恩橋 (ENB) 2008 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Enbridge, Inc. 2008 first quarter financial results conference call. I would now like to turn the needing over to Mr. Vern Yu.

Thank you and good morning. Welcome to the Enbridge, Inc. first quarter 2008 earnings conference call. With me this morning are Pat Daniel, President and Chief Executive Officer; Richard Bird, Executive Vice President and Chief Financial Officer and corporate development; Steve Wuorii, Executive Vice President at Liquids Pipelines; and Colin Gruending, Vice President and controller.

Before we begin I should advise you that during the call we may refer to certain information that constitutes forward-looking information. Please take note of the legally-required forward-looking information disclaimer in our slides, which generally state that you should not place undue reliance on our statements about the future since we necessarily apply certain assumptions to reach conclusions about future outcome, and future outcomes are always subject to risks and uncertainties affecting our business, including regulatory parameters, weather, economic conditions, exchange rates, interest rates and commodity prices. A more fulsome discussion of these risks and uncertainties is included in our securities disclosure filings, which are cubically available, both on SEDAR and EDGAR.

This call is a webcast and I'd encourage those listening on the phone lines to view the supporting slides, which available on our website at www.enbridge.com/investor. A replay of the call will be available later today and a transcript will be posted to our website shortly thereafter. The Q&A format will be the same as the Q4 call. The initial Q&A session is restricted to the analyst community. When we have concluded the Q&A's for the analyst community we will invite media onto the call for further Q&A. For both Q&A sessions we ask that you limit your questions to one plus a follow up then rejoin the queue. I would also remind you that Colin, Anu and I will be available after the call for more detailed questions that you may have.

And at this point I'd like to turn the call over to Pat Daniel.

Great. Thank you very much, Vern. Good morning, everyone. I'm very pleased that you were all able to join us. As we reported earlier today, our adjusted operating earnings for the first quarter of 2008 were $239 million, or $0.67 per common share, which exceeds the $0.65 consensus forecast and this provides us now with a very solid basis for meeting our full-year adjusted operating earnings guidance of $1.80 to $1.90 per common share, so we're very pleased with this start to the year. The Liquids Pipelines and Gas Distribution Services segments both have strong quarters and I'm very pleased with the results also reported by our affiliate, Enbridge Energy Partner where adjusted quarterly net income per unit was over 40% -- up over 40% from quarter one 2007 and this resulted in a significant increase in the contribution to Enbridge, Inc., of course. Richard Bird is going to review the quarterly financials in more detail in a few moments.

I'm going to keep my remarks on the strategic update relatively brief this morning, as I'm going to be speaking again later today at the annual general meeting in a little more detail, so what I'd like to focus on key developments since our year-end conference call. I'm sure you all know that these are very exciting times at Enbridge, as we're in the midst of the largest growth program in the history of the Company. Our very strong geographical positioning, particularly in the crude oil pipelining business, is allowing us to expand and extend our delivery networks to reach new markets for our customers and this is largely driven by the growing oil sands production in Western Canada. To implement this strategy, as you know we have some $12 billion in capital expenditures for projects that are commercially secured and are underway today, and I'm very pleased with the progress that we've made in construction and regulatory activities on several of these projects during the quarter.

Let me give you a few examples, starting with -- on April 1 we completed phase one of our Southern Access Expansion on schedule and the pipeline is now ready to accept line fill. Phase one, of course, added 190,000-barrels per day of net capacity to the Enbridge system and involved building 321-miles of new 40-inch pipeline -- 42-inch pipeline from Superior, Wisconsin, down to Delavan, Wisconsin. Stage two of Southern Access Expansion will add an incremental 210,000-barrels per day capacity to the entire system by the end of quarter one 2009. This second phase, of course, consists of additional upstream pumping capacity and 133-miles of the new 40-inch pipeline from Delavan, Wisconsin to Flanagan, Illinois. We expect to begin construction on that stage two in June of 2008.

Moving on to the Waupisoo pipeline, it is more than 90% complete and it may actually be in service a month ahead of its June 30 target completion date. And I think you will agree that given all of the construction delays that we've seen in our industry that we should be very proud of this achievement of bringing a project in a month early in this environment. Waupisoo will have an initial capacity of 350,000-barrels per day and will move crude oil from the Cheecham, which is south of Fort McMurray, Alberta down to Edmonton. With the addition of pumping stations Waupisoo can be expanded to an ultimate capacity of 600,000-barrels a day so we're very well positioned now with Waupisoo. Construction of our Southern Lights diluent return line continues to proceed as planned. Over 90% of the pipeline between Superior and Delavan, Wisconsin has been completed and we continue to expect this project to be in service late in 2010. Also in the quarter we received regulatory approval from the NEB that allows us to proceed with the Canadian portions of Southern Lights and the Alberta Clipper pipelines, as well as line four extension project, which as you may recall is between Edmonton and Hardesty, Alberta.

While most of the growth initiatives have been in the crude oil side of the business, we're also pursuing a number of significant initiatives in our gas division and we've made excellent progress on those, as well, over the quarter. We completed the Neptune pipeline in March and we now have the capacity to move an incremental 60,000-barrels a day of crude oil and 2,000mcf of natural gas from the Neptune oil and gas field, which is in the Green Canyon in the offshore gulf to our existing offshore Gulf of Mexico pipeline system. We expect production to commence from these fields in the third quarter of 2008, but in the meantime we do earn standby fees in having put those facilities in place. Construction on our 198 megawatt Ontario wind project near Kincardine is also progressing well. We now expect the facilities to begin producing electricity by the start of the first quarter of this year and then we expect that to be fully operational by the end of the year.

The most significant news in our Gas segment really was the Ontario Energy Board's approval in February of this year of an incentive regulation plan for Enbridge Gas Distribution and this is going to encompass now the next five years. We're pleased to be operating under incentive regulation, as this will allow us to earn returns in excess of the allowed utility rate of return on equity, and in this instance where the first 100 basis points of savings are going accrue directly to Enbridge and the next 200 basis points of savings will be shared 50/50 with our customers. So we believe that we're going to be able to generate an incremental, probably somewhere in the range of 100 to 150 basis points improvement in return for our shareholders at the same time that we pass significant savings on to our customers.

Now that I've covered that brief summary of the progress on the commercially-secured projects of the first wave of growth at Enbridge, let me remind you that we also have an additional $15 billion worth of growth opportunities which are forecast to come into service after 2007. We've labeled this the second wave of potential projects and it includes additional regional infrastructure in Alberta, further mainline expansion, developing new market access, and by new market access, we are thinking here primarily the U.S. Gulf Coast and then expansion into the eastern part of Pad two, and then what we call longer term new market access, for example the gateway project to the West Coast and the U.S. East Coast that had one access. And on top of all of that, some incremental contract terminals. I think that it's fair to say that it's unlikely that we're going win all $15 billion worth of that work, but we do expect to win our fair share of it.

Maybe I can spend a few minutes addressing the U.S. Gulf Coast and our Texas access initiative, primarily because transportation of Western Canadian crude oil to the U.S. Gulf Coast is a pretty hot topic in our industry today and it's timely that we bring you up to date on where we are. First of all, coming back to the fundamentals, getting Canadian heavy crude to the Gulf Coast will enhance net backs for Canadian producers and provide a secure source of heavy crude oil to the U.S. Gulf Coast refineries, so it's got dual benefit. This will allow Canadian producers and Gulf Coast refiners to share in the economic benefit of what is a converging heavy crude oil price differential between Canadian heavy crude priced in Alberta and Mexican Mayan crude priced in the Gulf Coast. On a quality basis these two crudes are the same, but Canadian heavy traded on average at about $11 a barrel discount to Mexican Mayan in the last quarter of 2007 and that's after taking into account transportation to the Gulf. So assuming 400,000-barrels a day that represents about $1.5 billion per year of economic benefit that can be shared between Canadian producers and Gulf Coast refiners. Canadian producers should see a further economic benefit as the pipeline will improve net backs on all barrels that they move to other markets, as well, or could very well do that..

So let me just give you a quick update as to where we are on this strategy. First we have projects underway that will expand our mainline system by 400,000-barrels a day from Western Canada to Patoka, Illinois, and that's two-thirds of the way to the Gulf Coast right off the bat. These projects, which are Southern Access Expansion, Southern Access Extension and Alberta Clipper -- all of which I've already talked about -- have been approved by our shippers and are now either under construction or they're proceeding into construction. So given this starting point, we believe the most economic and competitive solution to accessing the Gulf Coast for a volume of 400,000-barrels a day is our Texas access pipeline joint venture with Exxon Mobil. Here we will extend a large-diameter line due south from Patoka to the Gulf Coast at a capital cost of about $2.6 billion, and this is significantly cheaper than building a complete new line from Western Canada at a cost that would be in excess of $6 billion,

Not only that, when our current system expansions are complete we will be able to expand the entire Enbridge system all the way to the Gulf on a very cost-effective basis. Basically all we need to do at this point is add additional pumping stations. We can add another 400,000-barrels a day of system-wide capacity to the Gulf at a quarter of the cost of our current system expansion and we don't need to add any additional pipe. So for either 400,000-barrels a day by 2012 or 800,000-barrels a day at any time thereafter, the Enbridge mainline is the most economic solution for shippers. We remain in discussion with potential shippers on the scope and timing of the U.S. Gulf solution, obviously one that best fits their needs, bearing in mind that they will need to provide long-term contract commitments to utilize any new infrastructure. Based on these discussions we believe that the best approach may well be a phased approach where we reconfigure existing infrastructure to handle, say, 150,000 to 200,000-barrels a day of transportation, possibly as early as 2010, and then moving on to a new large-diameter pipeline south from Patoka when the volume reaches that 400,000-barrel a day threshold, sometime after 2011.

Finally, there's a lot of activity in the regional pipeline infrastructure segment of this second wave, as well, and these new pipelines will move oil sands crude from the producer projects the oil sands to the mainline pipeline hubs, both at Edmonton and Hardesty. Beyond our Fort Hills project there are three other large projects that we'll be looking to secure pipeline transportation within the next six to 12 months, then a couple more that come further down the road from that. With our existing regional pipeline systems -- and here I'm including Athabasca and Waupisoo, Waupisoo about to start operation and Fort Hills' under development -- delivering to both mainline hubs we are in a strong position to provide the highest value solution to our customers. We can provide the benefits of economies of scale and flexibility of multiple delivery points. We can also serve early phases of production using existing capacity until those projects achieve the critical volume thresholds required to support dedicated facilities.

So those are my comments at this point on the status on waves one and two of development. What I'd like to do now is turn the call over to Richard Bird to review the quarterly financials and then I'll come back for a very brief summary at the end. Richard?

Good morning, everyone. I'll begin with a review of the first quarter results and then conclude with an update of our financing strategy. As Pat mentioned, we released our first quarter results earlier this morning. Reported net income was $251 million, or $0.70 per share, up from $227 million, or $0.65 per share at 2007. The significant increase in reported earnings is mainly due to the following non-recurring factors. Weather in Enbridge Gas Distribution's franchise area was substantially colder than normal in the first quarter of 2008, resulting in increased earnings from EGD. Higher earnings at Aux Sable, which reflected unrealized fair value gains on derivative instruments.

These positive variances were partially offset by the recognition of an income tax liability resulting from an unfavorable court decision related to the tax basis of previously-owned pipeline assets in Kansas. Excluding the one-time and nonoperating factors summarized in the news release, our adjusted earnings for the first quarter of 2008 were $239 million, or $0.67 per common share, an increase of 4% in adjusted earnings and a 3% increase in earnings per share over the first quarter in 2001. So a solid start to the year and better than what we had expected for the first quarter.

While the quarter was strong, the significant appreciation of the Canadian dollar since the beginning of 2007 has caused the earnings generated by our U.S. operations to be lower than what they were where in Q1 2007. Overall, year to date earnings were lower by approximately $8 million, or $0.02 a share, when compared to Q1 2007 as a result of movement in the currency. As we noted on the previous quarterly earnings calls we do hedge our economic exposure to the U.S. dollar and we received after tax hedge payments of $5 million cash in the first quarter of 2008. Unfortunately, under GAAP we're not allowed to record these settlements as net income. However, these payments are recognized on our statement of cash flows and on our balance sheet.

In the first quarter we saw a number of business units perform very well. Let's start with Liquid Pipelines. First quarter earnings rose $7 million to $76 million when compared to 2007. Most of the increase was due to the contribution from AEDC on Southern Lights, which is currently under construction. As well, Enbridge System earnings benefited from AEDC on the Canadian portions of the Southern Access Expansion and Alberta Clipper projects. This was partially offset by increased taxes in the [Terrace] segment. Earnings from Spearhead were higher this quarter due to increased throughputs, while Olympic pipelines earnings decreased as a result of the timing of planned maintenance expenses.

Enbridge Energy Partners, as Pat mentioned, continues to be a very good news story. After adjusting for dilution gains and mark-to-market gains and losses on derivative financial instruments, Enbridge's earnings contribution from EEP increased by $3.5 million over the prior-year comparable quarter, that in the face of the foreign exchange great variance going in the other direction. This increase was due to higher incentive income and outstanding operating performance within EEP, underpinned by all-time high delivers on the Lakehead system, stronger natural gas throughput and improved gas plan reliability and expanded capacity. These were partially offset by Enbridge's modestly-lower average ownership position in EEP, up 14.9% in the first quarter last year compared to an average of 16.6% in the first quarter last year.

Looking forward, the future for EEP remains bright. In the second quarter we will begin to see earnings from the first phase of the Southern Access Expansion, which as Pat just mentioned, was completed at the end of the quarter, though we won't see a full three months' worth from Southern Access given the timing of the associated toll increase. And like Enbridge, Enbridge Energy Partners is well positioned for further earnings and distribution growth as it completes its current suite of organic growth projects.

Gas Distribution and Services had an excellent quarter, as earnings were up almost $7 million over 2007 after adjusting for weather and unrealized derivative fair value losses. The increase was due to better earnings from Title, as improved market fundamentals enabled higher margins to be captured on storage and transportation contracts. Enbridge Gas Distribution's adjusted earnings were flat to prior year. That's despite a shift in rate structure which will tend to move earnings into the later part of the year. This, together with gains from incentive regulation, bodes well for the rest of the year.

Aux Sable's first quarter reported earnings of $22 million include a mark-to-market gain of $19 million associated with the financial derivatives used to eliminate commodity price risks associated with this asset. We've entered into transactions to lock in Aux Sable earnings in the order of $20 million for 2008. Those hedges don't qualify for hedge accounting and as such the quarterly changes in the mark-to-market value of the hedges are booked to earnings. After adjusting for those mark-to-market gains in the first quarter, Aux Sable recorded earnings of a little over $3 million. Strong fractionation margins during the first quarter resulted in the earlier recognition of earnings pursuant to the contingent upside sharing mechanism included in the BP agreement. This was an unexpected positive be recording those earnings this early in the year and that should contribute to higher annual earnings for Aux Sable.

Finally, in corporate our corporate expenses are in line with last year after adjusting for non-recurring items, including a $5 million asset gain and a $32 million income tax expense resulting from that unfavorable court decision. Although the decision resulted in a significant impact of reported earnings, the cash impact of that decision is minimal. Tax expense in the first quarter, combined with amounts previously recorded, provided fully for the liability associated with that decision. Enbridge is appealing the decision and a final resolution of the matter is expected next year.

And I'll move now to update you on the financing plan that supports our investment in earnings growth. Starting with our liquidity perspective, we continue to carry a significant amount of unutilized bank credit. At the end of March our committed facilities for Enbridge and its subsidiaries totaled $6.7 billion, of which only $2.4 billion is either drawn or allocated to back stop commercial paper programs. The remaining $4+ billion of unutilized capacity is available to provide funding for our capital programs prior to putting in place permanent financing. We don't plan to dip into this liquidity in any material way or for any material length of time, but it has been sized to absorb a full-year's funding requirements plus a cushion. This will allow us the flexibility to optimize permanent financing alternatives and to ride out any capital market disruptions.

Our updated permanent financing plans are summarized in the flow charts that we've used in the past. Starting with capital expenditures of $11.6 billion and deducting free cash flow of $5.1 billion over the four year period we're left with a net funding requirement of $6.5 billion. This breaks down into a debt requirement of $4.6 billion and a gross equity requirement of $1.9 billion to be funded between 2008 to 2011. On the debt side, most of this will be funded on the balance sheet of either Enbridge or Enbridge Pipelines, Inc., however we do intend to utilize project financing for Southern Lights and structuring of that financing is on schedule to be in placed in the third quarter of this year.

Turning to the equity side of the chart on the right, we will need to add about $1.9 billion of additional equity over this four-year period. Our initial equity needs will be primarily met with our enhanced dividend reinvestment program and asset sales and monetizations.. On the DRIP, earlier this year we introduced a discount of 2% and actually saw our shareholder participation in that program increase from roughly 4% to 31% in the first quarter. With investors continuing to participate at this rate we expect that we would raise roughly $800 million through the DRIP over the next four-year period and so we'veupdated our financing plan to reflect that higher participation rate. As such, our remaining equity need is on the order of $1.1 billion over this period of time and we will use a variety of alternative sources to meet this requirement, as noted on the bottom right of the slide. As I noted on the Q4 call, a conventional equity issue is at the bottom of the list. This is because we believe that our share price is not yet reflecting our growth outlook and therefore, is currently undervalued, so issuing shares is definitely a preferred financing strategy.

On the other hand we have a range of other alternative sources through which we expect to be able to secure capital on more favorable terms, including asset sales and monetizations. In February we announced our intention to sell our interest in CLH and that sale process is well underway. We have received strong interest from potential purchasers, despite the recent uncertainty in the capital markets. Recent sales precedence indicate that we could expect up to C1.3 billion before tax from a sale of this asset. Of the after-tax proceeds we will need to set aside about $400 million to repay the debt financing associated with this asset, leaving a contribution of up to $750 million toward our equity requirements. As such we expect that the sale of CLH, combined with continuing higher DRIP participation, will take care of all of our 2008 equity needs along with a significant portion of 2009, as well. Beyond CLH we are examining several other asset sale or monetization alternatives, which appear to offer favorable valuations and economics.

We're also actively examining hybrid securities in order to achieve a lower cost of equity funding in a world where we anticipate progressive improvement in our share price. This type of security has the advantage of providing us with a significant amount of equity credit from the rating agencies, yet results in no earnings dilution to our current shareholders. A mandatory convertible debenture appears to be the most attractive of these securities. A hybrid security issuance, or a further asset sale or monetization would provide a valuable degree of flexibility and cushion to the financing plan at a favorable economic cost, looking after the remainder of our current financing requirements and in anticipation of success in securing additional growth projects.

In summary, we see the funding of our growth program to be very manageable over the next four years. And on that note I'll turn it back to Pat.

Great. Thanks Richard. So the next four years, as Richard has just indicated, should be a very exciting time of significant earnings growth for Enbridge. We're now fully engaged in building the $12 billion in commercially-secured Liquids Pipelines projects that will start to come into service this year and through to 2011. Beyond these projects, of course, we're actively developing this second wave of growth opportunities. We started the year off very solidly. Our financial results for the first quarter were very strong and we remain confident that we're going to be table meet our annual guidance range of $1.80 to $1.90 per share. More importantly we've continued to make significant progress on the construction of this first wave of growth, and as these growth projects come into service, primarily 2009 and 2010, we expect a steep ramp-up in our earnings and cash flow. These projects will allow us to deliver a compound annual growth rate of 10% for the next four years, 2008 to 2011.

So on that note, I think we can open up for the Q&A session.

(OPERATOR INSTRUCTIONS) The first question comes from the line of Linda Ezergailis from TD Newcrest. You may proceed.

Thank you. Just have some questions on the Southern Access Extension. The decision is still pending, still expected in Q2, but I'm wondering if there's -- what sort of risk there is of even further delays and what the issues are?

Linda, I'll maybe just briefly speak to that and then ask Steve Wuorii to add to it. It's difficult to assess. We doubt that we will see it delayed beyond the second quarter on it. We're, of course, looking for two approvals; regulatory approval from FERC with regard to rates and from the Illinois Commerce Commission with regard to basically the right to eminent domain and both processes have taken longer than expected. We've had some very strong interventions in support of us, but of course every time there's an intervention, then it takes time for the regulator to consider the evidence filed. So we think things are moving in the right direction, would expect second quarter, but can't guarantee we're going to have it through in that time. Steve?

Yes, I don't think I have anything to add to that, Linda. I think Pat's pretty well described what the two approvals are and I think everything is in that's needed, so now it's just a matter of the Illinois Commerce Commission and FERC finishing their decision process.

And can you give us an update on the capital spend profile? Previously I had $400 million even -- yes, I can't remember what I had, but can you give us an update on the CapEx spend?

On Southern Access Extension?

Timing, yes.

It hasn't changed.

It has not changed and you are earning AEDC in the meantime?

No, it's not on access extension, no.

We book AEDC on Clipper, Southern Access Expansion and Southern Lights.

Okay, so there's no AEDC on the Extension. Great.

Correct.

Thanks. Can I just ask a quick follow-up question on CLH? At what point would you consider moving it to discontinued operations and is your annual guidance of $1.80 to $1.90 inclusive of CLH for the full year?

Colin, do you want to speak to that?

Sure, yes, Pat. Good morning, Linda, it's Colin. We account for CLH on an equity basis, so it's a one-liner on our balance sheet, as you know. So we will not be required to break it out on a discontinued operations basis. And your second question is that --

I can take that one, Colin. So the original guidance range didn't incorporate a sale of CLH, but did incorporate an equity issue, so you have to effectively take the equity issue out and put the sale of CLH in to true it up with a scenario where the CLH sale proceeds as expected.

Great. Thank you.

Thanks Linda.

And the next question comes from the line of Sam Kanes from Scotia Capital. You may proceed.

Thank you. I'll stay with CLH, You bought some form of Euro hedge now and I'm just wondering hypothetically if the Euro fell 10% against the C dollar, what would the financial/economic impacts?

Richard or Ron, you to have a sensitivity on the Euro?

Well, the hedge that you're referring to is the hedge of the earnings anticipated for the year, so a significant unfavorable move in the value of the Euro versus the value of the Canadian dollar wouldn't impact the earnings that we expect to record up to the point of sale, but it certainly would impact the gain that we would recognize on conversion back into Canadian dollars from the disposition.

Okay, that's helpful. And just with respect to that, if I heard you correctly, if some folks are out there at $1.3 billion pretax for that value at whatever they chose at the time to do that, vis-a-vis that currency, and you were assuming $1.15 billion, presumably your tax rate you're expecting to pay is 12%, 13% or something like that?

Oh, I think the tax rate would be a little bit higher than that, Sam.

Okay, because you're using $1.15 billion, if I heard you correct, $400,000 for debt and $750,000 for equity, that's $1.15 million. Maybe you're assuming a higher price?

Yes, I'm not sure that we're going to pin it down quite that precisely for you.

Okay. Just wanted to get some flavor on that. Thanks.

Okay. Thanks, Sam.

And the next question comes from the line of Bob Hastings from Canaccord. You may proceed.

Hi, thank you. Just on the EGD incentive, you gave some guidance there that you hope to be getting 100 to 150 basis points of proved return with customers also benefiting. Can you give a little more clarification on the timing of how long it takes to get there, because you did mention it would be over five years?

Yes, that's -- it's probably a little early to provide that forecast, Bob, but on the basis of our experience going back to the Liquids Pipelines days when we first moved into incentive tolling it takes a little while to reorganize and to a certain extent, adjust the culture to the new operating environment. So it's not that you're going see it quarter over quarter right out of the gate, but I would expect that by the end of this year we should pretty well have things moving along pretty much as we like and hopefully build to that kind of improvement in turn through the year next year. But it's a little difficult to tell because it does impact and can impact the entire organization.

Okay. Thank you very much.

Thank you.

And the next question comes from the line of Matthew Akman form Macquarie. You may proceed.

Thank you very much. I wanted to follow up, Pat, on comments on the Gulf coastline, because I think it is important to future growth and I agree, you guys seem so have gone most of the distance and so it seems almost obvious that the lowest cost option is to continue on Enbridge. But I guess there was an open season held and I'm not sure exactly what happened there, but maybe you could talk about what your thoughts are on why that open season wouldn't have been successful off the bat, and is there things you can do to address shippers' concerns in the near term that could kick start that line again?

Yes, I'll give you the best reading that we can at this point, Matthew. First of all, I think it's fair to say that probably the upstream producers who are providing the main drive and incentive for this project have experienced some delays in terms of either mining operations or SAGD operations and hence their timelines may be a little pushed back from what we originally thought when we struck the open season, and hence, some hesitancy to make big commitments at a time when they're working out operational challenges in their own upstream operations.. As those come into -- in the line I think we're going to find they're more likely to commit, so think that upstream timing is probably the prime issue.

At the same time, as you know, we're involved in a competitive project and there are two or three or four other alternatives out there that I know that customers want to evaluate and rightfully so. So I think the important thing from our point of view is to make sure that they have the full and complete data set, and that's one of the reasons why I spent the time on it that I did this morning to explain that there is no expansion required of our system up to Patoka. It 's only new build $2.6 billion from there down and it's a much lighter commitment to new capital for them and significant delivery options and flexibility along the way in our system. But I think the prime reason for the delay likely is just upstream delay.

Okay, thanks. That sounds very logical. Can I shift on Title for a second? You guys are making more money in energy marketing and while I know you don't take significant risks there, it's nice to get more profit, is that sustainable especially because you'll be doing more around tankage and bringing more diluent into the Province. So is it possible that actually the profitability for that business could be pretty attractive going forward without taking more risk?

Maybe I could ask Richard Bird to respond to that, Matthew.

Yes. I think, Matthew, the market conditions that contributed to that opportunity in the first quarter are ones that are going happen occassionally and so, if it would be a little too optimistic to assume that level of profitability from Title on an ongoing basis. That was -- particularly a good part of it was due to a particularly-nice spread that opened up between the receive point and delivery point of some pipeline capacity that Title had in their contract. It normally delivers a nice tidy profit on a running basis, but in that case they were able to take advantage of that spread and do very well. But thats -- that condition will recur from time to time but not on a predictable or sustainable basis.

Okay. Thanks very much.

Thank you.

And the next question comes from the line of Robert Kwan from RBC Capital Markets. You may proceed.

Good morning. Just wondering, can you provide a break down of the increase in the major buckets in the Enbridge System earnings between the ADC and then the offset on the Terrace taxes and then anything else going on there?

Okay, Steve?

Sure. Robert, I think the pattern that we'll see through the year is generally ADC moving the system earnings up from Clipper and Southern Access and that being offset by Terrace tax, and in the quarter it's around $3 million to $4 million in increased ADC over the prior-year quarter offset by about $2 million in increased Terrace tax, so that's -- those are the big pieces. There's also smaller things moving around in terms of O&A costs and so on, but those are the big items. They're ADC up $3 million to $4 million, Terrace tax up about $2 million.

And so with the Terrace being $2 million, has your outlook changed in terms of the guidance you provided coming out of Q4 about the impact of Terrace taxes through '08?

I think it's a little early in the year to do that. I think at the end of the year on the year-end call, we walked through that whole dynamic and it's too early to say. I think -- and as you know, as the throughputs go up in a given year, in the year of transition with Terrace tax, so also the tax and throughputs are up. They're not up at exactly the pace that would have brought us to the overall guidance of about $20 million that we talked about on that last call, but it's too early in the year to say as volumes are ramping up coming off the Athabasca pipeline and other things, it is too early to say, so I think we'll leave it at where we left it there for now.

Okay. And just my last question there, on the CLH you referenced the debt repayment, does repaying that debt free up debt capacity somewhere else to finance the project portfolio?

Yes that's right, Robert. In fact, probably the best way to look at that debt repayment is it's not really repayment per se, it's displacing a portion of the debt that we otherwise would be raising.

Okay, great. Thanks Richard.

Thank you.

And the next question comes from the line of Steven Paget from FirstEnergy. You may proceed.

Thank you, good morning. Two questions. First, could you comment on the light versus heavy amounts that Southern Access will be shipping? And second question is, on your outlook on steel prices given their rise in the cost of coking coal?

Okay. First of all, Southern Access split light to heavy, Steve.

Yes, Steve, I don't have a specific split. Certainly the expansions are all targeted to the heavy crude capacity of the system. Southern Access, though is adding 45,000-barrels a day of light capacity downstream through what's called the LSR, or the light sour project. Actually that's part of Southern Lights. So it's certainly targeted more, very much, to heavy oil movements with some addition and that's the 45,000-barrels a day of additional light capacity, because there's flexibility needed that's going depend on how much upgrading is done and how much synthetic will move versus heavy. Certainly Clipper or Southern Access generally targeted to heavy oil.

Great, thank you.

And maybe just on the second part of your question, Steven, with regard to steel cost. The arrangement that we have with a major pipe provider has largely held us immune from significant increases in steel costs, but either Steve or Richard, are either one of you in a position to comment on the general market?

I can comment on that, because I know that we've looked at what the pricing for steel is for potential second wave projects. We have all the first wave projects locked in, as Pat just mentioned. Generally we're looking at steel prices at 30% to 50% higher than they were at the time that we locked in pricing for the first wave projects, but that won't, as Pat said, have any impact on those that are commercially secured through 2011.

I think the main value in that, Steven, is to realize the significant value of that long-term supply deal that we did on wave one and so we've seen quite a significant increase from the time that that was locked in to what a wave two price would be.

Yes, yes, thank you. I was just looking for your outlook on the very long term in steel.

Okay. Thank you.

And the next question comes from the line of Andrew Kuske from Credit Suisse. You may proceed.

Thank you, good morning. You've got a number of pipelines coming onstream in the next little while and just wondered if you can give us clarity and some idea of the line fill that will be required for those lines? And then on top of the line fill question just the relationship between the line fell and official commissioning where you're earning cash earnings off of those pipelines?

Okay, Steve.

I think -- it's a very good question, Andrew, because certainly line fill is a commitment that the industry that makes to expansion projects and then needs to fill. The one probably that is the most immediate -- Well, there's two, I guess, Waupisoo and Southern Access. On April 1st we notified the industry that we're ready to accept line fill on Southern Access from Superior south to a place called Delavan in Wisconsin -- that's about 320 miles -- and at the same time because of the agreement we have on Southern Access Enbridge Energy Partners applied the system toll surcharge that applies to the Southern Access capacity, so EEP started to earn on that per the agreement that as soon as we were ready to accept line fill. I don't have a total number for you. I guess we could do the calculations, but we do not have a total numbers of barrels of line fill required for all of Waupisoo and Southern Access, which are the two that are this year as far as line fill's concerned, but obviously a significant amount of crude required for that.

And then just as a follow-up question. If you were to look at the comparative amount of line fill on your system running all the way down -- from [post] system all the way down to the Gulf of Mexico versus any competitor pipeline or even an Enbridge-type proposal that'd be new build running more directly down the Express Corridor and then down Texas, what would that comparative be, roughly, if you have that?

I think -- roughly in terms of incremental commitment, as Pat's mentioned, we're two-thirds of the way there at Patoka, so you could argue that two-thirds of that line fill has already been accounted for through other expansion projects. And that's one of the issues, as we looked at a bullet line or a direct line from Alberta to the Gulf Coast line fill is one of the concerns because it's pretty significant in terms of incremental line fill the shippers need to come up with. Other things like transit times, line flow rates and other factors come into it, too. I think a rough proxy would be about two-thirds less incremental line fill required to get to the Gulf via Texas access.

That's great, thank you.

Thanks, Andrew.

And the next question comes from the line of Daniel Shteyn from Desjardins Securities . You may

Good morning, everyone. First on the tap to the Gulf Coast. I guess what -- certainly there's a lot of issues such as flexible delivery and so on that impact it, but ultimately a lot of the shippers' decision revolves around the toll, and I guess my question is how competitive do you you believe your toll would be for shippers from Alberta versus a greenfield pipe going from Alberta to the Gulf Coast?

Well, we obviously think it would be very competitive. In fact, we find it a challenge see how anyone can compete with the advantage of already being two-thirds of the way there, Daniel, and having the significant economies of scale associated with our existing system and existing right of way. And I'm sure as you can appreciate, in our case we removed the construction risk around two-thirds of the routing in terms of right-of-way access and control of capital costs. We will be using Exxon Mobil right of way all the way down and hence, not only terms of the absolute toll number but the uncertainty and the potential volatility around that as you actually get underway and truly build this thing is significantly lower with our system. So we feel we can compete quite comfortably with all newcomers on this as a result of already being two-thirds of the way there.

Right. And just to quantify that a little bit, do you believe that a toll using your facilities could be -- and I'm not asking what the toll actually is or that you've offered, but is it maybe -- could it be a half, two-thirds, one-third of a comparable route for a greenfield pipe?

That's hard to quantify. There are so many assertions depending on volumes, et cetera, but as -- Steve or Richard, I don't know whether you want to take a stab at that?

Well, it wouldn't be anything more that and I'd rather not -- rather not do that. It's going depend on CapEx assumptions in a pretty major way and as we looked at a Alberta to Gulf Coast project and the cost of it, I think as Pat mentioned from Patoka south we're looking at about $2.6 billion and then you can extrapolate that to 2.5, three times that distance and come up with a pretty large CapEx number, which would drive a toll that's going be a fair bit higher than what it is through the existing system and Texas access. Exactly what that is, though, Daniel, it's probably too early to say.

Okay. And in terms of the market capacity to absorb the incremental pipeline capacity to the Gulf Coast what would be your view for a total requirement for -- you're proposing 400,000 and increasing it potentially later on to 800,000 by extending the whole Enbridge system. Am I understanding that correctly?

Yes. Those would be the basic parameters. 400,000 would be the base Texas access expandable to 800,000-barrels a day. And I think that we're pretty comfortable that a 400,000-barrel a day demand, which obviously involves displacement of Mexican and Venezuelan crude in the Gulf, is quite realistic. Frankly, an 800,000-barrel a day figure starts to challenge the imagination a bit more as to exactly how much will be displaced in the Gulf and, frankly, where else Western Canadian barrels are going move. Eastern Pad two, we've talked about Pad one and then the gateway pipeline concept that we're also pursuing that would move barrels to California and Asia.. So those are the -- I think that's the interplay that would really weigh into the issue between 400,000 and 800,000-barrels a day into the Gulf Coast. Certainly the Gulf refining capacity is there, but recognizing that it's -- it's all displacement barrels. It's displacing a foreign barrel from elsewhere. It really is going to depend on pricing relative to pricing that's available to other markets, like Pad two -- Eastern Pad two and off the West Coast.

Okay. So under this scenario it's probably unlikely that there could be appetite for any more than 800,000-barrels per day capacity from Alberta to the Gulf Coast until well into the middle and the latter part of the next decade, at least from the point of view of availability of Canadian oil sands and crude?

Yes, I don't think that's an unfair way of looking at it. Obviously a lot of things could play into that including supply disruptions from other sources and other factors, but timing is, I think, the issue, both from a production perspective and also development of that market perspective, so that's not bad. I don't think I would say definitively that that will absolutely be the case, but indicatively I think, that's not bad.

Okay. Thank you for your time.

Thank you.

And the next question comes from the line of Andrew Fairbanks from Merrill Lynch. You may proceed.

Good morning, guys. Just had a question on construction cost pressures. As you build out the system do you find that labor productivity is holding up well in most of the various regions? Are there any real areas we should be watching closely as you proceed down the build out?

Andrew, I think it is fair to say that from the start of wave one to where we are now we have noticed significant upward cost pressures and also very significantly lower productivity from the last major round of pipeline construction that we did. However, I think it's fair to say that has leveled off. We're no longer seeing continued dramatic escalation in costs and we've seen that productivity has established a new level and we're not seeing the lore level of productivity that we did in the early stages, and that's largely because many of the companies now have been out and have got the crews, have got the guys trained out after many years of not doing a lot of pipeline construction and hence we're seeing more of a leveling out in that productivity. We anticipate going forward a much easier job. I hardly like to use the word easy in terms of controlling capital costs these days, but a much easier job in terms of keeping these projects on budget.

I think the other factor, Andrew, is that we're going to have these crews working year round for several years which also improves productivity, as opposed to the usual pipeline construction way which is a seasonal type of approach, so that's going help, also, to have the crews engaged and working year round.

Oh, that's excellent. Thank you.

Thank you.

And the next question comes from the line of Ramin Burney from National Bank Financial. You may proceed.

Good morning, everyone. I just had a couple of questions here. Could you please provide the status of discussions, if any, with ConocoPhillips and BP regarding their new proposed Alaska pipeline, and if there has been any discussions actually with the Alaska government?

Very informal discussions, and nothing substant at this point. We did receive a call from the BP/ConocoPhillips consortium, or JV, prior to their public announcement of their intent to proceed with plans to build the pipeline and with an indication that there will be a point in their process where they'll be interested in either inviting third-party pipelines in or putting out an RFP for third parties to participate, so we maintain contact with them to ensure that we're ready when they're ready for us to come forward, but nothing formal at this point.

All right, thank you. And as far as future plans for your interest in Customer Works now that EGD's no longer a customer for a while now, is that part of your asset sales plan?

For Customer Works?

Yes.

It could possibly be. It's going be a smaller source of earnings in the future than in the past and it's probably not a critical asset any longer. It's not a big value asset, either.

All right. Thank you.

Thank you.

And we have a follow-up question from Matthew Akman from Macquarie. You may proceed.

Thanks, just a quick detail. Richard, when you provide the generalized earnings guidance of 10% growth, is that 10% off of '07 so '07 through 11, is that what you're thinking about?

Yes.

Okay. Thank you.

Thanks, Matthew.

And another follow-up question from Sam Kanes with Scotia Capital. You may proceed.

You mentioned that there was some form of shifting going on in Enbridge Gas Distribution earnings throughout the year. Can you just give us a little color on that?

Sure.

Dollar wise.

Yes, it's Colin here. So there is -- there is an interest in the customer to see a more predictable monthly rate and a good mechanism to achieve that is to increase the fixed charge of the bill and reduce the variable part of the bill. So there is a scheduled five-year progressive shift in that, which basically increases the fixed charge each year. So that will move our earnings seasonality from the winter quarters into the summer quarters. In terms of quantum, it was just over $10 million in the first quarter, which we'll see come back in Q2 and Q3. And if you're modeling that out five years, I would, for now, form a similar extension of that amount.

So 10, 20, 30, 40, 50?

No, $10 million earnings less in Q1.

Well, no, I'm saying within Q1 for years two, three, four, five?

Something like that for now.

Okay. And with respect to the incentive tolling -- or the incentive within what OAB has approved, is there some form of corollary or side bar into demand-side management incentives as part of that as well or is that a separate standalone?

Yes, with regard to the demand side management we are projected on that, Sam, so to the extent that we encourage customer conservation there is a protection mechanism associated with that so that we're held whole on it.

Okay. Thank you.

Thank you.

And now we're going open the session for the media to ask a question. (OPERATOR INSTRUCTIONS) And the first question comes from Ian McKennon from (inaudible) you may proceed.

Him there's just a couple quick clarifications. Pat, you talked about $2.6 billion now for Texas access, previously it was $3 billion. What's the difference in price and what are the $2.6 billion include?

Basically the reason for the difference is just the end point of the line and effectively the $2.6 billion is a new line from Patoka, Illinois to Nederland, Texas.

And that's the 150,000 to 200,000-barrels or is that the 400,000?

That's 400,000-barrels a day.

Okay. Do you have an estimate of what it would cost to modify your existing infrastructure to get that 150,000 to 200,000 by 2010?

Oh, if we were to look at a short-term solution? Well, in terms of our system from Edmonton all the way through to Patoka, nothing. Everything is already underway. Those projects are under construction. From that point south there are a number of different alternatives that we're looking at and Steve, I don't know whether you want to try to elaborate a bit further? It's pretty early stage.

Yes, it is early stage. One of the projects that we have been discussing with the industry is the reversal of our Line nine and also the Portland pipeline system that would move crude from Sarnia, Ontario through Montreal south to Portland, Maine and then off the dock at Portland and that would make capacity available to move heavy oil to the Gulf Coast in possibly the 2010 timeframe. So that's -- that's the other nearer-term solution for moving barrels to the Gulf that we are examining together -- together with the industry. The total expenditure on something like that would be -- and this is rough -- something under $500 million in total for all of what's required to achieve that. So, that gives you some idea of one of the possibilities. We're also looking at other infrastructure that may be available in the Southern Corridors that move south to the Gulf Coast., but Line nine in Portland is one of the first things we're looking at.

Okay, thank you. And Richard, one question for you on the sale of CLH -- I'm sorry, I had to jump off the call briefly. Do you have a timeline for when the sale will be closed? And given what you said about $1.3 billion, I'm assuming the whole stake is going to be sold, is that correct?

A sale of the whole stake would be our objective and timing would be some time third quarter, possibly front end of the third quarter, but third quarter for sure.

Thank you kindly.

And the next question comes from Scott By Scott Haggett from Reuters. You may proceed.

Hi. -- pardon me -- Just looking for a bit more information on the Alaska discussions. Has BP and Conoco given you indication -- any indication on timing when you said there'll be a point in the process where they invite you in or launch a RFP? Any expectations on when you'll see that?

No,not really, Scott. I think it's probably a little bit too early for them to tell at this point in time. I think the purpose of the original contact was just to make sure that they wanted us to know that there would be an opportunity for us to put forward our cases to -- what our credentials are to participate, but difficult for them to know the timing.

Thank you.

Thank you.

And at this time we don't have any further questions in the queue. I will pass the call over to management for closing remarks.

Thank you, everyone. I think that's it for the call today and I guess if you have any more detailed follow-up questions, please either call myself or Anu in our offices. Thank you very much.

Thank you.

Thank you, ladies and gentlemen. This concludes the presentation for today. You may now disconnect.