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TransCanada (NYSE:TRP)

Q4 2013 Earnings Call

February 20, 2014 2:00 pm ET

Executives

David Moneta - Former Vice President of Investor Relations & Communications

Russell K. Girling - Chief Executive Officer, President and Director

Donald R. Marchand - Chief Financial Officer and Executive Vice President

Alexander J. Pourbaix - President of Energy and Oil Pipelines

Karl R. Johannson - Executive Vice-President and President of Natural Gas Pipelines

Analysts

Juan Plessis - Canaccord Genuity, Research Division

Paul Lechem - CIBC World Markets Inc., Research Division

Carl L. Kirst - BMO Capital Markets U.S.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Robert Kwan - RBC Capital Markets, LLC, Research Division

Linda Ezergailis - TD Securities Equity Research

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

David McColl - Morningstar Inc., Research Division

Carl L. Kirst - BMO Capital Markets Canada

Operator

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.

David Moneta

Thanks very much, and good afternoon, everyone. I’d 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’ll take questions from the investment community first, followed by the media. [Operator Instructions]

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’d 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 U.S. Securities and Exchange Commission.

And finally, I’d also like to point out that during the presentation, we’ll refer to measures 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.

Russell K. Girling

Thank you, David, and good afternoon, everyone, and 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 $19 billion of new, high-quality infrastructure projects that will position the company for growth well into the next decade. And our portfolio of blue-chip assets continued to deliver stable and growing cash flow and earnings. All 3 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 $1.7 billion or $2.42 a share. Comparable earnings increased 19% to $1.6 billion or $2.24 per share, and funds generated from operations were up 22% to $4 billion.

The strong year-over-year growth in cash flow and earnings were primarily due to the return to an 8-unit operational nuclear site at Bruce Power, the first time all 8 reactors have run for a couple of decades. Higher western power volumes due to the return of service at Sundance A and increase in New York capacity prices, growth in our NGTL natural gas pipeline system rate base and a higher Canadian Mainline return on equity due to the NEB's restructuring decision made in March 2013, all contributed to the growth.

After adding approximately $8 billion of new projects in 2012, we continued to build our portfolio of commercially secured projects by adding an additional $19 billion in 2013, including the Prince Rupert gas transmission project to transport natural gas to the B.C. Coast, further NGTL expansions and the largest company -- project in our company history, the Energy East pipeline, which is a combination of a newbuild 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 of projects is diverse and they are all backed by the long-term contracts or cost of service regulation. The portfolio includes $23 billion of crude oil pipelines, $13 billion of natural gas pipelines and $2 billion of power generation facilities.

If the required approvals are received, and I can tell you that we are very hardly -- we're 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. So 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 $420 million or $0.59 a share. Comparable earnings for the quarter were $410 million or $0.58 a share versus $318 million or $0.45 a share in Q4 of 2012, which is a 29% increase. Comparable EBITDA was $1.3 billion, and funds generated from operations were $1.1 billion.

The Board of Directors also declared a quarterly dividend of $0.48 per common share for the quarter ending March 31, 2014, a 4% increase over the previous quarterly amount of $0.46 per share. This results in a per share annual increase from $1.84 to $1.92. 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'd 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 FEIS actually says. So for those of you 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. And the project is also unlikely to significantly affect the rate of oil sands extraction or the volume of oil refined in the U.S., hence the project would not have a significant impact on GHG emissions.

It also said that the alternatives of 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 would 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 U.S. 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 steel pipeline, that can do nothing but increase energy security. The FEIS points out that demand will persist for imported heavy crude oil for U.S. 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 delivered from the Gulf Coast to their location, hence all of this oil is going to stay in the United States.

The report also states the U.S. 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 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 national 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'll now analyze the judgment and determine what our next steps may be. But first, let me say this is a solvable problem, and we are undeterred. And that Nebraska Department of Environmental Quality has reviewed the route, as well the Department of State has completed its own independent review.

We've dealt with many issues on Keystone XL in the past, and we have many options to deal with this latest hurdle. It's 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, and 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 and over a dozen polls 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 permit. As of December 31, 2013, we had invested approximately $2.2 billion in the project. We anticipate the pipeline would be operational approximately 2 years after we received 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. And an efficient and safe pipeline network is something that I believe all Americans support and expect.

The $2.6 billion Gulf Coast project was designed to connect U.S. oil production to markets that need it. Growing energy production in Oklahoma, Texas, North Dakota, Montana and in Canada created a glut in places like Cushing. And the Gulf Coast refiners 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. And we are proud to partner with more than 50 U.S. manufacturers and companies in building the pipeline and to 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 million barrels of oil to U.S. 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 Canadian 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 an opportunity for Canada to use and refine its own resources, something that benefits all Canadians from coast to coast to coast.

The benefits include $35 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 $10 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 the 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 through 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 $900 million and are expected to be operational in 2016.

In addition, last October, we received some very positive news from Suncor with the announcement the 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 and will transport crude oil and diluent from the Fort Hills mine site to Suncor's tank facilities, north of Fort McMurray.

Now moving over to our gas business. In December of 2013, we filed for NEB approval of a settlement reached with Canada's 3 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 extend this critical network of pipe, $730 million of new facilities became operational in 2013. The National Energy Board also approved $290 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 $1.7 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 9 Ontario solar projects from Canadian Solar Solutions. We acquired 1 in July, 2 in September and the fourth in late December [ph]. The combined capacity of the 9 projects is 86 megawatts at a total cost of $500 million. We anticipate the remaining 5 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.

1/3 of the power that we provide to North America comes from carbon-free energy sources. TransCanada has invested over $5 billion in energy -- or in emission-free energy sources, including the largest wind farm in New England, hydro facilities in the U.S. and Northeast, our solar investments, Canada's largest wind farm in Québec and our interest 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 $1.6 billion, and funds generated from operations were up 22% to $4 billion.

We captured $19 billion in additional projects last year, growing our current portfolio of commercially secured capital projects to $38 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'd like to acknowledge the hard work and dedication of 2 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 shareholder value.

As a result of those retirements, the growth in each of our core businesses and the development of the contractually secured $38 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 $38 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 nonregulated 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, and 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.

And with that, I'll turn the conference call back to Don.

Donald R. Marchand

Thanks, Russ, and good afternoon, everyone. Before I review the fourth quarter results in detail, I'd just like to reiterate a few of Russ' key messages.

Earlier today, we announced a 4% increase in the common share dividend. This marks the 14th consecutive year the board raised [ph] the dividend.

Our fourth quarter and overall 2013 financial results were strong and reflect our diverse portfolio of high-quality energy infrastructure assets, including $3.5 billion of new assets that were placed into service over the past 15 months.

The solid momentum is expected to continue heading into 2014 as approximately $4 billion of new assets are expected to be brought into service this year, including the Gulf Coast project, the Tamazunchale pipeline extension, the acquisition of the remaining 5 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 $38 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.

And finally, we remain well positioned to fund our current capital program. In 2013, we raised $4.8 billion on attractive terms, clear evidence of our ability to access varying sources of 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 $410 million or $0.58 per share increased $92 million or $0.13 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 plant outage days at Unit 4. This was partially offset by a decreased contribution from U.S. natural gas pipelines and lower realized power prices in Western Power.

Turning to our business segment results at the EBITDA level. Our Natural Gas Pipelines business generated comparable EBITDA of $778 million in fourth quarter 2013 compared to $690 million for the same period last year.

Canadian Gas Pipeline's EBITDA of $600 million increased $118 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 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. And 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 USD 20 million decline in EBITDA at U.S. and international natural gas pipelines. ANR experienced lower transportation and storage revenues, as well as higher costs 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 30%, effective July 1, 2013, following their partial sale to TC Pipelines, LP.

Turning to oil pipelines. Keystone generated $200 million of EBITDA in the fourth quarter. $20 million year-over-year increase was primarily a result of higher volumes.

In Energy, comparable EBITDA was $346 million in the fourth quarter compared to $222 million for the same period last year. The $124 million increase was the result of a combination of positive factors which included Bruce Power's equity income rising $123 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.

U.S. Power EBITDA also increased USD 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.

Natural Gas Storage results rose $7 million year-over-year, driven by increased volumes at higher realized storage spreads and incremental earnings from the acquisition of the remaining 40% interest in CrossAlta in December 2012. This was partially offset by a $24 million decline in Western Power's EBITDA in fourth quarter 2013 compared to the same period last year. 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 $240 million in the fourth quarter, a $6 million decrease compared to the same period last year. This was principally due to increased capitalized interest, as well as Canadian and U.S. dollar debt maturities, partially offset by interest charges on recent debt issues and higher foreign exchange on translating interest denominated in U.S. dollars.

In the fourth quarter, $92 million of interest was capitalized to assets under construction compared to $76 million 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 $75 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 on to 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 $1 billion for the second consecutive quarter and totaled a record $4 billion in 2013, representing a 22% increase over 2012.

Turning to investing activities. Capital expenditures were $1.4 billion in the fourth quarter, driven principally by the Gulf Coast project and construction of our Mexican pipelines.

Equity investments of $62 million decreased $33 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 $62 million in the quarter reflect the purchase of our fourth Ontario solar facility, which closed at the end of December. The acquisition of the 5 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 remain 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 $927 million of cash on hand. We also recently increased our committed credit lines by $1 billion, and at year-end, had approximately $4.7 billion of committed and undrawn revolving bank lines available with our high-quality bank group.

Our 2 commercial paper programs, one in Canada and one in the U.S., remain well supported and provide flexible and very attractive sources of short-term funds.

In October, we issued USD 1.25 billion of senior notes, split evenly between 10- and 30-year maturities, bearing 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 $200 million, and they carried an average of $11 million in annualized dividends.

Throughout the course of 2013, we raised $4.8 billion on attractive terms through an array of funding products to a diverse investor base.

We've also gotten off to a 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 the $450 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 $200 million, and it carries an aggregate of $11 million in annualized dividends.

And finally, we also announced in January the sale of Cancarb and its related power generation facility for $190 million. This sale is expected to close late in first quarter 2014.

In 2014, we expect to spend approximately $5 billion on advancing our capital program and to maintain our existing asset base. This includes $2.3 billion on oil pipelines, excluding Keystone XL; $2 billion on natural gas pipelines; and $700 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 dropdowns. As we advance our capital program, we expect to vend in the remaining interest in all of our U.S. natural gas pipelines to our MLP, TC PipeLines. With approximately $3.5 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 $2.24 per share and $4 billion of funds generated from operations were up 19% and 22%, respectively, compared to 2012.

Going forward, the addition of approximately $4 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 $38 billion portfolio of large scale, commercially-secured infrastructure projects, each of which is underpinned by long-term contracts with strong counterparties.

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 David.

David Moneta

Thanks, Don. [Operator Instructions] I'll turn it back to the conference coordinator for your questions.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from Juan Plessis with Canaccord Genuity.

Juan Plessis - Canaccord Genuity, Research Division

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 and when would you anticipate making a decision on this?

Alexander J. Pourbaix

Juan, 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 is -- 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. And we remain very committed to Bruce, we think there's a great opportunity for refurbishment. And by negotiating this option, it gives us a lot of flexibility as to how we go forward.

Juan Plessis - Canaccord Genuity, Research Division

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? And also, you've indicated in the MD&A that the demand curve reset could potentially negatively impact the capacity prices in 2015 and '16. I'm just wondering if you can elaborate on your 2015 and '16 capacity price outlook.

Alexander J. Pourbaix

Sure. I think the FERC just settled the capacity -- 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%. But that's obviously only 1 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 '15 and '16.

Operator

The next question is from Paul Lechem with CIBC.

Paul Lechem - CIBC World Markets Inc., Research Division

Just on Keystone XL, wondering what your thoughts are on the interaction between what's going on in Nebraska and the whole FEIS national interest determination process which is being run? Is there any concern that the change in Nebraska could derail the Presidential permit?

Russell K. Girling

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 the environmental impacts of 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.

Paul Lechem - CIBC World Markets Inc., Research Division

Okay and given where we're at in 2014, you commented that you need 2 full years to -- from when you get the permit to get this thing built. Is that 2 full years or 2 full construction seasons? I mean, is there a chance as you go through 2014, you could still salvage some of this year and you can still push for at least [ph] 2016 entry into service.

Russell K. Girling

There's always certain things that we can do, depending on when you get the permit. But I think the most important thing, I think, is to have sort of 2 full summer construction seasons to complete the project. So 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 might have on schedule and determine how we might rework our schedule to minimize the impacts it will have on the ultimate in-service date.

Paul Lechem - CIBC World Markets Inc., Research Division

Just one more question, if I may, just switching gears. In the U.S. gas pipes. Any sign of things bottoming out for ANR and maybe Great Lakes? Are you seeing any sign of a turn there?

Karl R. Johannson

It's Karl speaking. As we reported last quarter, we did see some extra take-up on capacity coming out of Marcellus and Utica, into our Lebanon lateral. That has been paid for and we'll expect those volumes to come on over the next year or so. And right now, we're right in the middle of another open season for more Marcellus and Utica volumes and we're quite optimistic that we'll see some more volume. So 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 revenues that, that pipeline generally gets has not had the same recovery with the storage emptying out throughout North America here this winter. It will have some depressing impacts on long-term storage spreads. So we'll -- but again, that's cyclical as well and we expect that to come out. So I guess the bottom line is I'd say that certainly, on a flow perspective, we're quite optimistic right now with being [ph] our 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.

Operator

And the next question is from Carl Kirst with BMO Capital Markets.

Carl L. Kirst - BMO Capital Markets U.S.

Russ, in understanding this is less than 24 hours post-Nebraska and I know you all are evaluating next steps. I guess my question is as we look at -- even if you kind of go back to putting this back under the purview of the PSC, it would seem like they have to make a decision within a 7-month time frame. Is the rebound side to just basically you're gearing up the process to actually file with the PSC just to get the clock ticking? And since we went through this process with the DEQ, does the filing -- I mean, is that something that takes 2 weeks to put together or is that something that takes 2 or 3 months to put together?

Russell K. Girling

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, that would obviously impact the schedule of which they could process that application if we went that direction. But 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 sort of the initial output of that is, as well as we calibrate what our strategy is. But I think what I would tell you is that my view is that the route that we picked is sound, it has been through the review process as I said at the Department of State. We will find the most expeditious route to getting that route ultimately approved and getting on with getting our Presidential permit, that's the current plan. But 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. But as soon as we do, I mean, we'll share that with the marketplace.

Carl L. Kirst - BMO Capital Markets U.S.

May be 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.

Alexander J. Pourbaix

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. And 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. So positive, but not knocking it out of the ballpark.

Carl L. Kirst - BMO Capital Markets U.S.

Okay. And then maybe last question, if I could, just 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 that sort of transpiring, excluding what happens with XL here?

Donald R. Marchand

I wouldn't link it to any specific project. We've got $38 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. So 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 the transaction. So it will be over several years but with a program of this size, moving this $3.5 billion suite of assets into the LP, makes sense.

Operator

And the next question is from Andrew Kuske with Crédit Suisse.

Andrew M. Kuske - Crédit Suisse AG, Research Division

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

Karl R. Johannson

Okay. Well, for 2013, for example, we -- on our gross revenue requirement on the Mainline, which was just a little over $1.6 billion, we essentially covered it, we're a little short but as we're talking about $50 million, $60 million, so it wasn't that, that significantly short. So 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 requirement. We're only 2 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. So 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 even closer to 90% of our revenue coming from firm transmission. So we're not relying on discretionary for that great of our revenue requirement right now. So I think it's in pretty good shape. I'm not sure if that answered your question, but I think we're quite optimistic in 2014 as well and we have some sales already on for 2015.

Andrew M. Kuske - Crédit Suisse AG, Research Division

So I guess it's just fair to say that you feel pretty comfortable on how you've de-risked the asset with just the increase in the FT.

Karl R. Johannson

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

Andrew M. Kuske - Crédit Suisse AG, Research Division

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

Karl R. Johannson

Well, let's -- don't forget, we have an application in front of the board right now with our settlement with our shippers. And that settlement with the shipper is essentially is with our Eastern LDC shippers. Essentially, segments are pipelined and what it does is our Eastern LDC shippers have come to us and said that they'll give a transition or bridging mechanism for our cost of capital or for cost in our entire system, if we were to build more Eastern Triangle capacity for them so that they can access more [ph] Marcellus. And so part of that is the system's 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 and 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. So we can make between 8.7% and 11.5% ROE on the pipeline. So if that settlement is approved, you will see, actually, our ROE fall a little bit vis–à–vis, what we're getting today. But then, we'll have a much longer -- a much better profile of secured cash flows.

Operator

The next question is from Robert Kwan with RBC Capital Markets.

Robert Kwan - RBC Capital Markets, LLC, Research Division

I guess 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 and I'm just wondering if you can quantify what the incentives were. And 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?

Karl R. Johannson

Yes, well, let's start with the Mainline, the LDC settlement has a very similar incentive program that we're under right now. It basically gives us a tiered percentage of the revenue that we get over our net revenue requirement. So yes, I think we -- to go in the settlement with the LDCs. We will have the same opportunity that we're seeing right now during [ph] incentives. Right now, as of, 2013, we earned about $14 million on the Mainline under the incentive program. And again, that incentive program was anything above our natural [ph] revenue requirement we shared and on NGTL, there was a more modest incentive. I think it was about $3 million to -- it was $3 million?

Donald R. Marchand

Yes, it was about somewhere in that, about $0.005, it wasn't much.

Karl R. Johannson

And that 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 savings.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay and that was all booked in the fourth quarter?

Karl R. Johannson

Yes that was all booked in the fourth quarter.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Just I guess, 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 Nations, Aboriginal and community stakeholder consultation process?

Alexander J. Pourbaix

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 the site for the Marine Terminal in Québec, that is significantly further east than we had originally been anticipating. And as a result, we're going to have to build more kilometers of pipe inside Québec before we get to the Marine Terminal. So just by -- 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.

Operator

And the next question is from Linda Ezergailis with TD Securities.

Linda Ezergailis - TD Securities Equity Research

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 and 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?

Russell K. Girling

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

Linda Ezergailis - TD Securities Equity Research

I'm looking on your statement of cash flow. So last year, your operating capital in 2012 decreased by $287 million and this year in 2013, it increased by $326 million.

Donald R. Marchand

Yes. And quite frankly, most of that is timing, there's a little bit of a -- current regulatory deferrals in that. But there's no underlying driver to it. It's really just timing of collections and payments.

Operator

The next question is from Steven Paget with First Energy Capital.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

You've got a $35 billion order book. Once you take the Gulf Coast Project off for the remainder of the decade, what's the un-risked dollar value of the potential additional projects that you are looking at adding, if any?

Russell K. Girling

I'm not sure if I have a good number for you, Steven. It's obviously the -- that we're looking at numerous things. Think of the Alaska project, for example, if we have a 20% interest in a $40 billion or $50 billion project, that's $10 billion by itself. So you add on sort of bolt-ons and add-ons, things that we're looking at, I think you could easily get another number that looks like $30 billion.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

And that might include Bruce B refurbishment?

Russell K. Girling

That will be included in that. Obviously, that one's an over time thing. But alone, Bruce B refurbishment I think, folks are talking between $10 billion to $15 million by itself. So it's an -- it's a great 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.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

And what's the driver on your dividend growth rate? Is it a steady increase per quarter -- or per year or as a percent of earnings or cash flow?

Russell K. Girling

It's more the latter, is our object -- and 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. And so there's no sort of set percentage in mind. Obviously, we want to sort of stay in a range of a payout relative to earnings in about the range that we have been lately or less. It's probably where we'd want to be. So as we start to see visibility of earnings growth going forward, it would be our intent to move dividends in conjunction with those.

Donald R. Marchand

Yes. Sustainability is the key. Historically, we've been in the 70% to 80% of earnings payout range, which equates to about 1/3 of cash flow. That seems like the right place to be, which gives a good balance of cash return to the shareholder and still retain capital to invest for growth. So that -- we don't see a clear reason to move off that.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

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

Donald R. Marchand

Of EPS, which is about 1/3 of cash flow.

Operator

[Operator Instructions] The next question is from Matthew Akman with Scotiabank.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

My questions are on Bruce and I guess, exercising or not, the option on some of the considerations that go into that. And obviously, Bruce has been in some sense, a good investment but also controversial and challenging at times. And maybe, for Alex I'm just wondering how you think about it now in terms of its desirability? And in particular, whether there are sufficient, I guess, 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?

Alexander J. Pourbaix

Well, I think from our perspective, you take a look at that investment, we -- when we invested in it, it was 4 units and those 4 units coming to the end of their life in about this time period, we now have all 8 units up and running and all of those units now with a time horizon out to kind of 2020 and beyond, even for the units we're contemplating refurbishments. So we certainly think, I would agree with you, it's certainly been an investment that we've had to be quite involved in. But 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 8-unit Bruce site is a key part of the mix going forward in Ontario. I think that 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, 1.5 years, there's been a very exhaustive review of -- sort of on the lessons learned basis. TransCanada has been very involved in that, all the way down to sort of an operational and technical perspective. And we are quite confident that Bruce and the partners have really learned a lot, but that is going to be the big issue for us, as we make a decision to participate in 3 through 8 where we're 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.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

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

Alexander J. Pourbaix

I think Bruce will have to -- and is spending a lot of time with the government and the OPA and with OPG, I imagine, in looking at refurbishment schedules. As I've said, it is a fact that we now have usable life in these reactors out into the sort of post-2020 period. But at the same time, that tends to be around the time that you see all the Darlington units coming to their end of life and you can't be refurbishing 12 units at once. So that there has to be a discussion about what units go first, what units follow and those discussions are going on right now. And from our perspective, I think we have a relatively open-mind, to the extent that someone wanted us to move quicker on those refurbishments. Well, 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 forgone generation that we could have got out of the units.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Okay and my last question on this topic is around Cameco as a partner and I guess, the necessity. I mean, 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.

Karl R. Johannson

We and Bruce maintain an excellent relationship with Cameco. I think 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. But I think that Cameco has been a fuel provider to Bruce for decades and I think that relationship is very strong and highly valued both by Bruce and by Cameco. So I don't see that their leaving would require us to bring in any more skill set in that regard. I think we have ample skill set within Bruce to deal with any fuel issues that come forward.

Operator

And the next question is from David McColl with Morningstar.

David McColl - Morningstar Inc., Research Division

Just jumping back to earlier questions, I guess, around Keystone XL. I maybe 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 is something that you really don't want to get into unless you're pulling the trigger on it?

Russell K. Girling

I think that as I've said before, that option will be driven by our customers and production continues to grow. And that production needs to move to market. We know that a number of our customers have ordered railcars and they are in sort of delivery process. We know that a number of the refineries, both in Canada and the United States, are building rail offloading facilities. And 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, and if our customers want us to do that, we will do that. And so we're, obviously, seriously looking at what services we can provide for them. I'd say that the longer these delays continue, the more traffic we're going to see on the rails. And obviously, what we want to do is help our customers. I hope my comments weren't sort of meant to -- 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. I mean, 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. So the primary function of it would be to service our customers and to build a bridge, essentially to the time in which we get these regulatory approvals to get our pipelines built.

David McColl - Morningstar Inc., Research Division

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

Russell K. Girling

Yes, I think there's no drop-dead in it. But 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. And 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 of building a pipeline.

Operator

And the next question is a follow-up question from Carl Kirst with BMO Capital Markets.

Carl L. Kirst - BMO Capital Markets Canada

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

Donald R. Marchand

Well, the -- they did provide a comment period, where all comments now are in. I think the last -- the comment period for those in support of the settlement was 1.5 weeks ago. So all comments are in. So we're waiting for further instructions from the NEB, and we would expect them as soon as next week. But it shouldn't be too long for further instructions and at this time we don't know what those instructions will be, obviously, there were -- some people have asked for an oral hearing and we've asked for written hearing. So we'll find that out shortly here.

Carl L. Kirst - BMO Capital Markets Canada

Understood, thank you. And then last question, if I could. Just, 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. And I didn't know if there was any additional color or status you could add on those negotiations?

Russell K. Girling

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

Operator

[Operator Instructions] The next question is a follow-up question from Steven Paget with First Energy Capital.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Just looking at Bruce B, could there be a sort of West Shift program to push the reactor refurbishments out to past 2025?

Karl R. Johannson

I think -- I don't know that I'd 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 they are -- there are some technical differences in the B units than the A units. And so right now, we're kind of still at that -- those dates you've heard us talk about earlier. But we always are considering.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

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

Karl R. Johannson

Yes. No, it's -- just if -- if kind of 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's still is very, very competitive power compared to the options in Ontario. So I think rebuilding looks way better than looking at any new build.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

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

Karl R. Johannson

Well, so we are -- on Grand Rapids, we are going to be in service. Recall that it is a -- 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. And that will be moving oil via the 20-inch line with the bit of the bitumen blend line in service in 2017, and that we are still sort of in the same time frame.

Operator

Thank you. There are no further questions registered from the financial community. We'll now take questions from the media. [Operator Instructions] The first question is from Kelly Cryderman with the Globe and Mail.

Kelly Cryderman

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 a lot of people out there who are saying it could slow the process down.

Russell K. Girling

I guess, 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 can think of as to why the process would have to slow down as a result of the events in Nebraska.

Kelly Cryderman

And have you been given legal advice in that regard?

Russell K. Girling

Our advisors have given us their views and that's what I'm sharing with you, is our view is, 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 review and 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.

Operator

The next question is from Rob Gibson with Sun Media.

Rob Gibson

It's Rob Gibson here. I'm 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. And then yesterday when the President, Obama, talked about Keystone, in particular, he brought up climate change again. Does that signal anything to you, to TransCanada, about this 90-day process and the chances of it winning approval in a timely fashion?

Russell K. Girling

I think there's a clearly -- the U.S. administration and other Canadian and global officials have talked about the importance of addressing carbon emissions. But I think clearly what the final environmental -- 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 and, hence, the Keystone Pipeline would not have any material impact on GHG emissions. So I think that after 5 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. So I think that those concerns continue with respect to policy that needs to put in place to curb 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.

Rob Gibson

So I had the opportunity to speak with Hunter Harrison of CPR, and I broached the idea of, perhaps, the rail line to whether it's CP or CN, or others working with pipeline companies like yourselves, 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?

Russell K. Girling

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 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 U.S. Bakken to delivery points to the United States, both to Cushing, so that they can load on to things like our Gulf Coast Project or directly to the Gulf Coast. And going forward, I think they're looking at additional terminaling facilities. If you think of along our Keystone XL route, places like Baker, Montana which would be an 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. So we're looking -- those solutions would be both east, west and south, in terms of rail solutions. And those are -- those conversations are going on amongst producers and refiners and terminals as we speak.

Rob Gibson

He kind of 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 is that -- does that resonate with you? Does that sound like that's right, 5% of their business? And a low margin one at that?

Russell K. Girling

I can't actually speak to you, what percentage of his business, what we've 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. And I think in the U.S., we're somewhere around 1 million barrels a day or more, and both of those numbers being considerably greater than they were in the previous years, and the expectation is that those numbers will continue to rise at those kind of rates until we get pipeline capacity in place. So I'm not sure how much market share there is they're picking [ph] up or what would -- 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.

Operator

And the next question is from Scott Haggett with Reuters.

Scott Haggett

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

Russell K. Girling

I think as I said before, I mean, 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 U.S. Gulf Coast refiners who want this oil. So the demand stays there. And 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. And 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, the pipeline has got to get built, and we've got a lot invested and this is the right thing to do. And therefore, TransCanada will stay in this thing until it gets completed.

Operator

[Operator Instructions] The next question is from Elsie Ross with the Daily Oil Bulletin.

Elsie Ross

This relates to the Canadian Mainline. And I was wondering if you would expect even more renewals, and to what extent you do and to what extent those are due to the NEB decision?

Russell K. Girling

Well, we just went through -- the end of January was the last renewal period. And we just saw our renewals for the next 2 years be enacted at the end of January. And we got about 70% -- just a little less than 70% of our FT contracts were renewed. So it was a very positive event for us. And is it, in fact [ph], the result of the NEB decision? Well, yes. I would say 2 things have impacted that. number one is, the NEB decision gave us pricing discretion, which really has driven people who need firm service onto firm contract. And the second part of that, I think is that, it's been a pretty cold winter for a lot of our customers. And I think people are starting to realize the value of firm service on the pipeline. So I think the renewal period came at a good time where people actually understood the value of firm service. So 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.

Elsie Ross

Were those mostly long-haul or combination?

Russell K. Girling

They were combination but -- for example, I think the short-haul eastern contracts, virtually 100% renewed. And long-haul was around in the 70% or 69%, I think was the exact number. 69% of the contracts were renewed.

Operator

And the next question is from Jeff Lewis with Financial Post.

Jeff Lewis

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?

Russell K. Girling

I would say it's a combination of delays and 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. And so, as you see 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. And given that we have advanced Energy East as far as we have, obviously, it's a very attractive option for folks as they look at the landscape.

Jeff Lewis

And does that include -- I mean, are you talking about just an increase in the firm commitments and would you then have to upsize the size of the pipeline itself? I mean, from 1.1 million to something else, just so you have that spot capacity is still available?

Russell K. Girling

We will have to maintain a certain amount of spot capacity under any deregulation. 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 the other alternatives. And obviously, we would have our slate of other alternatives to move growing production to market.

Jeff Lewis

And do you expect to make an announcement before you file -- I guess, it was mid-2014 for the project on additional commitments?

Russell K. Girling

Those additional commitments aren't a necessary component of a filing. So those would be announced if and when they come about. The 2 things aren't related. Our plan is to file our application, as I said, by mid-year. And what we would hope is that as time progresses, we would continue to sign additional long term firm contracts with shippers. And that may continue even on beyond the application date.

Operator

The next question is from Rebecca Penty with the Bloomberg News.

Rebecca Penty

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 and whether the recent ruling by the Nebraska judge affects how you guys negotiate with landowners and eminent domain and that whole situation?

Russell K. Girling

I'll do my best. We originally had in sort of 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 about 75-ish percent, which is actually faster than we have been able to negotiate easement agreements in other parts of the system, so we're pleased with that. So those negotiations continue. With respect to your question on eminent domain, we need an approval from some authority, whether that's 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. But 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 percent of voluntary easement negotiations and only a small minority, actually end up in that eminent domain process. But 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 feet to 5 feet under the property and the landowner continues to have the right of use over that property, and we pay for that right of access. And what the eminent domain process is, is one that's determining what the market value or fair market value of that right would be.

Rebecca Penty

Okay I'm just hoping you can speak to the 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's not the final be all end all, obviously, Obama's decision is. So I'm wondering can you speak to this latest setback in Nebraska. And do you think that Obama could just wait until that's resolved before deciding, which is what everyone is speculating?

Russell K. Girling

Yes, I can't speak to what the Department of State or the administration, how they will react to this process because we said we have our views and 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 has -- approves our pipeline route. And 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, and we will comply with all of those rules and regulations, as we have with the State Department process, and they just run on two different tracks and we would hope that they can run those two tracks can run in parallel and that there's no reason for them to run in series.

Rebecca Penty

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

Russell K. Girling

Yes, those were the 2 options I think that people have talked about to date. Our -- the appeal which has already, my understanding has already been launched by the Attorney General in Nebraska. The other is to file with Public Service Commission. There could be other alternatives as well. And 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. And 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's already been done by Nebraska authorities. In any decision that needs to be done, we just need to be pointed in the right direction as to what is the right process and we'll comply and we'll follow with those rules. My view is at the end of the day, we will receive approval of that route and underway [ph] whichever route we go in terms of next steps. And 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 the United States. And they have full information on which to make that decision at this point in time.

Operator

The next question is from Chester Dawson with the Wall Street Journal.

Chester Dawson

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

Russell K. Girling

It would've been something that we would have been monitoring. But I think as we said, our view was -- our view is that the decision -- incorrect -- and that the laws that we had made our application and had our approval under was sound, and 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.

Chester Dawson

Okay, thanks. And 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?

Russell K. Girling

Well, the way bridge solutions would work is you're going to -- basically you're going to load oil into tank cars at terminal facilities in the proximity of production locations. And 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 refineries in Canada and the United States. So there wouldn't be any sort of along the -- anything done along a pipeline corridor like 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.

Chester Dawson

But I guess what I meant was is it as a way around Keystone or are there other projects as well where you could see that demand...

Russell K. Girling

It's actually being done as we speak. As production grows, you need to move it to market and a number of projects have been delayed, not just the Keystone project. And as a result of that, rail traffic has moved up exponentially, and so I expect that to continue and the railways have the ability to accommodate more railcars, that the constraint has been in that marketplace, the availability of railcars. And what I can tell you is that railcar manufacturing facilities are chockablock full right now, delivering as many railcars as they can to the industry. So the industry is buying them or leasing them. And when I say the industry -- mostly producers and refiners are buying those railcars as quickly as possible, getting them on the tracks and what they may need is additional loading and unloading facilities, and that's probably the role that we would play in terms of adding a bridge and the likely place to put them would be at places where we already have plans for storage terminaling at the current time.

Operator

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.

David Moneta

Thanks very much. And 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.

Operator

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

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