TC Energy Corp (TRP) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen. 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. Please go ahead, Mr. Moneta.

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 Glen Menuz, our Vice President and Controller.

Russ and Don will begin today with some opening comments and 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 Investor section under the heading Events & Presentations.

Following their prepared remarks we'll turn the call over to the conference coordinator for your questions. During the question and answer period, we'll take questions from the investment community first, followed by the media. 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 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, 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 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, 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 and good afternoon everyone and thank you very much for joining us. I've spoken to you many times over the last number of years in my role as the CFO, President of Pipelines and most recently as TransCanada's Chief Operating Officer, but 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 the 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, that grow earnings, our cash flow and deliver long-term shareholder value.

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 meeting 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 Don Marchand to this call, TransCanada's new Executive Vice President and Chief Financial Officer. Don has been with TransCanada since 1994 and brings a wealth of knowledge to the CFO position, most recently as Vice President Finance and Treasury since 1999. I can tell you that I've worked with Don for a number of years and I have extreme confidence in his abilities. Don will speak to you in a few moments on our financial results, but before that I want to review some highlights from the quarter and provide an update on some of our key initiatives.

TransCanada's core business of pipe and energy continued to perform well in the quarter in what I'd call a very difficult environment. Net income applicable to common shares for the second quarter was $285 million or $0.41 per share. Comparable earnings were $275 million or $0.40 per share. Both of those numbers were reduced by $28 million or $0.04 per share due to losses on derivatives used to manage our economic risk to rising interest rates and foreign exchange fluctuations that do not qualify as hedges for accounting purposes. In addition approximately $20 million of net income or about $0.03 per share related to the Alberta Systems satellite was not recognized in the first six months of 2010, pending NEB approval of a three-year settlement with our customers.

Comparable EBITDA for the second quarter was $928 million and funds generated from operations in the second quarter were $935 million. Also today the Board of Directors declared a quarterly dividend of $0.40 per share for the three months ending September 30, 2010. Over the next 12 months we will begin to see EBITDA contributions from our many capital projects as construction is completed and those projects become operational. These projects will generate EBITDA of approximately $1 billion in 2011 as they come online.

As I mentioned earlier, we are focused on executing our $22 billion capital program. This program is the engine that will drive much of earnings growth through 2014. Progress towards completing the program on time and on budget continues. We celebrated the start of commercial operations of our Keystone Pipeline System just a few weeks ago near St. Louis. Oil is now flowing to refineries in Wood River and Patoka.

Construction of the Keystone System down to Cushing, Oklahoma continues and is now about one-third complete. This section of Keystone should be operational in the first quarter of 2011 and will increase the capacity from about 435,000 barrels a day to 590,000 barrels per day. Firm, binding contracts are in place for 530,000 barrels of crude to the US Midwest including Cushing, Oklahoma. That's approximately 90% of the initial Keystone's lines capacity. I'll speak a little bit more to the expansion of Keystone and the Gulf Coast in just a moment but I wanted to cover some of the construction at some of our other major initiatives throughout North America.

Construction is set to begin this summer on our Groundbirch Pipeline in Northeast British Columbia. Groundbirch will connect our Alberta system to prolific shale plays in Northeastern British Columbia. We have firm contracts on Groundbirch for 1.1 billion cubic feet a day of natural gas that comes online between 2011 and 2014.

Our other project in that region, the Horn River project continues through the regulatory process. When you add the 540 million cubic feet per day of contracts on Horn River to our contracts on Groundbirch, we will connect a total of approximately 1.6 billion cubic feet a day to our natural gas system in Canada over the next four years. This will offset the Western Canadian sedimentary basin supply decline that we've seen recently on all of our pipeline systems. I would also point out that we have requests for an additional service of about 1 billion cubic feet a day and we expect that interest to turn into contracts in the coming months. So between now and 2014, we could expect to connect up to 2.6 billion cubic feet a day of shale gas to our system from Northeast British Columbia.

Moving to Mexico, in Mexico construction crews continue to make progress on the Guadalajara Pipeline. The pipeline is now 25% complete and gas is expected to begin flowing in the first quarter of 2011. Construction has also started on our $600 million US Bison Pipeline and it is expected to begin delivering natural gas from the US Rockies to markets in the US Midwest in the fourth quarter of this year.

Moving over to the power side, our 683 megawatts power plant in Halton Hills Ontario is virtually complete. We expect the $700 million plant to be fully operational in the third quarter of this year. Construction of our 575 megawatts Coolidge Generating Station is over 60% complete and the $550 million US Power plant should begin producing power in the second quarter of 2011. Both Halton Hills and Coolidge are backed by 20-year power purchase agreements.

So in the coming months we will complete projects that are expected to generate, as I said, about $1 billion of EBITDA in 2011; tangible examples of our disciplined growth strategy producing real results.

We are also about halfway through the toll program and that's an investment of about $12 billion. TransCanada is well positioned to fund the remaining portions of our capital plan. In June we raised $1.6 billion through senior notes and preferred share issues at what I would call very competitive prices.

As I mentioned earlier, we will continue to look for high quality, long-term growth opportunities to build our company. One of those opportunities is the Alaska Pipeline project, an initiative we are working on with ExxonMobil. The open season for that project ends tomorrow. This is the first time the Alaska North Slope pipeline in its history has been to the marketplace to test whether or not natural gas is available to move to market. Working with ExxonMobil we've taken the steps necessary and the actions required to improve and maximize our chances for success. As with all projects like this one, we expect bids for capacity to have many conditions attached. Assuming we receive bids, we would expect to spend the next few months working to resolve those conditions.

I also want to talk a little bit about our Canadian Mainline for a moment. We told you last fall that we are working with shippers to develop a proposal that would improve the competitiveness of the Western Canadian Sedimentary Basin, while also improving Mainline toll stability and certainty. I can tell you that these talks have been going on for a number of months and they continue as we discuss a very comprehensive proposal. The Mainline is a very important piece of North American infrastructure that will indeed be needed for many years to come. The marketplace is changing and obviously we have to change with it. We will continue to listen to our customers' concerns, understand those concerns and try and find the very best way of adapting.

TransCanada has a successful track record of working out changes with our customers and adapting our systems to meet a changing environment. Some recent examples include the settlement on the Alberta/Foothill System which we announced today, the move to have the National Energy Board oversee the Alberta System which has been very beneficial to our accessing Northeast British Columbia, and the integration of the ATCO Pipeline system into our Alberta System.

Now I want to turn back to the Keystone Pipeline and our expansion of the Gulf Coast. Let me start by saying that the market has spoken and the shippers have signed binding long-term contracts for 380,000 barrels a day or about 75% of the capacity of Keystone Pipeline's - Keystone XL's initial capacity to deliver oil to refineries along the Gulf Coast. These shippers are not only Alberta producers, but they are also Gulf Coast refiners who are looking to diversify their sources of crude oil. When combined with the base Keystone system, TransCanada has binding, signed contracts with producers and refiners to transport crude oil for an average of 18 years for a volume of 910,000 barrels per day or about 83% of the line's initial 1.1 million barrels a day of capacity. These contracts clearly demonstrate that Keystone is very much needed by the marketplace.

The United States today refines about 14 million barrels a day of oil and consumes about 18 to 20 million barrels per day; oil that's used to heat people's homes, operate their cars and ship their goods to market and to run their businesses. Over 9 million barrels of that crude oil is imported from countries outside the US such as Venezuela, Nigeria, Saudi Arabia, Mexico and Canada and on a wells to wheels basis Canadian heavy oil greenhouse gas emissions are the same as other sources of heavy crude oil that are currently supplying Gulf Coast refineries.

The fact is, the US economy relies on oil imports and Canada provides the most friendly, reliable and secure supply of imported oil for our neighbors to the South. We all agree that North America is moving to a less carbon intensive environment but this will take some time and the US will continue to rely on imported oil for many years to come and Canada is well positioned to obviously fill that need.

Pipelines have proven themselves to be by orders of magnitude the safest mode to transport oil to market. A US Department of State included this spring in its Draft Environmental Impact Statement that after two years of public consultation the Keystone expansion would have limited impact on the environment. TransCanada will continue to work with the Department of State through its extended 90-day comment period following the release of the final Environmental Impact Statement. We consider this an opportunity to explain the benefits of Keystone XL and the importance of this project to US energy security. Impact on construction is expected to be minimal. We have built in contingencies so assuming we assume regulatory approvals in Q1 2011, construction could begin shortly thereafter.

In addition to Keystone being safe, reliable and environmentally responsible, it will provide a $20 billion boost to the US economy, over half a billion dollars in state and local taxes during the construction period and thousands of high paying jobs, all at a time when economic stimulus is required in the United States, so Keystone makes sense on a number of fronts.

We will develop the project in a responsible manner as we have developed all of our projects over the past 50 years, with a focus on safety and respect for the environment and the communities where we work.

I'll now turn the call back over to Don Marchand who will provide some additional details on the first quarter financial results. Don?

Thanks Russ and good afternoon everyone. I'm pleased to have a chance to speak with you today. It is a privilege to have the opportunity to serve as Chief Financial Officer during such an important time in the company's history and 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 minutes or so elaborating on these themes and our second quarter 2010 results. Net income applicable to 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 in the translation of certain US dollar working capital balances.

In addition, in the first six months of 2010, $20 million of net income or $0.03 related to the three-year Alberta System settlement as yet to be recorded pending final approval by the National Energy Board. We expect to receive NEB approval in the third quarter of this year, at which time the impact of the settlement from its effective date of January 1, 2010 will be recognized.

Other notable items affecting comparable earnings in second quarter 2010 were lower contributions from Bruce Power, higher realized power prices in Alberta and lower net interest expense resulting from the capitalization of interest related to the company's large construction program. On a per share basis, comparable earnings in second quarter 2010 were also reduced by approximately $0.05 per share as a result of a 10% increase in the average number of outstanding common shares, primarily due to the $1.7 billion common share offering in June 2009. The dilution associated with this prudent approach to financing our very large multiyear projects in what is proving to be persistently volatile market conditions will continue to have a near-term impact on our EPS. That being said, our $22 billion capital program is expected to generate significant growth and stable long-term earnings and cash flow as projects are completed and assets commence operations.

As Russ mentioned, we expect to generate approximately $1 billion of incremental EBITDA next year as projects such as Keystone, the Halton Hills and Coolidge Power Generating stations and the Guadalajara and Bison natural gas pipelines enter full commercial service and begin contributing to earnings and cash flow.

I'll now briefly describe the business segment results at the EBITDA level. The Pipelines business generated comparable EBITDA of $696 million in the second quarter compared to $747 million in the same period last year. The decrease is primarily for two reasons; the negative impact of the weaker US dollar on US pipelines results and a reduced revenue requirement in the Canadian Mainline that does not impact Mainline net income. I'd note that although the first phase of Keystone is now in commercial service, cash flow will be capitalized until the project is operating at its initial design capacity of 435,000 barrels per day. This is expected to occur in the fourth quarter.

Energy generated comparable EBITDA of $254 million in second quarter 2010 compared to $301 million in the same period last year. Higher earnings in Western Power resulting from an increase in realized power prices in Alberta and higher capacity revenue from Ravenswood were more than offset by lower contributions from Bruce Power, lower natural gas storage revenues and the negative impact of the weaker US dollar. On a consolidated basis, the impact of the weaker US dollar on both US pipelines and energy EBITDA is considerably offset by the positive impact on US dollar denominated interest expense.

Now turning to the income statement items below EBIT on slide 25. Interest expense in the second quarter was $187 million compared to $259 million in the second quarter last year. This decrease of $72 million is primarily due to increased capitalization of interest related to our sizeable capital program and a reduction in US dollar denominated interest expense as a result of the impact of a weaker US dollar, partially offset by higher interest expense from the issuance of US1.25 billion of senior notes in early June 2010 and losses from derivatives used to match the company's economic exposure to rising interest rates.

Interest income and other in the second quarter 2010 was an expense of $18 million compared to income of $34 million for the same period last year. The decrease was primarily due to losses on derivatives used to manage the company's economic exposure to US dollar denominated income and from the translation of certain US dollar working capital balances.

The company seeks to achieve hedge accounting treatment for its derivatives, however, in some circumstances this is not possible. As we have indicated in the past, TransCanada is exposed to movements in exchange rates as a result of its US operations. Although this exposure is considerably offset by US dollar debt which serves as a natural hedge, our US dollar operating income exceeds US dollar interest expense, leaving us with a net long US dollar position.

We further manage this resulting economic exposure to movements and exchange rates by using derivatives which do not qualify for hedge accounting. Similarly, the company uses derivatives to manage its exposure to rising interest rates, certain of which also do not qualify for hedge accounting. The combined negative impact of losses in second quarter 2010 for the interest rate and foreign exchange rate derivatives did not qualify as hedges for accounting purposes and the translation of certain US dollar working capital balances amounted to $28 million or $0.04 per share.

Income taxes were $65 million in second quarter 2010 compared to $97 million for the same quarter last year. The decrease was primarily due to produced pretax earnings and the net positive impact from income tax rate differentials and other income tax adjustments.

Moving on to review cash flow and capital expenditures on slide 26. Funds generated from operations increased to $935 million in second quarter 2010 compared to $692 million in the same period in 2009. The increase is mainly due to the income tax benefit generated from bonus depreciation for US income tax purposes on Keystone assets placed into service on June 30th, partially offset by lower earnings. Capital expenditures were $1 billion in second quarter 2010, principally related to the construction of Keystone, the Coolidge Power Plant, the Guadalajara and Bison natural gas pipelines and the Bruce A restart.

Now looking at slide 27. At the end of the second quarter our consolidated balance sheet consisted of 51% debt net of cash; 3% junior subordinated notes; 4% preferred shares; and 42% common equity. At the end of the second quarter we had over $1.2 billion of cash on hand, along with undrawn committed revolving bank lines of $4 billion. Our two Canadian commercial paper programs remain well supported and an attractive source of short-term funds.

In June 2010, TransCanada issued US500 million of five-year and US750 million of 30 year senior notes at coupon rates of 3.4% and 6.1% respectively. Also in June, TransCanada completed its second public offering of cumulative redeemable preferred shares this year, resulting in gross proceeds of $350 million at a yield of 4.4%. With approximately $2 billion of capital raised year-to-date, in addition to proceeds from the dividend reinvestment program, TransCanada is well advanced in securing its 2010 funding needs.

Going forward the company will continue to monitor market conditions and seek to raise additional senior and subordinated capital on both sides of the border. We will also continue to examine opportunities for portfolio management, including a role for TC Pipelines, LP and financing our capital program.

That's the end of my prepared remarks. I'll now turn the call back to Russ for some concluding comments.

Thanks Don. 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 will 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 of 2014 and we will continue to reinvest our cash flow in high quality new projects.

Today we have three platforms for growth; gas pipelines, oil pipeline and power generation and as we've seen, there are numerous opportunities to further expand our oil pipeline business and we will 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 strategy is unchanged. We will maintain our disciplined approach, growing our core businesses and reinvesting in new opportunities, we'll focus on increasing TransCanada's cash flow, increasing our earnings and driving dividend growth. The result, in the end, long-term, enduring growth and value for our shareholders.

I 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 will take questions from the investment community first and following that, we'll open the line to the media. With that, I'll turn it back to the conference coordinator for your questions.

(Operator instructions) Our first question is from 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?

Just with respect to Bruce 1 and 2, 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 o 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 off site towards the end of January of 2011 and in that time we're going to have de-staffed the project by about 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, Glen?

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 pricing of contracts year-over-year was probably about $0.02 to $0.03 but also last year had an amount in there for about a penny per share related to Q1 2009, so that's sort of the combined impact on a year-over-year basis. And as Alex says, these contracts have continued to roll off.

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

With respect to the Canadian Mainline and the indications that volumes may be 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. Could you quantify - 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?

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

Appreciate that, Greg. 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 interests, 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?

First I'd say that we are working diligently with our shippers. We're pleased that our shippers are engaged and are interested in working towards a settlement and I think we all recognize all the customers and TransCanada that we need to work together in order to develop a tolling 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'll work to get a unanimous settlement, but with diverse interests it's possible that we may not get 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 can and then we'd work with the NEB on a process to get those proposals approved over the next number of months following that filing.

Your 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 on 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 rate 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 discreet 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?

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

Your next question is from Bob Hastings with 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 to 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 what we've tried to do is give you the capital costs of the projects there. I think you can get a sense of the useful life in there for the 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, roughly the capital structure that we've had in the past for these kinds 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 that long-term probably 60/40 is kind of a good run-rate. And as well you know the IRR on these projects and we tried to do some back calculation and multiples, 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 (inaudible)? Do you think they're locked in there or are more opportunities coming, would you look at any processing?

I do believe that there's more opportunity for growth if you believe some of the producer estimates they're far in excess above what we've contracted to date or even the indications of interest, as I think I mentioned in my opening remarks. Current interest level is in around that 2.5 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 they be 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 move 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 make a 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 netback and doesn't have the same liquidity that we have to offer. Those are the reasons I guess we've been hearing from them as to why they've been signing up with our system.

Whether they choose to 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 netback is on a given day, we can get their 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 I 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 looked 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 their bullet pipeline that goes to essentially one market where coming to our system offers up other things. So 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 a competitive market was required to compete head on with folks offering other services.

Your next question is from Matthew Akman from Macquarie.

I have two questions, one on 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 comment 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, 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 even if 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 guess if it was delayed for a very significant amount of time, which we're not anticipating, 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.

Okay thanks. 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 a 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's 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.

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

Russ, you mentioned earlier, just coming back to Mainline, you had the 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. 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 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 or slightly higher kind of prices, 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 if there's a positive environment where you would see demand increase. So those are the things that I'm 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 slowdown the depreciation of our systems and the collection of capital, but there's no reason in my mind that I could see that we would need to have a reduction in return on capital, 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 or capital collection to meet what I think 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 wouldn'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 marketplaces. In a regulated business we have the opportunity to recover our costs, of which one of those costs is our return on capital and there's no reason in my mind right now why we wouldn't be able to continue to collect our costs on the system, whether it be return of capital or other components of the revenue requirements. 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.

Okay. And 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 100% basis it would have been about 30 million give or take and I think ours is - so half of that is like 14-15, in that range.

Your 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 Center. 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 and Oakville in many ways are in similar situations 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 at significantly below standards. So I think similar situations apply to Oakville.

Obviously it's no secret, that community or 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 issues or legal claims or issues that we have, trying to attack some of the actions that the municipality is taking 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're relying on them.

Somewhat related question; do you see any opportunities within the Ontario market for TransCanada to be involved in transmission? Clearly there are 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 that the vast, almost overwhelmingly all of our power in Ontario is either regulated or quasi-regulated, I don't think there would really be sort of 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's a lot of opportunities. What I would say is there's 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 that, 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.

Your 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 and how your capital structure might look in terms of maximum percentages of hybrid and preferred type securities in the mix?

So Moody's has come out and basically looking at junior subordinated notes, basically give 25% equity credit to those types of securities, but the preferred shares we have in our capital structure, they're getting 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 have distinct circuit breakers on these, so we would think that we've got maybe a couple percent left but probably wouldn't go beyond 10-11% of the capital structure.

That's helpful. 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?

Sure. 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's share of our profits in the winter period.

Your next question is from Steven Paget from FirstEnergy.

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

Obviously this just came out this week; we're taking a look at it, but as we 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) Your next question is from Chad Friess from UBS.

Question for Alex. We've seen fairly hot summer in the Northeast so far. I was wondering what impact it's having on utilization at Ravenswood and in general how the Northeast 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 had anticipated. Ravenswood has been running particularly through the hot period, running almost all of the units flat out and on peak period, 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 kind of sort of 58, maybe $58-$59, $58 in 2011 and then sort of $62-$63 in 2012. 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 has buoyed the forward markets a fair bit.

Your next question is from Matthew Akman from Macquarie.

Just a quick follow-up on Great Lakes. I noticed that there was I think 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 an 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 and 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's 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 first question is from Dan Healing from the 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, what we might expect from that?

I think it would 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's 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 more gas to market tomorrow.

Okay, so the interest has been pretty high then?

Yes, it has. It's 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 effect 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'd say it's premature to determine whether or not it has any impact on the permitting process for our 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'd be premature for me to make a comment on how it would impact our systems.

Your next question is from Scott Haggett from Reuters.

Just a question on the US 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're 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 a 90-day comment period. At this point in time, that's what we understand the schedule to be.

(Operator instructions) Your 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?

We declared commercial in 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.

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

No, not at all. It's really just the 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.

Thanks very much and thanks to 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.

The conference has now ended. Please disconnect your lines at this time and we thank you for your participation.