TC Energy Corp (TRP) 2007 Q2 法說會逐字稿

Good day, ladies and gentlemen, welcome to the TransCanada Corporation 2007 second quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Communication. Please go ahead, Mr. Moneta.

Thank you, and good day, everyone. I would like to take this opportunity to welcome you today. We're pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2007 second quarter financial results and other general issues concerning TransCanada. With me today are Hal Kvisle, President and Chief Executive Officer; Greg Lohnes, Executive Vice President and Chief Financial Officer; Russ Girling, President of Pipelines; Alex Pourbaix, President of Energy; and our Vice President and Controller, Glen Menuz. Hal and Greg will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com. It can be found in the investor section under the headings conference calls and presentations.

Following Hal's and Greg's 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, Miles and I would be pleased to discuss them with you following the call.

Before Hal begins, I would like to remind you that our remarks today will include forward-looking statements and are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U.S. Securities and Exchange Commission. Finally, I would also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, and funds generated from operations. These measures do not have any standardized meaning prescribed by Generally Accepted Accounting Principles and are therefore considered to be non-GAAP measures. As a result, these measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide interested parties with additional information on the Company's operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I'll turn the call over to Hal.

Thank you, David. Good morning, everyone, and good afternoon to those of you out east. Thank you all for joining us today. I'll take a few minutes to talk about recent developments in our business and then turn the call over to our Chief Financial Officer, Greg Lohnes, who will review our financial results in more detail.

TransCanada's strong financial performance during the second quarter and on a year-to-date basis continues to demonstrate that our disciplined approach to growing our portfolio of high quality energy infrastructure assets is creating value for shareholders. We continue to advance a large portfolio of pipelines and energy projects. For the second quarter of 2007, TransCanada Corporation's net income from continuing operations was $257 million, or $0.48 per share compared to $244 million, or $0.50 per share in the second quarter of 2006.

Comparable earnings were $241 million, or $0.45 per share for the second quarter of 2007 versus $198 million, or $0.41 per share in the second quarter of 2006. That's an increase of approximately 10% on a per share basis. Funds generated from operations since second quarter 2007 were 11% higher at $596 million compared with $539 million for the same period in 2006.

TransCanada's Board of Directors declared a quarterly dividend of $0.34 per share for the quarter ending September 30, 2007 on the outstanding common shares. Shareholders that reinvest their dividends in additional common shares of the Company through our dividend reinvestment and share purchase plan will continue to receive common shares from treasury at a 2% discount to the average market price. You will hear more about our financials in a few minutes from Greg Lohnes.

Let me turn now to pipelines. During the second quarter, we were pleased to announce a successful open season on the Keystone oil pipeline after shipping commitments for 155,000 barrels per day were secured from Hardisty, Alberta through to Cushing, Oklahoma for periods averaging 16 years. This brings our total contracted commitments on the Keystone oil pipeline to 495,000 barrels per day. The results of this open season support an expansion to 590,000 barrels per day, an extension of the pipeline to Cushing.

Another step forward on the Keystone project, was the National Energy Board Public Hearing related to the construction and operation of Keystone's Canadian facilities. That public hearing ended on June 21, and we expect a decision before the end of 2007.

Regarding our Canadian gas transmission system, our five-year settlement with interested stake holders for years 2007 through 2011, on the Canadian Mainline was approved by the National Energy Board in May 2007. The agreement released a 2007 tolls and costs for years 2008 through 2011. The settlement reflects an increase in the deemed common equity from 36% to 40%. This settlement demonstrates our continued commitment to working with our gas transmission customers towards mutually beneficial outcomes.

The National Energy Board has also approved TransCanada's application to add Gros Cacouna, Quebec as a receipt point on our integrated Mainline system and reaffirm the existing rolled in toll methodology on the PQM pipeline system.

In June of 2007, TransCanada made an application to the Alberta Energy Utilities Board for approval to construct approximately $300 million of new facilities on the Alberta System to initially serve the growing demand for natural gas in the Fort McMurray region of Alberta.

In our U.S. gas transmission business, the ANR pipeline system received regulatory approval to proceed with a 14 Bcf natural gas storage expansion project in Michigan. This capacity is fully contracted with an expected in-service date of April 2008 for injections and November 2008 for withdrawals. This project is in addition to a natural gas storage enhancement and expansion program that will increase Michigan capacity available for sale by 13 Bcf. This program was also fully subscribed with injections commencing in April 2007. The expected capital cost of both projects is $125 million U.S. dollars. Also in the United States, TransCanada successfully assumed operatorship of the ANR, Great Lakes and Northern border gas transmissions, transmission systems. And in Mexico, we commenced physical gas deliveries on the Tamazunchale pipeline in east central Mexico.

Turning now to our energy business, the Cacouna Energy LNG project, a joint undertaking of TransCanada and PetroCanada reached a number of important milestones in recent months. Federal Cabinet approval was provided, as well the Quebec Government granted a decree approving Cacouna reclassification terminal and facilities. And as discussed earlier, the National Energy Board has approved the Gros Cacouna receipt point and rolled in tolling methodology for the connecting pipeline.

On the power front, construction is progressing on the Bruce A restart program, the Portlands Energy Centre in downtown Toronto and on the Cartier Wind energy project in Quebec. Preconstruction activities continue at the Halton Hills generating station and in addition to these active projects our energy team continues to pursue a number of large scale power and other energy developments in Canada and in selected regions of the United States. I'd now like to turn the call over to Greg Lohnes, who will provide additional detail on our financial results. Greg?

Thanks, Hal, and good morning, everyone. As Hal mentioned earlier today, we released our second quarter results. Net income from continuing operations, or net earnings for the second quarter were $257 million, or $0.48 per share compared to $244 million, or $0.50 per share for the same period last year. Second quarter 2007 net earnings included positive income tax adjustments of $16 million. Second quarter 2006 net earnings included a $33 million favorable income tax adjustment and a $13 million gain on the sale of TransCanada's interest in Northern Border Partners LP. Excluding these items, comparable earnings were $241 million, or $0.45 per share in the second quarter 2007 compared to $198 million, or $0.41 per share for the same period last year, an increase of approximately 10%. The quarter-over-quarter increase is primarily due to income from the acquisition of ANR, and the start-up of the Becancour Co-Generation plant in September 2006, as well as higher income recorded due to a five-year settlement on the Canadian Mainline.

I will briefly review the second quarter results for each of our segments beginning with pipelines. The pipelines business generated net earnings of $166 million during the second quarter compared to $147 million for the same period in 2006. Excluding the $13 million gain on the sale of Northern Border Partners LP in the second quarter 2006, comparable earnings from the pipelines business increased $32 million. The increase was primarily due to the contribution from ANR and an increased contribution from the Canadian mainline partially offset by a lower contribution from GTM. TransCanada completed the acquisition of ANR on February 22, and included net earnings from that date. Earnings to date are generally in line with our expectations. ANR's revenues are primarily derived from its interstate natural gas transmission, storage, gathering and related services. Due to the seasonal nature of the business, volumes, revenues and net earnings are generally higher in the winter months.

The higher contribution from the Canadian Mainline reflects the impact of the five-year toll settlement effective January 1, 2007 to December 31, 2011. The settlement included an increase in deemed common equity from 36% to 40% and was approved by the National Energy Board in May 2007. The settlement also allows for performance-based incentive arrangements that will provide mutual benefit to both TransCanada and its customers. The Canadian mainline net earnings increased $14 million for the second quarter when compared to the same period last year. The increase was primarily related to the higher common equity ratio, certain performance-based incentive arrangements, and operations, maintenance and administrative cost savings under the settlement.

Six million of the increase is related to previously unrecorded earnings resulting from the settlement related to the first quarter 2007. The increased earnings were partially offset by a lower rate of return on common equity. The lower contribution from GTN was primarily due to lower operating revenues as a result of lower contracted long-term firm volumes, higher maintenance costs and a higher provision for nonpayment of contract transportation revenues from a subsidiary of Cal Pine Corporation that filed for bankruptcy protection. A $4 million decrease in TransCanada's proportion share in net earnings from other pipeline was mainly due to higher project development and support costs as a result of growing the pipeline's business and decreased earnings from GasPacifico Energy. These decreases were partially offset by the addition of earnings from Tamazunchale and increased earnings from Portland and TransGas.

Next, some comments on energy. The energy segment includes our power operations, as well as our initiatives in unregulated natural gas storage and liquefied natural gas. Energy generated net earnings of $94 million in the second quarter 2007 compared to $97 million in the same period last year. Excluding $4 million of income tax adjustments in the second quarter '07 and $23 million of income tax adjustments in the second quarter '06. Comparable earnings of $90 million increased $16 million quarter- over-quarter. The increase was primarily due to higher contributions from western power operations, eastern power operations, and natural gas storage. These increases were partially offset by a lower contribution from Bruce Power and higher general, administrative and support costs.

Bruce Power contributed $31 million of pretax operating income in the second quarter compared to $41 million last year. The $10 million decrease was primarily due to higher post employment benefit costs and other employee-related costs, as well as higher costs associated with changes in the scope of planned outages. These impacts were partially offset by higher revenues resulting from increased generation volumes. TransCanada's share of Bruce Power's generation increased 97 gigawatt hours as a result of fewer planned maintenance outage dates in the second quarter 2007.

Looking forward, two planned outages are scheduled for Bruce A in the remainder of 2007. Bruce A unit 3 is now expected to have an outage lasting approximately 1.5 months beginning in late third quarter. Bruce A unit 4 is expected to have an additional outage lasting approximately one month in early fourth quarter.

Turning now to western operations, western operations operating income was $57 million in the second quarter compared to $46 million last year. The $11 million increase was primarily due to increased margins from the Alberta power purchase arrangements resulting from the combination of slightly higher overall realized power prices, increased volumes, and lower PPA costs. The average spot market power prices in Alberta decreased 7%. However, western power operations sold fewer volumes into the spot market and recontracted at higher overall realized prices in the second quarter 2007 compared to the second quarter 2006. In the second quarter 2007, approximately 21% of western power sales volumes were sold into the spot market--

I apologize for the interruption. Mr. (Inaudible) joined our conference.

-- compared to 26% in the second quarter last year. To reduce our exposure to future spot market prices, western power operations has fixed price sales contracts to sell approximately 5300 gigawatt hours for the remainder of 2007, and 7400 hours gigawatt hours for 2008. Generation volumes increased by 21% in second quarter 2007 compared to the same period last year, primarily as a result of the return to service of the Bear Creek facility in the third quarter 2006, and a planned maintenance outage at the Mackay River facility in second quarter 2006.

Finally, in power, eastern operations operating income in the second quarter was $70 million, an increase of $27 million compared to the second quarter of last year. The increase was primarily due to incremental income earned in 2007 from the start-up of the 550-megawatt co-generation plant in September 2006. Payments received under the forward capacity market in New England, and margins earned on incremental volumes sold to new customers.

In the second quarter 2007, approximately 96% of eastern power sales volumes were sold under contract. To reduce our exposure to future spot market prices, eastern operations has fixed price sales contracts to sell approximately 7200 gigawatt hours for the remainder of 2007 and 11,000 gigawatt hours for 2008. Although certain contracted volumes are dependent on customer usage levels.

Finally, in the energy segment, natural gas storage operating income of $20 million in the second quarter increased $3 million compared to the same period last year. The increase was primarily due to incremental income earned in 2007 from the start-up of the [Essen] facility in December 2006. I will take a few minutes to discuss in more detail how we account for our natural gas storage business in Alberta following a discussion of our corporate results and financial position.

Turning now to corporate, net expenses from corporate in the second quarter 2007 were $3 million compared to nil in the same period last year. Excluding favorable income tax adjustment in the quarter, corporate's comparable expenses were $15 million to 10 million in the second quarter '06. The increase in net expenses was primarily due to higher financial charges as a result of financing the ANR and Great Lakes acquisitions.

Turning to the cash flow statement, funds generated from operations were 596 million in the second quarter, an increase of 57 million, or 11% when compared to the same period in 2006. Capital expenditures in the second quarter were approximately $386 million and related primarily to the ongoing development of Greenfield projects, such as the Bruce A restart, Portland's Energy Centre, Halton Hills and Cartier Wind, as well as growth and maintenance capital associated with the Canadian Mainline and the Alberta System.

Finally, our financial position remains strong. At the end of June, our balance sheet consisted of 58% debt, which included junior subordinated notes and our proportion share of joint venture debt, 2% preferred securities, 2% -- 1% preferred shares, and 39% common equity. Regarding preferred securities, on July 5, 2007, TransCanada redeemed at par all of the outstanding U.S. dollars 460 million 8.25% preferred securities due 2047. The redemption of these preferred securities was exercised in conjunction with the National Energy Board approved 5 year settlement for the Canadian Mainline.

In April, the Company issued U. S. dollars 1 billion of junior subordinated notes maturing in 2067 bearing interest at 6.35% until 2017, at which time the interest on the notes will convert to a floating rate reset to the three-month LIBOR plus 2.21%. TransCanada continues to manage the balance sheet in a prudent manner consistent with maintaining our A credit rating. A strong balance sheet and our significant discretionary cash flow will continue to provide us with the financial flexibility to make future investments in our core businesses.

I will now take a few minutes to review how we account for our unregulated natural gas storage business in Alberta. As we mentioned in our second quarter report, since Canada manages its natural gas storage asset exposure with a portfolio of third-party storage capacity leases and proprietary natural gas purchases and sales. Earnings from third party storage capacity leases are recognized evenly over the term of the lease. Earnings from proprietary natural gas sales are recognized when the natural gas is sold, which typically occurs during the winter withdrawal season.

Back to back proprietary transactions are comprised of a forward purchase and injection of natural gas at lower prices, and a simultaneous forward sale and draw in later periods of natural gas at higher prices. By matching purchases and sales volumes and thereby locking in a margin, TransCanada eliminates exposure to the price movement of natural gas. Based on the asset's physical capabilities, TransCanada actively manages the proprietary transactions to create incremental margin. This active management mandates fair value, or mark-to-market accounting.

On April 1, 2007, TransCanada adopted an accounting policy to record its proprietary natural gas storage inventory at it's fair value using the one-month forward price for natural gas. Fair value accounting rules require TransCanada to fair value the proprietary forward contracts at the forward prices for their contracted delivery month and fair valued the related inventory at current market prices. The change in fair value creates unrealized, or non-cash gains or losses. The unrealized gains or losses reverse when the gas is sold and the revenue is recognized.

There is the potential for non-cash earnings volatility, even though the inventory is economically hedged. This is due to the mismatch in the movements of the next month price used to fair value the inventory versus the delivery month forward price used to fair value proprietary transactions. These fair value calculations represent a theoretical liquidation value and are not reflective of the storage businesses actual locked in margins. Therefore, we intend to remove any material fair value adjustments for comparable earnings purposes. The net change in fair values of proprietary gas storage inventory and forward contracts included in income in the second quarter of 2007 was not significant. That concludes my prepared remarks. I will now turn the call back to David for the question-and-answer period.

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

Thank you. (OPERATOR INSTRUCTIONS) The first question is from Bob Hastings of Canaccord. Please go ahead.

Thank you very much. Clarification and the mainline incentives that you reported, there would have been something for the Q1 as well. Can you let us know what the breakout of that was?

Can you say that again, Bob? I didn't hear the end of the question.

The incentives you recorded in the second quarter, were some of that applicable to the first quarter and if so, can you give us a breakout between the amounts between the quarters.

It was, and Glenn will give you that number.

Hi, Bob. It's Glenn here. Yes, there was a portion of it that was related to first quarter. As we noted in our disclosure with the settlement coming in in the second quarter retroactive to January 1, both the increased deemed equity component, as well as the approval of any incentives would have covered both periods. And it was relatively even between the periods. I think the total, Bob, was approximately $6 million after tax that related to the first quarter.

Okay. I saw the 6 million. I wasn't sure if that included the incentives.

It does.

It does.

Okay. Thank you. Clarification, on the ANR, you mentioned the seasonality, most, more was coming in the winter months. Can you give sort of some kind of general breakout by quarter now that you've got a little under your belt?

Yes, I can give you maybe historically the portion of sort of what I call say the 6 winter months-- something like a 60/40. The summer months being 40%, winter months being about 60%. So that's sort of the November to March, April in the 60s and then the summer months being the 40.

Right. So the implication being that the third quarter shouldn't be too much different than the second quarter's and the big jumps will be the first and fourth quarters?

Yes, think that's probably, probably about right.

Okay. Thank you.

Slight seasonality in the numbers, but that's about where, where we expect things to land. The summer, obviously, the mid summer's going to be softer than the second quarter. But it's not that large between the months.

Okay. Thank you very much.

Thank you. The next question is from Robert Kwan from RBC capital markets. Please go ahead.

Great. Thank you. Just you noted on the change in the GTN earnings, you noted increased maintenance with the Cal Pine provision and then the lower long-term contracting. Is it possible to get just a breakout between those three pieces?

Breakdown between those, Glenn?

With, with -- were you looking, Robert, for the quarter or for the year to date?

For quarter, so year-over-year.

Okay. Probably fairly even split between changes in O&M versus the lower long-term revenue and the long-term revenue would obviously be impacted by the Cal Pine volumes.

Okay. So do you have the specific number then for the Cal Pine Provision? It's approximately in the $1 million a month range, maybe a little less, but round somewhere to about a million a month. Okay, and then just on Edson, how much of Edson are you viewing as being operationally in service right now?

This is Alex. We are right now working on about 40 PJs for '07.

Okay. And what's your thoughts in terms of -- at what point will you be up to full availability?

I, I think our -- we want to be fairly cautious and conservative about this as we really figure out the characteristics of the reservoir, but our estimation is that by '09 we should be up to the full capacity of the reservoir, which would be about 58 PJs or 50 Bcf.

Right. Thanks, Alex.

Okay.

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

Thank you. Good afternoon. This question is for Hal. When you look at some of the U.S. MLPs, and in particular, the valuations attached to some of the U.S. MLPs, how do you intend on surfacing some value for TransCanada at a corporate level with some of your U.S. asset base?

Well, Andrew, there's two parts to that question. One is how do we maintain those assets as good platforms for growth for TransCanada? And that's a good argument for keeping them in the current form. We have greater flexibility and ability to add value and augment those assets if they are held in corporate form.

You can capture the MLP value in a couple of ways, one by actually doing a transaction in which case you're done, and the other is just retaining the option. And at some point in time when it suits us, take advantage of the valuation in the MLP market. We, of course, would like all the analysts of our company to recognize that option value and reflect it in our share price and to some extent we think that is reflected today. But I do appreciate the essence of your question, that the U.S. MLP market is very attractive right now and may not remain that way forever.

We did move in that direction by putting a significant amount of Great Lakes into the MLP and significantly increasing our ownership of Northern border through the MLP. Those were strategic moves for us, getting 100% in the family, so to speak, of Great Lakes and getting 50% in operatorship in Northern border. I think I would call both of those win-win deals for TransCanada and the MLP. We have a lot of other options, and we'll make those moves carefully, always wanting to retain the strategic value of the asset for TransCanada.

Well, just following up on that, considering you are the GP of TC pipelines LP, wouldn't it be logical from a capital efficiency standpoint to vend something like ANR into TC pipelines LP, assuming that they would actually like to buy it, and then from a capital efficiency standpoint, you would have enhanced returns because you are the GP?

I guess that depends on whether or not you think we can do some fairly significant strategic things with ANR that we would like to do with TransCanada capital if we wanted to invest significantly in some parts of ANR or reconfigure that asset in different ways. There's much more upside to ANR than just a simple financial restructuring in my view. And so we want to work on that in a very deliberate way. I appreciate your point, but there are down sides to converting all of our U.S. assets into MLP form and we're aware of those and we're pursuing all of these options in a longer-term rather than shorter-term timeframe.

That's great. Thanks, Hal.

Thanks, Andrew.

Thank you. The next question is from Karen Taylor from BMO capital markets. Please go ahead.

Thank you. I just have two quick questions. David, for you, following up quickly on the effective taxation rate for the storage group as well as Bruce?

Yes, I got your message, Karen, and it remains the same as the first quarter. It's approximately 34% for both Bruce Power and for the unregulated gas storage business in Alberta.

And I don't know if maybe this is for Alex. Can you just talk about the cost profile at Bruce, what it looks like for the second half of the year and perhaps give us some view about whether that's going to ease off in 2008?

Well, I think, sure, Karen. I think you'll recall that I guess it would have been at our, at our end of the year conference call for last year that I had suggested that we were expecting operating costs to be moving up in the range of about 11%. And I think that's, that's probably -- I think we're going to end the year. I think that number is a very valid number for '07 and I think it's a valid number for '08 and going further.

So an incremental 11% for '08 versus '07?

No, no, no, '07 will be 11% above '06.

Yes.

And that that level will continue.

So no material increase then for '08?

We're not expecting anything.

Okay. Thank you.

Okay.

Thank you. The next question is from Matthew Akman from CIBC World Markets. Please go ahead.

Thank you. Hal, there's been a lot of speculation about what happened, what might happen with McKinsey valley pipeline in the last while, including things like TransCanada taking a much bigger interest in it. I wonder if you care to comment on the situation and whether TransCanada would be interested in stepping up for a bigger stake in that pipeline, if the terms were reasonable.

That's a good question, Matthew, and not one I can give a very clear or conclusive answer to. In any pipeline project that we're involved in, we would rather have a larger interest than a smaller one. So, so McKinsey, like any other pipeline, we would like to increase our interest. The issue here though is really about how do you build a major basin opening pipeline that will benefit Canada, that will benefit the core producers and will set the stage for a lot of exploration and production activity long-term. It's a very complex thing. It's difficult for the core producers to undertake that kind of a project when many other stake holders will get benefits out of it.

Capital costs are challenging right now. We're in the most expensive period that we've seen for a long time, and uncertainty in the gas market, gas prices very volatile and it's just difficult to go ahead with a 30-year timeframe project in the face of that volatility. So all of those issues, the capital costs, the ownership structure, the involvement of the federal government, the outlook for commodity prices, and so forth, these are big issues, but on top of all of that, we've got this incredibly difficult regulatory environment in which we are now into the fourth year of trying to get regulatory approvals for this project.

More than that, if you think about the work that was done preparing for the regulatory process, and we're still not done, and the issues that are being considered by the regulatory panels in many cases are social and not directly related to the construction of a pipeline. So I would say for this project to go ahead, we've got to get the capital costs under control, or at least develop comfort around them. We've got to bring an end to this endless regulatory process, we've got to reach agreements between all the parties and the federal government, and we have to see a gas price outlook that makes it fundamentally attractive to do this. So, much to be done. We're working hard on it. The other co-ventures are working hard on it, and we hope to get to the next stage soon.

Okay. Maybe I could shift with a question on the pipeline that seems to moving forth a little bit faster which is Keystone, and I'm not sure if you guys have ever clarified your ownership interest in that pipeline, and now that some open seasons have concluded successfully, can you comment on how that's shaping up?

Andrew, we currently own 100% of the Keystone project, and at a certain point in time, Conoco Phillips will be given the option to back into 50% of that ownership, and that will come at a time shortly down the road here.

So they have, they will have an option and may or may not exercise all or part of it, or--

I think it would be all, all or none of that 50%.

And TransCanada, given the returns that you're seeing on that pipeline with the open season contracts and so on, are you happy taking more of that investment? Is it meeting your hurdle rates?

It is, and I think as Hal mentioned earlier on McKenzie, our preference is always to take a larger interest than a smaller interest. Keystone's a very strategic project for us, which is also a very good platform for growth. As you know, production from the Canadian oil sands is expected to grow by some 2 million barrels over the next few years. Keystone currently is about 600,000 barrels a day. We would like to capture a larger market share of that growth with that platform. So it's strategic for us in the long-term and the returns in the short run are meeting our hurdle rates.

Okay, great. Thanks. Those are my questions.

Thanks, Matthew.

Thank you. The next question is from Sam Kanes from Scotia Capital. Please go ahead.

Thank you. I'll stay with Keystone for a second. In your release you mentioned that you have committed $300 million to Keystone and this project probably will go 2.5 billion, maybe 3 billion now with your extension. I don't know. Does that mean your 90% exposed potentially and I'm sure that's adjusted for in your most recent shipper agreements. How does that work, the inflation on Keystone or the inflation risk on Keystone relative to your I guess agreements at this stage?

I didn't really understand your question, or your comment on 90% exposed.

Well, I'm assuming let's say if it's 3 billion rounded upwards, with your extension now, and you have in your release 300 million of commitment project, at least 2.7 billion, so the overall project and any cost over on risk, how would that work in the context of your agreements? You fixed a price with your shippers for the deemed capital with your agreements, or that's still to be played out?

It's still -- we're still negotiating how that works, but essentially we will be putting a pin in the capital costs at a point here in the near future. Once we put that pin into the capital costs, then we will share overages and underages. We haven't talked publicly about the percentage and we're still negotiating what that looks like. But essentially what our intent is is to try to lock down as much of the capital costs as we can, so that $300 million commitment isn't necessarily a cash commitment to date. That has been locking down contractors, pipe, steel, materials, all of those other things that we need, to lock down a very good estimate. Once we've locked down that good estimate, then we will lock that price with our shippers essentially and then we'll share from that point forward. So our, our intention really is to, is to give as much certainty to our shippers and to ourselves as we can before we actually lock that number in place.

Thanks, for that. Follow-up question, too, very small clarities, I guess. Gas Pacific company you mentioned slipped. Is there anything chronic occurring there, or why the unusual kind of flat quarter versus 3 million?

It's -- I don't know if you have been following the going's-on in Argentina, but they are a bit short of gas and energy policy is such that there's not that much encouragement for the producers to produce new gas. So what's happened is basically a supply crunch where they have cut gas supply off to exports and in fact to industrial customers to service residential load.

Now, obviously that's going to cause a lot of grief to producers and to companies like us who want to continue to move gas and invest in the gas market.

So, it will be sometime I think before we see some changes. And not getting back on track, but again, it's not a large amount either way.

Okay. (Inaudible - multiple speakers).

-- issues we have on Pacific energy currently.

The gas crisis itself in general.

Yes.

Lastly, carbon [CanCarb Thermax] revenue was down 21 million from 38 million, natural gas. Anything unusual there on the revenue side of that?

No, I, I don't think, Sam, I don't think there's really anything, but we've been quite happy with the performance of the business.

So there was no kind of like shutdown or anything unusual in terms of maintenance turnarounds; it was just--

I think there was some maintenance, but -- sorry. Was your question on the revenue?

Yes, because that's all you gave us in your release.

Yes. No, I think there -- my recollection was there was some, some maintenance issues, but nothing, nothing very material or ongoing.

Okay. Thanks.

Sam, we have a little more factual information here. Glenn Menuz will comment on that.

Yes, on the line you're looking at in that table is other revenues, and as we say it, includes Can Carb, Thurmax and natural gas. Last year there were some natural gas sales also in that $38 million number. So as Alex says, Can Carb on a year-over-year basis is basically the same. Things are going well.

Okay. Thank you.

Thank you.

Thanks.

Thank you. Once again, please press star-one if you are a financial analyst and you have a question. The next question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thanks. I didn't see much of an update on the GTN rate application. Can you give us an update on timing and range of possible outcomes based on what you've applied for versus what other folks might be advocating?

I think that the range is still between 2006 rates and what we applied for. Not much headway has been made on the settlement front to date. I guess my view is that's not unexpected, given the hearing date is set out for sometime in October, that as we sort of get through the summer here, parties will solidify their positions and put those real positions on the table. So not much has occurred. In terms of an update, I would say that all the parties are still doing their homework and, but the parties have yet to come together and negotiate with the intent of actually getting a deal done.

So if you were to apply the 2006 rates and what you've applied forward to 2006 volumes, what would that translate it to into a range of earnings?

Essentially, we're booking earnings at the 2006 rates right now.

So that's the worst case scenario?

I believe so.

And then what would be the best case scenario?

What we applied for. So we applied for a number -- I don't actually have it in front of me, but I think that the number is somewhere around $0.40 an MCF compared to something that looks like the high 20s that is the current rate on the system.

And, Linda, that provision for rate refund, the difference between what we're collecting in the 2006 rates is sitting on the balance sheet as a deferral.

So what's that deferral year to date?

Pardon? Pardon me?

What's that deferral year to date --

We've been deferring since Jan 1, yes. What's the number?

Yes, so what's the number.

Oh, I don't have the number right here.

We can get back, give that to her, can't we? I don't see any reason why we can't give you that number, and I think, Linda, that would give you essentially the range. We're actually collecting tolls that are applied for rates. So that provision for refund gave the total Delta between '06 rates and what we've applied for.

Great, yes, if I could get that number that would be great. And just as a follow-up, your Bruce A restart, I see you've given an update on spend so far. Can you just comment on how you're doing versus your original time line and budget to date?

Sure, Linda. It's Alex. We are at this point, we are on time and on budget. One thing I would say, we are right in the middle of a very sensitive part of the restart, which is we are -- we have taken out or have taken out a number of the steam generators and we've replaced five of the 16. So we're obviously in a very sensitive time, but right now on time and on budget.

Great. Thank you.

And, Linda, it's Glenn Menuz. Just on your provision for rate refund on GTN, it's approximately $15 million per quarter, approximately $30 million on a year to date basis.

That's Canadian dollars?

Correct.

Thanks.

Thank you. The next question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Good afternoon, everyone. My first question is on the pipelines. I was thinking about the Alberta System and when would be the first possible opportunity for you to apply for an increase in equity. Again to what you've done on the Canadian Mainline?

That would be our current settlement, what was a three year deal, expires at the end of 2007. So we are in the process of -- we've made an application to the energy utility boards in Alberta to negotiate a settlement similar to the mainline settlement effective 2008. We have not yet received approval to do that.

Okay, and the, I guess turning to something else, the Alberta emission -- Alberta has now introduced their new carbon emission intensity rules and presumably you have some exposure to that through you being the counter party to trans -- coal-fired PP A's. Now, it turns out it has actually issued some sort of guidance regarding the amount of cost that they believe that they can pass through to the counter parties. Just wondering whether you have an estimate that's out there that could kind of quantify those assumptions.

We -- it's Alex. We do not have an estimate out there. It is certainly our position that a majority of those costs in Alberta will be passed through to consumers through the power price, but we've not put out any formal guidance on that.

Is there a certain point at which you can update the, I guess the analyst community or not?

I think that's something -- we can take that under advisement. We certainly have a view internally and perhaps we could just talk about it and think about how we could give some guidance to the analysts.

Daniel, it's Hal here. This payment or this economic burden that's imposed on coal-fire generation in Alberta commenced on July 1. And as the next couple of quarters unfold, it will become more clear I think to us and probably generally more clear as to what degree the market will be able to absorb those costs in the power price in Alberta. So it would be very difficult for us to give you a speculative number at this point, but over the next couple of quarters, we think that will become more clear.

Okay, thank you.

Thanks.

Thank you. The next question is from Robert Kwan from RBC capital markets. Please go ahead.

Okay, thanks. Just on ANR, looking at the potential development options that you have there, particularly around the eastern leg, did El Paso do a lot of work around this, or are you really just kind of starting from scratch in terms of looking at potential projects, formally discussing projects with shippers, that type of thing?

I didn't hear the first part of your question, Robert.

Oh, just did, just around the potential development options and particularly what you might do with the Eastern leg, did El Paso do -- was there a lot of work that they had already done, or are you kind of starting from scratch in terms of looking at different projects and discussing it formally with shippers?

There's a lot of work that's been done at ANR. While El Paso owned it, they have a very, very long project list actually. One of our challenges has been to sort of call that list down into what we think is doable and has the highest return and greatest probability of success. So there's a number of projects. Most of them are related to storage and what we can do with storage and how we can use that to attract volumes on the eastern leg. We are also looking at ways -- as you know the western leg of that system actually runs at capacity. We're looking at different options to move gas from west to east and use that capacity on the eastern leg to move gases up into the storage region and then on into the marketplace.

So the combination of those kinds of things, as well, integration options, again, using that storage and trying to move it further east through both the Great Lakes system and the TransCanada systems to customers that are going to need it and value that storage capacity.

So a lot of it's related to, as I said, around storage, number of projects that we're looking at, but nothing specific beyond the ones that we just announced here recently, the step 2008 and 2007 programs, which are related to transportation as well as storage.

Thanks, guys.

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

Thank you. With respect to your eastern power operations, I'm just wondering if you could give us a sense of the magnitude of the forward capacity payment that was paid in the quarter that contributed to the year-over-year growth.

, Karen, it's Alex. My recollection was that it's somewhere right now in the range of about 30 million a year pre-tax. So that capacity market is on -- is adding value on our assets.

Okay, and that will grow to what, by the next couple of years?

Right now I think '07, we're at $3, give or take, per kilowatt month, and by '09, that is escalated to about $4 per kilowatt month. And then as you're probably aware after that, sort of '10 onward, the price will be determined by the competitive auction.

Okay, thank you.

Okay.

Thank you. The next question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Thank you. I have another couple of questions and the first one relates to the revenue profile of Bruce. When I look at your disclosure on Bruce B power revenues, there is the realized power revenues of about $48 per megawatt hour, which is flat to second quarter last year. And then gets right up there against the threshold that's provided for by your PPA with the OPA. Just wondering what your outlook is for the balance of the year and for next year, given that I believe some of the Pickering assets may be offline for quite a while.

Sure. The Ontario power market is really interesting right now. I mean I'm personally of the view that prices are quite depressed from where one would expect them to be and I think there's a number of factors that are dealing with that. First in the short-term, it's the very low gas prices as a result of a glut of gas in storage. So I think that Ontario market is very much -- prices are driven by the price of gas.

I think we're seeing a little bit of softness in industrial demand for gas, just given the high Canadian dollar and the impact on the manufacturing sector. And I think -- but I think the primary issue in the short-term that is effecting the price and driving it downwards is we're now probably into about the fourth or fifth consecutive quarter of very moderate temperatures in Ontario. We had a very warm winter and we followed it up with a quite mild summer to this point. So air conditioning load is still very low and I think more than anything, it's temperature that drives prices in Ontario. And I think that's why we've been seeing the sort of call it 45 to $50 range, and I would expect that to improve over time.

Okay. So you're saying that you believe the second half of the year is likely to be better than the first half and kind of what in '08? Do you have any sort of expectations there?

I -- It's pretty hard for me right now to give firm pricing expectations, but I think what I could say is directionally, we would hope to see stronger pricing in the second half of the year and would also hope to see some stronger pricing in '08. And I would also agree with you on your comments on Pickering.

Okay. Thank you. And my other question is with regards to I guess the next step for Keystone now that you've had your open season for the expansion and extension. Where does your oil pipeline footprint go from here? Do you believe that your Keystone system may be a spring board for further extension right into the gulf or do you believe that there's scope for TransCanada to maybe put in a proposal for a bullet pipeline to the gulf or what are your thoughts on the matter?

I think that our goal all along has been to get to the Gulf coast. That's the largest refining center in North America, and as a result of recent events I guess in Venezuela, a lot of those refiners are looking forward to fill a supply shortfall that they see coming from Venezuela, so there's a lot of talk between, I guess, Gulf coast area refiners and Alberta oil SANs producers in terms of linking up supply to market and reconfiguring refineries to be able to run that kind of crude. We're immersed in the middle of those kinds of discussions and Keystone getting to Cushing is a spring board, which gives us critical mass, if you will, to actually base load a facility going to the Gulf coast. I think probably equal to or better than other alternatives that are in the marketplace today.

So we're working very hard to, to put together a proposal that would fit the needs of both those refiners and producers and we would need them to underpin contractually as we have in both steps at Keystone to date, to contractually underpin an extension of the pipeline to the Gulf coast. I suspect part of that line would be looping of the existing system and partly adding an extension to the existing pipeline. So we're looking at all those things in terms of design right now, but I think as you've heard us say before, the real prize for us at the end of the day is to get to the Gulf coast and that's what we've been working towards. The base projects are very good as well. If we don't get to the gulf coast, they stand alone, but obviously the producers in Alberta want to get to the Gulf coast and we're trying to provide a solution for that.

And how advanced do you believe your potential proposal will be in relation to other proposals that may potentially have first mover advantages?

The other proposal that have which?

Well, I'm just saying that there has been some other proposals that have been out there for a little while. How do you believe that your solution would stack up against somebody else that may potentially have first mover advantage?

I can't really comment on others' proposals, but I can tell you with respect to our project, what we have is we have the critical mass of 600,000 barrels a day that can go to Cushing, Oklahoma. There's about 2 million barrels a day to move out of Alberta to market. And so to build a pipeline to the Gulf coast; a direct pipeline to the Gulf coast, you're going to need somewhere around 500,000 barrels a day plus to get there. Given that we've got a head start of 600,000 barrels a day to base load that going more than about 70% of the distance. I would say that we're in a pretty good competitive position relative to others in the marketplace.

Okay, thank you.

Thank you. There are no further questions from financial analysts. We will now take questions from the media. Please press star-one at this time if you have a question. (OPERATOR INSTRUCTIONS) There are no further questions registered at this time. I would like to return the meeting to Mr. David Moneta.

Thank you, and thanks to all of you for participating today. I know it's a busy day for all. We appreciate your interest in TransCanada and we look forward to speaking to you again in the near future. Thanks. Bye.

Thank you. The conference has now ended. Please disconnect your lines at this time. Thank you for your participation and have a nice day.