TC Energy Corp (TRP) 2007 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2007 first quarter results conference call.

I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Communications. Please go ahead. Mr. Moneta.

Thanks, very much, and good afternoon, everyone.

I'd 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 first 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, Glenn 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 Web site at transcanada.com. It can be found in the Investor Section under the heading "Conference Calls and Presentations."

Following Hal's and Greg's remarks we'll turn the call over to the conference coordinator for questions. And each of the individuals I mentioned earlier will be available to answer 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'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties please see the reports filed by TransCanada with Canadian Securities regulators and with the U.S. Securities and Exchange Commission.

And finally, I'd also like to point out that during this presentation we'll refer to measures such as comparable earnings 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 readers with additional information on the Company's operating performance, liquidity and its ability to generate funds to finance its operations.

With that, I'll now turn the call over to Hal.

Thank you, David. Good afternoon, everyone, and thanks again for joining us.

I'll keep my remarks brief today as many of you may have joined us at the TransCanada annual meeting this morning, either in person or via webcast. At that meeting I provided an overview of how TransCanada has become one of North America's leading energy infrastructure companies, and I also described how we've created several platforms for significant long-term growth.

I'll take a few minutes now to talk about recent developments in our business and then I'll turn the call over to our Chief Financial Officer, Greg Lohnes, who will review our financial results in more detail. For those of you who weren't able to join the meeting this morning, the webcast will be archived at www.transcanada.com.

For the first quarter of 2007 TransCanada Corporation's net income from continuing operations was $265 million, or $0.52 per share compared to $245 million, or $0.50 per share in the first quarter of 2006. Comparable earnings were $250 million, or $0.49 per share for the first quarter of 2007 versus $227 million, or $0.46 per share in first quarter 2006. That represents an increase of approximately 7%.

Our funds generated from operations in the first quarter 2007 were 12% higher at $582 million compared with $517 million for the same period last year. You will hear more about our financials from Greg Lohnes.

TransCanada's board of directors today declared a quarterly dividend of $0.34 per share for the quarter ended June 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.

The first quarter of 2007 saw considerable progress on a number of fronts. The closing of ANR and Great Lakes acquisitions has been a significant accomplishment for TransCanada. With these acquisitions our North American pipeline system offers our customers unparalleled connections from traditional and emerging supply basins to growing markets.

In a matter of months, we were successful in securing regulatory approvals and financing the transaction. The integration is going well and we are very pleased to have added approximately 1,000 new employees to the TransCanada work force.

We increased our ownership in TC PipeLines LP to 32.1%. TransCanada is now the operator of all three TC PipeLines investments: The Great Lakes System, Northern Border, and Tuscarora.

This positions us well to have a significant degree of influence over the operations and potential future expansion of these pipeline systems. We are very pleased with the progress we are making on the Keystone Oil pipeline project.

In February, we reached a critical milestone when we received National Energy Board approval to transfer a portion of the Canadian Mainlines natural gas facilities to the Keystone Oil pipeline. Keystone will transport crude oil from Alberta to refining centers in the U.S. Midwest.

The facilities are a key component of the project. We continue to seek various other regulatory approvals and it remains on schedule for a late 2009 in-service date. In addition, we continue to assess the results of our open season to expand and extend Keystone to the Cushing, Oklahoma trading hub.

Turning to our Canadian wholly owned pipelines we reached a five-year settlement on our Canadian Mainline with interested stakeholders regarding 2007 tolls and costs for the years 2008 to 2011. This settlement demonstrates the strong collaborative relationship we have developed with our gas transmission customers.

TransCanada also received NEB approval on March 21, 2007 to fully integrate the BC System with the Foothills System. The transfer took place on April 1, 2007. The integration will result in administrative cost savings for our company and our customers.

In the north, on the MacKenzie gas project, Imperial Oil and the project co-venturers filed an updated cost estimate and scheduled with regulators. MacKenzie is an enormously challenging project and continues to move slowly through the regulatory process.

In Alaska we are encouraged by the Governor's recent introduction of the Alaska Gas Line Inducement Act. We continue to work with the state of Alaska, Alaska North Slope producers, and other stakeholders. Our objective continues to be to participate constructively in the advancement of the Alaska project.

Turning now to Energy we remain focused on transactions and new developments that will generate stable earnings over the longer term. On the Cartier wind project, construction of the second wind farm, Anse a Valleau, continues and it is estimated to be in-service in the fall of 2007.

In addition, we are currently evaluating the potential of a number of wind projects in Quebec in response to Hydro Quebec distribution's request for proposals for 2,000 megawatts of additional wind power. Bids are due in September 2007.

Our two power projects in development in Ontario, Halton Hills Generating Station and the Portlands Energy Centre, are proceeding on schedule. We have completed an environmental review report on Halton Hills and we continue with extensive consultation with local stakeholders. At Portlands the first significant structural concrete pour occurred in March of 2007.

Progress also continues on the Bruce Power restart program. Two of the used steam generators were removed in preparation for replacement as part of the overall one and two restart. Once complete in 2009, 2010, the two units will add 1500 megawatts of capacity to the Ontario power grid. The Bruce A restart project remains on schedule and on budget.

In liquefied natural gas we continued to progress on our two proposed projects, Broadwater and Cacouna with our partners. Over the remainder of 2007, we will continue to focus on three key objectives in everything we do.

Firstly, maximizing the profitability and value of our existing assets. Secondly, implementing new projects and initiatives and implementing them very well. And thirdly, continually cultivating a high quality portfolio of future growth opportunities.

I'll now turn the call over to Greg Lohnes, our Chief Financial Officer, who will provide additional details on our financial results. Greg?

Thanks, Hal, and good afternoon, everyone.

As Hal mentioned, earlier today we released our first quarter results. Net income from continuing operations or net earnings for the first quarter were $265 million, or $0.52 per share compared to $245 million, or $0.50 per share for the same period last year.

First quarter 2007 net earnings included positive income tax adjustments of $15 million. First quarter 2006 net earnings included an $18 million after-tax bankruptcy settlement with Mirant Corporation.

Excluding these items comparable earnings of $250 million, or $0.49 per share in the first quarter 2007 represents an increase of approximately 7% when compared to first quarter 2006 comparable earnings, up $227 million, or $0.46 per share. The quarter-over-quarter increase is primarily due to income from the acquisition of ANR, the start up of the Becancour cogeneration plant and the commencement of operations in at Tamazunchale.

I will briefly review the first quarter results for each of our segments beginning with Pipeline. The Pipeline's business generated net earnings of $155 million during the first quarter compared to $157 million for the same period in 2006. Excluding the $18 million bankruptcy settlement with Mirant in 2006, net earnings from the Pipeline business increased $16 million compared to the first quarter last year.

The increase was primarily driven by the contribution from ANR, partially offset by lower contributions from the Canadian Mainline, the Alberta System and GTN. TransCanada completed the acquisition of ANR on February 22nd and reported results for ANR reflect its net earnings from that date.

The lower contribution from the Canadian Mainline and the Alberta System is due to a combination of lower approved rates of return on common equity and a lower average investment base.

In February of this year we announced a five-year settlement with interested stakeholders regarding 2007 tolls and costs for years 2008 to 2011 on the Canadian Mainline. As part of the settlement, TransCanada and its stakeholders agreed that the offset capital will reflect an ROE as determined by the NEB's return on equity formula on a deemed common equity component of 40%, an increase from 36%.

In March, TransCanada applied to the NEB for approval of the settlement and a decision is expected in the second quarter of 2007. First quarter results for the Canadian Mainline reflect the NEB formula on the previously approved capital structure of 36%. Once the settlement is approved by the NEB, earnings will be adjusted to reflect the terms of the agreement effective January 1, 2007.

As mentioned, the lower contribution from GTN is primarily due to the receipt of an $18 million bankruptcy settlement in the first quarter of 2006 with Mirant, a former shipper on the GTN system.

Also contributing to the decrease are lower operating revenues in the first quarter due to an approximate $150,000 decatherm per day decline in long-term firm contracted volumes, and a provision taken in the first quarter of 2007 for nonpayment of contract transportation revenues from a subsidiary of Calpine Corporation that filed for bankruptcy protection.

A $3 million increase in TransCanada's proportionate share of net earnings from other pipelines was mainly due to earnings from the Tamazunchale pipeline which commenced operations in December 2006, and increased earnings from Great Lakes reflecting the increased ownership interest. These increases were partially offset by the impact of higher project development and support costs associated with growing the pipeline business.

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 $106 million in the first quarter of 2007 compared to $100 million in the same period last year. The increase was primarily due to higher contributions from western power operations, eastern power operations and natural gas storage. These increases are partially offset by a lower contribution from Bruce Power and higher general administrative and support costs.

Bruce Power contributed $29 million of pre-tax operating income in the first quarter compared to $63 million last year. The $34 million decrease was primarily due to lower generation volumes and higher operating costs associated with an increase in planned outage dates, as well as higher post-retirement benefit costs.

These decreases were partially offset by higher realized prices. The higher operating costs are primarily due to approximately 86 reactor days of planned maintenance outages and four reactor days of unplanned outages that occurred on the six operating unit in the first quarter.

The planned maintenance outages were related to a one-month outage of Bruce A Unit 4 and a two-and-a -half month outage of Bruce B Unit 6, both were completed in April 2007. In comparison, the first quarter of 2006, Bruce Power in the first quarter, Bruce Power experienced only 30 reactor days of planned maintenance outages and 13 days of unplanned outages.

As a result, the Bruce units ran at a combined average availability of 82% in the first quarter compared to 90% average availability during the same period last year. Looking forward, the overall plant availability percentage in 2007 is expected to be in the low 90s for the four Bruce B units and in the mid-70s for the two operating Bruce A units.

Two planned outages are scheduled for Bruce A Unit 3 in 2007. The first outage is expected to last one month in the second quarter, and the second outage is expected to last approximately two months beginning in late third quarter 2007.

Turning now to western operations. Western operations operating income was $73 million in the first quarter compared to $58 million last year. The $15 million increase was primarily due to increased margins from higher overall realized power prices on both contracted and uncontracted volumes of power sold.

The average spot market power price in Alberta increased 12%, or $6.85 per megawatt hour in the first quarter 2007 compared to the first quarter 2006. In the first quarter 2007, approximately 19% of western power's sales volume were sold into the spot market compared to 29% in the first quarter last year.

To reduce our exposure to future spot market prices, western power operations has fixed priced sales contracts to sell approximately 8,000 gigawatt hours for the remainder of 2007, and 7,400 gigawatt hours for 2008.

Finally in power, eastern operations operating income for the first quarter was $67 million compared to $49 million last year. The increase was primarily due to incremental income earned in 2007 from the start up of [Voltis], 550-megawatt Becancour cogeneration plant in September 2006, and the first of six wind farms at the Cartier wind project in November 2006.

In the first quarter 2007, approximately 95% of eastern power's 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 10,100 gigawatt hours for the remainder of 2007, and 10,300 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 $30 million in the first quarter increased $8 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 Edson facility in December 2006, and higher earnings from CrossAlta as a result of increased capacity and higher natural gas storage spreads.

Turning now to corporate. Net earnings from corporate in the first quarter 2007 were $4 million compared to net expenses of $12 million in the same period last year.

The $16 million increase in net earnings compared to last year was primarily due to favorable income tax adjustments, including a $10 million benefit on the resolution of certain income tax matters and a $5 million benefit resulting from an internal restructuring as well as certain other items related to changes in estimates and tax rate differentials. Partially offsetting these items was an increase in financial charges as a result of financing the recent ANR and Great Lakes acquisitions.

Turning to the cash flow statement. Funds generated from operations were $582 million in the first quarter, an increase of $65 million, or 12% when compared to the same period in 2006.

Capital expenditures in the first quarter were approximately $306 million and related primarily to the ongoing development of greenfield projects such as Cartier wind, the Bruce A restart and the Portlands Energy Centre, as well as growth and maintenance capital associated with the Canadian Mainline and the Alberta System.

Acquisitions net of cash acquired of $4.265 billion in the first quarter are due to the acquisition of ANR and an additional 3.55% interest in Great Lakes as well as TC PipeLines LP's acquisition of a 46.45% interest in Great Lakes. During 2007, in addition to the acquisition of ANR and Great Lakes, we expect to invest in excess of $1.5 billion in our Canadian wholly owned pipes and other greenfield projects currently under development.

Finally, our financial position remains strong. The ANR acquisition was financed in a manner consistent with the Company's balance sheet capitalization.

In February, through a subscription receipts offering, TransCanada issued 39.47 million common shares at a price of $38 per share, and subsequently issued an additional 5.92 million common shares at $38 per share under an option granted to the underwriters for a total gross proceeds of $1.725 billion. A variety of debt facilities were executed in February to finance the remainder of the ANR acquisition.

At the end of March, following the successful equity and debt financing of ANR, our balance sheet consisted of 59% debt, which included our proportionate share of joint venture debt, 2% preferred securities, 1% preferred shares, and 38% common equity.

A strong financial position is critical to maintaining our A credit rating. In February, DBRS removed us from credit watch and reaffirmed our A stable rating, and S&P changed their outlook to A minus stable from negative in early April. 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.

That concludes my prepared remarks. I will now turn the call back to David for the question-and-answer period.

Thanks, Greg.

Before I turn it back over to the conference coordinator, just a reminder that we'll take questions from the investment community first followed by the media and I'd also just remind you that we ask you limit yourself to two questions. If you have additional questions, please re-enter the queue. With that, I'll turn it back to the conference coordinator.

Thank you. We will now take questions from the analysts on the telephone lines. (OPERATOR INSTRUCTIONS) Our first question is from Sam Kanes, Scotia Capital. Please go ahead.

Good afternoon.

A question just on clarity on Bruce, since you mentioned it, the voluntary post employment benefit costs, was this something that, first of all, was it voluntary, was it contractual, was it inflationary, was it a shortfall in pension? What was it and how much was it?

Sam, it's Alex.

It's an obligation that we have to the employees and basically I think it would be described as the same kind of experience most pension plans are experiencing with higher medical care costs, higher prescription drug costs, and things along those lines. And it was something, you'll recall that at the last conference call we had estimated that the run rate from 2006 to 2007 was probably going to increase around 11% for operating costs, and so it was something that we had anticipated.

Embedded in there?

Yes.

Okay.

ANR so far you've only had six weeks with it. Is there any kind of color or quantitative positive or negative on the operations since you've taken it over that you can share with us?

I'd say that it's only been six weeks, it's been a very busy six weeks. I've been integrating staff, moving people across, getting office space, but I would say that on the positive side everything is sort of turning out as we expected.

No sort of unexpected land mines or anything like that that we found. The results are on track with what our expectation was for the six-week period. So I'd say all in all, things are moving very well and the integration is working.

Thanks, Russ.

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

Thank you.

I just wanted to confirm a couple of things on the pipelines. The Mainline earnings that were recorded were at the lower equity ratio that was in place before the negotiated settlement. Is that correct?

That's correct.

And could you qualify, Russ, the approximately, would that have been about $5 million higher than had you had the NEB decision approving the settlement in hand prior to the quarter?

Yes, net to the Company about that sort of penny kind of range, 5, $6 million.

Okay.

And then on GTN, I guess similarly the results could have been higher but I guess you guys are booking the revenues at the lower rate that was in place before January. What are the cash implications of that in general terms?

I'd turn to Glenn to find out exactly the difference in cash but we are collecting tolls at our filed rate, and only booking income at our existing, you know, last year rates. So cash flow-wise, do you know what the delta is there?

No, unfortunately, Matthew, I don't have that here.

We can get that for you, though, Matthew.

Okay.

But I guess overall, then, once you have regulatory decisions in place on these two pipelines, it looks like earnings should be directionally higher.

I guess I can really comment on the GTN rate case, is that the amounts that we're collecting are subject to refund depending on the outcome. I don't want to sort of speculate on what the outcome of that rate case is going to be at this point in time. But certainly on the Mainline one, if it's approved as filed there will be an incremental increase in earnings.

Okay. Thank you.

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

Thank you.

We've seen some recent announcements by some of your peers in the Alberta power markets on new build, I guess a supply response to higher power prices. There was some discussion in industry journals a while back about TransCanada studying an 1800-megawatt dam with Atco. Can you give us any color on where that's at, if there's any updates or anything you can share with us in terms of developments?

Sure, Linda.

It's-- the project in question is a project that has been studied really over the last 30 years, and it's on the Slave River in northeastern Alberta. And we, along with our partner, Atco are really doing a lot of preliminary work to see if that project is feasible, both in the market in terms of where it comes in at price, and issues having to do with the approvals, permitting and the construction costs.

So it's still relatively early days. We're certainly optimistic. It's one of North America's last and greatest hydro opportunities and we certainly hope that there's something there, but it's still pretty early.

Okay. So that's something that would take a few years to figure out?

Yes, we're working right now on a feasibility study, and we would probably expect in a year, some time less than a year we'd have the results of that and then we'd sit down and think pretty hard about whether we wanted to pursue it further.

Great. And maybe while we're on the subject of power, could you just give us an update on your expectations for the power markets, both in Alberta, Ontario, and the U. S. northeast?

Sure. Alberta, I think structurally, Alberta continues to be a tight market. You have mentioned there are a couple of proposals for new generation and a couple of projects proceeding slowly to construction, but I think we're directionally quite bullish on the Alberta market for the next couple of years or next several years.

Ontario, I also think we're generally directionally fairly bullish for the next few years. New England, same thing. I think we're pretty happy with the market.

The recent implementation of the capacity markets in our view was a very well thought out change which should ensure ample supply over the long-term in the market. But I think all three of them were directionally positive.

Great. Thank you.

Thank you. Our next question is from Robert Kwan, RBC Capital Markets. Please go ahead.

Thank you.

Just wondering if you could provide some of your initial thoughts recognizing it came out yesterday, on the federal government's climate change proposal and then specifically whether with respect to your gas plants, whether there's pass-throughs under those contracts?

Robert, it's Hal here. I'll provide some general comments and then ask Alex to comment on pass-throughs on the gas plants.

First of all generally, we weren't surprised by what came out. I've been involved in a consultation process with the federal government and other major players, including the producers in the energy sector for most of the past year, and we've put a lot of effort into realizing the two objectives firstly of achieving real progress on greenhouse gas reductions and secondly, doing so without major negative impacts on the Canadian economy.

And as you know, it's a tough balance to achieve. Very difficult, and I think a lot of major industrial emitters, large final emitters, as they're called, are going to be very challenged to meet the targets that are set out.

We would see in coal-fired power generation that we really have to face up to paying the 15 or $20 a ton of CO2 into the technology fund until such time as those plants reach the end of their useful economic life and can really be rebuilt from the ground up, either as integrated gas combined cycle plants or some other form that capturing CO2 out of the smokestack of an existing atmospheric pressure coal plant is just not a practical alternative, there's really no technical way to do it.

So I think coal-fired is the biggest area of exposure. We do emit CO2 from compressor stations on our Mainline and Alberta System pipelines, and those, there will be some costs to comply there.

Again, there's not much we can do in terms of actually capturing and sequestering that CO2 so it will be an added cost but it's a relatively minor cost, and I should add on the coal plants in Alberta, it's also relatively minor and we think the strong power demand in Alberta will enable us to flow most of that extra charge through to the end market.

So the third point I'd comment on is I think there's a number of opportunities here that open up. One of the obvious ones is some form of pep coke or bitumen gasification at Fort McMurray that could supply synthetic natural gas that could be easily transported around. That would have the dual benefit of reducing other gas consumption at Fort McMurray and I'd note that other gas is needed in places like Ontario and Quebec for power generation from new cleaner source power gen plants burning gas rather than coal.

But secondly, that conversion of bitumen to synthetic natural gas could provide the hydrogen and heat that the oil sands need at a lower cost, particularly if gas prices continue to go up.

There are many reasons in the plan why gas will be much in demand. Gas is the cleanest of the available hydrocarbon fuels and in a number of jurisdictions you simply can't move quickly enough to either go to gasification or to go nuclear.

And so we think incremental power is going to be demanding more and more gas and in the absence of a lot of LNG coming in, this is going to result in a pretty high gas price, and that would be one of my predictions coming out of the plan. So we're working on all of those things and studying them carefully, but I don't agree with some of the observers who have said this will, this plan will be met in the normal course of operations.

This is going to take some really significant adjustments by the industrial sector and very significant adjustments by some of the large final emitters. It should not be understated the challenges and impacts that this will have. But we accept that this is public policy and this is where Canadians wish to go and so we will do what we have to do to meet those targets.

And with respect to the gas-fired plants in Alberta, Alex?

How I would describe it with our co gen plants in Alberta, the CO2 costs will be allocated pro rata between TransCanada and our site hosts in proportion to the amount of energy that we are taking and the amount of energy they are taking in steamer waste heat.

In the plants we're presently building or have just recently built out east, the large PPA back plants, we would be responsible for that but I think it's fair to say that at the time we were developing those plants, we were very cognizant that this was a possibility. And in our economic analysis, we anticipated the exposure that we might have to CO2 remediation costs.

Hal, just to follow-up.

You mentioned the compressor stations on the Mainline and some of the costs. Were you talking about the costs accruing to yourselves in the sense that those would be covered under the O&M settlement and, therefore, would not be able to be passed through or --

Oh, they're legitimate flow through costs. These are incremental to anything that's included in the fixed part of the O&M. And so to the extent that costs are incurred, it's our job to be very prudent in the way we spend money and to minimize those costs. But at the end of the day, they're flow through.

Thank you, Hal.

Thank you.

Thank you. Our next question is from Karen Taylor, BMO Capital Markets. Please go ahead.

Thank you. Just a couple questions.

How big was the provision on the GTN for the subsidiary Calpine, if I heard you right?

And then secondly, can you just discuss, and I'm going to phrase it badly, but the drop-dead dates, if I could put it that way, for both Broadwater and Cacouna? And on Cacouna, I'm hoping you won't proceed with Russian gas supply.

Well it's Greg Lohnes. I'll address the first question, was the $3 million provision, and then I'll turn it over to Hal to address the second question.

Thank you.

Okay, Karen.

The case, I guess, for Russian gas at Cacouna is that the Russians do have the world's largest preserves of liquefiable gas and they are the shortest distance of haul from North America of any potential LNG source that we think is practical. So we are supporters of any initiative that would bring liquefied Russian gas to North America.

Having said that, we're not in the business of either developing gas fields in Russia or building infrastructure in Russia, so you don't have to worry about TransCanada being directly exposed to that. There will be other parties that are in that business that would stand between us and the source of the gas.

But I hate to disappoint you, but I think Russian gas actually is a very practical source for North America. And I just underscore everything that we've seen in the last 24 hours on the greenhouse gas front, and our own observations generally on supply and demand, and the ongoing delays with respect to northern gas.

North America needs LNG and it needs it much sooner than later. And failure to get it is going to lead to a lot of discomfort for a lot of parts of North America. So I think that will and should go ahead.

Now on the Broadwater project, we don't have a specific source lined up. What we do have is the corporate commitment from the Shell Companies. Shell will be the supplier of gas to Broadwater and we don't worry about it beyond that. That's their business.

As far as drop-dead dates, these projects, like all infrastructure projects, take longer than any reasonable estimate would think they should, and that's just the reality of life today, everything takes longer. And we have pursued both Broadwater and Cacouna in a very cost-conscious fashion.

We always understood that these projects might not come to market in the four-year period that we'd expected. It might take eight years or it might take 14 years. Just to highlight that these things can take a long time.

So our objective is to maximize our position, move the project forward, cultivate the value, and minimize costs at all times. So we're always figuring out ways to get through regulatory processes more economically rather than less.

A good example, Karen, is on the Keystone project where our team very astutely separated it into different approval steps, and we were able to get that really fundamental approval to convert the gas line before we spent an enormous amount of money on subsequent steps. We've done a lot of things like that on the Broadwater project where we have done work necessary to get through the FERC and Coast Guard processes but we have not spent enormous money on the technical design of the facility until a little later on in the process.

So we would hope that both of those projects would come onstream in roughly the 2010 range. I think originally Cacouna was 2009 and it realistically is probably now going to be 2010 and a sort of similar push back on the Broadwater project.

But we, these are extremely well located and extremely attractive projects from an economic net back perspective. I know of no LNG project in North America that could deliver a net back to the producer comparable to what we could give them out of Broadwater and so it's really those fundamentals we're mostly relying on.

Thank you.

Thank you. Our next question is from Andrew Kuske, Credit Suisse. Please go ahead.

Thank you. Good afternoon.

Hal, just in the context of the ANR deal, after that deal, where do you see yourselves positioned relative to the other American pipe companies? And maybe even thinking about that more broadly, just infrastructure companies generally?

Well, I think firstly we would like people to see us as very focused on selected market regions. That we're obviously the major transporter of gas from western Canada to every market that western Canada serves.

There's no flow path out of western Canada to significant markets that we don't dominate. So we think people should firstly recognize that.

Secondly, ANR was so appealing to us because it serves the Midwest and Great Lakes regional markets that we also serve through the Mainline and through Great Lakes gas transmission, and more recently, we now operate Northern Border, which serves that market as well. And so it's very advantageous from a competitive point of view.

We simply know the market really well and we can design our service offerings to deliver the best possible value to the customer and we think we can compete very effectively. I don't know that there are other pipeline companies that could compete as effectively as we could in the Chicago, Michigan, Ohio market region of the U.S.

And we think that there's some good opportunities there to make, you know, we acquired a terrific storage position in Michigan, and those storage services are increasingly in demand in Ontario, in New York, New England, as well as in the Great Lakes, Michigan area. And so we would like to move forward and do things like that.

We are not the major transporter of gas from the Gulf Coast region. ANR does give us a foothold in that area and we think we've got some very interesting assets there and we think that that could represent a source of upside, particularly if large volumes of LNG come into the Gulf Coast.

We're now more enthused about LNG into the Gulf Coast than we were before we acquired ANR. And that southwest leg of ANR that starts in Oklahoma, Kansas and West Texas, is quite attractive. It runs at a very high utilization rate, and the deeper we look at that, the more interesting upside we see around that.

But ANR is primarily an investment that allows us to maximize the quality and value of services that we deliver to customers in Michigan and markets around Michigan. You couple that with our ability to expand potentially in the future of the northern border pipeline, I think we're just in a really good position to meet market demand in that area.

As far as measurements that different people have about who's the biggest pipeline this way or that way, now that we unquestionably are the biggest pipeline, we don't care about that stuff anymore. So I don't think that matters.

And just being cognizant of your background with TransCanada, and given the fact you've just increased your natural gas storage capabilities by quite a bit, do you have any temptation to really get into the energy marketing business again as you were quite a few years ago?

And then just also on the storage question, [since you've] increased your natural gas storage are you tempted now to get involved in oil storage given the Keystone pipeline and any potential future forays into that world?

I don't know about oil storage, that's a completely separate question. It obviously is -- the fact that we're in gas storage bears no relationship to being in oil storage, I don't think.

But the fact that we're moving forward with the Keystone pipeline project might be a motivator of oil storage, I don't know. We can look at different opportunities there. And I know Russ' team has been looking at them.

Russ, I don't know if you'd have a comment on that.

Yes, I think oil storage, there is an operational requirement to have oil storage in conjunction with your pipeline given that the batching nature of business, the different qualities of crude oil. So we will have batching storage at the various terminuses of the pipeline, at the initiation point and at various points along the pipeline. So we will be in the crude oil storage business.

To the extent that there's opportunities to get into what I call merchant storage similar to our gas business, time will tell whether that opportunity unfolds for us. If there's a similar kind of low-risk way that we can play that game, we would probably do that. But our first entree will be storage associated with the movement of crude oil in our pipeline.

And as to getting back involved in gas marketing and trading, I'd want to highlight first of all that the kind of gas marketing and trading that we got out of was a very a high volume, thin margin business. It was a mature business that had become less and less attractive over time, as the many different competitors bargained that margin down to very low levels. And it just didn't strike us as being fundamentally attractive over the longer term.

Now, there is some gas trading activity related to storage that is quite a bit different than that. You have to do a certain amount just to effectively operate a storage facility and part of what we do in storage is proprietary and so you need to buy gas to put in the ground, and you need to sell the gas when it comes out.

But the kinds of trading activities that appeal to me are ones that are very deliberate, that would have an awful lot of thought and analysis behind them, and where you might have a number of days or weeks to think about whether you want to do that or not, as opposed to the kind of rapid fire, thin margin trading that we were engaged in before. So I'd say no, we don't have a lot of appetite to get back into doing what we were doing before 2001.

That's great. Thank you very much.

Thanks.

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

Yes. Good afternoon, gentlemen.

I have a question with regards to the increase in the common equity ratio for the Canadian Mainline. My question is not so much regarding the Mainline as your Alberta System.

Now, are you currently in the process of, I guess, trying to arrange some sort of increase in the common equity ratio on the Alberta System in parallel or following what happened on the Canadian Mainline, given that the Alberta regulator followed suit to the NEB by about a year in the '03, '04 time frame?

We're currently under a three-year settlement for the Alberta System that expires at the end of 2007. So we are in negotiations, we're just getting started in negotiations around what those rates will be in 2008 and beyond.

And certainly capital structure and return on capital and equity thickness are all parts of those discussions, as will be O&M costs and all the other factors that go into the toll. So obviously our objective has been consistently over the last six or seven years to move up our return on our capital employed in those businesses, and so that will be a major factor of those discussions.

But it's way too early to tell sort of where those are going to go and whether or not we will settle with our shippers or whether we will end up in some form of a rate case or litigation kind of process.

Okay.

And for my second question, I was just wondering about the level of capacity payments received under the forward capacity market in New England. Have those been -- where have those kind of been and perhaps you can quantify them in terms of revenue dollars?

The capacity market for the first three years, I think they describe it as interim capacity payments and those payments are actually fixed by regulation and with respect to the exact volume of those, I think I'd pass that on to David to -- I'm sure he'd be able to get you the (inaudible) levels of them.

I'll follow that up with Glenn, Daniel, and we can get back to you on that.

Okay. Thank you.

Thank you. (OPERATOR INSTRUCTIONS) Our next question is from Josh Golden, JPMorgan. Please go ahead.

Yes, good afternoon.

First and foremost I just want to complement you on the prudent management of the balance sheet and maintaining stable outlook from Standard and Poor's.

My next question is, is that you did have sort of a buildup in the short-term debt area on the balance sheet, and I'm curious, is there any plans to terming any of that short-term debt out?

It's Greg Lohnes.

Yes, we're always looking at what our short-term debt levels are, and managing them appropriately within a prudent range which we think is appropriate at any particular time for our company. And we do look at terming those out from time to time.

Okay. I appreciate it. Thank you.

Thank you.

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

Yes, hello again.

I have a question with regards to, well, first of all, maybe it's a little early to tell but on the ANR income contribution that was recorded for the few weeks that you held -- that you owned the asset in Q1, how, I guess, really how representative is that earnings contribution going to be for a quarter going forward?

I'll take a first crack and then I'll turn it over to Russ.

But the way the ANR system works, the revenues are higher in the winter period than in the summer period, so it's not representative of a full year. It's more representative of what the peak winter months would look like.

Okay. I see. And okay.

I think another thing you might be able to look at, Daniel, and we'll certainly work on this for everybody on the phone on a go-forward basis, but I believe in some of the historic ANR numbers that have been reported in 10-Qs and 10-Ks that there are some quarterly numbers there that go back over a couple of years.

And as Greg mentioned, it is a seasonal business, if you will, that results in higher income, certainly in the first quarter on a run rate basis than, let's say, in the second or third quarters of the year.

Okay.

And the shipper satisfaction survey results came out recently, I believe, for gas pipeliners across North America. How did TransCanada do on that survey?

I'm not sure exactly which survey you're referring to, but the surveys that I've, you know, that we have participated in and received the results on, TransCanada systems from a commercial and operational standpoint were usually at the top of the group.

In terms of integrity of those kinds of things, we come to the top of the group. Cost efficiencies, we come to the top of the group. So we consistently place at sort of the top in terms of customer satisfaction and operating statistics relative to other pipelines in North America.

If you're referring to the [Nastiele's] studies, Great Lakes, which, as you know, we just acquired 100% of has traditionally been in the number one or two spot in that survey and ANR's usually fairly high in that survey as well. It was my understanding that in the appropriate category that Great Lakes is up there again this year.

Okay. But the Canadian Mainline is a little bit lower than in relation to where Great Lakes has been?

No, I think the Canadian Mainline that Russ deferred you, that we do our own survey as opposed to participating in what's primarily a U.S. survey. And although they do collect some results for that survey, it's on a voluntary basis as opposed to us providing a list of customers for them to talk to. So I think the internal surveys we do through our own provider are probably more indicative, and those have been very positive.

Daniel, it's Hal Kvisle here.

We have, over the years, had vigorous discussion with our customers around appropriate financial returns and other financial matters like that. And I'm very pleased that in the last year we've made terrific progress with our customers in reaching agreement on settlements that are amicable and win-win for both sides.

So notwithstanding that there has from time to time been some controversy around financial parameters, that has never been the case around the service levels on the Alberta System and the Canadian Mainline.

You could talk to the key gas marketing and trading companies in Calgary and you'd find that the service and the customer responsiveness that TransCanada provides would rate very highly and I'm very confident in saying that, that our system has greater flexibility and better customer interaction software systems and better communication systems with customers than any other pipeline that we look at, and I think that's the reaction you would get from our customers here in western Canada.

Okay. Thank you for that.

Okay. Thank you.

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

Thanks.

Just further to Dan's question on the ANR first quarter results. Can you clarify where, if there's any debt residing in the pipeline segment, for example, the $475 million that's U.S. dollar-assumed debt, which I assume would be disappearing after this quarter?

It's not disappearing but that -- and the costs associated with that debt would be included in the ANR results.

Okay. So it will continue to be in ANR and then all the other debt is -- resides in corporate?

Correct.

Okay. Thank you.

Thank you. This concludes the analysts part of the question period. (OPERATOR INSTRUCTIONS) There are no questions registered at this time. I would now like to turn meeting back over to Mr. Moneta. Please go ahead, sir.

Thank you very much and thanks to all of you for participating this afternoon. I know it was maybe a bit of a wait, but with our AGM and other things, that was unavoidable. We very much appreciate your participation and we look forward to talking with you again in the near-term. Bye for now.

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