TC Energy Corp (TRP) 2009 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2009 fourth quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Corporate Communications. Please go ahead, Mr. Moneta.

Thanks very much and good afternoon, everyone. I'd like to welcome you to TransCanada's 2009 fourth quarter conference call. With me today are Hal Kvisle, President and Chief Executive Officer, Greg Lohnes, Executive Vice President and Chief Financial Officer, Russ Girling, our Chief Operating Officer, Alex Pourbaix, President of Energy and Executive Vice President Corporate Development, and Glenn Menuz, Vice President and Controller. Hal and Greg will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com and you can find it in the investor section under the heading Conference Calls and Presentations.

Following the prepared remarks we will turn the call over to the conference coordinator for your questions and during the question-and-answer period we'll 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 any detailed questions relating to some of our smaller operations or your detailed financial models, Myles, Terry and I would be pleased to discuss them with you following the call.

Before Hal 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 reports filed by TransCanada, Canadian Securities Regulators and with the US Securities and Exchange Commission.

And, finally I'd also like to point out that during this presentation we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA, comparable EBITDA and funds generated from operations. These 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 measured presented by other entities and these measures are used to provide you with additional information on TransCanada's operating performance, liquidity and it's ability to generate funds to finance it's operations. And with that I'll now turn the call over to Hal.

Thanks, David. Good afternoon, everyone and thank you for joining us today. As outlined in today's news release, TransCanada's net income for the year-ending December 31, 2009, was CAD1.4 billion or CAD2.11 per share. Comparable earnings were CAD1.3 billion or CAD2.03 per share and our funds generated from operations were CAD3.1 billion in 2009. Comparable EBITDA was CAD4.1 billion and funds generated from operations as I said were just at CAD3.1 billion.

Our 2009 financial results highlight our ability to generate strong earnings and cash flow from a diverse portfolio of North American energy infrastructure assets. In 2009, we invested approximately CAD6.3 billion in growth initiatives in assets that will provide our Company with long term value for shareholders.

Turning now to the dividend. We are confident that our CAD22 billion capital program will lead to significant growth in cash flow and earnings over the next five years, as a number of attractive low risk projects are placed into service. This has enabled our Board of Directors to increase the quarterly dividend on the company's common shares by over 5% to CAD0.40 per share per quarter. On an annualized basis this equates to CAD1.60 per share. This is the tenth consecutive year the Board has raised the dividend and represents more than a 7% compound annual growth rate in the dividend over that period.

We continued to make significant progress on a number of our growth initiatives in the fourth quarter. I'd like to discuss those in more detail starting on slide eight in our fourth quarter investor presentation.

Firstly, construction of Keystone Phase I to Wood River in Patoka, Illinois is now substantially complete. Over the past 18 months, a workforce that at one point totaled 8,500 men and women worked more than 20 million hours to get the job done. During that time, we installed approximately 2000-kilometers of new 30-inch diameter pipe. We converted almost 900-kilometers of existing natural gas pipeline to oil service and we constructed 39 new pump stations. As a result, we were able to start commissioning the first phase of Keystone in late 2009, as expected, and this stage will continue through the second quarter of 2010. During this time, shippers will provide approximately 9 million-barrels of oil to Keystone in order to complete line filling. We now expect commercial in-service to begin in mid-2010.

In this first year of operation, as we ramp up the operational capability of the system, Keystone will move contracted volumes of 217,500 barrels per day with the potential to move additional spot volumes.

Construction on Phase II of Keystone which comprises an extension of the system from Steel City, Nebraska to Cushing, Oklahoma, will commence in the second quarter of this year. Keystone is currently seeking necessary regulatory approvals in Canada and the United States to build and operate a large expansion and extension of the pipeline system that will provide additional capacity of 500,000 barrels per day from Western Canada to the Gulf Coast with that coming on stream in late 2012 or early 2013.

In September 2009, the National Energy Board held a hearing to review the application for the Canadian portion of that Keystone Gulf Coast expansion. We expect the NEB's decision in the first quarter of 2010. Permits for the US portion of the Keystone Gulf Coast expansion are expected by the fourth quarter of 2010. Construction of the expansion is expected to begin in 2011 following TransCanada's receipt of all those necessary regulatory approvals. The highly contracted nature of the Keystone system at 83% of capacity or 910,000 barrels per day, for an average of 18 years, clearly demonstrates the strong need for the pipeline and Keystone's value and usefulness to both Alberta producers and US refiners.

Turning to our Natural Gas Transmission business, TransCanada and Exxon-Mobile continue to advance the Alaska pipeline project by filing the open season plan in January of this year with the US Federal Energy Regulatory Commission. That filing was made to obtain approval to conduct the first natural gas pipeline open season ever to develop Alaska's vast natural gas resources. If FERC approves the own season plan, the project will commence the open season process in April of 2010.

Here in Western Canada, the Ground Birch pipeline public hearing process with the NEB concluded in November 2009, a decision from the NEB is expected in February 2010, this month, with construction commencing in July of this year, and in-service expected in November 2010. Ground Birch has 1.1 Bcf per day of secure firm transportation contracts that will connect natural gas supply primarily from the Montney Shale Gas Formation in Northeast BC to TransCanada's existing infrastructure in Northwest Alberta.

To the North of Ground Birch, the Horn River pipeline contractual commitments have now risen to 503 million cubic feet per day, further increasing natural gas supply from the Horn River Shale Gas Formation. TransCanada filed an application in February with the NEB for approval to construct and operate the Horn River pipeline in the first quarter of 2010. The Horn River project is anticipated to be placed in service in the second quarter of 2012.

Work also continues on our Northcentral corridor pipeline in Alberta. The first phase of this project is now complete and the second phase is expected to be complete by April 2010. Northcentral corridor will provide capacity needed to deal with increased natural gas supply in Northwest Alberta and in the shale plays of Northeast BC. It will also address declining natural gas supply in Northeast Alberta. It will serve growing markets within the province and it will help deliver more gas to the Alberta Saskatchewan export point.

In Mexico, regulatory approvals were reached in December of 2009 for the Guadalajara natural gas pipeline project and construction is underway with an anticipated in-service date in the first quarter of 2011. The pipelines 25 year take or pay contract and an expected double digit unlevered internal rate of return are a perfect fit for TransCanada as a secure cash flow generating energy infrastructure asset. We will continue to look for further opportunities to expand our Mexican presence in the future.

Finally, in pipelines, our Bison Natural Gas pipeline project is expected to commence construction in May of this year with an expected in-service date of the fourth quarter of 2010. Bison is a good example of our strategy to commercially develop new asset investments and it's also a good example of how we continue to maximize the full-life value of our existing infrastructure. The accompanying long-term downstream contracts our Bison shippers have paid in our northern border pipeline serve to further diversify and stabilize Northern Border's cash flow in the years ahead.

Turning now to our Energy business. Construction of the 683-megawatt Holton Hills Generating Station in the Greater Toronto area of Ontario is continuing on schedule and the facility is anticipated to be in service in the third quarter of 2010. The 575-megawatt Coolidge Generating Station in Arizona is also continuing on schedule with an expected in-service date of the second quarter of 2011.

In our Wind Power business, TransCanada placed the first phase of Kibby Wind in service in October, which includes 22 turbines capable of producing 66-megawatts of power. Construction continues on the 66-megawatt second phase and we expect that to be in service in the third quarter of 2010.

At our Cache Wind Project in Quebec, brush clearing work for the 58-megawatt Montagne Seche Wind Farm and the first phase of the 212-megawatt [Girel] Morn Wind Farm was completed in the first quarter of 2009. These two wind farm projects in Quebec are expected to be operational in 2011. Girel Morn Phase II is thereafter expected to be operating in 2012.

At the Bruce Nuclear Facility, progress continues on the refurbishment and restart of Bruce A Units 1 & 2, with a focus on the reassembly of the reactors and other related activities. The bulk of the highly technical, high risk work is now finished or is very near completion. Although a significant amount of work remains, most of this remaining work is conventional power plant construction activity. We expect that Unit 2 will be restarted in mid-2011 with Unit 1 expected to follow approximately four months later. Bruce Power continues to advance an initiative to further extend the operating lives of Units 3 and 4. Unit 4 is now expected to continue to operate beyond 2018 and plans are in place to implement an extensive maintenance program that could see the life of Unit 3 extended for a similar period of time.

In summary, we continue to build our competitive position in our three core businesses of Natural Gas Transmission and Storage, Oil Transmission, and Power Generation. We have now invested approximately CAD10 billion or almost 50% of our CAD22 billion growth program in large-scale multi-year projects such as the Keystone Oil Pipeline, the Alberta Systems Northcentral Corridor Expansion, the Bruce refurbishment project and the construction of many large-scale gas-fired power plants.

There is significant long term visible growth of TransCanada with these CAD22 billion of commercially secured projects now in construction and an additional CAD60 billion of capital opportunities in development. Between 2009 and 2013, we estimate we will achieve a 12% compound annual growth rate in EBITDA and a 10% compound annual growth rate in funds generated from operations. This will drive significant growth in earnings, cash flow, and dividends per share, all leading to a superior total shareholder return in the years ahead.

I will now turn the call over to Greg Lohnes, our Chief Financial Officer, who will provide additional comments on our fourth quarter financial results. Greg?

Thanks, Hal. Good afternoon, everyone. As Hal mentioned earlier today, we released our fourth quarter results. We also expect to file our 2009 Annual Report to shareholders tomorrow, which contains the consolidated financial statements and accompanying notes for the year-ended December 31, 2009, as well as the related management discussion and analysis.

Starting with slide 14, comparable earnings in the fourth quarter were CAD328 million or CAD0.48 per share, compared to CAD271 million or CAD0.42 per share for the same period in 2008. The primary reason for the CAD57 million increase in the fourth quarter comparable earnings is lower interest expense from increased capitalization of interest related to TransCanada's large capital growth program. 2009 comparable earnings were CAD1.325 billion, a CAD46 million increase over the 2008 comparable earnings.

On a per share basis comparable earnings of CAD2.03 in 2009, a decrease compared to 2008 by the dilutive impact of a 14% increase in the average number of shares outstanding as a result of common share issuances in the second quarter 2009 and fourth quarter 2008. The proceeds of the share issues were partially used to fund our CAD22 billion capital program including the acquisition of additional interest in Keystone and other capital projects. As a result of pre-funding during these liquidity concerns that existed early in 2009, the carrying cost and earnings per share dilution associated with our prudent approach to financing is multi-year program will continue to have a near term impact on our earnings and cash flow per share. That being said, each project is expected to generate significant long-term earnings and cash flow as they commence operations.

I will now briefly review the fourth quarter results for each of our business segments at the EBITDA level, beginning with Pipelines on slide 15. The Pipelines business generated comparable EBITDA of CAD745 million during the fourth quarter 2009, a decrease of CAD35 million over the same period in 2008. The decrease is primarily due to the negative impact of a weaker US dollar on US pipelines results and increased business development costs related to the Alaska pipeline project, partially offset by higher earnings from the Alberta system.

Before I turn to Energy results. I'd like to make a few comments on our Keystone Oil project. As Hal said, commercial operations are now expected to begin in mid-2010. Although TransCanada expects to begin generating cash flow from Keystone in mid-2010, we will continue to capitalize the related interest cost and EBITDA until we're through the commissioning period and the facilities are capable of running at the full commercial design nominal capacity of 435,000 barrels per day. The decrease from previously discussed EBITDA amounts will be largely offset by the continuation of interest during construction. Based on current long-term commitments ramping up to 910,000 barrels per day between 2010 and 2013, we expect Keystone to generate EBITDA of approximately US $1.2 billion in 2013, its first full year of commercial operations. If volumes were to increase from the current contracted amount of 910,000 barrels per day to the full commercial design of the system of 1.1 million-barrels per day, Keystone would generate annual EBITDA of approximately US $1.5 billion.

Next, some comments on our Energy results on slide 16. Energy generated comparable EBITDA of CAD248 million in the fourth quarter 2009 compared to CAD297 million in the same period last year. The decrease is primarily due to lower power prices in Western Power and US Power and reduced volumes in Western Power and Bruce Power. These decreases were partially offset by incremental EBITDA from the start-up of Portland's Energy Center, which went into service in April 2009. Energy's EBITDA also reflects a higher contribution from the natural gas storage business due to increased third party storage revenues as a result of higher realized seasonal natural gas price spreads.

Now, looking at slide 17. I'd like to take a few minutes to talk about our highly contracted Energy business and how we use hedging strategies where we have exposure to spot power prices. 100% of Eastern Power sales were sold under contract in the fourth quarter and are expected to be sold under long term contract in 2010 and beyond. 100% of the output from Bruce A in the fourth quarter was sold at a fixed price. All of the output for Bruce B is subject to a floor price. Both the fixed price received at Bruce A and the floor price at Bruce B are adjusted annually for inflation on April 1.

77% of Western Power sales volumes were sold under contract in fourth quarter 2009 compared to 68% in fourth quarter 2008. At December 31, Western Power had fixed sales power contracts for 8,400-gigawatt hours or approximately 55% of planned sales for 2010 and 6,000-gigawatt hours or approximately 40% of planned sales for 2011. And finally, US Power has entered fixed price power sales contracts to sell forward approximately 10,300-gigawatt hours for 2010 and 5,400-gigawatt hours for 2011.

Turning now, to the Corporate segment results on slide 18. Corporate EBITDA in the fourth quarter 2009 was a loss of CAD28 million compared to a loss of CAD33 million for the same period last year. Overall in 2009, Corporate costs were higher primarily due to higher (inaudible) costs reflecting a growing asset base.

Now, I'm looking at items below EBIT on the income statement on slide 19. The fourth quarter 2009 interest expense of CAD184 million is a decrease of CAD142 million compared to fourth quarter last year. The decrease in interest expense reflects increased capitalization of interest to finance TransCanada's larger capital spending program in 2009, primarily due to Keystone construction. The lower interest expense is also a result of a decrease in US dollar denominated interest expense due to a weaker US dollar, as well as improved fair value adjustments on interest rate derivatives.

Interest income and other increased CAD26 million compared to fourth quarter 2008, primarily due to higher gains from foreign exchange management and translation of US working capital balances. Income taxes were CAD67 million in the fourth quarter 2009 compared to CAD95 million for the same period in 2008. The decrease was primarily due to positive tax adjustments in the fourth quarter 2009, including CAD30 million resulting from a reduction in Province of Ontario corporate tax rates, partially offset by taxes resulting from higher income.

Turning to cash flow on slide 20. Funds from operations were CAD850 million in the fourth quarter 2009 compared to CAD712 million in the fourth quarter 2008. Capital expenditures in the fourth quarter 2009 of approximately CAD1.5 billion related primarily to a number of growth opportunities, including construction progress on Keystone and other capital projects.

Now, looking at slide 21. At the end of the fourth quarter 2009, our balance sheet consisted of 50% debt, 3% junior-subordinated notes, 3% preferred shares and 44% (inaudible) equity. We have an A-grade credit rating with a stable outlook. Our working relationships with all three credit rating agencies are strong.

In 2009, we raised approximately CAD6 billion of debt and equity capital at favorable rates during turbulent times in the economy. At the end of 2009, we had CAD1 billion of cash on hand along with committed revolving bank lines of CAD4.3 billion. In December, TransCanada pipeline's limited filed a US CAD4 billion debt shelf prospectus giving the Company CAD6 billion of total debt shelf availability.

Now, turning to slide 22. Looking forward to 2010 and 2011, we expect to invest approximately CAD11 billion over this two-year period. The first source of funding will be our strong internally generated cash flow after dividends, which is expected to total approximately CAD5 billion over the two-year period.

Our dividend reinvestment plan is expected to contribute an additional CAD725 million over the same timeframe, assuming a historic participation rate of approximately 30%. The common equity we raised through the dividend reinvestment plan along with retained earnings means we have the capacity to issue an additional CAD3 billion of term debt over the two-year period without materially changing our consolidated capital structure. That leaves us with remaining needs of approximately CAD1.5 to CAD2 billion over the two-year period that we expect will be met through various forms of subordinated capital. We expect to raise additional subordinated capital using hybrid securities, preferred shares, LP drop-downs, or portfolio management activity.

In September 2009, we raised CAD550 million in a very successful preferred share offering. That market appears to be open to us and we'll consider further preferred share issues as we move through this two-year period. In April 2007, we issued US $1 billion of junior subordinated notes that received 50% equity treatment from the rating agency. That hybrid security market closed for a while during the financial crisis, but appears to be opening up again subject to hybrid security rating agency reviews.

In July 2009 we completed the sale of our North Baja pipeline to our TC Pipelines LP and we continued to expect that the LP will play an ongoing role in our funding program. That concludes my prepared remarks.

I'll now turn the call back to David for the question-and-answer portion. David?

Thanks, Greg. Just a reminder before I turn the call over to the conference coordinator, we'll take questions from the financial community first and once we've completed that we'll turn it over to the media.

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

Thank you. (Operator Instructions) The first question is from Carl Kirst of BMO Capital. Please go ahead.

Good morning or afternoon, everybody. If I could start with Keystone, please, the timeframe seems a little bit delayed I guess, from sort of the first quarter, second quarter we were originally thinking and I guess I wanted to touch on both the EBITDA guidance that was given for Keystone 2010 prior from the Analyst Meeting, as well as Greg, I wanted to go back on your statement on the capitalized interest, I want to make sure I understood exactly what you were saying there which is I guess in short that the interest is going to continue to be capitalized until I guess that Phase I reaches full commercial operation, is that correct?

Yes, that's correct. Maybe Russ you would like to speak to timing and I'll talk to the other two questions.

On the timing front we're continuing as planned. It's not moving as quickly through the start-up phase as we had hoped. We've got about 1 million barrels in tankage right now and will commence line filling over the next week or two.

We should have the line full within about 100 or so days and then we'll be able to sort of start ramping up throughput through to the end of the year, so we're probably delayed by a few weeks here, Carl, but it's not substantial I guess from our perspective in terms of the start-up problems that we anticipated and the kinds of activities that were going on, we're moving along the track we thought we would be moving on. We set up this first year under these interim contracts as you're aware. Our long term contracts don't kick in until the beginning of next year so we kind of anticipated we would have sort of these start-up issues, but as I said we do have about 1 million barrels in tankage and we'll start linefilling in the next week or so so we're into as I said into Q2 we'll be operational.

Great.

So, just to comment on your two questions, one was EBITDA, so obviously if things move back a little bit I think at Investor Day we were looking at something in the CAD150 million range on the contracted volumes and as we finalize what the in-service date as we work through any start-up issues that will of course be pushed back a little bit and there for decrease pretty much proportionately with the change in time as we get closer to in service.

With regard to capitalized interest, until we're substantially complete and capable of running the pipeline at it's full productive capacity, we've determined that we will continue to capitalize the interest and that will largely offset any reduced EBITDA over that. So, for that same period where we're ramping up and there for not collecting EBITDA, we're capitalizing EBITDA and capitalizing the interest, so reducing capital expenditure with the EBITDA that's being generated during the start up.

Okay, I appreciate that clarification and I'll jump back in queue here.

Thanks, Carl.

Thank you. The next question is from Bob Hastings of Canaccord. Please go ahead.

Yes, sorry, just to stay on there for a minute, so is the net result you said we should be adjusting just by a few weeks, three weeks or something? It looked a little longer than that.

I would say that we're around probably six to eight weeks kind of outside of where we thought we were at the sort of third or fourth quarter of last year, we're probably out between six and eight weeks, something like that.

Okay, great, thank you and Greg, what are you capitalizing the interest at? What's the rate?

We capitalize it at our average long-term rate which was around 7%.

So, is that moving from quarter-to-quarter or that would have been average last year?

Well, there's a fairly large amount of debt out there so as we make additional investments or issue more debt it doesn't really move around much.

Okay. Thank you and you would be using that on all your projects beyond Keystone as well?

Yes.

All the power projects?

Yes.

That's my two questions, I'll go back, thanks.

Thank you. The next question is from Harry [Matiere] of Barclays Capital. Please go ahead.

Hi, good afternoon guys. Just looking for a sense to the extent you can provide us with more color on timing of potential financing here. I know your cash balance has been worked down from a very high level to a little under CAD1 billion and it looks like you outspent cash flow during the last quarter by roughly CAD1 billion as well, so when you think about financing plans over the next couple of quarters, do you plan to hit up your bank lines first or are you considering possible near term debt issuance?

Well, I think we've showed in the last few years that we're opportunistic and that we have our shelf prospectus' in place and we're in a position to move fairly quickly when we see windows in the market so we'll just monitor that. We do have lines in place, we put the new US CAD1 billion credit facility in place so we have the flexibility to increase those revolvers and look for the right timing on debt and then, of course, always look for the right timing on subordinated capital.

And then in terms of your capital structure, you mentioned you see room to issue about CAD3 billion of term debt without materially changing your capital structure, but how do you think about that in relation to potential hybrid security issuance as well because there is some debt component associated with that, right? Even if you have 50% equity credit there's also 50% debt associated with it?

Yes.

So, how do you think about sizing that as well?

Well, we look at the overall capital picture we can't just look at balance sheet metrics. We also have to look at our cash flow-to-interest coverage and cash flow-to-total debt, and so we look at balancing the subordinated capital with the debt. As you say, you do get 50% equity treatment on the hybrid, but it sits on your balance sheet as debt and it's US debt, which is really positive in helping us balance our US asset gap, so we look quite favorably on that type of an instrument because of the US dollar exposure, so we'll continue to monitor that.

That market -- right now we're just waiting for the rating agencies to come back and determine how they are going to treat hybrids going forward and we would expect to hear on that in the next couple months.

And during the construction period for Keystone, you're right around five times debt to EBITDA right now. Is that a number you're pretty comfortable with for the time being? You don't want to go above that during the construction buildout?

We look at it on an overall portfolio basis for the Company as we look at what our debt structure is like and we'll just be prudent as we manage the overall ratios going forward.

Okay, but there is no debt-to-EBITDA target you have?

We don't drive to a particular target for debt-to-EBITDA.

Okay, thank you very much. Thanks.

Thank you. The next question is from Matthew Akman of Macquarie. Please go ahead.

Thanks very much. Greg, I was just wondering if there's increased exposure to the US/Canadian dollar exchange rate? Obviously the US pipeline EBITDA moves down as the Canadian dollar appreciates, but interest expense moves down as well. It just looks to me like perhaps the EBITDA is moving down a little bit more than the interest expense, so what's the latest update on that?

Well, I guess when we look at the US exposures it's obviously increasing and we're over CAD12 billion of assets now in the US. So, as we've managed two exposures, one is the income exposure and the income statement and the other one is the balance sheet exposure of the asset gap. So, as the cash flow moves around -- the short-term hedging we're doing which is basically rolling month to month forward is adjusted, so we do have natural hedges for a significant portion of that and then that would be -- sort of about 80% of it is naturally hedged by interest payments, so then we have that other 20% exposure in the sort of CAD100 million range and we manage that through derivatives and we ramp those up and down as we see the EBITDA unfolding through changes in commodity prices and other impacts to our US cash flow.

So, we should not be seeing a significant earnings impact from changes in the Canadian dollar/US dollar exchange rate?

That's right. There's a bit of a lag, of course, as you're rolling, but generally we'll try and balance that out.

Okay, thanks, I just have one follow-up question which is on the Pipeline business. I don't know if you guys are going to disclose the volumes on your pipelines in the fourth quarter, but I was interested the volume on the main line in the quarter.

We'll see if we can get that for you, Matthew. In the annual we will disclose the total volumes for the year on all of our systems.

Okay.

Glenn is just looking for that so we can certainly try and follow-up with you on that.

Thank you. Those are all my questions.

Thanks, Matthew.

Thank you. The next question is from Ted Durbin of Goldman Sachs. Please go ahead.

Hi, a question for you on the New York City capacity markets with Poletti retiring -- how are you thinking about where the pricing is going there? I know you've heard maybe there might be a change to calculation for [CONE], can you just talk about that market a little bit?

Sure. So, looking at the price with Poletti off, as we had anticipated, we saw a very significant run-up in the value for capacity in Zone J for February and we would obviously expect to see that continue, moderated perhaps modestly by just very minor reductions in demand in the Zone J area.

With respect to sort of the calculation of CONE, that's an ongoing issue and all kinds of parties have lots of views on that, but we're not anticipating anything very significant or material coming out of that.

Okay, great. Thanks, and then just the next question is a little bit more big picture, but if you think about the Keystone Gulf Coast expansion and sort of in front of the NEB, you've got a tough refining environment in the US, you've got quality differentials are down, you've had some shipper complaints on the competitor pipeline, how are you thinking about the need for the pipeline? We're in a little bit of different environment than maybe when you first conceived of it?

We continue to have conversations with our shippers with respect to timing and need and as I've said before, pretty much all of the capacity that is on the Keystone expansion system has been spoken for by refiners who are replacing crudes from other locations, even though margins are down, whether we use a Canadian barrel or Venezuelan barrel, unfortunately margins are tight for them.

We feel for them on that front, but they are still moving forward with replacing those crudes with Canadian crudes, they have long-term contracts for supply and on the producer side of things, again, the volumes that we expect to be moving on the Keystone system are either flowing today or will be flowing by the time Keystone starts up and those two things are being linked together. The first phase obviously is to Wood River and Conoco Phillips is busily trying to get their refinery ready for the crude oil that's going to come. We expect that to be early in 2011 here and in the Gulf Coast the same thing is happening with our contracted customers, so from our perspective, nothing has really changed in the environment.

Actually on the positive side going forward we have seen with higher oil prices a number of projects get put back on the slate. The Totel Conoco project, the Sun Core project, the Imperial Exxon (inaudible) project, we've soon a number of things move forward in this environment over and above what we saw at the end of or sort of middle of 2009 when the market sort of totally moved downward. So, I'd say that we're optimistic and nothing has really changed on our front with respect to movements of crude and the utilization that we expect to get out of the expansion in the Gulf Coast. Longer term, there will be excess production in Canada and we need to move that production to a new market and the logical market to move that crude to is the Gulf Coast.

Okay, great. Thanks very much.

Thank you.

Thank you. The next question is from Robert Kwan of RBC Capital Markets. Please go ahead.

Good afternoon. Just coming back to Keystone to make sure I'm clear, the modest pushback in the start-up, that just impacts the interim contracts? There's no impact on the guidance you gave for 2011 with the fall contract that is coming into place?

I think as long as everything goes as planned and we get to full operations towards the end of the year, then those long term contracts will kick in and EBITDA will move up into that CAD6 million to CAD700 million range.

And if I could just ask about western power on the Alberta hedge side, you're pretty close to where you historically would be hedge for the current year. As you look out to 2011, if the curve stays down where it is, which really isn't that different from where the spot price is, should we be expecting to add any hedges or are you just happy to keep the exposure high going into 2011 with the hedge level that you've got right now?

When I look at the forwards in the Alberta market and I think that's what you're getting at, I market and I think that's what you're getting at, I look at these prices as unsustainable in the medium to long term so from the incentive to add more hedges, we'll always consider contracting forward a month or two and if we saw attractive opportunities longer term, we would consider that, but we probably are not as motivated to be selling a lot of power forward at these very low prices right now.

Would you consider buying back any of your hedges?

Yes. We would definitely consider that. I think particularly I'd be, I think it is possible that 2009 could remain reasonably depressed, but 2010 and 2011, we actually hit an all-time peak demand in Alberta over the winter and we haven't added a lot of generation capabilities so when I look at those forward prices for 2011 and 2012, those look to me like they're pretty attractive levels.

Great. Thanks Russ. Thanks Hal.

Thanks.

Thank you. The next question is from Andrew Kuske of Credit Suisse.

Thank you. Good afternoon. More of a big picture question for Hal, and really when you look out beyond 2012 and you've done really the lions share and the bulk of your CapEx program and you look across the North American map, you've got a pretty big footprint as it is, but do you really look around and think you're lacking a geographic footprint in a specific area or business line that you'd like to add when you look out over a period of time?

Well, Andrew, I don't think we would see that we're lacking anything. It's more a question of where would we see significant opportunity to grow. We think that the Northern buildout potential around our existing Alberta system bringing more gas into the Alberta hub is pretty attractive both for our Company and the market longer term.

I know everybody is very excited about shale gas these days and we're certainly well positioned for that with Ground Birch, Montney and Horn River, so I expect we'll continue to invest fairly significantly to bring more of that volume into the system, but we also remain enthused about the Alaska and McKenzie projects.

The challenge for North American producers replacing annual decline is a huge challenge. We essentially reinvent the gas producing side of the business every five years. Most of the gas on production today will be gone five years from now and so we see the industry continually moving around, figuring out ways to replace that decline and we do believe in the coming decade that both McKenzie and Alaska will be part of that, so those are pretty big opportunities for us.

Right now what we need to do is proceed cautiously, not spend money that can be deferred until later and try to keep those two projects moving forward at reasonable cost and we're comfortable with the way that's going.

On the oil side, our whole strategy is focused around the oil sands and we believe that oil sands will be an attractive source of supply throughout North America. Today, there are some concerns about the so-called dirty oil issue. We think as the facts get out about the relative dirtiness or non-dirtiness of oil sands versus any other oil, we think that there will be a greater appreciation for the benefits of supply within the continent here and we look forward to moving more of that oil sands production to North American Markets, possibly to offshore markets, but we just think the North American market is the best market for oil in the world and that's the one that we're focused on.

Power Gen, it's a very big business and we have about approaching 12,000-megawatts right now which makes us a good mid-size player, but there's lots of room for us to grow two or three times beyond that. The largest players in North America would be roughly at the 50,000-megawatt generating size and we would see some good running room for us to grow in a number of those areas. So, I think a good case to be made for sticking to the core strategies in gas transmission, gas storage, oil pipelining, power generation and looking in power at further growth in wind and high voltage transmission. Those would be the areas that I think we're focused on for the decade ahead.

And if I may just ask a follow-up, a bit more precise, as it relates to northern natural gas since it's specifically in relation to Alaska, just give us a little bit of color around the relationship with Exxon? They just have an unbelievable amount of resources as far as people, financial resources, et cetera, and how do you manage the relationship in dealing with them on a project which they could put on the back burner or accelerate at any point in time?

So, like Alaska is a huge project and it would be a very difficult thing if we didn't have a well understood and constructive relationship with Exxon. That is not a relationship that came together overnight. We worked with Exxon for six or seven, eight years on the McKenzie project. We've developed our understanding of each others ways of doing things with the work that we've done on McKenzie and with the very challenging regulatory things that we've had to deal with on McKenzie.

I'd characterize it as Exxon and TransCanada are two companies that have great respect for each other. We bring a lot of experience and some very current hands-on experience in the construction of large diameter pipelines. The North central corridor project in Alberta, 330-kilometers roughly, a 42-inch diameter pipe, that is a challenging winter construction project, probably the closest analogy to building on the Alaska right -way that you'd find anywhere in North America today and we've had great result there.

The TransCanada team has brought that very large project in under budget, significantly under budget and ahead of schedule, so those are the kind of things that we bring to the partnership. Exxon-Mobile is contributing a lot to the gas processing plant design side and we've never put ourselves out as the leading partner on the process plant side. They're very much in the lead there but it's a project that we're pursuing together. We think Exxon is the best possible partner for that project. They're the largest holder of gas reserves on the North slope and they are the operator of Point Thompson, which is going to be a pivotal field in the whole bringing of Alaska accounts to market business so, so far so good, but it's a big project.

Thank you. That's helpful.

Thanks.

Thank you. The next question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thank you. I guess maybe I'll start with a Power question. Volumes were down a little bit in Alberta which I guess isn't surprising given the environment there, but when do you expect those volumes to pick up in terms of sales and are you seeing any volume decreases along other parts of your business?

Linda, it's Alex. It's interesting. Volumes were down to some degree, a very modest degree I guess you could call it, some demand impacts, but I think a lot more of it was availability in bidding behavior with respect to the assets. We've already seen -- demand in Alberta appears to be for the most part recovered, so that isn't an ongoing issue for us. Obviously, I think other jurisdictions are taking a little bit longer to recover, but we don't see Alberta demand as a significant problem. We are going to lose one of Alberta's coal plants is scheduled to shut down on March 31 which I think will further sort of sop up any sort of supply demand sloppiness that's going on there.

Okay, and I guess across your other businesses, I guess we'll see some of the pipeline volumes in your annual tomorrow, but can you maybe comment on that just broadly if there was any declines in volumes even in your Canadian pipes which aren't affected by volumes?

So, I think on the Canadian side our fourth quarter volumes will be down year-over-year as they've been sort of all year, so fourth quarter I don't think will be any change from that. That's impacted through-put on our US deliveries out of Canada. Probably, most impacted would be Northern Border, but volumes have shifted around based on sort of market demand. GTN was actually -- flowed a lot of volume in the fourth quarter.

Great Lakes was about close to where we were last year, maybe down just slightly, so most of it emanates from the decline we've talked about before and in the Western Sedimentary Basin, and we didn't see any increase in supply in the fourth quarter that would have offset that so I think you can take a look at what happened in the third quarter and it would be approximately the same.

Okay.

I think, Linda, it's Hal, I'd add that we have seen drilling rig utilization pick up. We have seen a lot of activity in the shales that sort of underscores or corroborates what people were predicting a year ago and we are hopefully going to see some positive changes in the Alberta royalty regime.

We're certainly seeing land sales in Alberta pick up quite dramatically as people start poking around in Alberta looking for shale along the lines of Horn River and Montney although probably on a smaller scale. So, I think there are some very encouraging signs in the sort of two to three to five year outlook, but we do anticipate continuing low through-puts and continuing difficulties in the toll for the next couple of years. Beyond that we think we do see the Western Canada Basin stabilizing as shale starts to backfill some of the decline on the conventional side.

Linda, it's Glenn, just to provide a couple of those numbers and as we said they will be published in our annual MD&A. On the main line we're looking at 2,030 Bcf for the year, which is just down slightly from the 2,173 Bcf last year and that puts about 469 Bcf in the quarter. Alberta, we're looking at 3,538 Bcf for the year or 886 Bcf for the quarter, A&R 1,575 Bcf for the year or 376 Bcf for the quarter and those are obviously the three biggest.

Okay, that's great, thank you. Now just a clean up question on your expense side, there was mention of a drop in your Bruce fleet expenses. What was the order of magnitude for that and for how long?

It reflects an adjustment for the year. It's Glenn here. It reflects an adjustment for the year. I don't think we're in a position of giving out exact numbers, but it represents approximately CAD0.02.

And it's likely a one-time item.

Yes, it depends on as we've disclosed, it's based on the annual spot price in Ontario versus the threshold amount in the contract so we would look at that each year, but this reflects for 2009.

Okay, and then another expense you have is your Alaska development expenses. How much will be reimbursed versus what you're expensing and what sort of run-rate might we expect for the next couple years for that expense line?

I would say that what you're seeing in terms of expense for the year is our share so none of that would be reimbursable. We expect to probably spend an amount close to that in 2010 and then I would see the number post 2010, dependent upon what happens in the open season outcome.

As we've said before, our cost sharing mechanism with the state at the current time is 50% for the project and 50% for the state and once we get to the end of the open season that changes to 90% state, 10% the project, and within the project we're sharing those costs with Exxon-Mobile, so I think 2010 you can expect to see a number that's approximately the same. I really can't say at this point in time what 2011 looks like until after we see the open season results and once we know what that looks like and where the project is going we'll share with you what the expenses are beyond that.

And just to clarify the amount we have expenses, Russ, that is our share, but that is net of any recoveries or expected recoveries.

Thank you.

Thanks, Linda.

Thank you. The next question is from Pierre Lacroix from Desjardins Securities. Please go ahead.

Yes, thanks very much. Just a question on Bruce. You keep doing the refurbishment of Unit 3 and 4 and now you're talking about 2018. Can you maybe give us some perspective on what kind of production profile and expense that you will need to do in 2012, 2015 period in order to reach that goal?

Sure, I'll try to give some color on that. There isn't significant work that is required to be done in terms of capital on Unit 4. Unit 3, in order to get that extended life, we're going to take two relatively significant outages. The first outage might already be taking place, but it's about an eight-week outage and it was commencing right around now and there was one more outage that will be done in 2011, which is about 110-day out age and there is some capital associated with it, but we're not talking in the CAD100 million range. This is mostly labor that's required and at the end of those two outages it's our expectation that Unit 3 should be put in a position where it can operate safely until the end of 2018.

All right, so it means that what we can see right now in terms of plant availability for Bruce A is it something that you'll be able to maintain through 2010 and 11?

I think if -- I'm going from memory here, but I think that we're probably going to do as well or better on overall availability for the A units in 2010 and obviously it would be slightly worse because of the longer outage in 2011. But, those two outage numbers are good numbers for you to think about, eight weeks and 110 days for the second one.

All right, great. Thank you very much.

Okay.

Thank you.

Thank you. The next question is from Craig Sheer from [Toy] Brothers. Please go ahead.

Hi, I think during the Q&A, you had mentioned that you could possibly see over time increasing two or three times your megawatts in the IPP space. I wonder if you can comment about the regions in North America or elsewhere and the fuel types that might be of greatest interest to you and whether you've kind of be thinking about individual assets or considering a more rapid kind of corporate level M&A to achieve that scale?

Sure. It's Hal here. My comment was really around the five to ten year outlook for the Company -- over the past 10 years, we've built a 12,000-megawatt power business essentially from scratch. We did have about a 500-megawatt position back then held through our power LP, but we've divested that to other people. So, if you could think about it we've grown from under 500-megawatts to almost 12,000-megawatts in a decade and I think we could replicate that kind of growth in the years ahead.

I did mention that the largest power companies in North America have about 50,000-megawatts, so I was providing that number as the upside target that we might get to.

When we look at different kinds of megawatts, the thing that we're always interested is where does it sit on the cost curve and how fundamentally attractive is it in the market in which we operate and even when we build contracted plants under low-risk contracts to TransCanada, we still like to build plants that are fundamentally very attractive and so a good example is the Portland's Energy Center in Toronto which serves a really vital need in the urban core of Toronto and we would expect that plant to run very well, whether it's covered by contracts or not.

Of course, it is covered by contracts for the first 20 years under our deal with the OPA, so when it comes to gas-fired plants we like to build essential infrastructure that's covered by those long-term contracts. When it comes to other forms of base load power, obviously we're interested nuclear.

We're one of North Americas most successful wind developers. We look at a number of gas peaking operations like you're seeing Indiana the Coolidge market down in Arizona.

In terms of regions, Ontario, Quebec, New York, New England is a region that has received the bulk of our power investment in the last few years and we expect that will continue. That's a very large market reach on both the Canadian and US sides of the border. We like the desert states, Arizona and the states adjacent to it, Nevada, and we would continue to look at opportunities there, including the high voltage DC opportunity that you'll see in our Zephyr project. So, those are the regions.

Of course, Alberta is an important market to us, but we've got a pretty big position here in Alberta and we don't want to overgrow the market, so we would certainly look at opportunities here, but I think it's the Eastern Canadian, Northeast US, and possibly a few other market regions in the US where you'll see us grow.

Acquisition opportunities are always interesting to us, but at this particular time we're very focused on completing the buildout of our multibillion dollar program in the Power Gen space and notably completing the refurbishment at Bruce Nuclear. Those would be our priorities to date.

Did you see a meaningful number of retirements of coal-fired generation in North America providing opportunity for the market?

I've been very involved in discussions relating to carbon dioxide emissions and the negotiations leading up to the Copenhagen Summit and my personal view is that the coal-fired plants will by and large continue to run to the end of their normal life and then people will face a tough question, do they spend money to refurbish or extend the life of a coal-fired plant or do they shut it down at that point and replace it with something else.

I think that's the question that power companies are going to face that regulators are going to face and that the various agencies focused on CO2 are going to have to face. One thing we know for sure is that the alternatives are probably going to be a lot more expensive than running an existing coal plant and in some ways that's where we see the opportunity for TransCanada. We're not a large coal operator. We hold significant coal-fired output entitlements here in Alberta, but we're not a large operator of coal plants. We don't operate in any at all to be perfectly clear and so we see all of this as an interesting situation going forward.

Thank you.

Thanks.

Thank you. The next question is from Stephen Paget from FirstEnergy. Please go ahead.

Good afternoon. My first question regarding Great Lakes is a subject of our FERC hearing if you could comment on that particularly as it seems that going to Southcentral Ontario via the Canadian main line and Great Lakes is roughly the same price, so that would seem to indicate that Great Lakes is relatively competing against the main line, but that has implications for the ROE which is the angle FERC is taking in saying that the ROE is a difficult, so if you could comment on the status of the hearing that would be great, or investigation?

It's basically that FERC initiated a Section 5 Rate Case and their stated reason for doing it was that it appeared the pipeline was making excess returns because on the FERC Form 2, which is the accounting reporting, it appeared that we were basically making a return that was in excess of 20%. The first step in the process for us is to file our cost of revenue study and we did that in the last couple weeks and I think that our costs, as you can probably see in that study, are justified and don't lead you to the conclusion that we're making excess returns. The FERC has yet to respond to that filing, but that would be the next step is the FERC then responds to that filing, puts in place what's called top sheet, which is is really in my view the start of the negotiation process.

Where we would like to go with the process is to negotiate a settlement with our shippers and that has already begun, our discussions have already begun. As I said the goal posts have to get set out there in the marketplace, one being our cost and revenue study and the second is the FERC's position and from there the parties can start a negotiation process.

I believe and this is just my opinion but I believe the FERC is encouraging a rate settlement or a negotiated settlement as opposed to a litigated outcome as well. I think that process has worked well in the past whereby shippers and the pipeline companies get together and settle on things like rates and terms and conditions as opposed to moving to a full-blown litigation and that's where we're focused right now. So, that's about all I can tell you Steve is we want to get a settlement done, but we have to get sort of the preliminary work out way first.

Thank you for that Russ. My next question is for Alex and just looking at US coal generation there's about 50-60 gigawatts that is pretty small coal, at 250-megawatts or lower and greater than 30 years old, but most of it seems to be located East of the Mississippi River and I'm wondering how attractive could it be for TransCanada to replace some of that old small coal out there?

We would think that opportunity would be very attractive. I think we have developed a great deal of expertise in building large scale gas-fired power plants and I think most of that coal that gets retired in the Eastern US, although people are always interested renewables, I think overwhelmingly the bulk of that generation is going to be replaced by gas-fired generation and we are seeing a lot of utilities have been moving down the path of RFPs, kind of not dissimilar to the kind of structure you see in Ontario. So, to the extent that there was an opportunity for us to use that expertise and that competitive advantage and back it up with long term contracts, I think we would be quite interested in those opportunities, Stephen.

Great, thank you. Those are my questions.

Thanks, Stephen.

Thank you. The next question is from Carl Kirst from BMO Capital. Please go ahead.

Thank you. Just a clean up question if I could. It looked like the Bruce B forward-hedging levels were a little bit lower than what was discussed on last quarter and I guess I just wanted to confirm that and if that is the case, if we did have a decline in 2010 and 2011 or even as positions monetized or what happened there?

Some of those contracts were just rolling off at the end of their term, Carl. I think we have considered buying some of those back, but I don't believe we've done so in a material manner at this point.

Okay. And then maybe just a follow-up with respect to some of the comments that were made about the Alberta volumes and the tariff, obviously a difficult situation over the next two years, but with what was sort of struck here at the end of December getting some of the underage put -- what was in effect into rate base, is that kind of the model that if there are stresses on the system that is generally going to be followed over the next two years?

We'll have to negotiate that with our shippers, Carl, but I think that the tools we use to achieve a settlement with our shippers for the 2010 totals will be similar to going forward. I think obviously we'll do a more detailed approach. What we've told the industry is that we would move to get them a proposal by the end of the first quarter and then we would look to negotiate with them over the next four or five months with the hope of having something in a filing position by the end of Q3 and into Q4 for approval and for 2011.

Now that might be just for 2011, it might be for 2011 and 2012 and part of it will be based on what peoples forecasts of throughput are going to be and as Hal mentioned earlier we see a fair bit of optimism around the Western Sedimentary Basin here recently with land sales and as you saw the contracted level that we have put in place for Horn River went up in the fourth quarter.

Now those volumes won't come on until later, but obviously those will be factors that impact where we set our totals for those years, but generally speaking I think what we would like to do is to find a way that we can smooth our way through to the time where we see volumes starting to come back on the system and I think that's generally what our shippers are looking forward to as well. But, as I said, that negotiation will get under way as we put our proposal out at the end of the quarter and then you'll spend the time with our shippers discussing the various aspects of that proposal that they can stick and those that they don't think can stick.

And as far as the specific numbers go that are disclosed we'll take a look at that.

Great. Thanks, everyone.

Thank you.

Thank you. The next question is from Petro Panarites from CIBC. Please go ahead.

Thank you. My question is for Alex. Beyond the closure of Poletti, what are you seeing in terms of capacity additions to the New York market over the next several years?

There is one project which is a 300-megawatt project associated with the Lindon Power Plant. It basically is just an inter -- the Liendon Power Plant is in the PJM market, but connected electrically to the Zone J market and what they've done is they have reconfigured or rebuilt the transmission between the two nodes and we think that will bring in about 300 more megawatts. We actually thought it would be in by now, we thought it would come in in November. We haven't seen it show up. We would probably expect it some time over the next six months into Zone J. That's something that we had in mind at the time we acquired Ravenswood.

There's another cable project and we can get, sorry, the Hudson cable project and my recollection is that was another one that we had assumed was coming in and that seems to be a project that continues to be delayed sort of quarter-by-quarter, so I don't see that coming in any time in short order, but if that one comes in, that would be about another 300-megawatts and as far as I can see I think that's it for material capacity additions for Zone J.

So, the changes in capacity rates are whatever might come on in terms of new supply, is anything there attractive enough to entice you to pursue greater expansion at Ravenswood or any updates on your expansion plans there?

Yes, we've continued to advance our expansion thoughts at Ravenswood. We're in the middle of doing a study to determine exactly what the options are in terms of capacity additions on the site. Sort of the pros and cons of various options, but we do think there are some interesting, there's a couple of interesting shorter term opportunities we have that have to do with dealing with this A house facility, which is a lease facility we have with Con Ed on site and it actually is a steam plant that sends steam across the river to Con Ed and we think there's probably a shorter term opportunity to do a deal where our Unit 40 combined gas plant actually produces that waste, heat and steam. So, we think there's an incremental opportunity there and then we do think there are longer term opportunities either to put in place peaking or combined cycle opportunities on the Ravenswood site and that would probably, once again, kind of be in the sort of two to five year time frame that we see those opportunities arising.

Thank you.

Thank you. The next question is from Bob Hastings of Canaccord. Please go ahead.

Yes, since you started Kibby, we've seen some PPAs actually signed in that market from the local utilities. Wondering as that market transitions whether you've been able to contract it up or if you have that opportunity what you're going to do there?

Yes, Bob, we've sold a significant amount of the RECs forward already to the utilities at quite attractive rates and we have sold, I think we're probably around 30% of the energy we've sold over longer term power purchase agreements to local utilities, so that is definitely within our intention, but so far, we're quite happy with the contracting we've been able to do and particularly with respect to the RECs.

So, there's nothing more that you can do at this point?

No, I think we will keep marketing, particularly as I said, the RECs, there is a really robust market in New England for the Renewable Energy Credits and they frankly, more liquid right now than the energy market, so that is an area that we're going to really pursue with respect to the expansion of Kibby, but we will also -- our goal would be to knock down some of that merchant capacity with PPAs over the next year or so.

So, can you give us some details or some kind of guidance on how many or what proportion of the RECs have been sold and kind of pricing or anything like that?

Yes, I mean, I won't tell you what we sold them at but what I would say is that the prices for RECs in that market have kind of been anywhere from sort of CAD20.00 to around CAD50.00 a megawatt hour and we've sold them in that range. Sorry, was that helpful?

Well, just as a proportion, have you sold half?

Sorry, yes, I think we're probably at around 50% or 60%.

Thanks, and moving back to Alberta and I apologize, I got called aside for a second, but I may have missed this, but Alberta demand was I guess flattish in the fourth quarter, you mentioned it might have been down, but and I notice that some of your coal-fired capacity you've been buying was down 11% in the quarter, can you go through that a little bit?

I think a lot of that is availability from the operator, some of it would be offer strategy and just related to demand in the market in Power prices. Nothing really material that would be behind that reduction.

Okay. But, there's no, it's not 11%, that stuff should have been, I would assume, is always profitable in that market wasn't it? Yes. Yes. Okay, thank you very much.

Thanks, Bob.

Thank you. (Operator Instructions) The next question is from Stephen Paget from FirstEnergy. Please go ahead.

Yes, just as you work on the tolls on the Canadian main line, would you consider taking part of it out of general shipper service and contracting it?

That's not a model that we're considering right now. If that opportunity rose where there was a large incremental body of volume that wanted to sign a long term contract, obviously that would be something that we could consider, but right now that large sort of incremental volume doesn't exist, but obviously maybe going to an open season might be something that we could try, but it's not at the top of our list right now, Steve.

Okay, thank you.

Thank you.