Welcome to the TransCanada Corporation 2010 second 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.

Thanks very much and good afternoon everyone. I'd like to welcome you to TransCanada's 2010 second quarter conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of Energy and Oil Pipelines; Greg Lohnes, President, Natural Gas Pipelines; and Glenn Menuz, our Vice President and Comptroller. Russ and Don 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 and a copy of the presentation is available on our website at transcanada.com. It can be found in the Investors section under the heading Events & Presentations. Following their prepared remarks, we'll 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 detailed questions relating to some of our smaller operations for your detailed financial models, Terry and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities regulators and the U.S. Securities and Exchange Commission. And finally, I'd also like to point out that during this presentation, we will refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA, and funds generated from operations. These measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thanks, David. Good afternoon, everyone, and thank you very much for joining us. I've spoken to you many times over the last number of years here my role as the CFO, President of Pipelines and most recently as TransCanada's Chief Operating Officer. This is my first opportunity to speak to you in my new role as President and Chief Executive Officer. TransCanada is a great company, and this is a challenge that I welcome and an opportunity that I'm very excited about. The question that I've been asked most often is how will the direction of the company change under my leadership. And my answer to that has been that the direction won't change. As I said, I've worked on this company's strategy for many years and always with a focus on becoming the leading energy infrastructure company in North America. We will achieve that outcome by continuing to do things that have made us very successful, a disciplined approach, focusing on growing TransCanada's core businesses. This starts with a focus on running our businesses well and completing our ambitious $22 billion capital program. In the future, we'll continue to reinvest in growth opportunities where we have a competitive advantage, to grow our earnings, our cash flow and deliver long-term shareholder value. And I'm very fortunate to have an executive team with me to lead our 4,000 skilled and very dedicated TransCanada employees. Last month, I made some adjustments to the executive leadership team to keep the company focused on meetings its goals. It's an experienced team and one that knows our business very well. Alex Pourbaix, Greg Lohnes, Don Wishart, Dennis McConaghy, Sean McMaster and Sarah Raiss are all individuals with expertise and experience to meet our challenges and to get the job done. I'm also pleased to welcome…

Thanks, Russ, and good afternoon, everyone. I'm pleased to have the chance to speak with you today. It is a privilege to have the opportunity to serve as Chief Financial Officer during such and important time in the company's history. I look forward to meeting and working with you in the months and years ahead. Earlier today we released our second quarter results from which there are three key messages. First, our core businesses, Pipe and Energy performed well. Second, our consolidated results were impacted by losses on derivatives used to protect against rising interest rates and foreign currency fluctuations that do not qualify for hedge accounting. And third, TransCanada's financial position remains strong and we are well positioned to fund our existing capital program. I'd like to take the next 10 minuets or so elaborating on these themes and our second quarter 2010 results. Net income of applicable common shares in the second quarter was $285 million or $0.41 per share compared to $314 million or $0.50 per share for the same period in 2009. Comparable earnings in the period were $275 million or $0.40 per share compared to $319 million or $0.51 per share in 2009. As noted in the quarter, comparable earnings were reduced by $28 million or $0.04 per share due to losses on derivatives and the translation of certain U.S. dollar working capital balances. In addition, in the first six months of 2010, $20 million of net income or $0.03 per share related to the three year Alberta system settlement has yet to be recorded pending final approval by the national energy board. We expect to receive NED approval in the third quarter of this year at which time the impact settlement from its effective date of January 1, 2010 will be recognized. Of the…

Thanks, Don. And before we turn the call over to Q&A, I'd just like to offer some closing comments. TransCanada remains focused on its core businesses, Pipe and Energy. We remain focused in our approach to completing our capital projects on time and on budget. This is expected to lead to a $2.5 billion increase in annual EBITDA in 2014. And we will continue to reinvest our cash flow in high quality new projects. Today, we have three platforms for growth, gas pipeline, oil pipeline and power generation. And as we've seen there are numerous opportunities to further expand our oil pipeline business, and we'll continue to pursue those. On the gas side, connecting new conventional gas, shale gas and eventually northern supply to North American markets are opportunities we are actively pursuing in our gas business. On the power side, there are signals that there will be a migration away from coal to less carbon intensive sources. So that should present further opportunities for natural gas-fired power plants, renewables and nuclear, all of which we are well positioned to compete for. So as I said at the beginning, our strategies are unchanged. We will maintain our disciplined approached, growing our core businesses, reinvesting in new opportunities. We will focus on increasing TransCanada's cash flow, increasing our earnings and driving dividend growth. The result, in the end a long term, enduring growth and value for our shareholders. Thank you for listening today and I'll turn it back to David for the Q&A.

Thanks, Russ. Just a reminder before I turn it back over to the conference coordinator, we'll take questions from the investment community first and following that we'll open the lines to the media. With that I'll turn it back to the conference coordinator for your questions.

(Operator Instructions) The first question comes from the line of Sam Kanes from Scotia Capital.

I'm going to focus on Bruce a bit, not much detail with respect to refurbishment timing, cost estimates and Bruce B just in general, how many contracts are available at above market rates I guess that are about to expire this year? How many expired year-to-date, and what dollar differentials did that mean to Q2?

Sam, it's Alex. Just with respect to Bruce I and II, I think there hasn't been any real material change to the guidance that we gave earlier in the year, which I think was around $4 billion, slightly over both units back by the end of 2011. There's always going to be challenges, but I think so far our experience is we're continuing to see improvement in productivity that I think I mentioned at the last conference call. We are actually moving towards commissioning activities. We're starting to commission a number of systems. We expect to have ACL completely offsite towards the end of January of 2011. And that time we're going to be staffed, the project by both 50%. So I think generally, the guidance is similar to where we were before on that. With respect to the contracts at Bruce B, we are seeing those contracts are significantly rolling off over this year and next year. I don't have the exact numbers in front of me. Do you have them in front of you, Glenn?

Yes, as far as the realized prices, obviously they're impacted by the floor price on all volumes as well as the contracts over and above that. So the difference in the volume and the pricing of contracts year-over-year was probably above $0.02 to $0.03. But also last year had an amount in there for about $0.01 per share related to Q1 '09. So that's sort of the combined impact on the year-over-year basis and as Alex says, these contracts have continued to roll off.

Our next question is from Carl Kirst from BMO Capital Markets.

With respect to the Canadian Mainline and the indications that volumes may be I guess about 10% to 15% less than what was originally expected, I guess that won't be impacting earnings this year, but it will from a cash flow standpoint. Should we be thinking of 10% to 15% of roughly the $1.1 billion of EBITDA, or how should we think about that from a cash standpoint?

I think that's the right way to look at it, Carl. And I think as we look forward with the Mainline, summer seems some higher volumes with the heat and the power demand in the east. And we'd hope to, as we start to bring volumes on, start to see that volume starting to rise.

Then just a follow-up also on that and understanding there's probably only limited you can say with respect to the ongoing discussions with your shippers as far as a comprehensive settlement, but I guess the idea is to get everyone onto the same page and then bring that proposal to the NEB by year-end. And I guess my question is; clearly, it's going to be challenging, given the different shipper interest. Do you have to have everyone on the same page before you approach the NEB, or is it some point where you get maybe two-thirds of the shippers onboard and that's when you approach the NEB? Is there any sense of color you can add there?

Sure, first I'd say that we are working diligently with our shippers. We are pleased that our shippers are engaged and are interested in working towards a settlement. And I think we all recognize, all the customers in TransCanada, that we need to work together in order to develop a total link structure that will support the business as it currently sits and as we expect it to grow with the new shale developments coming on as are outlined in the quarter. I think we will work to get a unanimous settlement, but with diverse interests it's possible that we may not get a 100% of the way there. But we are committed to filing by the end of the year in the fourth quarter based on support from as many of our constituencies as we can possibly get, and then would work with the NEB on a process to get those proposals approved over the next number of months following that filing.

The next question is from Ted Durbin from Goldman Sachs.

Just coming back to sort of the financing questions again. How are you seeing the market for the preferreds versus maybe potentially needed to issue common equity to finance some of the CapEx, kind of what are you seeing in the market right now for financing?

The market's strong for most product lines on both sides of the border. We've done 1.25 billion of preferred shares since last fall, and our dividend reinvestment program's running at about a 36% clip now, generating over $300 million a year of equity. So with that and the hybrid market potentially reopening, now that Moody's has released its views of the world and how it's going to treat those, we see all kinds of avenues to keep adding subordinated capital other than a discrete common share issue going forward here.

That's helpful. Thanks. And then if you can just go through a little bit more on the presidential permit process here with the State Department? You sort of said the first quarter of 2011; is that kind of the way you're thinking this comes through for Keystone or maybe just a little more detail on what you're thinking there?

Yes, I think, we are expecting that we would receive a decision either towards the end of this year or very early into next year at the latest.

Our next question is from Bob Hastings from Canaccord Genuity.

With all the continuing capitalization of Keystone while the volumes ramp-up, when we look out to next year, Russ, you mentioned a billion dollars of additional EBITDA from that and the other projects. Can you give us an idea what that comes down at the bottom line, just from the incremental projects you're doing, maybe give a range or something?

We haven't provided that guidance. I think that what we are trying to do is give you the capital cost of the projects there. I think you can get a sense of their usual life and their further depreciation, make some tax assumptions. But we haven't ourselves provided any guidance from EBITDA down to earnings. I think you can assume capital structure Bob, of roughly the capital structure that we've had in the past for these types of projects in that sort of 60-40 kind of range. Our balance sheet will probably remain in that 50-50 kind of range until we get out of the capital building, but I would see the long term, probably 60-40 is kind of a good run rate. And as well, the IRR in these projects, we try to do some back calculation in multiple (inaudible). So hopefully that gives you enough information to try to calculate where earnings are going to be.

I've done that. Thank you. Can you give us a little color then, with the LNG issues in BC, you've got a bunch of contracts signed up now, you've got some others. But sort of how do you see that playing out longer term, alliances to try to get some more of those gas plants? Do you think they're locked in there or there are more opportunities coming? Would you look at any processing?

I do believe that there is more opportunity for growth. If you believe some of the producer estimates, they are far in excess of what we've contracted to-date or agreed in the indications of interest. As I think I had mentioned in my opening remarks, your current interest level is around that 2.5 billion to 3 billion cubic feet a day for both the Horn River and Montney plays. I don't think you'd see us move in the direction of getting into gas processing, Certainly West Coast and others have done a good job up there. We continue to work with gas processors, whether producers or West Coast directly to provide our services of transporting that gas. It appears that the market that they like the best today is the Alberta market which provides a significant amount of liquidity. As you know, we remove about 10 billion cubic feet a day, but about 60 billion cubic feet a day trades on our Alberta System. So those producers can instantaneously sell their gas. We're making very, very minimal balance sheet commitment. Any commitment to move to the LNG market or to other markets requires more financial capacity from their balance sheets, perhaps leads to a worse net back and doesn't have the same liquidity that we have to offer. Those are the reasons I guess we'd been hearing from them as to why they've been signing up with our system. Where they choose do something different down the road, would be up to them. But I do think those are enduring values of the Alberta System. And then from there they can get to any market in North America, and we have capacity in our system. So depending on where the best net back is on a given day, we can get the gas there. So as we've been signing up this gas, that's the kind of feedback that we've been getting, and we do have, as we said, more inbound requests for service. So I believe we've got a good product offering, and it seems to be working right now.

Does that improve once Alliance tolls or contracts are over?

Again, I'm not sure. I've put out a fair number of years to when the Alliance contracts come to an end, and how they will toll their system going forward and what markets they will access. As you know, it's a high pressure system, so it offers a different kind of service than we offer today. And it's a bullet pipeline that goes to essentially one market where you're coming to our system, offers up other things. Again, I don't know how they'll toll their system at that point in time. What I can tell you is that we're large and that we have the capacity to continue to adapt to competitive market environments, and we would adapt to whatever competitive market was required to compete head-on with folks offering other services.

Our next question is from Matthew Akman from Macquarie.

I have two questions, one on the pipes and one on power. On the pipelines, how would you guys deal with any delay on Keystone XL? Let's say it gets approved but it's delayed, I guess first of all, what kind of delay in the approval would cause the pipeline in-service date to be delayed? And then how would you deal with that from a planning and procurement standpoint?

I think as we prepared for construction and permitting on this facility Matthew, we certainly built in some slack and we think that for example this 90-day incremental common period that the state department has put forward, we don't really see that as having a material impact. With respect to what kind of a delay, I mean, it would have to be a delay of several months to really have a significant impact on this project.

And how do you plan for that, I guess Alex, with ordering materials and lining up contractors and stuff like that?

Well, that already for the most part has been done. The pipe contracts have been let, the pumping station contracts have been let, most of the construction ones have also been, and they have been put in place in a manner that gives us some flexibility as to when we actually trigger construction.

So hopefully, if even in the worst case, let's say it is delayed; hopefully there wouldn't be any other impact other than maybe the timing of it being in service?

I think that's basically correct. I mean, I guess if it was delayed for a very significant amount of time, which we're not anticipating, I mean you could potentially see some escalation of labor, things like that. But we wouldn't at this point be anticipating that kind of a delay.

And I just had one quick question on the power side. It looks like maybe you're around 50% hedged in the West next year for 2011. I'm just wanting to confirm that and then maybe get your philosophy on hedging going forward, since obviously pricing hasn't picked up much?

We're about two-thirds hedged for the rest of this year. We're pretty close to 50% hedged, and that's up a fair bit. We took the opportunity of those high prices couple of months ago to get off some hedges into 2011 and 2012. Right now, where prices are, kind of $50 for 2011, I think around $53 for 2012, frankly, I don't think there is a lot of upside to be doing a lot more hedging at those prices. I don't think we have a lot of downside, and I'd probably take the view, there's some upside off those prices.

Our next question is from Robert Kwan from RBC Capital Markets.

Russ, you mentioned earlier, just coming back to Mainline, to quote, the marketplace is changing and that you're going to need to change with it. Can you just elaborate a little bit on that? Is that you being open to a significant change in tolling methodology and maybe one that could cause a bit of softness in earnings in the near-term until some of these additional volumes come online?

That's a couple of questions Robert. I think the first one is with respect to changing our tolling system to meet the marketplace. That's just what we have to do as a company. The second question you asked was around collection of our revenue requirements and whether we would be willing to forego some of that collection for a period of time. And I think given that there appears to be significantly more gas in North America than we thought 24 months ago, it appears that that gas is recoverable at today's prices, are slightly higher kind of prices. It appears that we've got abundant supply. On the market side, it appears that we're going to migrate away from coal-fired power for example in North America to more carbon friendly generation sources, of which gas would be one of those. So I would say that that's a positive environment where you would see demand increase. So those are the things that we're responding to. That would suggest that our facilities are going to be used and useful for a longer period of time. And under that kind of situation, we'd be willing to slow down the depreciation of our systems and collection of capital. But there is no reason in my mind that I could see that we would need to have a reduction in return on capital that given the market fundamentals that I just talked about that doesn't necessarily make sense. But it does make sense to adjust our return of capital and capital collection to meet I think what is a more robust marketplace in the long term.

So at the end of the day, what you might do going forward is very similar to what you have been doing over the last, call it 12 to 24 months, where you're protecting the earnings stream and that's of paramount importance?

I didn't say that we're protecting the earnings stream. I would say that what we're doing is, we're trying to adjust our tolls to meet the competitive marketplace. In a regulated business we have the opportunity to recover our cost, and one of those costs is our return on capital. And there is no reason in my mind right now why we wouldn't be able to continue to collect our cost on this system, whether it be return of capital or other components of the revenue requirement. We just may have to allocate those in different places of the system. And in the case of depreciation, which is just one of those costs, if it's prudent to reduce those costs and that makes more sense for our customers, we would do that.

Just a quick question on the power side. Do you have what the impact of the Sundance 3 outage would have been if the force majeure had been granted?

If force majeure had been granted, my recollection is that on a 100% basis, it would have been about $30 million, give or take. So half of that is, like $14 million, $15 million, in that range.

Our next question is from Andrew Kuske from Credit Suisse.

Just a question as it relates to the Oakville plant proposal. And I ask the question in part, because after the market closed, Pristine Power received some news from the government enacting a regulation under the Planning Act, really allowing them to proceed with the York Energy Centre. So I'm just sort of curious as to what you think about Oakville in light of that news and the potential success of that plant.

I think the Pristine plant in Oakville in many ways is in similar situation. And if anything, the Pristine plant was maybe even a little bit more urgent. But both locations have been identified by the OPA and by the ISO as areas where there is significant transmission congestion and that eventually there will be a risk of blackouts if the power plants aren't constructed. I think it was perhaps even a little bit more acute in the North York area in that I think they were already operating it significantly below NERC standards. So I think similar situations applied to Oakville. Obviously, it's no secret that certain elements of the community have been very vocally opposed to the project. We are satisfied that at the end of the day, the Southwest GTA area absolutely needs that power in order to keep the lights on in Oakville and other communities in that area. So we are continuing to push forward with a series of legal claims or issues that we have, trying to attack some of the actions that the municipality has taken in the attempt to stop the plant. But at the end of the day, we're quite comfortable that that area needs a power plant. And we have a contract to build that power plant, and we are relying on that.

And a somewhat related question. Do you see any opportunities within the Ontario market for TransCanada to be involved in transmission? Clearly, there is a lot of transmission issues within Ontario. You're not a licensed transmission operator. But given your power generation capacity, does that really preclude you from being involved in the market on transmission basis?

Given the almost overwhelmingly all of our power in Ontario is either regulated or quasi-regulated, I don't think there would really be any competitive reasons why we couldn't get into the transmission business. We've taken a look at the opportunities. It certainly appears that there is a lot of transmission that needs to be built in that region. If we were to consider it, I think we'd actually want to hear pretty strongly from the government that they would favor our involvement. And I think at this point, they are considering whether they want to bring in third parties into the transmission game. But they haven't really made any final decisions on that.

Our next question is from Linda Ezergailis from TD Newcrest.

In light of Moody's coming out with their views on hybrid securities, can you give us an update on your discussions with the rating agencies on how your capital structure might look in terms of maximum percentages of hybrid and preferred type securities in the mix?

Moody's has come out, and looking at junior subordinated notes, given our base gets 25% equity credit to those types of securities, but the preferred shares we have in our capital structure, they're going to be about 50%. When we look at the hybrids, we recognize there are limitations as to how much of that we can put on our balance sheet. We would think something in the 10% area in total is something that would make sense for us. Each of the three has distinct circuit breakers on these. We've got maybe a couple of percent left, but probably wouldn't go beyond 10%, 11% of the capital structure.

And just a follow-up question on your actual operations. Can you maybe give us a sense of what the outlook for your natural gas storage business is for the balance of the year?

As you know, Linda, we are pretty much sold out for the balance of this year, I think probably in the range of around 85% to 90% of our capacity. And all of that is locked up, and the profits are locked up into that. So I think I can say that if you take a look at what we've done for the first six months of the year, we're probably going to look to do that and maybe a little bit more for the last six months. The summer period is always kind of our soft period, and we do tend to make the lion share of our profits in the winter period.

Our next is from Steven Paget from FirstEnergy.

Will you be taking advantage of the two-year window to wait on IFRS?

Steven, it's Glenn. Obviously, this just came out this week. We're taking a look at it. But as we've put in our disclosure today, assuming the exposure draft is approved, we would be expected to take advantage of the two-year delay or deferral mainly because of the uncertainty currently at the international board level.

(Operator Instructions) Our next question is form Chad Friess from UBS.

A question for Alex. We've seen a fairly hot summer in the Northeast so far. I was wondering what impact is it having at upfront utilization at Ravenswood and in general. How the Northeast U.S. power market is shaping up for the second half of the year and into 2011?

It has had obviously a pretty significant impact on the Northeast. Energy prices have been a little stronger or overall not insignificantly stronger than we'd anticipated. Ravenswood has been running particularly through the hot period, running almost all of the units flat-out in non-peak periods. So that's been a good story for us. If I take a look at the balance of the year, we're probably looking in Zone J at sort of maybe $58, $59; $58 in '11 and then sort of $62, $63 in '12. So I think one of the good things that we've seen with this hot weather is we've actually seen demand, if not meeting all-time peaks, has certainly been getting very close to all-time peaks. So we are seeing demand has come back pretty strongly. I think New York City demand is up about 3% year-over-year. And I think that knowledge that the demand is still there is moving the forward markets a fair bit.

Our next question is from Matthew Akman from Macquarie.

Just a quick follow-up on Great Lakes. I noticed that there was a settlement there recently of the FERC proceeding. And I was wondering whether that was reflected at all in the second quarter or how that might impact EBITDA going forward?

The settlement is in and the settlement was a 8% reduction in the full toll. I would say that we're seeing some volume increases. We continue to be pleased with the sale of capacity on that line. So we don't overall expect there to be a material impact on the revenues from Great Lakes for the year.

Did it reflect in Q2 at all or does it start in Q3 if there is an impact?

I believe it came into effect in May. So there would be a small impact.

It was recorded in Q2, Matthew, but as Greg mentioned, the impact was not material to us.

We have no more questions from the investment community. We will now take questions from the media. (Operator Instructions) Our next question is from Dan Healing from Calgary Herald.

Just a quick question on the open season for the Alaska Pipeline ending tomorrow. Can you give me any idea as to how that's been greeted by shippers and what we might expect from that?

It'd be premature to tell you what we expect from that. We have worked very hard addressing shippers' questions and concerns. I can tell you that there has been a large volume of questions and issues raised. I think that we've done a very good job of addressing those. And we're hopeful that we will see some bids to move gas to market tomorrow.

So the interest has been pretty high then?

Yes, it has been very high. All of the shippers in the North Slope have been engaged in conversation with us.

My other question was with regard to the pipeline oil spill in Michigan. Do you think this will have any affect as you go forward with the Keystone XL approvals?

I don't know the answer to that question. Obviously, it's a very unfortunate circumstance and I guess premature to determine whether or not it has any impact on the permitting process for a pipeline system.

I guess it's not related at all, but in terms of public opinion, it's a significant thing. Is that your fear?

As I said, it's premature we don't know exactly what happened in this case and how it will unfold. So it would be premature for me to make comments on how it would impact our systems.

Our next question is from Scott Haggett from Reuters.

Just a question on the U.S. approval process. Is there any sense that the EA's request for a much broader sense of the impacts of the pipeline, including expansion of oil sands projects, does that have the potential to delay further than the 90 days you're anticipating?

I believe that the Department of State has to determine what the scope of their review is going to be and to-date they have addressed some of those issues. And I would expect that they would address the rest of the questions raised by the EPA. And from what we've been told currently, they are staying on the schedule that they announced here over the last couple of days whereby they will issue their final Environmental Impact Statement and then allow it a 90 day comment period and at this point in time that's what we understand the schedule to be.

(Operator Instructions) Our next question is from Justin Amoah from Argus Media.

I'm wondering what kind of deliveries into Illinois you've been averaging since beginning commercial operations on Keystone?

I think we declared the commercial and service around the end of June. So we are still in what I would call a ramp up phase. I think it's probably been somewhere in these early days, probably around 100,000 barrels a day.

And is that mainly because of the maximum operating pressure restriction or are there other factors in play there?

No, not at all its really just normal things you go through as we commission the pipe. And we'd expect it to be over 400,000 barrels a day, by the end of the year.

We have no more questions at this time. I would like to return the meeting over to Mr. Moneta.

Thank you very much and thanks all of you for taking an interest in TransCanada and your time this afternoon. We look forward to talking to you soon. Bye for now.