% and 5% respectively.

Also in October, we redeemed at par all of the outstanding 5.6% TCPL Series U first preferred shares. The total face value of the outstanding shares was CAD200 million, and they carried an average of CAD11 million in annualized dividends.

Throughout the course of 2013 we raised CAD4.8 billion on attractive terms through an array of funding products to a diverse investor base. We also gotten off to busy start in 2014, with a variety of financing activities, and continue to be opportunistic in sourcing additional capital at what remain compelling levels.

In January we completed a CAD450 million preferred share issue in Canada. The Series 9 cumulative redeemable first preferred shares have an initial dividend rate of 4.25%, which is fixed to October 2019.

We also gave notice that on March 5, we will redeem all of our outstanding 5.6% TCPL Series Y first preferred shares at par along with accrued and unpaid dividends. The total face value of this issue is CAD200 million and it carries an aggregate of CAD11 million in annualized dividends.

Finally, we also announced in January the sale of Cancarb and its related power generation facility for CAD190 million. This sale is expected to close late in first-quarter 2014.

In 2014, we expect to spend approximately CAD5 billion on advancing our capital program and to maintain our existing asset base. This includes CAD2.3 billion on oil pipelines, excluding Keystone XL, CAD2 billion on national gas pipelines and CAD700 million on energy.

Looking forward, we remain well positioned to finance our capital program through funds generated from operations, new senior debt, as well as subordinated capital in the form of additional preferred shares, hybrid securities and portfolio management, which includes LP drop downs. As we advance our capital program, we expect to vend in the remaining interests in all of our US natural gas pipelines to our MLP, TC PipeLines. With approximately CAD3.5 billion of net book value, this represents a significant and attractive funding source.

In closing, TransCanada produced another strong quarter and had a very successful 2013. Comparable earnings of CAD2.24 per share and CAD4 billion of funds generated from operations were up 19% and 22% respectively compared to 2012. Going forward, the addition of approximately CAD4 billion of new capital projects in 2014 is expected to positively impact future earnings, but will be partially offset by expectations of lower power prices and lower natural gas storage spreads in Alberta.

Finally, we continue to advance the balance of our CAD38 billion portfolio of large-scale, commercially secured infrastructure projects, each of which is underpinned by long-term contracts with strong counter parties. We remain well positioned to fund the balance of the program. This unprecedented portfolio of projects is expected to generate significant growth in earnings, cash flow and dividends for our shareholders over the remainder of the decade.

That's the end of my prepared remarks. I'll now turn the call back over to Dave.

Thanks, Don. Just a reminder, before I turn it over to the conference coordinator, we will take questions from the financial community first. Once we have completed that, we will then turn it over to the media.

With that I'll turn it back to the conference coordinator for your questions.

Thank you, Mr. Moneta.

(Operator Instructions)

Juan Plessis, Canaccord Genuity.

With respect to Bruce Power, you have the option to participate in the purchase of Cameco's interest in Bruce B. How long is that option good for? When would you anticipate making a decision on this?

It's Alex. We're not right now talking about the term of that option. What I think I could tell you is that it has a long enough term that we're quite confident that we'll have all the time we need to make a decision on this. We remain very committed to Bruce. We think there's a great opportunity for refurbishment. By negotiating this option, it gives us a lot of flexibility as to how we go forward.

Okay, thanks for that. As a follow up here, capacity prices in New York have had a pretty good start to the year, almost double from 2013 levels. Can you talk about your outlook for New York capacity prices for 2014? Also, you've indicated in the MD&A that the demand curve reset could potentially negatively impact the capacity prices in 2015 and 2016. I'm just wondering if you could elaborate on your 2015 and 2016 capacity of price outlook?

Sure. I think the FERC just settled the parameters for the capacity curve reset. I think, all in, we take a look. We, by the way, disagreed with one of the changes they made, which was they made a change in the reference unit used to calculate capacity payment in the demand curve. From our perspective, as I said, we disagreed with that.

Notwithstanding, all in all, it probably has a relatively modest dampening impact on the actual demand curve, maybe 6% or 7%. That's obviously only one part of determining capacity prices. At the same time, we're seeing we had a few retirements. We've had demand expectations increase. So, net-net, I'm probably looking at it as pretty close to a push, year over year, for summer 2014, and potentially a very modest dampening impact on 2015 and 2016.

Okay, thank you very much.

Paul Lechem, CIBC.

Just on Keystone XL, wondering what your thoughts are in the interaction between what's going on in Nebraska and the whole FDIS National Interest examination process, which is being run? Is there any concern that the change in Nebraska could derail the Presidential Permitting?

I wouldn't use the word derail. It's our view that there shouldn't be any impact on the Department of State process. The Department of State has completed its independent review of environmental impacts to the pipeline, issued their Final Supplemental Environmental Impact Statement. That said, there's always potential for delays in the process. We would hope that that doesn't occur, but that's yet to unfold here over the coming days.

Okay. Given where we're at in 2014 and your comment that you need two full years through when you get the permit to get this thing built, is that two full years or two full construction seasons? Is there a chance that as you go through 2014 that you could still salvage some of this year and you could still be pushing for an early 2016 entry [into service]?

There's always certain things that we can do depending on when you get the permit. I think the most important thing I think is to have two full summer construction seasons to complete the project. There could be some things we get done in 2014. Certainly, that's what our objective is right now is to understand what impact this may have on schedule and determine how we might we rework our schedule to minimize the impacts it will have on the ultimate in-service date.

Okay. Just one more question, if I may? In the US gas pipes, any sign of things bottoming out for A&R and maybe Great Lakes? Are you seeing any sign of a turn there?

Yes, it's Karl speaking. As we referred last quarter we did see some extra take-up of capacity coming out of the Marcellus and Utica into our Lebanon lateral. That has been paid for. We'll expect those volumes to come on over the next year or so. Right now we're right in the middle of another open season for more Marcellus and Utica volumes. We are quite optimistic that we'll see some more volumes.

Certainly, I think on throughput on that line, we've seen it bottom out and now we're quite optimistic on going through. The storage revenue that that pipeline generally gets, it has not had the same recovery with the storage emptying out and throughout North America here this winter. It will have some depressing impacts on long-term storage spreads. Again, that's cyclical as well. We expect that to come out. I guess the bottom line is I'd say that certainly on a flow perspective we're quite optimistic right now with A&R pipeline.

Great Lakes, still about the same as it was last year. We're seeing some more spot volumes go through with the higher volumes coming through the Mainline, but nothing that I would say, on Great Lakes, that is structural.

Okay, thank you.

Carl Kirst, BMO Capital Markets.

Russ, and understanding this is less than 24 hours post-Nebraska and I know you all are evaluating next steps. My question is, as we look at -- even if you go back to putting this back into the purview of the PSC, it would seem like they have to make a decision within a seven-month timeframe. Is the rebound side to just basically gearing up the process to actually file with the PSC just to get the clock ticking? Since we went through this process with the DEQ, does a filing, is that something that takes two weeks to put together or is that something that takes two or three months to put together?

I don't have an answer to those questions. Obviously, one of our options is to file with the PSC. I think as you correctly point out a lot of work has been done already. We have provided all the information through the Nebraska Department of Environmental Quality process. I would hope that would obviously impact the schedule at which they could process that application, if we went that direction. It's too early to say just exactly what that looks like. We're in those discussions right now, both with internal and external advisors and with the state. As well, as you're probably aware, the State Attorney General has appealed this ruling already. We have to wait and see what the initial output of that is as well as we calibrate what our strategy is.

I think what I would tell you is that my view is that the route that we have picked is sound. It has been through the review process, as I said, at the Department of State. We will find how the most expeditious route to getting that route ultimately approved and getting on with getting our Presidential Permit. That's the current plan. Unfortunately, Carl, I just can't give you any insight on details because we really haven't had a chance to put that together yet. As soon as we do, we'll share that with the marketplace.

No, understand. I appreciate that. Maybe a question for Alex, if I could? Just with respect to your view -- I think Juan had asked about capacity prices, but power prices in New England have been going kind of crazy. I didn't know if you had any longer-term view on that? And whether or not you all were able to capture some of the benefit of that here in the first quarter?

Yes, it's a good question. I would say going into this first quarter we were pretty well hedged, so probably net-net some upside but not significant, because that we do have a pretty significant load serving business in New England. We have a lot of assets, but they were pretty dedicated to serving those loads. Positive, but not knocking it out of the ballpark.

Okay. Maybe last question, if I could? Really more for Don in recognizing the drop-down opportunities that you mentioned for the MLP. Given that we've historically looked at that as in part a funding tool in the toolkit, should we continue to look at that or should I continue to look at that as somewhat linked with the timing of XL and major funding expenditures? Or, do you see the transpiring, excluding what happens with XL here?

I wouldn't link it to any specific project. We've got CAD38 billion coming, which gives us a comfort level that the CapEx spend and the capital requirements are going to be substantial over the next several years here. I'd look at it to be more methodical over time. There are capacity limits as to how much we can put into the LP on any given transaction. Watch for this to be paced more methodically than in any big-bang transaction where we take back paper. Ultimately, we're looking to realize cash on this transaction. It will be over several years, but with a program of this size, moving this CAD3.5 billion suite of assets into the LP makes sense.

Understood. Thank you, guys.

Andrew Kuske, Credit Suisse.

The question is for Karl, and it's just on relation to the Canadian Mainline. If we look at the asset in the old regime, you had a high-8%s ROE and now you're doing about 11.5%. Could you just give us a sense on how are you achieving that, just on the mix of volume, the tariff structure and cost reductions?

Okay. For 2013 for example, we -- on our gross revenue requirement on the Mainline, which is just a little over CAD1.6 billion, we essentially covered it. We're a little short, but we're talking about CAD50 million, CAD60 million, so it wasn't that significantly short. We are actually collecting the revenue now for the revenue requirement. We do expect in 2014 that again. We're going to collect our revenue retirement. We're only two months into it, but we've had a couple good months on discretionary here, and we're still signing up lots -- a good volume of firm contracts. We're quite optimistic that we will cover our revenue requirement in 2014 as well.

When I look forward, I see probably 85% plus maybe closer to 90% of our revenue coming from firm transmission. We're not relying on discretionary for that great of our revenue requirement right now. I think it's in pretty good shape. I'm not sure if that answered your question. We're quite optimistic in 2014 as well. We have some sales already on 2015.

So it's fair to say that you feel pretty comfortable on how you've derisked the asset, with just the increase in the FT?

Yes, so of course our objective -- I think any pipeline or capacity provider's objective it to sell firm contracts on their assets. Right now, we're running probably right now about 3.2 BCF of FT contracts on our assets. That falls off a little bit next year because of the renewals came up, but we're starting to already add that. I'm quite comfortable that we have a pretty good balance and a good percentage of FT covering that revenue requirement.

Then related, but jumping ahead a few years, when we look at the conversion project and really taking some of that plant out of service and putting it into Energy East, what's you confidence in the Mainline achieving 11.5% ROE?

Don't forget we have an application in front of the Board right now with our settlement with our shippers. With that settlement with the shippers, essentially is with our Eastern LDC shippers, essentially segments our pipeline. What it does is our Eastern LDC shippers have come to us and said they will give a transition or bridging mechanism for cost of capital for our cost on our entire system if we were to build more Eastern triangle capacity for them so they get access more Marcellus. Part of that is the system is going to be more heavily utilized in FT if we get that settlement approved. We'll see more volumes migrate over the short haul from long haul. The LDCs, of course, will give us a bridging mechanism to pay for that.

As part of that settlement, our ROE will decline. We have agreed to, if they were to essentially, for a long period of time, commit to covering our system cost, we agreed to a lower ROE. That ROE that we've got in that settlement is 10.1% on 40% equity. We do have a contribution that we make every year, but we also have an incentive program. We can make between 8.7% and 11.5% ROE on the pipeline. If that settlement is approved, you will see actually our ROE follow a little bit, vis-a-vis what we are getting today. Then, we will have a much better profile of secured cash flows.

Okay that's very helpful, thank you.

Robert Kwan, RBC Capital Markets.

Coming back to the Mainline, here, you mentioned -- well, Mainline and NGTL, you mentioned in the MD&A that you booked incentives for both of those systems. I'm just wondering if you can quantify what the incentives were? Then for the Mainline, do you have a rough sense of how much of those incentives are from activities or tools that you would retain under the LDC settlement?

Let's start with the Mainline. The LDC settlement has a very similar incentive program to the one we're under right now. It basically gives us a tiered percentage of the revenue that we get over our net revenue requirement. I think as we go into the settlement with the LDCs we will have the same opportunity that we're seeing right now during incentives.

Right now, as of 2013, we earned about CAD14 million on the Mainline under the incentive program. Again, that incentive program was anything above our natural revenue requirement we shared in. On NGTL, there was a more modest incentive. I think it was about CAD3 million --

Yes, it was about somewhere in that -- about CAD0.005. It wasn't much.

Yes, the incentive mechanism there really is we have a fixed O&M charge to the customers, and if we can come in underneath that then we get to keep that that savings.

Okay, and that was all booked in fourth quarter?

Yes, that was all -- both were booked in the fourth quarter.

Okay. Just turning to Energy East, you've got some refined timing here. Is that just related to some delays in the regulatory application with respect to you just being a little bit more thoughtful or taking a little bit more time with the First Nation's Aboriginal and community stakeholder consultation process?

Thanks, Russ. No, I think it's relatively simple. We're still on track to making our regulatory filing to the National Energy Board this summer, so no delay there. I think the biggest impact on our thoughts on timing is now that we've chosen Cacouna as of the site for the marine terminal in Quebec, that is significantly further east than we had originally been anticipating. As a result, we're going to have to build more kilometers of pipe inside Quebec before we get to the marine terminal, so just with adding those, not necessarily significantly increasing the total kilometers, but increasing the amount of kilometers inside the Province, we're going to have to build. We've just modestly amended the in-service date just to take account of that.

That's great. Thank you very much.

Linda Ezergailis, TD Securities.

I don't know if this is too much of a detailed question for the call, but I noticed that your operating working capital changed a lot in 2013. I'd assume that it's not entirely related to growth in the business. Is it timing of something or can you walk me through what's going on there?

Sorry, Linda, are you just looking on the balance sheet then?

I'm looking on your statement of cash flows. Last year your operating capital in 2012 decreased by CAD287 million and this year in 2013 it increased by CAD326 million.

Quite frankly most of that is timing. There is a little bit of current regulatory deferrals in that, but there's no underlying driver to it. It's really just timing of collections and payments.

Okay, that's what I was thinking, thank you.

Steven Paget, FirstEnergy Capital.

You've got a CAD35 billion order book once you take the Gulf Coast project off for the remainder of the decade. What's the unrisked dollar value of the potential additional projects that you are looking at adding, if any?

I'm not sure if I have a good number, Steven. It's obviously that we're looking at numerous things. I think of the Alaska project for example, if we have a 20% interest in a CAD40 billion or CAD50 billion project. That's CAD10 billion by itself. You add on bolt-ons and add on things we were looking at, I think you could easily get another number that looks like CAD30 billion.

That might include Bruce B refurbishment?

That would be included in that. Obviously, that one is an overtime thing. Alone, Bruce B refurbishment, I think folks are talking between CAD10 billion to CAD15 billion by itself. It's a good question. It's not one that we've actually added up. But I think easily you could come to a number that's equivalent approximately to what we've actually secured under long-term contracts.

Thank you, Russ. What's the driver on your dividend growth rate? Is it a steady increase per quarter? Or per year? Or not as a percent of earnings or cash flow?

It's more the latter. I'll let Don maybe jump in here as well, our focus for the dividend is to move it up in conjunction with sustainable and visible increases in cash flow and earnings on a go-forward basis. There's no set percentage in mind. Obviously, we want to stay in a range of a payout relative to earnings in and above the range that we have been lately or less. That's probably where we would want to be. As we start to see visibility of earnings growth going forward, it would be our intent to move dividends in conjunction with those.

Sustainability is the key. Historically, we've been in the 70% to 80% of earnings payout range, which equates to about one-third of cash flow. That seems like the right place to be, which gives a good balance of net cash return to the shareholder and still retain capital to invest for growth. We don't see a clear reason to move off that.

Sorry, Don, you said 70% to 80% of EPS?

Of EPS, which is about one-third of cash flow.

Right. Thank you. Those are my questions and best of luck to Sean and Greg.

Thanks, Steven.

(Operator Instructions)

Matthew Akman, Scotiabank.

My questions are on Bruce and exercising, or not, the options and some of the considerations that go into that. Obviously, Bruce has been, in some sense, a good investment but also controversial and challenging at times. Maybe this is for Alex. I'm just wondering how you think about it now in terms of its desirability? In particular, whether there are sufficient learnings in the organization through the last process on the As where you feel more comfortable that if you were to take this on that it would be closer to on time and budget?

I think from our perspective, you take a look at that investment. When we invested in it, it was four units and those four units coming to the end of their life in about this time period. We now have all eight units up and running, and all of those units now with a time horizon out to 2020 and beyond, even for the units we're contemplating refurbishment. I would agree with you, it has certainly been an investment that we've had to be quite involved in.

I think overall, we've been pretty pleased with where we've got to. With respect to the issue of the refurbishment of Units 3 through 8, I think those are excellent opportunities. I think you saw with the recent publication of the Province's long-term energy plan that they clearly have a view that Bruce, an eight unit Bruce site, is a key part of the mix going forward in Ontario. I think the focus for us is to make sure that we do learn lessons from 1 and 2.

What I would tell you is that there has been, over the past year, year and a half, there's been a very exhaustive review on a lessons learned basis. TransCanada has been very involved in that all the way down to an operational and technical perspective. We are quite confident that Bruce and the Partners have really learned a lot. That is going to be the big issue for us as we make a decision to participate in 3 through 8. We are going to want to be absolutely comfortable that we've learned all the lessons from 1 and 2 and that we're not going to repeat that experience.

Just in terms of the timeframe, you talked about the OPA report. I read that, and it just looks like the refurbishment timeframe from their perspective was more in the 2020 or so on the Bs. I have also heard earlier dates. I'm wondering what your perspective is on the potential timing or necessity of that?

Bruce will have to, and is spending a lot of time with the government and the OPA, and with OPG, I imagine, and looking at the refurbishment schedules. As I said, it is a fact that we now have usable life in these reactors out into the post-2020 period. At the same time, that tends to be around the time that you see all the Darlington units coming to their end-of-life. You can't be refurbishing 12 units at once.

There has to be a discussion about what units go first, what units follow. Those discussions are going on right now. From our perspective, I think we have a relatively open mind to the extent that someone wanted us to move quicker on those refurbishments. First, we need to be very comfortable with the deal, and we'd also want to be comfortable that if we're bringing the units off early that we're getting appropriately compensated for foregone generation that we could've got out of the units.

Okay. My last question on this topic is around Cameco as a partner and the necessity. You had them as a partner in some of the units but not in the others. I'm just wondering if you feel that they are necessary as a partner, or whether they brought any significant value that you'd have to make up elsewhere, especially obviously in the fuel availability and cost?

We and Bruce maintain an excellent relationship with Cameco. From Russ and my perspective, they were a fantastic partner. We were disappointed to see them leave, but we understand where their strategy was going.

I think that Cameco has been a fuel provider to Bruce for decades. That relationship is very strong and highly valued both by Bruce and by Cameco. I don't see that their leaving would require us to bring in anymore skillset on that regard. I think we have ample skillset within Bruce to deal with any fuel issues that come forward.

Great, thanks, guys. Those are my questions.

David McColl, Morningstar.

Just jumping back to the earlier questions around Keystone XL. I want to revisit comments, I think it was, Russ, that you made regarding the possible idea of using rail to almost help fill any issues that you could have with the Gulf Coast connector in terms of adequate volume or also really as a way to offset the delayed revenue from Keystone XL. So, with the Nebraska decision, dithering in Washington, I'm really wondering is this becoming a more serious option at this point in time, or something that you really don't want to get into unless you're pulling the trigger on it?

I think, as I've said before, that option will be driven by our customers. Production continues to grow, and that production needs to move to market. We know that a number of our customers have ordered railcars. They are in the delivery process. We know that a number of the refineries, both in Canada and the United States, are building rail-offloading facilities. We're being asked the question as to whether or not we can potentially provide bridge facilities to load tank cars both out of Canada to those locations. If our customers want us to do that, we will do that. We're, obviously, seriously looking at what services we can provide for them.

I would say that the longer these delays continue, the more traffic we're going to see on the rails. Obviously, what we want to do is help our customers. My comments weren't meant to give people the impression that our strategy with respect to rail would be a major revenue generator, or that it would offset the revenues that we would otherwise achieve on the pipeline side. In and of themselves, we would expect a decent return on capital, but the capital requirements in that side of the business aren't that large. The primary function of it would be to service our customers and to build a bridge essentially to the time in which we get regulatory approvals to get our pipelines built.

Okay. I don't think anyone interpreted it as a revenue offset. Definitely just as a bridge. Thanks for that. I assume from your statement, there, there is no real drop dead you guys are thinking for that? If happens, it happens. If it doesn't, it doesn't?

Yes, there's a no drop dead. What I would say is that it's going to be a necessary part of this business until such time as we get approvals. I think the industry has already indicated that they're up for that. But as I've always said, it's not a long-term replacement for our pipeline. I would say as soon as we have a pipeline in place, that will be the preferred alternative for the long-term shipment of large volumes over large distances. Our customers have clearly told us that and have indicated that their foray into shipping under that scenario really doesn't replace the long-term solution in building a pipeline.

Okay, great, thank you.

Carl Kirst, BMO Capital Markets.

Thanks, just a couple quick follow ups and understanding here of the NEB filing with the utility settlement was done in December. Is there a rough expectation when you think you might get a ruling from them?

Well, they did provide a comment period, where all comments now are in. The comment period for those in support of the settlement was a week and a half ago. All comments are in, so we're waiting for further instructions from the NEB. We would expect them as soon as next week.

It shouldn't be too long for further instructions. At this time, we don't know what those instructions will be. Obviously, there -- some people have asked for an oral hearing, and we've asked for a written hearing. We'll find that out shortly, here.

Understood, thank you. Last question, if I could? Russ, on Energy East, I think there was perhaps some optimism or hope maybe that even the 900,000 barrels a day of committed volumes could even be increased. I didn't know if there was any additional color or status you could add on those negotiations?

We remain optimistic that that number will grow. There's been a lot of inbound interest in the project, but at this point time we're not prepared to announce anything new. What I can tell you is that interest is strong and my expectation is we would see a larger number in the future.

Great thanks so much, guys.

(Operator Instructions)

Steven Paget, FirstEnergy Capital.

Looking at Bruce B, could there be a west-shift program to push the reactor refurbishment out past 2025?

I don't know that I would describe it as a west-shift program. I think there are certain things that potentially we could do to continue to add life to the units, but there are some technical differences in the B units than the A units. Right now, we're still at those dates you've heard us talk about earlier, but we always are considering.

Your work so far says rebuilding the Bs makes more sense than building C and tearing down B?

Oh, yes. Just at the numbers we're looking at, even if we were to achieve an outcome that looked a lot like the Bruce, the A unit, the 1 and 2, restart escalated to future dollars, it still is very competitive power compared to the options in Ontario. I think rebuilding looks way better than looking at any new build.

Thank you, Alex. Could you please update us on the progress on Grand Rapids? I remember you were looking at beginning construction in summer of 2014?

We are, on Grand Rapids, we are going to be in service. Recall that it is -- we have a 36-inch bitumen line and a 20-inch diluent line. Our plan is to bring that 20-inch line into service, early in service in 2015. That will be moving oil via the 20-inch line with the bitumen blend line in service in 2017. We're still in the same timeframe.

Thank you those are my questions.

Thank you. There are no further questions registered from the financial community. We will now take questions from the media.

(Operator Instructions)

Kelly Cryderman, The Globe and Mail.

I just wanted to know what gives you the confidence that the 90-day process that the State Department is currently undergoing with Keystone will not be impacted by the Nebraska ruling? Have your lawyers advised you that, or internal advisors said that it won't impact it? Because there's are a lot of people out there who are saying it could slow the process down.

The way I would answer it is that we don't know what the impact on the process will be. It's still too early to tell. Our view would be is that there's no reason, that we could think of, as to why the process would have to slow down as a result of the events in Nebraska.

Have you been given legal advice in that regard?

Our advisors have given us their views and that's what I'm sharing with you, is our view is a collection of both internal and external advisors that have told us that there's no reason why the Department of State process needs to be impacted by this issue in Nebraska. We're past the Final Environmental Impact for review. We're now in National Interest determination. The process in Nebraska will have to sort itself out at the end of the day, but that's not related to what is going on at the Department of State at the current time.

Thank you.

Rob Gibson, Sun Media.

Russ, it's Rob Gibson here. I'm just curious to know if you've been following some of the comments that John Kerry made about climate. He was in Indonesia and he brought up the impact of the climate. Then, yesterday when the President Obama talked about Keystone, in particular, he brought up climate change again. Doe that signal anything to you, to TransCanada, about this 90-day process and the chances of it winning approval in a timely fashion?

I think that clearly the US administration and other Canadian and global officials have talked about the importance of addressing carbon emissions. I think, clearly, what the Final Supplemental Environmental Impact Statement from the Department of State indicated was that the Keystone Pipeline wouldn't have an impact on either the rate of production from the oil sands or the rate at which oil is refined and consumed in the United States.

Hence, the Keystone Pipeline would not have any material impact on GHG emissions. I think that, after five years and what is the new 11 volume set of review, has come to the conclusion that the pipeline doesn't have an impact on GHG emissions. I think that those concerns continue with respect to policy that needs to be put in place to curb the GHG emissions, but my view would be is that the actual facts and science coming out of the Department of State would indicate that it's not an issue that's relevant to the Keystone XL pipeline.

I had the opportunity to speak with Hunter Harrison of CPR. I broached the idea of perhaps the rail lines, whether it is CP or CN or others working with pipeline companies like yourselves, to try to coordinate either a hub at the border or some such thing. He indicated there was no real development in that area, but he was interested in the idea. He brought it up. Obviously, there is some merit to it. Have you thought at all about the logistics of what that would look like?

I would say a hub at the border isn't been something that's been primary on our radar screen. I think more logical you would see something built at a terminal or at some place on the other side of the border, which is actually what's occurring today is production companies are railing both out of Canada and the US Bakken to delivery points in the United States, both to Cushing, so they can load onto things like our Gulf Coast project or directly to the Gulf Coast.

Going forward, I think they're looking at additional terminaling facilities. If you think of a longer Keystone XL route, places like Baker, Montana, which would an off/on ramp for both local production as well as potentially other production that could be railed to a place like that. I'm not saying that's a location that we've chosen or anything, but I think that those would be more logical places for us to build rail facilities, is where there is interconnection with oil pipelines to be able to move it from that point on to refinery locations.

We're looking -- those solutions would be both east, west and south in terms of rail solutions. Those conversations are going on amongst producers and refiners and terminals as we speak.

He indicated that oil by rail was only a very small portion of his business. I know that's just one railroad and just one Canadian railroad, but does that resonate with you? Does that sound like that's right, 5% of their business? And, a low margin one at that?

I can't actually speak to what percentage of his business. What we have seen is that rail traffic out of Canada has increased from a few thousand barrels a day to close to 200,000 barrels a day. I think in the US, we're somewhere around 1 million barrels a day or more, both of those numbers been considerably greater than they were in the previous years. The expectation is that those numbers will continue to rise at those kind of rates until we get pipeline capacity in place. I'm not sure how much market share they're picking up. What I would say is that we're looking at the number of tank cars that we're seeing rolling and the numbers are growing quite considerably.

Thank you, Russ.

Scott Haggett, Reuters.

Russ, I'm just curious. Is there a limit to TransCanada's patience with the US process? If this continues to be punted ahead, when does it become too much?

As I've said before, the market demand for this pipeline hasn't gone away. In fact, it's increasing. As I just mentioned, we're seeing increasing production both in Canada and the United States, and in this case the US Gulf Coast refiners who want this oil. The demand stays there. As I've said before, as long as the demand stays there and our customers want this pipeline built, TransCanada will be 100% committed to getting it done. That continues to be our position, Scott.

That's not to say that I'm not frustrated and disappointed by the continued delays, but at some point in time a pipeline's got to get built. We've got a lot invested. This is the right thing to do. Therefore, TransCanada will stay in this thing until it gets completed.

Thank you very much.

(Operator Instructions)

Elsie Ross, The Daily Oil Bulletin.

This leads to the Canadian Mainline. I was wondering if you expect even more renewals? To what extent you do? To what extent those are due to the NEB decision?

We just went through -- the end of January was the last renewal period. We just saw our renewals for the next two years be enacted at the end of January. We've got about 70%, just a little less than 70% of our FT contracts were renewed. It was a very positive event for us.

Is it the impact a result of the NEB decision? Yes, I would say two things have impacted it. Number one is the NEB decision gave us pricing discretion, which really has driven peak diluent need-firm service onto firm contract. The second part of that is I think is that it's been a pretty cool winter for a lot of our customers. I think people are starting to realize the value of firm service on the pipeline. I think the renewal period came at a good time where people actually understood the value of firm service. The next renewals will happen as the year progresses depending upon the expiry date of the contracts, but our last renewal provision was very successful.

Okay. Were those mostly long haul or a combination?

They were a combination. For example, the short haul eastern contracts, virtually 100% renewed. Long haul was around in the 70%, or the 69% was the exact number, 69% of the contracts were renewed.

Thank you.

Jeff Lewis, The Financial Post.

On Energy East and the possibility of more customers signing up for firm commitments, what's driving that interest? What are you hearing from shippers? Is that a function of delays to XL?

I would say it's a combination of delays in other alternatives, but as well production just continues to grow over time as people achieve approval for their expansion of their facilities. They're in a position, then, to commit to longer-term contracts. As you've seen new projects get announced in Western Canada for new production both conventional and unconventional, I think that we'll see increased interest in transportation alternatives leaving the Province. Given that we've advanced Energy East as far as we have, obviously it's a very attractive option for folks as they look at the landscape.

Does that include -- are you talking about just an increase in the firm commitments? Would you then have to upsize the size of the pipeline itself? From 1.1 million to something else, just so you have that spot capacity still available?

We will have to maintain a certain amount of spot capacity under any B regulation. We're required to do that. We're just in the process of understanding what that amount is going to be that we're going to apply for. At the current time we don't have any plans to increase the capacity beyond 1.1 million barrels a day, but obviously we're continuing to look at other alternatives. Once oil supply grows above the current available capacity that's being offered in the marketplace, producers will begin to look at other alternatives. Obviously, we would have our slate of other alternatives to move growing production to market.

Do you expect to make an announcement before you file, I guess it was mid 2014, for the project? On additional commitments?

Those additional commitments aren't the necessary component of a filing, so those would be announced if and when they come about. The two things aren't related. Our plan is to file for application, I said, by mid year. What we would hope is that as time progresses we would continue to sign additional long-term firm contracts with shippers. That may continue even on beyond the application date.

Okay, thanks.

Rebecca Penty, The Bloomberg News.

I'm just hoping that you can get into the level of support that you have from landowners in Nebraska for Keystone? Where the contracts are at with those landowners? Whether the recent ruling by the Nebraska judge affects how you guys negotiate with landowners and eminent domain and that whole situation?

I'll do my best. We originally had in the 90% kind of range in terms of negotiated land easement agreements with landowners in Nebraska. We're close to 100% in South Dakota, as you know, and in Montana. With the reroute we had to start from square one with landowners along that reroute section. Along that reroute section, we're at about 75%-ish, which is actually faster than we have been able to negotiate easement agreements in other parts of the system, so we're please with that. Those negotiations continue.

With respect to your question on eminent domain, we need an approval from some authority, whether that be the one that we thought that we had or under the PSC, or some other alternative that may arise, in order to exercise those rights. As we said before that's not our natural inclination. What we would hope is to negotiate with the landowner, and in most cases we get ourselves to a place that's in the high 90%-ish of voluntary easement negotiations, and only a small minority actually end up in that eminent domain process.

Again, the eminent domain process is really just one of setting price. It's not one of expropriation of land or anything like that. It's an easement, which is the right to cross a piece of property. The pipe will be buried 4 to 5 feet under the property and the landowner continues to have the right of use over that property. We'd pay for that right of access. What the eminent domain process is, is one of determining what the market value or fair market value of that right would be.

Okay. I'm just hoping you could speak to a bigger picture about how important Nebraska is in this whole process, because earlier you guys were talking about how this ruling wouldn't affect the State Department National Interest Determination, but that is not the final be all, end all. Obviously, Obama's decision is. I'm wondering, can you speak to this latest setback in Nebraska? Do you think Obama could just wait until that's resolved before deciding, which is what everyone is speculating?

I can't speak to what the Department of State or the administration, how they will react through this process. We have our views. We don't believe that there should be any connection between the two. We believe that we should be working in parallel to resolve our issues in Nebraska, which again is just ensuring that the proper authority approves our pipeline route.

If it's not the governor of Nebraska, under what we thought was the current law, or what was the current law, then our question is, what is our process for determining or getting approval of that route? We will comply with all of those rules and regulations, as we have with the State Department process. They're just run on two different tracks. We would hope that they could run, those two tracks can run in parallel. There would be no reason for them to run in series.

Sorry, just last question. I'm just wondering, you were speaking earlier about alternative options that you were looking at for your next steps? Like where you go from here, can you speak at all to any of those alternative options? One of which would be filing with the PSC obviously?

Yes, those were the two options I think that people have talked about to date, are the appeal, which has already, my understanding, has already been launched by the Attorney General in Nebraska. The other is to file with the Public Service Commission. There could be other alternatives as well. At this point, Rebecca, we just haven't had a chance to thoroughly review what our options are, what the pros and cons are, and pick a path. Over the next few days, we will obviously be engaged in several conversations with officials in the state and our advisors to determine what the best path is to seeking approval for the route that we now have.

As I said the existing route approval wasn't done in a vacuum. It wasn't done independently by the Governor of Nebraska. It was actually conducted by the Department of Environmental Quality. All of that work has been done and sound any new process that is initiated would incorporate, I would hope, would incorporate all of that work that has already been done by Nebraska authorities in any new decision that needs to be done. We just need to be pointed in the right direction as to what is the right process. We'll comply and we'll follow with those rules.

My view is that at the end of the day, we will receive approval of that route and [minor weight], whichever route we go in terms of next steps. As I said, I don't think that should impact the National Interest determination, which really isn't asking the question at this time -- what is the route in Nebraska? It's really asking -- is this pipeline in the national interest of United States. They have full information on which to make that decision at this point in time.

Okay. Thank you.

Chester Dawson, Wall Street Journal.

Two questions, first of all, in regard to the court ruling, was it something that came out of the blue, or had you been monitoring it and expecting a decision?

It would've been something that we would've been monitoring, but I think as we said our view was, or our view is, that the decision isn't correct, and that the laws that we had made our application and had our approval under was sound. We continue to believe that. So not out of the blue, it's something we were monitoring, but certainly we hadn't expected that the decision would go this direction.

Okay, thanks. Secondly you mentioned customer interest in rail bridges. Can you provide a little more information about exactly where that interest lies? Is it along the proposed Keystone route? Is it elsewhere? Where is there interest in that type of a bridge solution?

The way a bridge solutions would work is you're going to -- basically you are going to load oil into tanks cars at terminal facilities in the proximity of production locations. It will move on existing rail corridors through both Canada and the United States to receiving terminals at either storage facilities in Canada and the United States or at refineries in Canada and the United States. There wouldn't be anything be done along a pipeline corridor along the Keystone Pipeline corridor, for example. Maybe tank cars moving on existing railways from either existing or new loading facilities to either new or existing unloading facilities at a place where you're actually going to refine or use the crude oil.

What I meant was, is it as a way around Keystone or are there other projects as well where you could see that demand?

It's actually being done as we speak. As production grows, you need to move it to market. A number of projects have been delayed, not just the Keystone project, and as a result of that rail traffic has moved up exponentially. I expect that to continue. The railways have the ability to accommodate more railcars, that the constraint has been, in that marketplace, the availability of railcars.

What I can tell you is that railcar manufacturing facilities are chock a block full right now delivering as many railcars as they can to the industry. The industry is buying them or leasing them. The industry, mostly producers and refiners, are buying those railcars as quickly as possible, getting them on the tracks. What they may need is additional loading and unloading facilities. That's probably the roll that we would play in terms of an adding a bridge. The likely place to put them would be at places where we already have plans for storage terminaling at the current time.

Okay, thank you.

Thank you. This concludes the question-and-answer portion of the program. I would now like to turn the meeting back over to Mr. Moneta.

Thanks very much. Thanks to all of you for your interest in TransCanada today. We look forward to speaking with you again soon. Have a good day. Bye for now.

Thank you. The conference call has now ended. Please disconnect your lines at this time. Thank you for your participation.