TC Energy Corp (TRP) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the TransCanada Corporation 2010 first quarter results conference call. I would now like to turn the meeting over to 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 2010 first 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 Glen 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 copy of the presentation is available on our website for download at TransCanada.com. It can be found in the Investor Section under the heading, "Conference Calls and Presentations." I would just highlight briefly at this point that we may be experiencing some slight problems with the webcast. If we are, you can certainly listen via teleconference and as I mentioned, the slides will be available for download. Following prepared remarks from both Hal and Greg, we'll turn the call over to the conference coordinator for questions.

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 any additional questions, please re-enter 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 detailed questions relating to some of our smaller operations, or your detailed financial models, Miles 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 the reports filed by TransCanada, with Canadian securities regulators and with the US Securities Exchange Commission. 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 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 Hal.

Thank you, David. Good afternoon, everyone, and thank you for joining us on a Friday afternoon. I intend to keep my remarks fairly short today. Russ Girling and I provided a fulsome update at the annual general meeting this morning. If you're interested, a webcast replay of the meeting is available on TransCanada.com in the Investor Centre under conference calls and presentations.

I'll take a few minutes now to talk about our first quarter 2010 results and recent developments in our business, and I'll then turn the call over to our Chief Financial Officer, Greg Lohnes, who will review our financial results in more detail. TransCanada's pipeline power and gas storage businesses posted strong results against the backdrop of an economy that is slowly moving towards recovery. The Company's disciplined low-risk approach produced comparable earnings of CAD328 million, within 5% of our earnings in the first quarter of last year. Comparable EBITDA for the first quarter was CAD1 billion, and funds generated from operations in the first quarter were CAD723 million. This quarter, we invested another CAD1.3 billion, bringing our total investments to CAD11 billion invested in capital growth projects that will generate growing cash flow and earnings as these projects come into service. We are now about halfway through our large capital growth program and we continue to fund it with strong internally generated cash flow, the dividend reinvestment program and our continued access to capital markets. To that point, TransCanada successfully issued CAD350 million of preferred shares in the first quarter of 2010.

We continue to make excellent progress on our suite of major projects that are part of our CAD22 billion current capital program. I'll now expand on some recent developments that occurred in our business in the first quarter. In March, the National Energy Board approved our application to construct and operate the Canadian portion of the Keystone Gulf Coast Expansion project. This was a significant milestone in advancing the project. The Keystone Expansion will be the first pipeline to directly connect a growing and reliable supply of Canadian crude oil to the largest refining market in North America. On base Keystone, line fill and commissioning of the first phase extending from Hardisty, Alberta to Wood River and Patoka, Illinois continued in the first quarter 2010, and as of today, line fill is over 60% complete, with over 5.5 million barrels of oil in the system, and we have now moved crude oil across the border, well into the United States. I believe that front is in South Dakota today. Commercial in service of the first phase of Keystone is expected to commence late in the second quarter of 2010.

Progress also continues on our large Northern development projects. The open season for the Alaska Pipeline Project was launched today. Results of the open season are expected to be announced near the end of 2010. Closer to home, on our Alberta gas pipeline system, we had several positive developments this quarter. First, the CAD800 million North Central Corridor pipeline is now operating. This 300 kilometer expansion of the Alberta System provides needed capacity to accommodate increasing natural gas supply in northwest Alberta and northeast BC, with growing markets in Alberta and beyond. The project was completed ahead of schedule and notably under budget.

We also received National Energy Board approval to construct and operate the 77 kilometer Groundbirch pipeline, connecting new natural gas supplies in the Montney shale formation near Dawson Creek in northeast BC. Construction is expected to be completed on the Groundbirch project by November 2010. Groundbirch has firm transportation contracts that will reach 1.1 billion cubic feet per day by 2014. And I'd just underscore that number, we have 1.1 billion cubic feet a day of Groundbirch gas contracted on the TransCanada system.

Our Horn River pipeline project, which is also connecting shale gas in northeast BC, is making good progress. The NEB scheduled a hearing for October of 2010. Subject to approvals, the project is expected to be operational in the second quarter of 2012, with firm transportation contracts ramping up to 503 million cubic feet per day. Together, Groundbirch and Horn River will connect 1.6 billion cubic feet per day of new shale gas to the TransCanada system. The ultimate potential of the Western Canada sedimentary basin has improved dramatically with the development of these shale gas resources. While near-term production is not as robust as it once was, optimism on the medium and long-term natural gas supply picture in Western Canada continues because of this growing unconventional supply.

Finally, in pipelines, the Bison project received Federal Energy Regulatory Commission certificate in April. Construction is expected to commence in the second quarter of 2010, with an expected in service of fourth quarter 2010. Bison has long-term shipping commitments for 407 million cubic feet per day. It's an excellent project and further strengthens and diversifies Northern Border's natural gas supply mix. I'd like to now turn to our energy business. Construction of the 680 megawatt Halton Hills Generating Station in Ontario is now substantially complete. Commission activities have begun, and the facility is on schedule to begin operating in the third quarter of 2010.

Progress also continues on the Cartier Wind project in Quebec, the Kibby Wind project in Maine, the Coolidge generating station in Arizona and the Bruce nuclear restart project in Ontario. In summary, TransCanada's capital growth program continues as planned, and will build long-term value for our shareholders. As I close, as many of you know, this will be my last quarterly conference call as the CEO of TransCanada Corporation. Russ Girling will succeed me as CEO on July 1, and I will retire as an employee of TransCanada on the September 1. It's been a pleasure working with all of you in the financial community and in the media over the years, and I give my best wishes to you all. With that, I'll turn the call over to Greg Lohnes, who will provide additional details on our first quarter 2010 results. Greg?

Thanks, Hal. Good afternoon, everyone. As Hal mentioned, earlier today we released our first quarter results. Starting with Slide 10, comparable earnings in the first quarter were CAD328 million, compared to CAD343 million for the same period in 2009. The decrease in first quarter comparable earnings is due to lower power prices in Alberta. This was partially offset by lower interest expense due to increased capitalization of interest related to TransCanada's large capital growth program.

On a per share basis, comparable earnings also decreased quarter-over-quarter due to the diluted impacts of an 11% increase in the average number of shares outstanding as a result of a common share issuance in second quarter 2009. The proceeds of this share issue were partially used to fund our CAD22 billion capital program, including the acquisition of additional interest in Keystone and other capital projects. The carrying costs and dilution associated with this prudent approach to financing will continue to have a near-term impact on our earnings per share and cash flow. 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 first quarter results for our business segments at the EBITDA level, beginning with pipelines on Slide 11. The pipelines business generated comparable EBITDA of CAD768 million during the first quarter of 2010, compared to CAD871 million in the same period last year. 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.

Energy generated comparable EBITDA of CAD259 million in the first quarter 2010, compared to CAD290 million in the same period last year. The decrease is primarily due to the reduced realized power prices in Alberta, lower volumes and higher operating costs at Bruce A, and lower contracted earnings at Becancour. These decreases were partially offset by increased capacity payments at Ravenswood, higher third-party storage revenues for natural gas storage and incremental earnings from the Portlands Energy center, which went into service in April 2009. Now looking at items below EBIT on the income statement on Slide 12, first quarter 2010 interest expense of CAD182 million is a decrease of CAD113 million compared to the first quarter last year. The decrease in interest expense reflects increased capitalized interest to finance TransCanada's large capital program in 2010, including Keystone construction. Interest expense also decreased, due to a reduction in US dollar denominated interest expense as a result of a weaker US Dollar in the first quarter 2010.

Turning to cash flow on Slide 13, funds generated from operations were CAD723 million in the first quarter 2010. Capital expenditures in the first quarter of 2010 of approximately CAD1.3 billion, related primarily to a number of growth opportunities including construction progress on Keystone and other capital projects. Now looking at Slide 14, at the end of the first quarter 2010, our balance sheet consisted of 50% debt, 3% junior subordinated notes, 3% preferred shares and 44% common equity. We have an A-grade credit rating with a stable outlook. Our working relationships with all three credit rating agencies are strong. At the end of the first quarter 2010, we had over CAD700 million of cash on hand, along with additional committed revolving bank lines of CAD4.3 billion. In March 2010, we completed a public offering of preferred shares resulting in gross proceeds of approximately CAD350 million at a 4% dividend rate.

TransCanada's well-positioned to fund its existing capital program through internally generated cash, its dividend reinvestment program and continued access to capital markets. We will continue to examine opportunities for portfolio management, including a greater role of TC PipeLines, LP and financing our capital programs. That concludes my prepared remarks. I'll now turn the call back to David for the question and answer period. David?

Thanks, Greg. Just a reminder, before I turn it over to the conference coordinator, we will 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 for your questions.

Thank you. (Operator Instructions) Our first question is from Sam Kanes from Scotia Capital. You may go ahead.

Thank you. Congratulations, Hal. I hope you enjoy your retirement. And you're too young to retire, frankly, so I hope you have a lot of active opportunities in front of you. If I could switch to balance sheet, Greg, this is to you, taxes current went up to CAD81 million from CAD54 million and only CAD20 million was forward. With all this capex, I would have thought it would have been the opposite way, you'd be heading towards zero current. Is there something unusual going on there with respect to current versus future taxes?

Sam, it's Glenn Menuz here. There's nothing special really going on there. I think your thought pattern's right on the mark. But what you will see, as the capital goes into service, so once construction is completed and that's into service, that's usually when the deductions will begin. And so as, as assets go into service, you should see more of that.

Okay. So just simply, just upon completion is the only time it's recognized, that's all?

Yes, and the other thing you do see impacting that is the change in the regulatory deferrals. That has a fairly good impact on the current tax profile.

Okay. So something else there in terms of regulatory deferrals. That should flip over, I would think, to near zero current, right, as time goes on?

Especially as Keystone comes into place, yes.

Okay. That will be soon now, obviously. If I could switch, one follow-up, Western Power of course was down significantly to CAD42 million EBITDA from CAD93 million. Was that 100% due to your 33% exposure to spot markets, or were there other things?

Yeah, I, I think it's almost entirely due to exposure to the very low prices that we saw in the first quarter, Sam.

Okay. Just wanted to know that. Thank you.

Sam, it's Hal. Thanks very much for your kind comments, and I appreciate the work we've done together.

Appreciate it as well, Hal. Take care.

Thank you. Our next question is from Ted Durbin from Goldman Sachs. You may go ahead.

Congratulations, Hal on your tenure there. Just a question in terms of what's next on the regulatory time line for Keystone Gulf Coast? Just walk us through the process here and sort of the timing that you're thinking about.

The next major regulatory hurdle is the Department of State Presidential Permit. We're in the process, it's an environmental process. There's been a draft environmental report issued. And now that report is out for comment and we would expect, given the process that we went through for the base Keystone, that we would see approval of that permit sometime towards the end of this year. That's the nature, the next -- the last sort of major regulatory hurdle and obviously we've got some state approvals and some land acquisitions and those types of things yet to do, and we would hope to commence construction sometime in the first part, first half of 2011.

Okay, great. And then if I could have just a question in terms of an update on your capital financing program, your thoughts on using preferred stock versus common versus debt. Maybe investor appetite for preferred stock and thinking about your leverage metrics, things like that.

Yes, sure. Well, I think we feel that we're in good position here to finance the rest of our current capital program. As I mentioned, we continue to use our dividend reinvestment program and we had a high participation rate, over 30%. This quarter we'd expect that trend to continue as we move forward. Obviously, we had a very successful preferred share offering, so that's the second one we've done in a number of months here. That market remains open for us, so we continue to monitor that market. We feel the markets are fairly stable and that we have some flexibility around timing.

Obviously, we're sitting on a fair bit of cash right now. We've got lots of room under our CP program. We're drawing down to about the tune of CAD500 million on our CAD2 billion available backstop credit facility there. So, we've got some flexibility. So, what's the timing in the market? We think this is probably a pretty reasonable time out there in the bond market with rates and spreads where they are. So, we will continue to monitor that market, particularly on the US side, because of our requirement for US Dollars as we continue with this large growth program for Keystone and then other levers we look at include, as I mentioned, continued participation of our LP.

We did a very successful drop-down last year, followed by a November equity issue and that's considered 100% consolidated equity on our balance sheet. With regard to the metrics, as you've seen from the analyst -- or from the reports from the rating agencies, our metrics are challenged right now due to the size of the capital program, but due to the certainty of the cash flow and the fact that it's fairly near in term and starting to -- as these processes are starting to come online, we think that we're in a good position with our rating agencies.

Okay, thank you very much. Thank you.

Thank you. Our next question's from Matthew Akman from Macquarie. You may go ahead.

Thank you. I don't know if this is maybe for Glen, because it's kind of nit-picky. But there's a mention of incidental natural gas and condensate sales in ANR. Could you quantify that, please?

Matthew, if you can just give me a second.

Okay. And then I have another -- I guess I'm in a nit-picky mood. The other question I have is, what was the Ravenswood prior year adjustment that came into earnings in the quarter?

Okay, so on the first one, on the liquids and condensate, excuse me, the gas and condensate, it really wasn't that material. It was really a composite or a laundry list of a number of small items that added up. So there's nothing big there. It was just a few million dollars.

Okay.

And then with respect to the Ravenswood adjustment from last year, let me see, it's probably better part of CAD0.01.

Okay. Okay, thanks. Those are my questions.

Okay, thank you.

Thanks, Matthew.

Thank you. Our next question is from Andrew Kuske from Credit Suisse. You may go ahead.

Thanks. It's a bit of a big picture question. Hal, you took on the role of CEO about 10 years ago, nearly 10 years ago now and the company's in much different shape than when you're leaving it. So if you could just essentially give us a little bit of an idea as to directionally where you see the company going? And then if Russ could also give us some commentary from the outlook beyond 2012 for your capital program? Between now and then, it looks pretty much locked and loaded.

Yes, I think, Andrew, it is. We've got a fairly well defined capital program over the next couple of years. One interesting challenge that we face over the next 10 years, is proceeding with the Alaska Project, which I do believe is going to go ahead this time. Back in the year 2002, when we were talking to the large producers, they pointed out that TransCanada wasn't nearly big enough to play a leading role in that project and we didn't agree with the comment at the time because of our capability on the building side. But we did acknowledge that on the financial side, we needed a bigger balance sheet to be able to do projects like that. I think we're there today. By the time we go ahead with something like Keystone, TransCanada will be three times as big a company as it was seven or eight years ago. So, I think that our ability to pursue these big projects just gets better, as time goes on. The Company gets financially stronger, I think you'll see in the years ahead, we're bringing Keystone to a conclusion here.

We've got many different power projects under construction today. Those will be coming on stream in the next three years. The Bruce nuclear project will be complete just roughly a year from now. The first reactor will be coming up. And so, I think one thing that may shift, or one challenge Russ may have that will be different than the last couple of years, is dealing with a very large increase in cash flow and making choices about how much of that to direct towards dividends and how much to direct towards further debt reduction. We've really reduced the debt leverage in the balance sheet and as a result, TransCanada has a lot of dry powder today. That's going to be very useful I think to the management team going forward, and we could significantly increase our earnings per share if we ramped up leverage, and to some extent, that might be the right thing to do. But it might also be a good time to look at other opportunities for that financial capability. Those would be my very broad comments, Andrew. I'll turn it to Russ and he can add his thoughts.

Andrew, as I outlined at the annual meeting today -- I don't know if you had a chance to listen to that webcast, but we've been planning for this for a long time. We've, you know, over the last five or ten years, we've built a significant portfolio of high quality projects that we have in our development portfolio. There's currently about CAD60 billion of those kinds of things today. I think they are all built off our three solid platforms for growth, and that's what will drive sort of our future investment opportunities. As Hal said, we will have lots of cash flow.

But to be a little bit more specific, around the gas side of things, obviously we see new supplies coming online. Shale gas supplies in Western Canada, as well as the onshore Gulf Coast shale gas and even the shale gas in Eastern Canada and Eastern US will meet the capital investment opportunities for us. It's already led to that in Groundbirch and Horn River, as well as connections into our NAR system. LNG into Mexico, obviously, is another large place for potential new investment in our gas pipeline business, and then longer term, we've got our Northern Frontier portfolio, both Alaska and Mackenzie, which our view is the North American market's going to continue to need that gas in the decades to come. I think the gas business is pretty solidly positioned for reinvestment going forward. Our oil platform is just getting started. You've seen us build out four new phases in a very short period of time where we've gone from a project that was envisioned at about 450,000 barrels a day to Patoka and Wood River to Cushing and then on to the Gulf Coast and Expansion on top of it. I see further extension of that system, both upstream and downstream to connect new supply market.

As you know, those investments come in CAD500 million to billion dollar chunks, as well as terminalling and storage and those sort of things that are offshoots of that business. Our view is that Canadian oil production will continue to grow with both the advancements of the oil sands and the same horizontal drilling technology that's now being applied to old oil fields, where they're going back and recovering substantially more crude than they have in the past. Again, I think we're well positioned in front of that potential growth platform. And on the power side, obviously we've made a fair -- we had a fair bit of success in the Ontario market, where that market has been migrating away from the higher carbon intensive fuels. They've been getting off coal. We've been able to directly benefit from that by investing in a lot of gas-fired facilities, as well as the Bruce nuclear expansion. We'd expect that to continue.

And I would say as North America migrates itself to a lower carbon intensive footprint from a power generation perspective, that scales in, in wind, in nuclear, in natural gas, in hydro. All those fuels will replace the coal slate as we move forward. So, I would say all three of our business platforms are very well-positioned and we're going to have the luxury of selecting the very best opportunities out of those to reinvest our free cash flow.

So when you think about all the cash that you will have beyond 2012 and all the platforms you could possibly invest in, do you see any meaningful change in really the way you think about capital allocation today? And from a hurdle rate perspective or really expected targeted IRRs?

I would say that our hurdle rates have been fairly consistent for the last decade. Unless we see some major change in cost of capital in the marketplace, I'd expect them to continue going forward. What we know is for the kind of assets that we build and construct and operate, we work in the lower risk end of the spectrum, and that sort of 8%-ish return is what is required to attract capital to those projects. So I'd say that will continue to be our hurdle rate. And then we'll look to optimize those assets to see if we can get a return, a few hundred basis points above that. That's what provides a good return for our shareholders. So, I don't see any changing discount rate on the horizon. The marketplace hasn't changed in its -- the way it operates. When it needs infrastructure, the contracting party, whether that be a regulated entity or an authority of the government like the Ontario Power Authority, or large-scale energy users or producers, when they need to build the connecting infrastructure, they are willing to step up to the table and sign long-term contracts. And I don't expect that to change going forward.

That's all. Thank you.

Thank you. Our next question is from Robert Kwan from RBC Capital Markets. You may go ahead.

Great. Thank you. Just wondering if you can comment, I know we're a little early in the year, but where you are on the mainline in terms of cash collection in the tolls versus what was planned as part of the toll settlement.

We're probably -- we are collecting less than anticipated. I would say that number on the first part of the year would be in the neighborhood of 10%, 15%, something like that, undercollected at this point in time.

Okay. And are there any thoughts on how you might -- is there something you might be doing mid-year, or are you going to wait until 2011?

In terms of the undercollection?

Yes.

It is -- we've had periods of time where we've had overcollection, undercollection before. We won't adjust that until the end of the year, though, being under collection. And then the question will be -- is do we collect that in in the current year tolls, or do we defer that over a longer period of time? And depending on the magnitude, we've done different things with our shippers in the past. My view would probably be is that we would likely defer that over a longer period of time than a one-year period. But that will be dependent on what the other elements of the revenue requirements are for 2011, but that's something we'll work out with our shippers when we get there.

Okay. Just on the Alberta power price outlook, have you had any changes since the last quarter? I know you seemed pretty bullish, and Alex, I think you mentioned you might even consider buying back 2011 hedges. It looks like you might have modestly added to it. Is -- just any change in the outlook here?

Yes, I think we've seen, particularly balance of year 2010 is up quite significantly from Q1. We're sort of in the mid to high 50s now for balance of 2010. You know, 2011 and 2012 have come up a bit, but they -- we would probably still look at those and not really consider it good value to be selling a lot into those markets.

Okay. Great. Thanks very much. And Hal, best wishes in retirement.

Thank you, Robert.

Thank you. Our next question is from Chad Friess from UBS. Please go ahead.

Hi, guys. I was wondering if you could provide some comments on the relative strength on your contracts at Keystone given that we saw earlier in the week some headlines that a few US refiners were trying to extricate them from their contracts?

I'm not sure what you mean by relative strength in contracts. But we have, as you know, 910,000 barrels a day of firm contracts with shippers, the average term of that is 20 years. These are shipper pay contracts, and --

Well, I'm just asking I guess, is there, could you provide some comments on whether their complaints or their filing has any basis in terms of the contracts you've signed already?

Our view is that they don't have any basis. They're without merit. Obviously, we will continue to try to work with those shippers to find resolution to their issues. But at the end of the day, our contracts are firm contracts and we believe that they'll prevail at the end of the day.

Are there anybody -- has there been anybody else that's signed on for the contracts that has expressed a displeasure with the tolls or the costs of the project?

No, the only party, the only parties that have expressed concern are those three parties that have been cited and they're about 10% of our overall volume on our system. The other 90% have actually encouraged us to keep going and to get to the Gulf Coast as quickly as we possibly can. All of those other contracts are firm and we have no issues with those shippers.

Okay, great. And I just -- one follow-up. I wonder if you could talk about the size and perhaps timing of a potential dropdown to TC PipeLines in the context of what's left to fund on the capital program prior to the end of 2011?

Yeah, it's Greg Lohnes here. The LP market continues to improve, so we're seeing larger transactions being done, assets being dropped down and the ultimate equity being raised. So, we feel good about that market. It appears to be continuing to strengthen. So, we monitor that market, with respect to the pricing of the units, we would like to see the Great Lakes settlement sorted out and the Great Lakes rate case sorted out to get that out in the public domain. We think that the price of those units shim prove with some of that uncertainty removed and we then would look at the potential assets we have. So we're always looking at our portfolio for mature, stable assets that would be a good fit for the LP and we continue to do that and we're working on a number of fronts, but I would say that it's probably towards the later part of the year.

Great. Thanks, guys.

Thank you.

Thanks, Chad.

Thank you. Our next question is from Bob Hastings from Canaccord. You may go ahead.

Thank you very much. Just to follow up on that Great Lakes comment, in the first quarter you booked earnings now, but the settlement's not out there in public. Can you give us some idea of how you might have accounted for those results? In effect, could there be a step-up later in the year or do you think they're accurately reflected in the settlement?

I believe they are accurately reflected. The rate settlement doesn't come into effect until May 1. That's sort of the retroactive date if we come to conclusion. Looks like we're headed down that path. So, to date we've booked earnings consistent with the way we've done in the past and then there'll be no adjustments to those.

Okay. Thank you. And then back in the quarter, there was some statement that the net income was down, but I would have thought that was a flat capacity payment.

Bob, it's Alex. One thing, I had thought I made a comment about this at probably the last meeting, but I'm not sure I did. The original contract with Hydro-Quebec at Becancour has sort of a three-year element of cyclicality to it and what happens is every third year, the EBITDA experiences a not insignificant pop. And that would have occurred in '09. So I would think when you look at 2010, I would go back to -- '08 would be a good year to look at in terms of what '09 should produce. Or, sorry, at 2010.

2010?

Yes.

Okay, thank you for that. And back to you, Russ, maybe. On Keystone, we're not going to start booking EBITDA until the fourth quarter, is that correct?

Correct.

And of course we're capitalizing interest on the, on the expenditures up until you do that. I think there's some uncertainty mentioned a few quarters ago about how you do the depreciation and some other things. Can you explain, just confirm sort of the net impact of all of those moving parts with Keystone, how they come into earnings on the bottom line?

I think they'll be, from an earnings perspective, relatively flat through the end of the year. We'll capitalize both the interest costs, as well as the cash flow that we generate from the facility until we're in a place where we can sort of commence operations and start providing service on our long-term contracts. That's kind of where we're looking for the change-over. So I'm just looking at Glenn right now. I think the impact on earnings over the year's going to be relatively flat to slightly -- is it slightly positive or negative?

It's relatively flat, and as Russ alluded to, is that until Keystone is ready for its intended use, and currently we're under the startup volumes, until that is lifted, we will continue to capitalize the cash flow that starts from that. But as noted, that is expected to start within the next few months. So, we'll see the economic benefit coming in and the cash flow, but we just won't have booked the earnings until that restriction is lifted.

So on a quarterly basis, the first meaningful contribution to the bottom line earnings from Keystone will be Q1 of next year?

Yes. There might be some in Q4. And we'll be able to give you a better update of that as we -- the oil gets to Wood River at the end of June here. We have a better feel for what our operational issues are going to be over the summer. So we'll be able to give you a better sort of update on that in the next conference call, after Q2.

Okay. Thank you very much.

Thanks.

Thank you. Our next question is from Andrew Fairbanks from Banc of America. You may go ahead.

Good afternoon. Thank you. Hal, wanted to congratulate you on where you've taken the company during your stewardship. I hope you enjoy your retirement. My question was just around LNG and what you all see as potential opportunities in LNG, either in regas as you've looked at previously or potentially even gasification or being part of a gasification scheme going forward?

Well, it's Hal. First, thanks, Andrew, for your comment. On regas in North America, we've kind of lost interest in that side of it. We did have a difficult experience with probably the best LNG regas project that was presented by anyone in Long Island Sound. And the decision by the governor of the state of New York to turn us down on that was very disappointing. So that would be an example of an LNG regas project that would work and that would make sense even in a relatively more well-supplied North American domestic market. That one would make sense because of the nature of the New York market.

More broadly than that, I think it's safe to say that we won't have much interest, at least in the near-term. On the Kitimat project, as far as liquefaction goes, I think I'll turn to Russ and let him talk a little bit about that. Just suffice to say, I've been involved in different liquefaction projects at Kitimat Prince Rupert over the years. The first one was back in 1984 and they look good from time to time and then inevitably they seem to fade in their attraction. An LNG export project out of Kitimat has to compete with a North American market that is connected by increasingly cost effective pipelines, as the pipelines depreciate, and it just makes it tougher and tougher to justify the building of new pipe capacity to get from northeast BC out to Kitimat. But Russ has thought about that maybe more than I have. So let me turn it to him.

My thoughts are consistent with Hal's. Obviously, the global LNG market is also very competitive, and so if North American gas is going to compete with that marketplace, it has to do so on a cost basis. I think the production cost in North America probably is equivalent to a lot of places around the globe, but what we find is, from a resource cost, LNG, for the most part, has a much lower cost structure than the cost in North America. And as well, there's a fairly robust market. So, the opportunity cost, if you will, of gas in North America is pick a number between $5 and $7 or $8 as being the current forecast in the marketplace. You have to take that $5 to $8 gas, transport it to an export point on the water and then you have to liquefy it and all of that is very expensive. So the question is, how does the cost of all of that compete with LNG that's already out there in the marketplace. And there are -- so there are sources, whether that be Qatar or other places around the world that produce it cheaper than Australia. So, that's what we're up against and the market will sort itself out. I'm a believer that the market will dictate which direction gas flows and our view right now is that those kinds of projects will be difficult.

Obviously, in our Alaska open season, we have included an option to move the gas developees and that would provide an opportunity for someone to build a liquefaction facility and we'll get an indication of whether or not those producers see that as an opportunity. But certainly, we see the resource cost, or the opportunity cost of that resource being less than a lower 48 or even Canadian production source, and therefore it's likely to be more competitive internationally and we'll see whether or not that gas moves that direction. To date, the producers have all indicated to us it's the lower 48 market that they're going after with that supply. But as I said, the open season will give us a little bit of insight into that. The market will dictate where gas flows.

That's great. Thanks, guys.

Thank you.

Thank you. Our next question is from Barry Klein from Citi. You may go ahead.

How's it going?

Good.

What was the impact -- I saw the volumes on the pipes were down, at least on the Canadian side, quite a bit. What was the impact on earnings from the decline in pipeline volume?

The earnings aren't impacted on our pipeline system. We -- it's a cost of service system, and so when the volumes decline, the totals actually increase and that's done on a lag basis. So, if there's any undercollection, if you will, on the current year, that goes into a regulatory deferral account and that gets delayed into future years. So, there's no impact on net income as a result of changing volumes, up or down, on our system. Canadian systems.

And on the American side, was there any impact from volume changes?

Not in the first quarter, there wasn't. They were pretty close to where we anticipated that they would be. The volumes were pretty close to where we anticipated that they would be.

Got you. And what is the tariff that you've applied for for the US portion of Keystone to, I guess to Wind River, Cushing, and eventually to the Gulf?

I think the details of that -- just one second. So we have filed interim tariffs. I'm not familiar with the exact numbers in those filings, but roughly, I think you'd be looking at something like CAD4 to CAD4.50 to the markets Patoka, Wood River, CAD5 to CAD5.50, something like that, into CAD6, into Cushing and probably CAD1 more than that into the Gulf Coast in that kind of range. But those are the kinds of interim tariffs we've filed. I don't have the exact numbers, though. But if you want them, David or Miles could provide you with that.

Okay, thank you. That's it.

Thank you.

Thank you. Our next question is from Linda Ezergailis from TD Newcrest.

Thank you. First of all, Hal, congratulations on a successful decade stewarding TransCanada and all the best in your retirement.

Thanks, Linda.

A few questions, I don't know if it's for Alex or someone else, on the Bruce side. What was the magnitude of the payment that Bruce B made to Bruce A on 100% basis with the contract reset on the OPA? And I guess further to that, on a percentage basis, we have to know how much TransCanada now owns of Bruce A?

Do you have that off--

Well, the percentage basis, Linda, has not changed as a result of this. This was merely just a reflection of the amendments that were made to the contract with OPA and it was more of a sharing of costs related to the contract. So, there has been no change in ownership either by TransCanada or by the partners in either of the respective entities.

Yes, but over time as your capex increases, your ownership creeps up and I've lost track of that.

Bear with me. I'll just pull it out. It's about 48%. But each partner generally would contribute equally -- contribute proportionately into this. So, it moves just a little bit, but not too much. 48.8% at the end of the year.

Okay, and then what was the payment on 100% basis that Bruce B made to Bruce A?

I--

Sorry, Dave.

I was going to say, sorry, Linda, we're just double-checking. I'm not sure that we have that number available.

Not off, not off the top. But as we said, the difference was -- the only impact to us, because we're an owner in both, is just the difference in ownership.

Okay. I guess I'll wait for the Cameco release to find that out. And maybe can you just as a follow-up, my second question, can you describe the nature of the unplanned outage at Bruce A?

We -- on Bruce A, we had a -- when we were doing some overhaul maintenance work on unit 3, we found out there was a problem with stroking the valves that are involved in shutting down the nuclear reaction in the event of a safety concern. And because it was a safety concern, what we had to do was shut both units down over a period of weeks, over a period of time for reasonably significant period in order to rehabilitate those valves.

Okay.

Technically, we found there was a build-up of magnetite in those valves. And as a result, they weren't stroking properly, so we had to replace them.

And when is the last time that you have inspected your stroke valves in Bruce B?

They've all been inspected.

Okay, so it was kind of a one-time thing?

Yeah, it was a one-time situation.

Okay, thank you.

Okay. Thanks, Linda.

Thanks, Linda.

Thank you. Our next question is from Craig Shere from Tuohy Brothers. You may go ahead.

Thanks. Hal, best of luck with your retirement.

Thank you, Craig.

I just wanted to revisit -- I know it's really far out there, but the Alaskan Pipeline question, Hal, I think you stressed appropriately the important and significant off take that you all have developed from the western shale plays and how important that is. I think I've heard some numbers that based on the EURs and the cost of wells, I mean it's very far south of a dollar cost per Mcf for some of these prolific shale plays. And I just wonder with CAD4 Henry-hub gas and new shale plays in Western Canada well under CAD1 cost TransCanada may be ready for a very large project like the Alaska Pipeline, but is the market really ready right now?

So I think just to put it in context, North America produces and consumes about 75 Bcf a day. And we continue to see 20% to 25% and 30% decline in that kind of a volume every year. At 20%, which is the absolute minimum, you need 15 Bcf a day of new supply every year, just to stay flat. You look at that over an eight-year period, 15 Bcf a day, you need to bring on 120 Bcf a day of new sources of supply over that period, most of which begin declining the day after they come on. So, you think about over an eight-year period needing to bring on 120 Bcf a day, 1 B of that might come from the Mackenzie, 4 B of that might come from Alaska, and that leaves you with about 115 Bcf a day that has to come from either shale sources or conventional. In our view, and it's a view shared by many of the more experienced upstream companies, it's going to be a very big challenge to maintain flat production. And in fact, we see the need to grow production in North America by about 10 Bcf a day to 85 Bcf a day just to meet the demand from a large and growing gas-fired power sector. That as a number of these coal plants reach end of life and increasingly we think they won't be replaced with coal plants, they will be replaced with gas fire generation.

So now the other point that you raised that I'd comment on directly, the cost structure of finding and developing and then producing shale gas out of the plays in Canada and the US I think that that $1 in Mcf as a finding and development cost is quite optimistic. The best numbers I've seen from the best companies across a whole play, as opposed to well by well, would be more in the $2.40 range and but you then add $0.60 to $1 in operating and compression and processing costs to that. So in our view, even the very best shale plays require gas prices approaching $4 in order for a return on capital employed to be achieved.

Now, there are some places, there are some really extraordinary top decile portions of some of these shale plays that will come in cheaper than that. I'll acknowledge that, but on average, we don't think $4 is going to be enough, because like any play, the portions of the play that are below average are much more extensive than the portions that are above average. There's a relatively small number of wells that really drags up the average on any play. So, we stick by our outlook that the gas price has to go back and forth sort of in a $5 to $7 range in order for most of this stuff to work. And I'd point out, our analysis indicates that of the 15 Bcf a day of new gas that's required every year to maintain flat supply and demand, still about two-thirds of it will be coming from plays other than shale plays and they are much, much more expensive than that. So we don't think shale at the margin is actually setting the price of gas.

Understood. Very detailed response, I appreciate it. Best of luck.

Sorry for the detail, but that's the way I understand it.

Very helpful. Thank you.

Thanks, Craig.

Thank you. There are no further questions registered from analysts. We will now take questions from any media. (Operator Instructions) Our first question from the media is from Justin Amoah from Argus Media. Please go ahead.

Hi. Is there any more detail you can provide on the specific period Keystone is expected to start deliveries to Wood River and Patoka? I'm assuming from your comments today that we're looking at late June to early July. Is that right?

That's correct.

Okay. I also had a second question. What is the process in determining whether North Dakota crude will be able to move on Keystone XL? And just could you outline how that will be determined and how that would work?

I think for the most part it's determined by commercial arrangements between ourselves and those producers in North Dakota. Those discussions are underway and if we can come to some resolution on commitment, because obviously we'd have to build infrastructure to tie that crude oil into either the Keystone play system or into the Keystone XL system. There's actually a number of different options we're looking at depending on where the producers are in that play. So like any, any connection of new supply, we sort of have to work through those details. Then there's obviously some regulatory issues that we need to deal with in terms of getting permits and regulatory approval to build and construct and to operate under tariff basis with that production, but those wouldn't be out of the ordinary. So, I think it can all be done and it's all dependent upon whether or not those producers want to make a significant enough commitment for us to tie in that crude oil.

Okay, thank you. Have there been any discussions yet about how TransCanada would mitigate the effects of the heavy crudes on XL or Keystone with the light crudes moving out of Montana and North Dakota?

We operate a batch system, so, we would obviously collect batches of different quality crudes and we store them in tanks. And then we inject them into the pipeline when we accumulate a large enough batch. And if we have to do it in the middle part of the pipeline, we can slow down the upper end of the pipeline and inject the batch into it coming from another location. So, that's pretty standard pipeline operations. The crude oil business is that you put batches, if you will, of 200,000, or 300,000, 400,000 barrels next to each other of different quality crudes as they move down the pipeline. And that's why we use the tankage for it at both the front end and back end of the pipeline to accumulate the batch and then to take the batch off and to keep them separate and maintain the integrity of the quality of each kind of crude we have in the system.

Okay, thank you.

Thank you.

Thank you. There are no further questions registered. I would like to turn the meeting back to Mr. Moneta.

Okay. Thanks very much. Thanks, everyone, for participating this afternoon. Just a couple of quick things. To the extent we did experience any technical difficulties, we apologize. We're just coming to you from our AGM location this afternoon. A rebroadcast or an archive version of this should be available later today. Finally, Myles, Terry and I will be available for any of your further detailed questions. We'll be quickly making our way back to the office and be happy to talk to you later this afternoon, if need be. On that note, again, we thank you for your participation and look forward to talking to you soon. Bye for now.

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