TC Energy Corp (TRP) 2009 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2009 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.

Thanks very much and good afternoon, everyone. I'd like to take the 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 2009 first quarter financial results and other general issues concerning TransCanada. With me today are Hal Kvisle, President and Chief Executive Officer; Gregory Lohnes, Executive Vice President and Chief Financial Officer; Russ Girling, President Pipelines; Alex Pourbaix, President of Energy; and our Vice President and Controller, Glenn Menuz. Hal and Greg we 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 that presentation is available on our Website at transcanada.com and it can be found in the Investors 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 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 detail financial models, Myles, Terry and I would be pleased to discuss them with you following the call.

Before Hal begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the US Securities and Exchange Commission. And finally, I'd also like to point that during this presentation, we'll refer to measures such as comparable earnings; comparable earnings per share; earning before interest, taxes, depreciation and amortization or EBITDA; earnings before interest and taxes or EBIT; 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 measure are unlikely to be comparable to similar measures presented 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 and finance its operations. And with that, I'll now turn the call over to Hal.

Thank you David. Good afternoon, everyone and thank you for joining us here on a Friday afternoon. I'd like to take a few minutes to talk about our 2009 first quarter results and about recent developments in TransCanada's business. I'll then turn the call other to our Chief Financial Officer, Greg Lohnes, who will review our financial results in more detail. TransCanada's solid first quarter financial performance demonstrates our ability to generate significant earnings and cash flow from our large portfolio of energy infrastructure assets. As outlined in today's news release, TransCanada's net income for the quarter ended March 31 was CAD334 million or CAD0.54 per share. Comparable earnings for the first quarter were CAD343 million or CAD0.55 per share. Comparable EBITDA for the first quarter was CAD1.13 billion. And funds generated from operations in the first quarter were CAD766 million.

Looking forward, we are well positioned to fund our large 2009 capital program. This is due to our strong internally generated cash flow, as well as our prudent decisions to maintain TransCanada's strong financial position and liquidity during these uncertain economic times. To that end, TransCanada successfully issued CAD3.1 billion of long-term debt in the first quarter and CAD1.1 billion of common shares at the end of 2008. Although the carrying costs and dilution associated with these financings, will have an impact on our 2009 results, we remain well positioned to generate strong long-term return for our shareholders. Today, we are in the midst of constructing CAD19 billion of commercially secured, low-risk projects, such as the Keystone oil pipeline, the North Central Corridor expansion, the Bruce Power refurbishment and three large scale gas-fired power plants that will be completed and placed into service over the next four years. Each of these projects is expected to generate significant long-term earnings and cash flow for our shareholders. During the first quarter of 2009, we continued to make significant progress on these low-risk growth projects.

I will now expand on some recent developments. As you know, in October 2008, TransCanada agreed to increase its equity ownership in the Keystone oil pipeline partnerships to approximately 80%. ConcoPhillips equity ownership was reduced concurrently to approximately 20%. Certain parties that have made volume commitments to the Keystone expansion had options to acquire up to a combined 15% ownership in the Keystone partnerships. None of these options were exercised.

Our 2009 capital spending and financing plans were prepared in the expectation that we would remain as an 80% owner of the Keystone partnerships. The decision by certain committed shippers does not change our financing plans for the year. Construction on phase one of the Keystone oil pipeline continues and is expected to be completed by the end of this year. On the regulatory front, TransCanada filed an application with the National Energy Board to construct and operate the Canadian portion of the Keystone expansion to the Gulf coast. And we are proceeding with state and federal regulatory filings in the United States.

On the gas side, regarding our Alberta system, later this month, we expect to complete the first section of the North Central Corridor expansion, at a total capital cost this year of approximately CAD400 million. Construction of the remaining sections and associated facilities will continue throughout 2009. With final completion of the North Central Corridor expansion anticipated in April 2010, about a year from now. In February, the National Energy Board determined that the Alberta System is within federal jurisdiction and is subject to regulation under the National Energy Board Act, effective April 29, 2009. Under federal regulation, TransCanada will be able to apply to the National Energy Board for approval to extend its Alberta Pipeline System across provincial borders. This will allow the Company to provide attractive service auctions and rates to producers in British Columbia and the north.

In February, TransCanada announced the successful completion of a binding open season, to connect new shale gas supply in the Horn River Basin, north of Fort Nelson, BC to the Alberta System. TransCanada also recently concluded the successful binding open season for gas transmission service connecting the northeast BC Monteny shale gas play to our Alberta System. Together, the Horn River and Groundbirch pipelines have secured firm transportation support for volumes climbing to 1.5 billion cubic feet per day by the year 2014. The Horn River and Groundbirch extensions of the Alberta System will further strengthen our pipeline franchise in western Canada and on the Canadian mainline and US pipelines that move national gas to premium North American markets.

Further on our Canadian gas pipelines, Trans Quebec and Maritimes pipeline received the National Energy Board decision on its cost of capital application for the years 2007 and 2008. The NEB decision granted TQM an aggregate return on capital of 6.4%, leaving it to TQM to choose it optimal capital structure. This was an important National Energy Board decision for the Canadian natural gas pipeline industry.

On the US side, in our US gas pipeline business, we continue to advance our Rockies pipeline initiatives. TransCanada's Bison pipeline project filed an application in April with the Federal Energy Regulatory Commission for the right to construct, own and operate the pipeline. The Bison project will consist of approximately 302 miles of 30-inch diameter natural gas pipeline. The pipeline is designed to transport gas from the Powder River Basin in Wyoming to Midwest US markets. Bison's contracted capacity of approximately 407 million cubic feet per day has the potential to expand up to approximately 1 Bcf per day over time.

Turning now to our energy business. the 550 megawatt Portlands Energy Centre, located in downturn Toronto, was fully commissioned, under budget on April 22, 2009. We are very pleased with that outcome and very pleased to have Portlands Energy Centre in service. The power plant, which is 50% owned by TransCanada, will provide much needed electricity to Toronto homes and businesses. The predictable, sustainable cash flows and earnings contributions from Portlands, under a 20 year accelerated clean energy supply contract with the Ontario Power Authority, is another example of TransCanada's low-risk business growth to the power business in Ontario and Quebec. Progress also continues on the Bruce nuclear restart project and the Halton Hills generating station, both located in Ontario, along with the Kibby wind project in Maine and the Coolidge generating station in Arizona.

In summary, opportunities such as these and many others, I highlighted at our annual meeting earlier today, will continue to build long-term value for our shareholders. I'd now like to turn the call over to Greg Lohnes, our Chief Financial Officer, who will provide additional details on our first quarter 2009 financial results. Greg?

Thanks, Hal. And good afternoon, everyone. As Hal mentioned, earlier today, we released our first quarter results. Net income for the first quarter was CAD334 million or CAD0.54 per share, compared to CAD449 million or CAD0.83 per share for the same period last year. Comparable earnings in the first quarter were CAD343 million or CAD0.55 per share, compared to CAD326 million or CAD0.66 per share for the same period in 2008. First quarter 2009 and 2008 comparable earnings, excluded CAD9 million after tax and CAD12 million after tax, respectively, of net unrealized losses resulting from the changes in the fair value of proprietary natural gas storage inventory and forward purchase and sale contracts. In addition, first quarter 2008 comparable earnings excluded CAD152 million of Calpine bankruptcy settlements, the CAD10 million GTN lawsuit, and the CAD27 million write-down of Broadwater LNG project costs.

Before I review our results in more detail, I would like to highlight, for the benefit of those who did not have the opportunity to listen to last week's conference call, that we have changed our financial reporting format. The pipeline and energy business segments are now grouped into Canadian and US categories. We also have enhanced our financial reporting to show asset results at the EBITDA level and segment results at the EBIT level. Information on these changes, along with supplemental financial information for 2008 and 2007, can be found in the Investors section of our Website under the heading "Conference Calls and Presentations."

I will now briefly review the first quarter results for each of our business segments at the EBITDA level, beginning with pipelines. The pipelines business generated comparable EBITDA of CAD871 million during the first quarter 2009, an increase of CAD69 million over the same period in 2008. US pipelines comparable EBITDA increased CAD79 million primarily due to a stronger US dollar and higher revenue from new growth projects at A&R. The average US to Canadian exchange rate in the first quarter of 2009 was CAD1.25 compared to CAD1.00 in 2008. Canadian pipelines EBITDA in the first quarter 2009 of CAD505 million is comparable to CAD517 million reported in the first quarter last year.

In light of the nature of the Canadian regulated model, we continue to report the Canadian mainline, Alberta System and Foothills net income as supplementary information in our quarterly report. The net income contribution in first quarter 2009 from these three wholly owned Canadian pipelines increased CAD4 million to CAD111 million, primarily due to the impact of the 2008/2009 Alberta Systems settlement. Looking forward, although the global economic downturn can impact throughput on certain pipelines, the short term financial outlook for our pipeline segments is not expected to be materially impacted on an annual basis. Our pipeline assets earn a regulated rate of return and are generally underpinned by contracts with strong counterparties. Seasonality does affect our US pipelines. For example, ANR has realized approximately 1/3 of its annual EBITDA in the first quarter. The second and third quarters tend to be weaker as a result of the spring and fall shoulder season. ANR's EBITDA then tends to rise again in the fourth quarter, as we start into the winter months.

Next, some comments on energy. Energy generated comparable EBITDA of CAD290 million in the first quarter of 2009, compared to CAD287 million in the same period last year. Western Power EBITDA for the first quarter of 2009 decreased CAD6 million, compared to the first quarter last year. This was primarily due to lower volumes of power sold in Alberta, resulting from lower power plant availability under the PPA's, partially offset by lower PPA costs per megawatt hour. Approximately 64% of Western Power sales volumes were sold under contract in the first quarter of 2009, compared to 72% in the first quarter of 2008. To reduce it exposure to spot market prices on uncontracted volumes, as at March 31, 2009, Western Power had fixed price power sales contracts for approximately 6,500 gigawatt hours or approximately 54% of planned production for the remainder of 2009. And 5,500 gigawatt hours or approximately 37% of planned production for 2010.

Eastern Power EBITDA of CAD52 million increased CAD17 million, compared to CAD35 million in the first quarter 2008. This was primarily due to increased earnings from Becancour and the Carleton wind farm at Cartier Wind, which went into service in November 2008. 100% of Eastern Power sales volumes were sold under contract in both first quarter 2009 and first quarter 2008 and will continue to be fully sold under contract in 2009 and 2010.

Finally, in Canadian Power, TransCanada's proportionate share of Bruce Power's comparable EBITDA increased CAD45 million compared to first quarter 2008. This was primarily due to increased revenues from higher output and lower operating costs, both as a result of fewer outage days at Bruce B. Higher contract prices at Bruce A also increased TransCanada's proportionate share of Bruce Power comparable EBITDA when compared to the first quarter 2008. 100% of the output from Bruce A in the first quarter 2009 was sold at a fixed price of CAD63 per megawatt hour, compared to CAD59.69 per megawatt hour in the first quarter of 2008. The Bruce Power units ran at a combined average availability of 96% in the first quarter of 2009 compared to 79% in the first quarter of 2008.

Looking forward, the overall plant availability percentage for 2009 is expected to be in the low 90's for the four Bruce B units and in the mid- 80's for the two operating Bruce A units. To reduce its exposure to spot market prices, at March 31, 2009, Bruce B had entered into fixed price sales contracts to sell forward approximately 8,350 gigawatt hours or approximately 45% of planned production through the rest of 2009. And 7,560 gigawatt hours or approximately 35% of planned production for 2010. At March 31, 2009, Bruce A had incurred CAD2.7 billion for the refurbishment restart of Units 1 and 2 and approximately CAD200 million for the refurbishment of Units 3 and 4.

Turning to US power. EBITDA in the first quarter over 2009 was CAD30 million, compared to CAD55 million in the same period last year. This was primarily due to decreased water flows at TC Hydro and a small expected loss at Ravenswood, as a result of seasonally lower capacity payments. These decreases were partially offset by higher realized prices on sales to commercial and industrial customers in New England and the positive impact of a stronger US dollar in the first quarter of 2009. To reduce its exposure to spot market prices, approximately 74% of power sales volumes were sold under fixed price sales contracts in the first quarter 2009. At March 31, 2009, US power had entered into fixed price power sales contracts to sale forward approximately 5,000 gigawatt hours for the remainder of 2009 and 4,100 gigawatt hours for 2010. Certain contracted volumes are dependent on customer usage levels.

Finally, in our energy segment, natural gas storage comparable EBITDA was CAD36 million in the first quarter of 2009, compared to CAD67 million in the same period last year. The decrease was due to lower withdrawal activity and reduced sales of proprietary natural gas at the Edson storage facility, compared to first quarter 2008. Looking forward, when compared to the outstanding results we had in 2008, our energy segment results outlook for 2009 is expected to decline as a result of the reduced market prices we are currently experiencing for power.

Turning now to corporate. Corporate EBIT in the first quarter 2009 was a loss of CAD30 million, compared to a loss of CAD22 million in the same period last year. The decrease in corporate EBIT was primarily due to higher support service costs in 2009, reflecting a growing asset base and inflation, as well as a third party reimbursement of certain costs in the first quarter 2008.

Now looking at some line items below EBIT, on the income statement. First quarter 2009 interest expense of CAD295 million, increased CAD77 million, compared to CAD218 million in the first quarter last year. The increase in interest expense was primarily due to new debt issues of US $1.5 billion and CAD500 million in August 2008. And US $2 billion and CAD700 million in January and February 2009, respectively. In addition, US dollar denominated interest expense increased due to the impact of the stronger US dollar. These increases were partially offset by increased capitalization of interest to finance the Company's larger capital spending program in 2009. On a consolidated basis, the positive impact of a stronger US dollar on US pipelines and energy results, is almost fully offset by the net negative impact on US interest expenses and other nonoperational expenses. Thereby, effectively reducing the Company's exposure to changes in foreign exchange.

Interest income and other was CAD22 million for the first quarter 2009, compared to CAD11 million for the same period in 2008. The increase of CAD11 million was primarily due to higher gains from changes from the fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations. Income taxes were CAD116 million for the first quarter 2009, compared to CAD252 million for the same period in 2008. The decrease in income taxes was primarily due to the first quarter 2008 Calpine bankruptcy settlements, as well as higher tax rate differentials and other positive tax adjustments in 2009. Noncontrolling interest of CAD35 million in the first quarter of 2009, decreased CAD36 million, compared to CAD71 million in the same period of 2008, primarily due to the noncontrolling interest portion of Portlands Calpine bankruptcy settlement in first quarter.

Turning to the cash flow statement. Funds generated from operations were CAD766 million in the first quarter 2009, compared to CAD922 million in the first quarter of 2008. Excluding after tax proceeds received from the Calpine bankruptcy settlements in the first quarter 2008 of CAD152 million, funds generated from operations in the first quarter of 2009 were consistent period over period. Capital expenditures and acquisitions in the first quarter of 2009 of approximately CAD1.3 billion, relate primarily to a number of growth opportunities, including the Keystone pipeline system, expansion of the Alberta System, Bruce Power, Kibby Wind, Halton Hills, Coolidge and Portlands Energy Centre.

TransCanada's financial position remains sound. At the end of March, our balance sheet consisted of 55% debt, which included our proportionate share joint venture debt; 4% junior subordinated notes; 1% preferred shares; and 40% common equity. I would note that our debt on this slide is calculated net of cash. Our liquidity position remains solid, underpinned by highly predictable cash flows from operations, significant cash balances on hand from recent debt issues, as well as committed revolving bank lines. To date, no draws have been made on these bank lines. TransCanada has maintained continuous access to the Canadian commercial paper market on competitive terms.

In the first quarter 2009, we issued CAD3.1 billion and retired CAD482 million of long term debt. We also issued 2.1 million common shares under the dividend reinvestment program in lieu of making cash dividend payments of CAD67 million. At the end of 2008, we also issued CAD1.1 billion of common shares. This strategy is strengthening our liquidity and financial position through a proven ability to successfully access capital markets in uncertain economic times has significantly reduced the financing requirements for our 2009 capital program. While the significant cash balance on hand, means we are well positioned to fund our large capital program, the increased interest costs and dilution associated with these financings will have an impact on our 2009 overall and per share results. However, the near term impact will, in due course, be offset by the incremental earnings and cash flow that will be generated in the future, as CAD19 billion of commercially secured low-risk projects are completed and placed into service.

Going forward, we will continue to look at portfolio management, either through outright asset sales or asset sale downs to our US Master Limited Partnership, TC pipelines. We will also look at subordinated capital options, such as mandatory convertibles and preferred shares to prudently help finance our growth initiatives. That concludes my prepared remarks. I'll now turn the call back to David for the question-and-answer period.

Thanks, Greg. Just a reminder, before I turn it over 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. So with that, I'll turn it back to the conference coordinator for your questions.

Thank you. (Operator Instructions). The first question is from Cark Kirst from BMO Capital Markets. Please go ahead.

Hi, good afternoon, everybody. Just starting in Alberta on the power price issue for a second. Can you tell me if we've got the absolute volumes, how much hedges were actually added in the first quarter? And I'm trying to get a sense of how you're viewing the hedge program in today's prices? If it's just sort of a methodical roll forward of layering in hedges, as is typically done or as we go through second quarter perhaps, just get to where prices are, we're going to hold off on hedging any more. I'm ultimately trying to see if you guys have a specific outlook you can share with us.

Carl, it's Alex. You've probably heard me talk in the past about this sort of 75/50/25 plus hedging percentage that we like to maintain, sort of in the prompt, year one out and year two. And what I would say in Alberta is, we're probably a little under hedged, particularly in '10 and '11 versus, versus that plan. I would say going forward, when I look at forward power prices, gas prices and the implied heat rates coming out of that. I think the prices we're seeing in '09, sort of in the low 60's, for the balance of the year, those are probably pretty reasonable prices. And I would not be opposed and in fact, you'll probably see us continue to hedge forward, as opportunity permits, in and around that range. My general view on 2010 and 2011 is, we're talking about implied heat rates at those power prices well below 10,000. And I look at that -- this is a market that on average has cleared average heat rates in the range of CAD12 to CAD14 heat rates. I look at that and implied heat rate of CAD 9 or CAD10, it looks to me like 2010 and 2011 are not really good opportunities to hedge significantly right now. I think we'll have a better opportunity later on.

Okay. That's very helpful. And maybe a question for Alex with respect to the Ravenswood. It was nice to see the newer capacity summer auction be up actually 3% or 4% versus last summer.

Yes.

Kind of nice to see that that's not cratering down with demand. I just wanted to ask; Are you seeing, hearing or smelling anything with respect to the [Polety] plant, coming off in early 2010? And given what we've just seen with the summer auction and the Polety comes out, are we still looking at basically capacity prices in 2010 summer doubling over 2009?

Yes, I think that that's pretty fair. You'll recall when we did this deal, we very much acknowledged that '09 was going to be our toughest year as we worked through the capacity. Where we are now, at the time we announced the deal, we had said, one of the reasons we were comfortable with the market was that we felt that the New York City Zone J market was particularly insensitive to even very major economic dislocations. And I think so far, that assumption has proven to be well founded. I think the New York ISO is, so far, looking at a reduction in peek demand of somewhere about 1% over previous forecasts. So, the demand and particularly the peak demand is holding in. What I would say when I look at capacity, we were pleasantly surprised to see that the first of the summer months, the May spot auction cleared close to CAD1 over our expectations. We expect -- we're not seeing anything that would suggest that Polety will not be coming out at the end of January 2010. In fact, I would argue, given how incredibly difficult it would be to reverse that decision, if there was any thoughts whatsoever of doing it, there would have to be very active intervention going on right now to keep that plant alive. So, I would say our comfort level with Polety retiring is as high or higher than at the time we bought the plant. And when that retires, we would expect to see probably close to a doubling of the 2009 contribution from Ravenswood.

Great. Appreciate the color and I'll jump back in queue.

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

Thank you. Just further on Ravenswood, When might we expect to see Unit 30 coming back into service over the next couple of months? And can you provide some more color as to both cost and revenue impact that it had in Q1 and what might be expected for Q2? As well as an outlook on when insurance recoveries might kick in and how you'll be booking for those? Or you're already booking any of those insurance recoveries.

I'll talk about sort of the technical assets and sort of my thoughts on the insurance Linda and Glenn might want to talk about the -- how we're accounting for this. The unit 30, the rotor is now repaired, it is back on site. We expect to see unit 30 back in service around the middle of the month. In time for, obviously, the very important summer capacity season. With respect to the insurance proceeds, we have taken the position that this is a loss that we believe is fully insured under our -- both for property and for business interruption insurance. And I'll pass it on to Glenn as to -- if he has any comments on sort of how we're treating that.

Sure. As we had said before, the property insurance side of this is rather small, in that the cost is not that large. It's quite small in relation. But from a business interruption point of view, obviously, any time you're dealing with any insurer, there's always a debate as to; How much will be covered? What it will be? And working through all of the details of that. So once we have more clarity on that, obviously, we'll be able to look more at the accounting. But right now, things are still in the discovery stages and working through the details.

But you didn't book any recovery, assumed, implied in Q1 at all?

No, Linda, we have not.

So, what is the estimate for lost margins in Q1?

On an energy basis, it wouldn't have been a huge number, Linda. I don't have it in front of me. But it certainly would have been something significantly less than CAD10 million.

On an energy basis and then, plus, you had the capacity loss as well.

Yes, sorry. Yes. I thought we were talking about the energy side of it. The capacity, I don't have the number in front of me. We'd have to think about it. It's probably a number in the range, I am going to say all in, probably somewhere in the range of CAD30 to CAD50 million.

All in, including the energy basis?

Including any impact on capacity and energy. Okay. That's very helpful. And can I ask a follow up question?

Sure.

On your energy side, just in terms of -- this is somewhat accounting related. One of your partners in Bruce B, Cameco, has indicated they expect to make -- or to get some pretty major floor payments in the coming year. And my question is, is that the outlook that TransCanada expects as well? And how would it be booked? Because I'm understanding that Cameco would actually not book that on the income statement.

I'll take a shot at that and let Alex jump in. The floor payments on Bruce B are the difference between where the market is clearing versus this preset amount. But due to the terms of the contract with the OPA, these are also refundable at a future data, at some point when the actual price exceeds the floor payment. So as a result, to date, as we've disclosed in the quarterly report and in our annual reports in the past, we have not recorded any of that in income. Because it really requires an outlook of where you see power prices going over the course of the contract.

Okay. But you haven't received any cash payments on the floor payments to date, either, though.

Bruce Power has, yes. But they are refundable when the actual prices do exceed the floor.

Okay.

And to just to reiterate, we have not taken that into income. And I think you'll see that in our quarterly disclosure.

Okay. Thank you.

Thank you. The next question is from Matthew Akman from Macquarie. Please go ahead.

Thanks very much. I wanted to ask about your gas pipeline strategy because the gas market in North America has changed so much lately and TransCanada had a lot of focus on northern gas also developing regasification facilities in and around North America. Is there a shift now in strategy in terms of what you're developing on the gas front, given changes in pricing, both in North American and globally with LNG? So, what is the focus now, if it's not as much northern gas and regas facilities? What is the focus for development on the gas pipeline business over the next, say, five years, given where we are?

Sure. Matthew, it's Hal. Clearly, LNG projects are on the back burner for the next little while. We have our regulatory set back on the Broadwater. But given that we have full FERC approval and full Coast Guard approval, we're just working with Shell, our partner, and considering whether we should terminate the project or put it on the back burner or just what kind of an approach we should take. But clearly, there's not a strong economic signal that we should be proceeding with Broadwater or any other LNG project in the near term. We had pretty much terminated work on [Kokoona] quite awhile ago. So, it's not really an impact there. Kokoona was not driven by the changes in the gas price market but rather by the Russian decision not to go ahead and enter into the gas supply contract with us. So, that project was effectively on hold, in any event.

Northern pipes are interesting. I don't think anybody would proceed with a Mackenzie or Alaska pipeline project based on this month's gas price versus what gas prices were eight months ago. Gas prices are obviously volatile and we look at them today and we would say that our gas price outlook for the longer term is somewhere in the 6 to 10 range. And you could see over that period, gas prices going well above 10 and you can see them going down into the 3 or 4 range, as we're seeing right now. But we don't think gas prices are going to remain below CAD4 because you can't actually offset the annual decline that occurs in the supply base. Every year, we lose about 13 BcF a day through declining production in North America and that much has to be brought back on just to maintain flat production. And if the price is below 4, that simply can't occur. So, we would expect gas prices to move back up into that 6 to 10 range.

The Alaska project is different from MacKenzie, in that it is just a project to bring gas that's on production and that is being processed every day and bring that production to market by building a pipeline to connect it. MacKenzie is a little more complicated. There's no field development occurred. And so, in addition to the pipeline, the producers have to make all of the investments to drill l up the fields and develop the facilities. And that just puts an extra burden on MacKenzie. And the urgency, if you will, of getting going on MacKenzie is not there, to the same extent it is in the case of Alaska. What are we doing in the meantime? We've actually got on awful lot of really interesting opportunity in front of us right now. As you've seen, we're building the North Central Corridor in Alberta to connect Northwest Gas over into our eastern Alberta System.

We're going to be building pipelines to connect Groundbirch, that's the Monteny play near Dawson Creek. And to connect Horn River, up near Fort Nelson. Those are both large diameter pipes. And you know, just the magnitude of gas infrastructure is significant. If you look at the Bison project, that's 300 miles or 500-kilometers of 30-inch pipe. That's a relatively long haul, large capital investment pipeline project in its own right and we've got good commercial terms on that. We see opportunity to build feeder lines into the ANR system from the Haynesville Shale play. And there's other projects like Marcellus and Fayetteville. Really the thing that's going to drive LNG offshore and might delay northern gas, would be things like shale gas. And so, we just have to shift our focus and look at those opportunities in the near term and we're not uncomfortable with that at all.

Is that -- just a quick supplementary, are there also opportunities still to develop more storage around the ANR pipeline?

Yes, there are. We have significant opportunities to develop -- to both expand existing reservoirs and operations in Michigan, and to develop other -- there's a number of other geological features there that are well suited to gas storage. In some of them, we have to negotiate commercial arrangements with other people that have a partial interest in them. But the opportunities are there and we're watching storage closely. And if the market demand is there for it, we've got a number of opportunities to go ahead.

Okay. Thanks very much, Hal.

Thank you, Matthew.

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

Thank you. Maybe just staying on the storage side. We look at where gas prices are right now and you look at kind of where the strip is, it looks like there's a much better opportunity to make some money versus where you sat last year. What's your ability right now to capture that curve? And are you seeing the same dynamics, at least kind of just building for better earnings, as we get into the back half of the year and then into 2010.

It's Alex. You are correct, we are seeing some very attractive spreads right now, sort of up in the -- up towards the 1.06, 1.80 range. We are right -- one of the things I would say about the unregulated storage business is, we are relatively hedged right now. We're probably about 90% to 92% forward sold, in terms of our remaining storage capacity. So when you look at -- I would look at the Q1 results and say, they're fairly representative of a run rate for the rest of the year. Maybe a little lower in the middle and a little higher at the end of the year. And so -- but if you -- as you look into 2010, is 2010 maybe shaping up to be something like what 2008 looked like?

Just have to -- let me get back -- let me just think about that one. My gut feel is that it would be probably closer to '08 than '09 is going to turn out to be.

Just my other question was, with respect to looking at the subordinated capital or kind of the "equity alternatives," can you give a sense, probably for Greg, what you're seeing in terms of the timing, when you want to try to complete one of these transactions? And then, specifically, you mentioned the TC pipelines. We've seen that unit price come up quite a bit. Is it at a level where you think you can do more than just kind of sopping up some of the debt capacity down at the LP?

Well, you're right we're seeing the LP market come back. And we're actually seeing all of the subordinated product markets starting to improve. So, we continue to monitor them. We're starting to see the mandatory convertible market coming back. Obviously, the Canadian pref market has been a very active, particularly, with the banks and the demand for some diversification in that product, with some industrial issuance would be, I think, fairly popular. So, that market is available to us. We're in pretty good shape right now but we continue to monitor that market going forward. We're cognizant of the negative carry. And I think we've established for the marketplace, that we do have access to capital and that we can fund our growth program and that liquidity isn't an issue for us. So, we'll just continue to monitor those markets as they open up and as the all-in costs improve going forward here.

And how long would you want to wait before you start to get a little antsy?

Well, as I said, I think we're in really good shape right now but we are opportunistic and we're cognizant that we're still in a volatile capital market and we see things moving up and down. So, we will be opportunistic but we've got the opportunity to bide our time a little bit here.

Thanks, Alex.

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

Thank you. Good afternoon. Hal, if you could just give us some commentary on your thoughts on the value of long haul pipelines? And in particular, when you start to think about some of the shale plays, and things like the Marcellus and the Utica that are close to essentially big demand centers. And what does that mean for the longer term viability of pipelines like TransCo and really things heading up from the Gulf into those regions?

I would say, we don't know, at this point, How aggressively people will develop the Marcellus, how sustainable the production is, what kind of decline rates will occur? Emphatically, we don't know what kind of local opposition people are going to run into as they try to get drilling locations. I'm not trying to be pessimistic on it but these are some of the things that we have to see unfold over time. Obviously, if the Marcellus develops into a 5 Bcf a day play, it will have an impact on volumes coming up from the Gulf Coast. But it may not necessarily be all that negative for TransCo because they tend to be very well positioned to move short haul gas from Pennsylvania into the New York market and things like that. And these big US pipes, including our own ANR pipe, are heavily depreciated and the rate base or the billing determinants for tariffs are much, much lower than the cost of any new build pipe. So, I think that -- I expect that the industry would be able to cope with it and it would not have a dramatic effect. If there was a long haul pipe, that just came from the Gulf Coast to the Marcellus New York/Pennsylvania area and did not have any distribution element to it at the end, I think those people would more worried. But both tracks going into Tennessee, for example, have got very valuable end market service pipes at the north end.

I think we see -- for TransCanada, it's a very interesting situation, that as Horn River and Monteny gas come on in western Canada, we get a little bit higher throughput on our system. And under the Canadian cost of service model, that reduces the toll for everyone. And actually, could be a good thing to help keep tolls low and stimulate development in other areas. As volumes increase, we really don't make a lot more money on the Canadian regulated pipes but we do sustain our income. And it gives us a competitive advantage for tying in northern and other gas. Just keeping the volumes up, reduces the toll for everyone. We always like to have 20% spare capacity. So, it makes it easier for people just to deliver to us than commit to any kind of a new pipeline. And so, we're always aware of that as well.

Now, if you see very aggressive development of the shale plays in the US and we do see some of the higher end numbers like the 5 B's out of the Marcellus actually come to fruition. In the North American context, what are your thoughts on what does that mean for plays like Horn River and Monteny? Do you see that essentially wind up being -- since it is the end of the pipe in a North American context, essentially not being developed or the base is blowing our pretty wide from an Alberta market perspective?

I've looked back over the last 15 years and if people -- there have been many interesting new sources of gas come along. That at the time they come along, people proclaim that they're going to change the world. And they get pretty significant, some of them, but in the grand scheme of things, they're just one more source of supply. And I would particularly highlight coalbed methane. Coalbed methane was really going to have a dramatic effect and a lot of us thought it would never exceed 1 Bcf a day in western Canada. And it struggles to maintain 700 million a day. So, that in fact, has turned out to be the case. Looking broadly across North America, there's clearly some shale plays that are going to generate very impressive volumes. But I would argue that they are just the latest place that industry looks to replace declining production. And that as people turn their attention to drilling shale, they tend to leave other plays behind. Good examples are companies like Talisman, which has moved very aggressively into unconventional gas but has pulled back quite significantly on more conventional gas. So we do -- it's always good to remember that we have this 10 to 15 -- let me say 13 Bcf decline a day annual decline, every year in North America. We see production, including Mexico, going from something like 78Bcf down to 65 Bcf a day. And people need to drill like crazy to get it back up and sustain 78 Bcf a day. So, I think that big decline gets offset from new sources over time and I just see that shale is the most interesting opportunity for a lot of companies right now. But it's wrong -- if there's 5 Bcf a day of new shale gas coming on, you shouldn't just add that to the conventional base. I think people will be looking to shale in lieu of some of what they otherwise would have looked for to offset decline.

Andrew, I'd just add to that is, it's still an 80 Bcf to 90 Bfc a day market. And what we're going to need to see this gas come on, is something probably 5 to 6 range. In order to get that kind of demand -- that kind of price, we've got to see demand increase. And I think it's tied, as well, to; Where does gas-fired generation go? Relative to the renewables, where does coal go? So, there's a number of dynamics and your question is a good one is, How does all that play together? And I think you can't really take sort of Marcellus in isolation, it's outside of everything else that goes on, the declines. What we've tried to do as a pipeline Company, is position ourselves to move the gas between supply locations and market.

So for example, if Marcellus does come on, the gas can't be consumed in that region every day of the week. It needs to be backhauled, for example, back into Michigan storage because there isn't sufficient storage in the formations in the northeast. So again, our pipeline system becomes valuable in terms of moving that gas back into storage in the periods when demand isn't high in the northeast. And then, back when the demand occurs. And so, what we try to do is set up our systems so that it's all interconnected. And what we're finding right now with Haynesville supply, Fayetteville supply, where that's coming on in large quantities currently, it's trying to get out of that region. And so, what we're seeing is our ANR system, the east leg, where when we bought the pipe, it was probably running at about 60% to 70% capacity. Now, we're running at 100% capacity. So, now it's all moving up into the Dawn region, where we've got storage. But now we've got to figure out how to debottleneck the system and go east. And once we figure out that, then, like you said, there will be another change in the marketplace where Marcellus comes on.

But I think that where we're positioned today in North America is sort of coast to coast, in front of the shale plays in Alberta, shale plays in the mid-continent US, the onshore stuff. I think we're in well positioned in eastern Canada, as well as the northeast US to move gas around that region, through Iroquois, Portland. When we originally thought we were going to see LNG coming in large quantities in the East Coast, we looked at ways of reversing our DQM and Portland natural gas by system to deliver gas back up into eastern Canada. So, there's other ways that we can change our tolling structure, as well. Like when you get there, you change your tolling structure to load more costs into those regions that can support those costs. There's the postage stamp tolling methodologies. And given these are all regulated pipelines, at the end of the day, we have the ability to recover our costs. And what we would do is adjust our tolling structure to service the market that needs to be serviced and we would allocate the costs accordingly. So not saying that we don't worry about these things but we also think that we're very well positioned and we also look at them as just huge opportunities for us.

That's very helpful. And as well as you answered the last question, this one is an easier one for you. Just on Keystone, later this year, that line will come up and running. When will you start line fill how much volume will you need to actually fill the pipe from a line fill perspective?

I can answer the first question. I believe it will be some time in October, November that we start to line fill process. I don't actually have the number of -- the quantity, I know it's a big, big number that starts in October. If you need the actual number, you can follow up with David after the call. We've got the number, I just don't have it at the top of my head.

Okay. That's great. Thank you very much.

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

Thank you. I was surprised to hear anybody coming in under budget, which you mentioned for your Portland project. Halton Hills I could see as progressing along very well. Other projects, I'm sure, are progressing along a little bit better than one might have thought on a budget basis. Just curious as to how much, potentially, is there in terms of under budget opportunities within your CAD19 billion set right now? And how would that be shared or do you keep it all in case of Portlands or do you split it with your joint partner? Just some color about that because that might be some upside here for you in the next year or two.

Well, first of all, Sam on Portlands, the fact that we came in under budget was the result of a careful contracting strategy at the time when we entered into a fixed price contract to have that plant built. And we do a lot of big projects. So, we're, I think pretty, good at the fixed price contracting or whatever other commercial arrangement we make with the EPC contractors. The Portlands coming in under budget was not a result of recent reductions in steel price or anything like that. This is an outcome that was set up a long time ago. And then you just always have to be diligent and make sure you don't go off the rails in the last few months and have a whole bunch of things go wrong and have a whole bunch of incremental cost claims from your contractor. So, our contractor there, SNC, did a very good job on that project. And we appreciate their efforts and we're happy for everyone that we came in under budget. To the extent there's extra economic rent available from that plant because we came in a little bit cheaper than expected -- and I want to emphasize, this wasn't huge under budget but it was enough under budget that we like to brag about it a little bit, in the current circumstance. But to the extent there's economic rent there we share it with our partner, we're 50/50, I think Alex, with OPG.

Yes.

And so, that would be the case there. On projects like Halton Hills, we don't have a lot of upside there because again, we were very careful to fix the price of all of the major equipment and of all of the construction contracts. What you will see though, on project like Keystone, even the first phase of Keystone, because the overheated market is gone, we're not seeing some of the zany manpower shortages or extravagant overpayment demands from contractors or things like that. People, at this point, suddenly really like working for TransCanada. And so, it's much easier to maintain labor stability on the job and it's much easier to keep the contractors happy. It's just a less overheated market. So you don't necessarily set the stage for a big under budget performance but you remove much of the pressure that might have driven you over budget.

Now, looking beyond that, Sam, as we get into projects like the Keystone expansion, or some of the northern pipeline projects, or even subsequent phases of expansion here in Alberta; We're going to see pipe costs quite a bit lower than what we were seeing before. And there's tow or three things that drive steel pipe costs. One of them, is the coast of steel which, goes up or down quite independently of the cost of rolling that steel into pipe. So if everybody is buying pipe but the rest of the world of steel is down, the steel will be cheap but the rolling costs will be high. And of course, it can go the other way. So, those are all factors that we look at. But I'd say right now, the demand for pipe is down and certainly worldwide, the demand for steel is way down. So, that should set the stage for better outcomes on some of our future projects.

Thank you. A quick follow up. Has to do with Bruce, Alex, there's been a couple of weeks or months more drift away, phrase your words, will you be able to start that one unit in Q4 this year? Is that now Q1 officially or how does it look?

Sorry, I missed that.

The Bruce refurbishments. Last quarter you had one you were hoping to start in Q4. The way your words read now, it looks like it will be ready for '10.

No, Sam, they were always in the back half of 2010.

Yes.

If you went back a couple of years, there might have been an expectation it was going to start in Q1 of 2010 but everything has been pushed back about six months, Sam. So we were -- we've always been looking at -- for several years now, at the second half of 2010.

I think the commentary, Sam, in the quarterly is pretty consistent with the last quarter and the annual report.

Okay. I just kind of vaguely recall, maybe I'm the one vague here, that you had one that was going to start ahead of the other, of course, in the sequencing of things.

Yes, your memory just might be pretty good and you might be going back about three years ago.

I lost three years. I guess it is time for the weekend. Thank you.

Thank you. The next question is from Steven Paget from FirstEnergy. Please go ahead.

Thank you. My question has been answered.

Thanks, Steven.

Thank you. The next question is from Harry Mateer from Barclays Capital. Please go ahead.

Hi, guys. You talked about some of the sources of subordinated capital you might seek. I was just wondering if you could talk about what you're seeing the in asset sale market, away from potential drop downs in the MLP? And then, second related to that, even though you came relatively recently to the public bond market, is that something you're considering again this year? Particularly, in light of the market being quite accessible to investment grade issuers during the past couple of weeks?

Sure. On the divestitures side, we're always looking at our portfolio and culling our portfolio as necessary. We have a very high quality group of assets right now, some very valuable assets but we do have some that are fairly mature or don't have additional upside. The market is a little soft right now. But in certain cases, there are strategic buyers that might be interested in particular assets. So, we continue to monitor that market and to look at our portfolio as we move forward. I think we're seeing things improving in that area a little bit.

With regard to the debt side, we've just done a significant debt issuance. We tend to go in large quantities and then stay out of that market for a significant period of time. And that seems to be what the bondholders like to see, particularly, in the US market. We've funded the majority of our 2009 spend. We do have a maturity remaining towards the end of the year of about CAD250 million. And then, two maturities -- in '10 and '11, we have maturities in each year of about CAD400 million. For a total of CAD1 billion. So, it's quite a benign maturity profile.

And as we've said in the quarter and in my comments, we're pretty well funded here for the next while for 2009 and our CP program at the TCPO level is down under CAD300 million. We've got CAD2 billion worth of room under our lines there and we still have another CAD400 million or so of room under our Keystone line. And that, we're funding at sub 2% level in the US and around 2% Canada in that market. So, that's an attractive market for us right now. We we do have some financings to do at the subsidiary and affiliate level. There's a financing at Northern Border at TQM and as well, at Iroquois, that we're working on right now. And those usually get financed in the private placement market.

Okay. So, is it fair to say that at, this point, to the extent you do go out and raise some capital, you're going to be prioritizing other forms away from public debt market for the time being?

Well, on the debt side, that -- yes, we would look to use short term using our CP program. We tend to like to ramp that up not all of the way to the CAD2 billion level but in that CAD1 billion to CAD1.5 billion level, and then, take it down. But when we do that, we like to do benchmark sized deals that are significant.

Got it. Thank you.

Thank you. The next question is from Jeremy Rosenfield from Desjardins Securities. Please go ahead.

Thank you. Good afternoon, everyone. First question is just pretty much on the NEB TQM decision, which was received in March. Just if you can break out for me what the amount that was actually recovered for '07 and '08 and the first quarter '09, if there was an amount? And then, maybe afterwards, if you can just give a more general comment as to how you think you the move to an [ATWAC] formula, might actually impact Trans' other regulated assets and if there's some kind of strategy or positioning that might be going on with regard to some regulated Canadian pipelines?

Well, looking at the answer to 2007 and '08, I can give you some glimpse as to how that may impact the balance of TransCanada's Canadian regulated pipes. Basically, the National Energy Board moved from a formula that it used for all of its regulated pipelines in Canada -- or moved TQM from this formula that it used for all the other regulated pipelines in Canada. It would be our view, is given that they'd made the fundamental shift on that one pipeline, that sort of sets the stage potentially for us to get a similar result on our other pipelines. The Canadian mainline is the largest piece of that Canadian regulated puzzle. It has a settlement in place with its shippers through to the end of 2011. So, until that point in time, there won't be any impact on the rates return for that. But post-2011, I would expect that over time, that the mainline rate of return would migrate towards the TQM like return. NDTL is the second largest piece, which is now regulated by the National Energy Board, as of yesterday, I believe the actual certificate was given to us. It has a settlement in place for 2008 and 2009. The 2009, there's some issues there with respect to how we were going to calculate the rate of return in the event of some sort of generic change in cost of capital. In Alberta, now that it's not regulated in Alberta anymore, we'll have to figure out how we're going to manage that or negotiate that change, in light of the TQM decision and a generic review of cost of capital that's going on in Alberta right now.

And then, the other sort of smaller pieces of Canadian regulated pipe, would be that the Foothills System and I would expect that over time we would migrate towards that for the Foothills System as well. There's no settlement in place currently for the Foothills System. So, just to give you sort of a gut feel, is if the return on equity rose by about 100 to 150 basis points but just to pick 100, for example, we have a CAD12 billion rate base, approximately, in Canadian regulated assets. And about 40% equity thickness, on average. So, you're looking at about CAD5 billion of equity that we have employed in that business. And if you move the return on equity by 100 basis points, it's about CAD50 million of after tax net income. If over time, we were able to achieve a similar kind of result as we achieved on the TQM system.

And it's Glenn here. As far as what we recorded on TQM for '07 and '08, as noted in the quarterly report in other Canadian pipelines, we've got a variance there of about CAD6 million and that represents the entire settlement for those two years, the impact on TQM. So it's about CAD6 million, CAD7 million. But that only reflects '07 and '08.

And would you expect that recovery is for -- that's for the entirety of '07 and '08 or will there be more going forward in 2009?

That is the full amount of '07 and '08 on an EBITDA basis, so on a pretax basis.

Right.

And as far as '09, it would depend where the final tolls follow.

I believe we're still booking 2009 at the formula.

Yes, we're using the NEB formula because that's what is currently out there for TQM because the decision only related to '07 and '08.

So, you can take a look at the delta would be approximately what it was for '07 and '08, for '09, if we're able to achieve in '09 a settlement or a litigated outcome that's the same as 2007 and 2008.

Okay. Great. And if I could just come back and maybe ask even more generally, do you see a strategy now in terms of looking at Canadian regulated pipelines because of this sort of move towards ATWAC? Do you think there's some assets out there that might be more attractive for TransCanada to go after in terms of M&E, for example?

What we were more concerned about was the low nature of the number, and allocating capital to new projects in our portfolio at that low normal number. What we know is that we do need incremental infrastructure in Canada to move new gas around. And just a couple of the examples that we have underway, are the Monteny and Horn River plays, that Hal mentioned. And then, our Central Corridor play in Alberta. We've got about CAD2.5 billion of capital under development right now. And our concern was, we were achieving a return that was sub-6% on those assets. And our belief was, in the longer term, we would see a more fair and rational return. The positive in the TQM decision, is it looks like the National Energy Board supports our view as a -- that long term infrastructure is needed. And that you need a return on capital, such that you can attract the capital necessary to those projects. So I would think that you'd probably see, in our portfolio, us pursuing development projects that are necessary. Whereas before, we were pursuing them but probably with a little less enthusiasm, if you will. We knew volumetrically, we needed to bring them on line but from a return perspective, they were very difficult or very challenging. So, that's that's probably the biggest bonus for us as a Company is, we can move forward with our development work with a bit more confidence than we had before. And that's a pretty big number, it's about CAD2.5 billion right now.

All right. Thank you very much.

Thank you. The next question is from Carl Kirst with BMO Capital Markets. Please go ahead.

Appreciate the time, guys. Just very quickly, Russ, has there within any movement with respect to -- can you hear me?

Yes, we can, Carl.

to Port Arthur? And are we kind of many the environment with producers where they are, that we probably shouldn't expect to see much movement on that? Or because it might be more refining pool, that might still something that could go a little bit longer?

You skipped out right at the very beginning of that, Carl, on your question, with respect to Port Arthur. So, you may -- could you ask the question again?

Well, I was just trying to see if there had been any movement on continuing to contract for additional volumes down into the Gulf Coast area? Or if just kind of given the state of the right now, that in all reality, that's probably put on hold for the next six months or so?

I would say that there's still interest on both ends of the pipe. On the refining end, I believe that there's still a number of refiners that can take Canadian bitumen that are looking at it as an opportunity or an alternative to Venezuelan crude oil or Cantoral crude oil. Given that crude is not going to show up until 2011, they're sorting what their options are right now in the current environment. We're looking at a potential lateral to Houston, which opens an opportunity to move about 2 million to 3 million barrels a day. So, we've had some inbound calls from those, which may sort of increase our pull, if you will, at the demand end. And so, those conversations are ongoing.

And then, at the producer end, as we see it, a slow down or a delay in the upgrading projects, what that means from a transportation perspective, is if the bitumen still comes online, you actually need about 140% of that volume -- actually it's greater than that, if it would have turned into -- bitumen turning into crude oil, you only need about 85% of the transportation to actually produce a battel of bitumen, you turn it into a barrel of SCO, you really only need 85% of the transportation capacity. So, as we move from producing synthetic crude oil to bitumen, you move from that 85% to needing diluent and you need about 40% more diluent to move the product to market. So, we actually see a shift on that barrel of bitumen, that would have otherwise turned into better crude oil, you need about 1.4 barrels of transportation capacity to get the barrel of bitumen, plus the diluent to market.

So given that shift upstream, we're seeing, again, interest in our transportation capacity to get that crude oil, that upgraded bitumen, through to the Gulf Coast where it can actually be refined. So, we still have inbound interest at both ends of our pipeline. So, I would say, stay tuned in terms of various open seasons and those kind of things that we could have in the coming months, if you try to assess the demand in the marketplace for additional contracts.

Great. Thanks, guys.

Thank you. The next question is from Bob Hastings from Canaccord Adams. Please go ahead.

Thank you. Just back on Keystone. The cost estimate that you had there, you're mainly complete, everything is pretty much locked in. But have you looked ahead at the Keystone expansion and your expectations? Because I believe you have a cost sharing formula there, so in stead of the formula.

Let's start with the expectations. I think that our expectations are still in around that CAD7 billion level. The cost sort of rose in the marketplace and then come back down again around sort of where original estimates were. As Hal mentioned, steel prices have come off. We're seeing pipe, now, in the CAD1,800 a time range, opposed to say CAD2,500 that we saw last year. But when we started the process of evaluating Keystone XL, we were probability in the CAD1,800 range, maybe about the CAD2,000 range. So we've seen the estimate or -- the prices in the marketplace move around our estimate. So, I'd tell you that we're still pretty comfortable with our estimate. Based on the learnings that Hal mentioned on the base Keystone project, in terms of what we've learned about productivity and those kinds of things, weather-related issues that we've encountered and terrain things that we've encountered. I think we're pretty comfortable at CAD7 billion. And to his earlier comments, there's always an opportunity to come in under budget. But we set really ourselves up with, what I think, is real estimates up front and I wouldn't expect a big gain or a big loss on that. To extent that there is -- our cost sharing agreement that we have in place is 75% of any cost overage or underage accrues to our shippers. And TransCanada picks up -- or Keystone picks up 25%.

Okay. Thanks. And then, going back to the first phase of Keystone. Can you give us some ideas, Hal or Russ, on the step up of the earnings? We know you're going to start putting oil in the pipe but when do the contracts actually start? And how should we think of modeling the EBITDA coming into earnings? I'm sure there's a few step up periods here.

Yes, so, I think what we're kind of working today on a package that we can put out to the marketplace to help you better understand the step up. We're just sort of getting through that period of line fill and then, how how our contracts are going to ramp up over the year. And at the end of year, I could give you some sort of view on EBITDA. But we haven't released what our tolls are yet. So, from a competitive standpoint, you kind of know what the volumes are but we haven't told you how the tolls are going to work. But what we hope is that over the next few months, as we get closer to filing our tariffs and that kind of information become publicly available, we'll be able to give you a better road map as to the ramp up in EBITDA over the next year or so. That's the best that we could do for now.

As you can probably tell, at 500,000-barrels a day, if we charge about CAD3 a barrel, which is sort of an around the market kind of number, that gives you a feel for the end EBITDA number. And what we'll try to do is fill in the blanks for you over the next year or so. That CAD3 relates to the first markets that we attach ourselves to. And then, subsequently, we'll attach ourselves to Gulf Coast markets and those will be higher priced markets and approximately equivalent volume going in that direction. So stay tuned, is what I'm telling you. We recognize that we haven't provided a whole bunch of information.

Right. Would you give us any comfort on, in terms of say, your IRR's that you've talked about in past, that they're still there and there's not any sort of substandard returns for the next number of years until we can get up to those levels?

Absolutely, not. That's all -- the ramp up period is baked into the IRR. So, for the first year, as you bring the line fill on and the contracts sort of move in and we go through all of our sort of operating hiccups and that sort of thing, we've built in sort of enough room in year one for that. But once we're up and operating, that cash flow is flat essentially for the next 20 years. There is some upside with respect to where we think the flat number is for spot volumes moving on the system. But we've got minimal amounts of those baked into our forecast so far. So, I think what I've told you before is, if we just moved the contracted volumes, the IRR is going to be at around 7%. If we move a base level of spot volumes, we can get a return of about 8%. And if we sort of move all of the spot volume or spot available in the system, we can achieve a 9.5% or 10% kind of an outcome. So, that's the kind of range. And that hasn't deteriorated at all. So, I would sort of look to 2011 as being as sort of the first full year of service of the base Keystone. And probably 2013 as being the first full year service for Keystone XL or the Keystone expansion.

Okay. And that includes the higher debt costs that we have now?

Correct.

Okay. Thank you very much. Perfect.

Thank you. (Operator Instructions). Thank you. We will now take questions from the media. (Operator Instructions)

Operator?

There are no further questions registered at this time.

Okay. Thanks very much. I'd just like to extend my thanks to all of you for listening this afternoon, late on a Friday afternoon. I very much appreciate your interest in TransCanada. We look forward to talking to you soon. Bye for now.

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