恩橋 (ENB) 2008 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Enbridge, Inc. 2008 Second Quarter Financial Results Conference Call. I would now like to turn the call over to your host, Mr. Vern Yu.

Thank you. Good morning and welcome to the Enbridge, Inc. Second Quarter 2008 Earnings 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 this conference 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 states that you should not place undue reliance on the statements about the future since we necessarily apply certain assumptions to reach conclusions about future outcomes, and future outcomes are always subject to risks and uncertainties effecting our business, including regulatory parameters, weather, economic conditions, exchange rates, interest rates and commodity prices. A more fulsome discussion of these risks and uncertainties are included in our securities disclosure filings, which are publicly available on both SEDAR and EDGAR.

This call is webcast and I'd encourage those listening on phone lines to view the supporting slides 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 last earnings call.

The initial question session is restricted to the analyst community. When the analyst community is finished we will open it up to the media. For the Q&A sessions I would ask you to limit your questions to one and a follow up and rejoin the queue. I would also remind you that Colin, Pat, Wuorii, and I will be available after the call for any detailed questions that you may have.

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

Very good, thanks Vern. Good morning everyone and thank you for joining us today. We have got lot of very good news to talk about this morning, so I am going to try to move through this as rapidly as I can. As we reported earlier today, our adjusted operating earnings for the second quarter were approximately $150 million, or $0.42 per common share, and year-to-date results were $388 million or $0.08 per common share.

This represents a year-over-year adjusted earnings increase of 8%. So, very good year-over-year results. These results and our projections for the balance of '08 have enabled us now to increase our full year guidance by a nickel where we now expect 2008 full year earnings to be in the range of $1.85 to $1.95 per common share. Richard, of course, will take you through the quarter in more detail as well as speaking to this guidance range in a little more detail later on.

All of our business segments had very solid results for the quarter. We are extremely pleased to report that both of our sponsored investment vehicles Enbridge Energy Partners and Enbridge Income Fund reported record adjusted earnings for the quarter and as a result of this they were both able to increase their common distributions.

With the latest distribution increase of each we now have hit the high splits under the partnership agreement where Enbridge as the general partner will now receive 50% of any incremental cash flow distributed by EEP.

This is significant as we expect to partnerships' cash flow to grow significantly over the next few years as we complete phase II of Southern Access and Alberta Clipper of course. I should note that both our sponsored investment vehicles are expanding to take advantage of the Bakken play and Saskatchewan, Montana, and North Dakota were once again this company is very well positioned.

Enbridge Income Fund has been expanding the Saskatchewan by adding 65,000 barrels a day on the West Coast system and EEP spends about $225 million over the last year to expand the North Dakota system by 80,000 barrels a day to take incremental crude delivery in the Balkan. Before we get to Richard, let me update you on the progress that we had during on the quarter on our slate of expansion projects, and once again I will try to move through this very quickly, because there is a lot to update you on.

First of all in our Liquids business, we are pleased to report that we were able to complete construction of 2 of our expansion projects, both of these projects were completed on time and started to contribute to earnings in the second quarter. The Waupisoo pipeline was actually completed one month ahead of schedule on June 1st. Given the construction delays that we have seen in our industry, we are very proud of this achievement in bringing a major project like this on stream a month early. Waupisoo has got initial capacity of 350,000 barrels a day and we moved crude from our Cheecham terminal south of Port McMurray all the way down to Edmonton. Waupisoo can be expanded to an ultimate capacity of 600,000 barrels a day at a very low incremental cost now that the mainline is in place.

The completion of Waupisoo makes Enbridge the largest operator regional crude oil pipelines serving the oil sands. Together Athabasca and Waupisoo enable us now to provide shippers with the flexibility to move their crude to either of the two major Alberta hubs either in Edmonton or Hardisty, but even more importantly we have the ability to provide interim service on these systems to oil sands startups as we construct dedicated systems for them and that provides us with a very significant competitive advantage as we develop further regional pipeline opportunities.

Moving on, the first phase of our Southern Access expansion also came into service at the beginning of the second quarter. Phase 1 provides additional capacity of 190,000 barrels a day to our mainline system at a capital cost of roughly of $1.3 billion. You'll recall that we started construction on the phase 2 of the Southern Access expansion in June and upon completion this will add another 210,000 barrels a day of capacity to the Enbridge mainline system.

This phase will be completed in the second quarter of 2009 and it consists of additional mainline pumping capacity and also 133 miles of new 42-inch pipe from Delavan, Wisconsin down to Flanagan, Illinois just south of Chicago. Construction of diluent return pipeline continues to proceed as planned. Construction activities are complete on the pipeline between Superior and Delavan and construction on the remaining U.S. line segments began in June. This project is still expected to be in service in late 2010.

Construction on Alberta Clipper and Line 4 has begun in quarter 3 as we received National Energy Board approval for both of those projects in the first quarter of this year. Also regulatory applications were followed with ERCB for the Fort Hills pipeline system during the second quarter. The project includes a 42-inch diameter crude oil pipeline and a 24-inch diluent return line. Scope and cost estimates will be further refined with the Fort Hills partners in mid 2011 end service date remains on target of Fort Hills.

Moving on to our natural gas systems, they also continued to perform really well. Volumes at Enbridge Energy Partners have grown by more than 10% since this time last year as it continues to be one of the largest gathering in process in service providers in the Barnett Shale, Bossier and the Anadarko regions in Texas. We continue to process over a third of the total volumes in each of these highly prolific and natural gas reservoirs, once again positioning has been outstanding for us.

Despite a weakening economic environment in Ontario, Enbridge Gas Distribution also continues to exceed our expectations. We have already added over 18,000 new customers in 2008 and we are on target to add 40,000 new customers again this year. And we are also starting now to see the financial benefits of incentive regulation where we have indicated that we hope to be able to boost our returns by 50 by 100 basis points on those assets.

During the quarter we also made some strong progress on the number of development projects within the gas and renewable side of the business. For example, Alliance in conjunction with our partner Questar continues to work on the Rockies Alliance Pipeline that would link fast growing gas production in the Rockies area in the U.S. to the Chicago pipeline hub.'

Earlier this year in the open season held showed that there is considerable interest for the pipeline and we continue now to work with shippers to finalize the necessary shipping commitments and also the best routing for that line.

During quarter two, the Rabaska partners signed a letter of intent with Gazprom U.S. regarding supply for the proposed Rabaska LNG terminal. Gazprom, of course, will become an equity partner in the project and will contract for 100% of the terminal's capacity. Partnership agreements are expected to be completed by the end of the year and Rabaska already has in place all of the authorizations required for the project from both the federal and provincial governments.

I should caution on this project that while the LOI with Gazprom is very promising, Gazprom's ultimate participation will be dependent on the development of the Shtokman field, which is expected to be completed in 2014.

Moving on to the wind business construction of 190 megawatt Ontario Wind Project in Kincardine is progressing well. Over two-thirds of the towers have now been installed and we expect to start producing electricity by the end of August to be fully operational in the fourth quarter of this year. The Alberta Saline Aquifer Project, and that ASAP and that Enbridge's spearheading added four more participants in the quarter and we now have a total of 33 industry participants.

The ASAP has the CO2 sequestration part of project remains on schedule to have construction start in 2009. This is on the pilot, and we've begun freight evaluation engineering work on that pilot project during the quarter. We are also very encouraged by the upgraded government's commitments to $2 billion to support the development of carbon sequestration projects within the province.

Lastly, but I'd like to just spend a few minutes on the current state of development projects because so far I've been speaking only of those projects underway and under construction. And this is primarily our Wave 2 of projects. These development projects are designed to provide our customers with access to multiple markets and provide Western Canadian producers with better optionality for their barrels.

These projects will allow Western Canadian crude access to the Eastern part of PADD II. That's primarily refineries in Line 1 and Toledo, Ohio, also to the refineries in Montreal to the U.S. East Coast refineries primarily Philadelphia and to the U.S. Gulf Coast and ultimately the West Coast and the Far East.

Our recently announced Trailbreaker project will provide Western Canadian producers with access to multiple new markets. Shippers will be able to send their production to refineries in Montreal and will have access to the U.S. Gulf Coast and U.S. East Coast by the Portland pipeline. The project involves expanding a portion of our mainline system within the partnerships, revisiting our Line 9 that currently provides service from Montreal to Sarnia. I should say, re-reversing, which you may recall was originally built to operate in the Western from Sarnia to Montreal. And then the reversal of one of the two pipelines on Portland pipeline system.

Trailbreaker has a modest capital cost of roughly $350 million and that's a mid 2010 target in-service date. Once completed, we'll move about 220,000 barrels a day from Sarnia to Montreal, where 80,000 can be delivered to refineries in Montreal and the remaining 140,000 barrels a day then shipped to the U.S. Gulf Coast and East Coast. We expect that the total cost to the U.S. Gulf Coast using Trailbreaker will be around $8 to $9, inclusive of shipping cost.

Trailbreaker of course is part of our phased approach in getting crude to the U.S. Gulf Coast at a low cost way. And in the near-term, Trailbreaker and in expansion to the ExxonMobil Pegasus pipeline will provide ample short-term access for Canadian producers to the U.S. Gulf Coast market. And then as Western Canadian heavy crude production ramps up, our Texas Access Pipeline will provide the most economic alternative to ship larger volumes to the U.S. Gulf Coast and that would be post 2011.

We believe that at a capital cost of $2.6 billion, Texas Access continues to provide the strongest fundamentally competitive alternative, as our existing pipeline metric is already two-thirds of the way there. However, we will manage the pace of development on this project to achieve a level of throughput commitment, which ensures an adequate return on investors' capital.

My final update is on Gateway. Support for the project has never been higher. Canadian producers have recognized the value of having access to offshore export markets, primarily in the Far East. Once complete, Canadian crude oil producers will have an ongoing bid for their crude, which will include net products for our customers. Belief in the project is so strong that we have obtained $100 million of funding from a group of Western Canadian producers and East Asian refiners to get the projects to regulatory approval.

In exchange for the finding, the sponsors will have an option to have founder shipper status and to make an equity investment in Gateway. The support from Asia for Gateway is broad based and now includes refinery support from Singapore to Japan. And we still expect to file the regulatory application in early 2009 on this project.

So now for a little more detailed review on the Q2 results, let me turn the call over to Richard Bird.

Okay. Thanks, Pat, and good morning everyone. I'm going to begin with a review of the second quarter results, provide a little more detail on our updated guidance for 2008 and then also update you on our financing plan.

So as Pat mentioned, we released our second quarter results earlier this morning. And reported net income was $658 million or $1.83 per common share, up $147 million from the amount reported in 2007. And the significant quarter-over-quarter increase in reported earnings is obviously due to the gain on the sale of our investments in the Spanish refined products pipeline CLH. The sale brought in over $1.38 billion in cash and generated $556 million gain on the sale.

Other significant items in the quarter that we adjusted out the reported earnings include additional cost related to repairs from the 2005 hurricanes within our offshore assets and we are seeking insurance recovery of these expenses and expect to receive this in the latter half of 2008.

Also adjusted for non-cash mark-to-market losses associated with the financial instruments that we use to hedge our earnings within the Energy Services and the Aux Sable business segments.

And lastly, the warmer than normal weather in EGD's franchise area, which decreased EGD's earnings by about 4 million in the second quarter. When we exclude all of these non-operating factors, adjusted earnings for the second quarter, as Pat mentioned, were $150 million or $0.42 per common share.

So just in terms of where some of the strength is coming from, in the second quarter we experienced strong performance from our Liquids Pipelines business unit. Earnings rose by 10 million when compared to the prior year. Our expansion projects were the primary driver for the increase. We recorded AEDC on a number of these new pipelines, Southern Lights, Southern Access and Alberta Clipper. We also on the Athabasca System picked up earnings for one month from the Waupisoo Pipeline, which was placed in service on June 1st.

Gas Pipelines earnings are slightly lower than the prior year as a result of the weaker U.S. dollar as well as the depreciated rate base within the Alliance Pipeline. The significant appreciation of the Canadian dollar since the latter half of 2007 has caused the earnings generated by the U.S. operations to be lower than what they were in 2007. That's across the board for all of our U.S. operations, and of course, our Gas Pipeline earnings are only U.S. dollar denominated.

Just to give you a sense of the magnitude, overall in which earnings on a year-to-date basis were lower due to the stronger Canadian dollar by approximately $12 million year-over-year or $0.03 a share compared to the first half of 2007. And as we have noted on previous calls, we do hedge our economic exposure to foreign currencies. And we have, in fact, in 2008 received after-tax hedge payments of $9 million. Unfortunately, the settlements on these hedges are over cash in the bank or not included in earnings reported under GAAP.

The Sponsored Investments segment of our business, as Pat mentioned, had a record quarter. EEP reported adjusted results, record adjusted results in the second quarter and continues to be a very good story. EEP stream's contribution was $3 million higher than the second quarter of 2007 and on a year-to-date basis almost $7 million higher. That increase reflects higher incentive income and outstanding performance within EEP, which was underpinned by strong throughput volumes on the liquids pipelines systems as well as higher throughput on the gas gathering and processing assets, and stronger fractionation margins.

The Enbridge Income Fund results are also positive in the quarter due to favorable fundamentals within the Saskatchewan system and of course flowing through to Enbridge with a 7.5% distribution increase, which was announced at the end of the first quarter. And gas distribution and services also had an excellent quarter with adjusted earnings up almost 10 million over the prior year quarter.

That increase was largely due to the impact of very strong fractionation margins at Aux Sable, which allowed us to recognize a larger portion of the contingent upside sharing mechanism that we have in our agreement with BP relative to what we were able to recognize in the second quarter last year.

We anticipate that the full year earnings contribution from Aux Sable will be around $25 million. The GAAP loss that was reported in the quarter and again that was reported on a year-to-date basis are associated with the financial derivatives used to eliminate commodity prices associated with this asset. We have entered into financial derivative transactions to lock in our 2008 Aux Sable earnings, but these hedges don't qualify for hedge accounting and as such the quarterly changes in the fair market value and the hedges are booked to earnings.

EGD's earnings in the quarter were also higher than the prior year by 3 million, and that increase can be attributed to stronger customer growth, lower operating costs and lower taxes. As Pat mentioned, we are already starting to see the initial benefits of the new incentive regulation framework and all sorts of earnings improvement that I just mentioned that actually made significantly stronger contribution than the 3 million in the aggregate, but that contribution was offset in part by a change in EGD's toll structure where a larger portion of the annual distribution cost will come in the form of a fixed rather than a variable charge.

So this change in the rate structure will increase earnings in the summer months and lower earnings in the winter months. And the unfavorable year-to-date impact of this change will reverse out over the balance of the year leaving us with just that strong fundamental performance evident in the second quarter.

Energy Services full year results are well above the prior year due to accrued market fundamentals, which enabled higher margins to be captured on storage and transportation contracts. During the second quarter, there was a significant non-cash mark-to-market loss related to this business. This mark-to-market loss reflects fair value charges on derivative transactions used to lock in the profitability of transportation and storage transactions at Tidal Energy.

Under GAAP, these financial derivatives are revalued each quarter. And any change is reported in earnings. However, the offsetting change in the underlying physical crude inventory is not revalued. So you see one side of the transaction, but not the other. And as such, you will see non-cash mark-to-market losses in the segment in periods of rising oil prices.

The overall profitability of that transaction will not appear until the underlying crude oil is sold from inventory. So that second quarter mark-to-market loss will reverse out in the reported earnings over the balance of the year.

Of course, internationally you see the large gain on the CLH investment. After moving that gain, the earnings are lower as a result of the sale of CLH, which we didn't have earnings during the latter part of June. And our corporate costs are slightly lower than last year in the quarter due to the use of the proceeds from CLH to retire some commercial paper balances.

Moving on now to our revised guidance for 2008, as Pat mentioned, we have revised upwards by a nickel to an adjusted operating earnings per share range of $1.85 to $1.95. And strong performance from all of our business units has cost us to revisit our earnings guidance. Additionally, we are seeing the impact of double taxation on our Terrace earnings, which we talked about earlier this year, coming in so far - and at this period it continue to come in less than what we have expected at the beginning of the year.

We are seeing growth and volumes from the oil sands projects a little slower than what we originally anticipated. So our revised guidance reflects in part an expected $10 million improvement in Terrace earnings in 2008 due to lower taxes than reflected in our original guidance. And so we keep track of that particular aspect.

In the medium term, we continue to expect to achieve a compound annual average growth rate in earnings per share of 10% from 2007 base to 2011 based on our commercial and secure projects with plenty of opportunity under development to extend our double-digit growth beyond 2011.

And lastly, just a few minutes on our updated financing plan. A couple of recent actions have made our funding and the balance of the Wave 1 commercially secured projects very manageable. First was the sale of CLH, which provided roughly 1.2 billion in after-tax proceeds. Above $300 million of that proceeds will displace a portion of our debt funding and the remaining $900 million satisfies a very large portion of our equity requirement.

The second item is our dividend reinvestment program. At the beginning of the year, we added a 2% discount to the plan and we have seen participation in that plan increase from about 4% to roughly 30%. As a result, the dividend reinvestment is now expected to provide about 800 million of incremental equity over the next four years.

So just to quickly revisit the impact of these two items on the overall funding requirement. You will recall it, Wave 1 requires about $12 billion of capital expenditures at Enbridge, Inc. and if we deduct our free cash flow, we are left with a net funding requirement of $6.6 billion. This translates a requirement for 1.9 billion of equity and 4.7 billion of debt.

On the debt side, we have recently secured underwriting commitments for 1.5 billion to project finance of Southern Lights pipeline and we are in the process of syndication and closing our transaction is expected to be completed in the current quarter. But the 1.5 billion is underwritten.

On the equity side, the sale of CLH in our hands grip program will provide 1.7 billion of equity capital, which leaves us with only 200 million of equity to be funded from now until the end of 2011 to meet the requirements of that first Wave of commercially secured projects. This equity can be met from a variety of sources that includes further asset sales, asset monetizations, the issuance of hybrid securities, and in concept common equity.

However, with respect to common equity, our internal valuation work continues to show a significant gap between our common share fundamental value based on the extended double-digit growth we foresee and our current market valuation. And that's the case despite the fact that our P/E on current earnings has added significant premium to the peer group. In other words, the P/E still does not reflect fully our unique combination of (inaudible) growth.

Now we expect over the next year or so as the growth is realized that our market valuation will converge on our fundamental value, but in the meanwhile issuing common equity would be dilutive to our existing shareholders and would be our least preferred source. Given the modest remaining equity requirements and a variety of preferable alternatives we have, an equity issue really isn't in the picture of the foreseeable future.

On the other hand, our work on a mandatory convertible hybrid instrument indicates that it is an attractive potential source of equity because it provides a significant amount of equity credit from the rating agencies, but the conversion prices have a large enough premium to avoid any shareholder value dilution to our existing investors.

So the near-term 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 in preparation for continued success in expanding and extending our secured growth opportunities. Those are the things we'll continue to work on.

On that note, I will turn it back to Pat for his concluding comments.

Great. Thanks, Richard. So these are very good times for Enbridge. Our six-month results have exceeded our expectations and that has allowed us to increase our 2008 guidance by a nickel, which I'm sure you'll agree as good news. We continue to make good progress with our expansion projects and have now completed Waupisoo and the first phase of Southern Access on or ahead of schedule.

We've almost entirely eliminated the equity funding requirements for Wave 1 with the sale of CLH, as Richard has just outlined. And of course, we continued to develop our $15 billion slate of Wave 2 expansion projects that really are designed to maximize market optionality for our customers, while ensuring that Enbridge system remains the lowest cost shipping solution for our customers.

So, on that note, I think we can move to the Q&A session.

(OPERATOR INSTRUCTIONS) Your first question comes from the line of Sam Kanes of Scotia Capital. Please proceed.

Good morning and (inaudible) results. I'm curious, Pat, now that CLH has financed you a number of years and Richard just referred of course to your preferred hybrid potential debt financing for some combination of financing.

What is non-core, semi non-core to you at this stage? I mean, looking at New Columbia pipeline, your offshore gas pipelines, your EIF interest, which of course you will have to decide what you want to do in 2011, or even your new wind farm, which seems to be one-off at this stage, how do you view those assets in going forward with your core?

Well, first of all, Sam, I think it's fair to say that all of those assets are definitely a part of core business. Some are a little bit closer to debt center core than others, but they are all a logical part of our business. And you mentioned Columbia, I guess you could say it appears to be stranded because it's now our only international investment.

But to tell you the truth, we never really considered international to be an area of investment. We just considered good investments to be a good idea for our shareholders and two of them happened to be international. Looking at Columbia, we've mentioned before that there is a good heavy oil play underway right now that's resulting in expansion opportunity within OCENSA and we obviously want to be able to take advantage of that.

We don't have any intention at this point to exit and see further upside on that asset. We have indicated that we will look at restructuring opportunities both at the partnership level and at the income fund level to better utilize what were intended to be low cost to capital vehicles in the partnership and the income funds.

So, we will continue to do that to optimize on those structures. The wind business, actually we are building our fourth wind farm. We have got 3 already and have used the income fund as a way of monetizing those assets and could look at something similar with regard to the new Kincardine facility.

There is strong interest from other partners in participating in wind. So, a number of opportunities there, but none of them are outside the core business of Enbridge or burning needs to restructure our assets in any way.

Thanks Pat. A quick follow up, Richard I guess it is for you. Unrealized oil derivatives for the oil, so much in Q2, you gave us a number in the past quarter of what is unrealized that should be realized, unless I miss it in your press release here?

Sorry Sam, I didn't understand that. Could you --?

In your oil derivatives, you are recording the hedge loss, but of course, you have a physical value enhancement because you have locked in the economics of the one side of the trade, if you may.

So I am just wondering what is running book -- what you have accrued but you can't recognize yet within the context of those derivative features contracts? I think it was $200 million last quarter or so of what should potentially come back after you if you like as they mature?

That would be the cumulative amount of those - all those mark-to-market losses to date?

Could it simply be the addition of Q2 to where the status was of Q1?

Take Q1 and Q2 together. That is -- all of that will come back, plus of course, the profit margin on that transaction as well.

That is right, that is where I am going with it. Just wanted to get some rough idea of what is on the coming, if you may -- coming into your financials and your bank for that matter?

The cumulative on the oil services side is about $36 million to date mark-to-market loss, so that will all come back along with the profit margin associated with it.

So, something in the $50 million area or so?

Pardon me?

Something in the $50 million area or so?

Oh, I don't think we want to get down into disclosure of the specific margin on that piece of business.

Okay, Richard, thank you.

But, it certainly is -- it is a margin, it is a profit.

Yes. Thanks.

Thanks, Sam.

Your next question is from the line of Carl Kirst of BMO Capital Markets. Please proceed.

Good morning, everybody and congratulations on a nice quarter here. Just a couple of questions. First, perhaps on Trailbreaker and here just to make a clarifying question. Just to make sure that, you know, in your 2008 to 2011 spending of the Trailbreaker at this point, even though it is small, it is not part of that $11.6 billion, is that correct?

The $11.6 billion was a planned number that had built into it a small amount of capital over and above projects that we were committed at that time we put that number together. So, I think you could say that the Trailbreaker will still fit within the allowance.

Okay, great. And then just sort of a followup, you know there was a - earlier I think given some of the numbers that were tossed around on Trailbreaker it looked like it was, you know, the current number is $350 million, sort of reflective of kind of the new cost environment we are in. Pat, now that it looks like we might be sensing some, -- at least some forward momentum on Gateway, I didn't know if you had a sense of perhaps where the -- initially thought $2.5 billion dollar, where that project might be if indeed that you didn't report in 2009?

Maybe, let me answer the latter part of that first and then just come back and address the first part with regard to Trailbreaker, if I understand you correctly Carl. First of all, we have not done a new update with regard to Gateway on capital cost, and we won't be doing that until we get into the year in 2009.

We will work closely with the other supporters of the project in order to put that in place. I am not able to give that to you before. I believe the most recent number we had was about $4.2 billion, but that was a 2006 number, so obviously it is going to be revised upward on the basis of where capital costs have gone over that period of time.

Coming back to Trailbreaker, I think what you were asking was that, I know, I was originally quoted as indicating there was about a $100 million reversal project and then we are now talking about $350 million. The difference is that I was talking about simply the reversal portion of that project, which is still accurate at around $100 million.

We are now talking about all the ancillary expansions in our U.S. system and tankage and ancillary facilities that they set up to 350. So, it was an apples and oranges comparison between the $100 million and current 350.

Great. I appreciate the clarification. Just on the Gateway, when you were putting the number $4 billion, that included the condensate then?

When we are talking about the Gateway we are looking at both sides.

Okay, thank you.

4.2 and that included both.

Great, thank you.

And just to clarify a little further on the Gateway spending profile, we are filing for regulatory application in 2009 but construction wouldn't start for a couple of years after that. So, the regulatory approval process will run a couple of years and we are fully funded by our partners on the project through that period of time. So, it doesn't really have a significant impact on - again on the near-term capital requirements.

Great, thank you.

Thanks Carl.

Your next question is from the line of Linda Ezergailis of TD Newcrest. Please proceed.

Thank you. Looking at your offshore business. Other than the continuing impact of the 2005 hurricanes, are there any other contributors that you would attribute to the lower than expected earnings. Are you seeing higher competition and maybe you can comment on the outlook for the next year and the next 5 years?

Yes, indeed. By the way the -- first of all with regard to the first part of that Linda the ongoing cost associated -- you may recall way back at the start we indicated we had a ship sitting on top of one of our lines and removal of that is what has caused the continued cost. That finally has been completed and you shouldn't see any significant going forward costs associated with the hurricanes.

It has been primarily delayed in new facilities coming on stream, producer delays in volumes that has caused the softer quarter and also insurance premiums in combination with the fact that of course, the Canada U.S. dollar exchange rate has been moving the wrong way, of course, on that income stream as well.

We do anticipate in the medium to longer term good prospectivity in the Gulf and a significant recovery there, as you probably know, we are very well positioned particularly in the deep-water gulf. We are the prime gas gatherer and that is where the majority of the activity is and producers post the hurricanes, of course, have spent a bit of time on remediation getting facilities that we due to come on stream back in service and now they are able to turn their attention again to exploration and development work. So, we do anticipate those assets will improve over time.

And what sort of ramp up in earnings rate over the next 5 years would do expect?

Maybe we can get back to you on that Linda to the extent that we are going to provide that kind of detail. I don't think any of us have it at our fingertips here though.

And just a quick follow up question, can you break up the amount of aid you received for each of Southern Access space to expansion Alberta Clipper and Southern Lights?

Could maybe Vern get back to you on that after the call ended.

Sure.

Okay, thank you. We will do that.

Your next question comes from the line of Ross Payne of Wachovia. Please proceed.

Yes, can you kind of speak to what your target debt to cap is going to be?

Ross, we have normally targeted in the range of you know, 62% debt - 60% to 64% debt is kind of where the rating agencies have been and so targeting the low 60s range.

Two other questions, can you speak to the Spearhead volumes, it looks like they are down a little bit year-over-year and also if you can comment on how much of your CapEx is that you have already spent is not yet producing any cash flows so we can kind of move towards a pro forma number, thanks?

Okay, maybe, I will try and just put that into the notes, Steve Wuorii, if I could ask you to speak to Spearhead volumes and then Richard to the CapEx?

I think, Ross, that Spearhead volumes are effected by the volumes moving through the system generally and are effected by some of the delays that we have seen in the oil sands with production ramp up. The differences aren't very large and so there is really nothing to point to there in terms of a trend.

So, Spearhead is basically doing fine and it has the expansion program that we have soon to go underway to increase it to 195,000 barrels a day, but there is really nothing there except that some of the delays for the oil sands would have been reflected down into Spearhead.

Okay, thank you.

And Richard on the CapEx, will you be able to --

Yes, on the CapEx side, the biggest chunk of that at the moment would be the Southern Lights project. It isn't cash flowing yet. We got about $800 million that has been spent to date on Southern Lights. You know, a variety of the other projects like the remainder of the Southern Access Expansion, the Line 4 extension, Alberta Clipper would be building up capital, but none of those would be a huge amount at this point in time. So, $800 million on Southern Lights, I guess, would probably at this point sitting with maybe a $1 billion of capital but isn't cash flowing.

Okay that is very helpful, thank you. And one other question if I may, about what kind of capacity utilization are you guys getting on the lines right now?

Mainline capacity utilization Steve.

Well, it depends on the line. Some of the lines are full, but probably as a rough proxy for utilization of the full aggregate capacity, probably about 85% or so.

Okay, very good. All right thank you guys.

Thanks Ross.

Your next question comes from the line of Matthew Akman with McGuire. Please proceed.

Thanks, McGuire. Pat, I just wanted to -- I just heard your comments on Gateway. It sounds like you have more comments on it. It sounds like you are making progress there. I wonder if you can maybe, you know, be more specific on what kind of progress you have made in the last few months and how you see a potentially rolling out in time lines if you firm up support?

Okay, the main progress, of course, has been the continued work on preparation of the regulatory application, which we will file in the first quarter of 2009. So that has involved engineering work, railway work, first nations and landowner consultations, and just the beginning of the preparation of the regulatory application, Matthew, and the optimism comes from the fact that we have pulled together this $100 million funding support from a variety of supporters both producers and refiners, have now held a number of joint project meeting with them to get their guidance and direction and input on the project and have got very strong support to move this along as quickly and promptly as we can.

I personally have attended and participated in some of the meetings relating to environmental and first nation's challenges which I know, we have been asked a lot about, and my confidence in our ability to work effectively with the landowners and first nation's people has gone up significantly as we have walked through with them our intentions with regard to the project and have outlined the way in which Enbridge historically has operated and will intend to operate this facility.

So, we have got very strong support provincially and federally for the project. It is considered very much in Canada's national best interest and see momentum building. We would like to be able to tell you who the other participants are. At this point, we are not able to do that because of the confidentially agreements we put in place, but we do think at some point there are going to prepared to allow that to be announced and I think you will be impressed with the broad based nature of that support.

Okay, and potential timing again, if you file in '09?

Filing in '09 and you know we would be expecting to be up and operating in 2014, most likely. You know, we initially had indicated 2012 to 14. So, we still expect to be in that range, probably in the 2014 timeframe. And that is really based on need. It is going to be driven by the customers' needs as to when they -- you know it is most important to have that option with regards to markets in place.

And I guess just a follow up Gulf Coast, I know that you can go on for a long time about it, but just in a nutshell can you please tell us whether you have sort of given up on winning that project outside of the short term solution, interim solution you are proposing, are do you still see Enbridge as being seriously on the running for a larger and longer term solution to the Gulf Coast?

If you are asking whether or not we have given up, and if you want me to summarize it in a nutshell, absolutely not. We think that what we have is the most responsible and cost effective solution for our customers, and due to the slowdown upstream we feel the shorter term smaller volume solutions are the most appropriate but with the need at some point to have a large volume outlet to develop and we feel we are in by far the best position to provide that as a result of being two-thirds of the way there. So, again in a nutshell, have we given up? Absolutely not.

Okay, thanks. Those are my questions.

Your next question comes is from the line of Andrew Fairbanks from Merrill Lynch. Please proceed.

Good morning gentlemen. Had a question for you as you look at lining up the shippers' board again for the wave 2 project. Do you sense there has been any diminishment on the part of the interest of refiners in going ahead and doing a larger coping project necessary to run more of the medium investment projects given the recent downturn in the industry, or is it not really changed given the clients we are in line of production?

I would definitely say the latter, Andrew. We have seen no diminished interest in putting the cokers in place in order to be able to accommodate Canadian heavy and we stay in touch with that very issue on a day-to-day basis, and I think it is fair to say that although we have seen a few days upstream in production coming on stream that everyone is highly confident that oil sands will be developed and is absolutely critical to security and supply concerns in the U.S.. Hence the U.S. refiners will be making those investments.

So, we are confident of that. As you probably know, there have been a few permitting delays in some of the projects but I am sure that the companies will work around those and the projects will proceed. Steve Wuorii, you may have a comment on that as well, because you are even more in touch with it than I am.

I think one other thought there is that we really aren't seeing any new refineries being built and so one of the angles with -- to meet increasing demand and also as you said decreasing supply from elsewhere has increased the complexity of those refineries that are existing, which cokers do. And so it really increases the flexibility they have to run the lower cost heavy barrel, and so that interest definitely continues that matches the upstream development in the oil sands.

And just a second question if I could on the part of the upstream producers, I guess for these longer-term wave 2 projects do you sense there is a growing interest in shipping, you know, heavier crude preferentially to upgraded synthetic crude oil? We have heard a couple of upstream companies talk about post 2013 or so perhaps not needing to build additional upgrading in Alberta and just allowing all of it will be done at the refinery site.

I think you have hit a good point. There is probably a practical limit to how much upgrading can be done in the oil sands, and can be done economically, and because there has to be a market for all of that upgraded product and we are looking at projects that will put that into markets that it doesn't traditionally find right now.

But, I think, trend wise that is probably so. They will continue to be upgrading for a time, but there is that practical limit after which and during the same time you are going to see heavy bitumen movements move to the higher complexity refineries in the U.S.

So, I think there is something of that trend and of course, upgrades live and die on the differential and one of the imponderables looking forward is exactly what will the light heavy differential be if it is wide upgraders and new investment in upgraders may experience benefit, if it is narrow and it is expected to remain narrow and by that I mean something in the $8 a barrel range, it becomes more difficult to justify an upgrading project.

So, those are the factors that are playing in. Our -- well, there are several. One is what is the availability of (inaudible) to move the heavy oil and that is what Southern Lights pipeline is designed to address, the move the heavy barrel to the high complexity refinery and then where is the differential going to go in terms of light and heavy and if that is expected to stay wide then it makes sense and if not it doesn't as far as upgrading goes.

That was great. Thank you.

Bye Andrew.

Your next question is from the line of Robert Kwan from RBC Capital Markets. Please proceed.

Good morning, my first question is for Richard. You mentioned on the guidance and related to Terrace that you expected a $10 million increase with that. Was that an increase versus '07 or an increase versus the initial guidance that Terrace taxes would take on its own by up to $30 million for the year?

It was relative to the initial guidance and my recollection, I could be wrong on this, but my recollection is we are expecting about a $20 million double taxation hit in 2008 and we are now expecting more like a $10 million double taxation here.

So that accounts for - half of the $0.05 shift in the guidance.

That is about right.

Okay, and then just the other question, and I don't know whether this is for Pat or for Steve, but you had some comments in terms of some of the issues you have having around the Southern Access Expansion situation. Do you think that shippers might now shift support to Keystone in terms of some of the issues if they are going to have to pay to the full freight south of Chicago, can you just kind of give an overview what the situation is and what the status of the project is?

No, we don't expect that kind of a shift in interest. The Southern Access Expansion provides very strong, I guess, capability or opportunity to those that are shippers on the Enbridge mainline system and it is very much in their interest of moving that crude further south and then to a variety of points from Patoka. It also is a very effective pre-build for Pegasus expansion and for possible movements by a large down the Mississippi.

So, we see a number of alternatives there. We are working now with customers to come up with a new tolling methodology based on standalone support and Steve, I don't know whether you would like to update on that.

I think that is right, and of course - it wasn't intended as roll in project anyway, it was a standalone toll and the latest application to further involve the back stock if the revenue requirements wasn't met, and that now with the court decision is what we need to address in terms of still going with the standalone toll but designing commercial arrangements that are acceptable to shippers to ship on that line without that broader back stop in the main system and we think that that will work. It is a fairly small project. It is a 170 miles in length.

We have just gone through the Illinois Commerce Commission proceedings around the eminent domain land issue and so we are well along the way in terms of the arrangements necessary to construct that project and as Pat said we are discussing with shippers now the commercial arrangements that will make it work.

Just to getting across your point, it is a pretty small project and with the semi depreciated or adventitious total industry cargo, what kind of a tie-up from the shippers side of things that really shouldn't be that big as an issue for people who want to get some of this cargo into Patoka.

I think you said it well, it is not a really large project. It is an important link as Pat mentioned and so it is certainly doable and I think we just have to come to the commerical structure that works for the shippers that want to use it the most and also provide acceptable economics to Enbridge

I think, Robert as you know, it is had strong support from cap and we see that support continuing, disappointed that the tolling methodologies as presented, were not acceptable to FERC but we will come up with one that does work.

Thanks Pat. Thanks Steve.

Thank you Robert.

Your next question comes from the line of Andrew Kuske of Credit Suisse. Please proceed.

Thank you. Good morning. Just one question as it relates to your Midwest pipeline construction program, Given the weather that we saw throughout Q2, was very wet and a lot of severe flooding in portions of the Midwest, what does that do to labor productivity on some of your pipeline builds in that area?

Actually Andrew the most severe flooding when you look at the map of where our projects are, it really occurred in Central Wisconsin which had already been finished by that time. We had completed stage 1 of Southern Access all the way down to the Illinois border and so we really weren't effected by the flooding that hit the Madison area, Wisconsin most severely and of course, we aren't in Iowa or places like that. So, actually there was a not a big effect on the construction because of the June deluge that hit some of the parts of the Midwest.

Okay, and then just a bigger broader question from a strategic perspective. How do you see your positioning for a lot of the national gas shell plays that are really emerging in this and emerging also daily into new pockets and in the middle you have got some pretty good exposure with EEP. But I think you are not in a lot of the areas other than, say, where we can see the Northeast British Columbia from the emerging plays there with Alliance. So what are your expectations longer term for the natural gas part of the business?

Well, Andrew, you've let me break out into a smile when you asked that question because we feel we are very well positioned. And let me kind of march from north and south and cover as many of those plays I can. Obviously, we feel that Alliance is well positioned for both the Montney and the Horn River plays.

And I think that's pretty obvious as we extend up into the Fort St. John area, particularly the Montney, we are central to that. So, we're well positioned on that shale play. Moving south, the Bakken, I already mentioned particularly on the oil side in both Saskatchewan and in North Dakota we couldn't be better positioned than we are with the South Saskatchewan system and with the old Portal system, which is now Enbridge North Dakota.

So, very well positioned for that. And we are looking at a potential gas pipe on that area as a result of our oil pipe involvement there and a proximity to the Alliance System. As we move further south, we've of course got a proposal coming out of the Rockies in the form of the Rockies Alliance Project. And then we move into the Texas shale plays.

As mentioned, we collect about a third of the gas in the Barnett, the Bossier, the Anadarko. As you move east in the Bossier - into east Bossier and over into Haynesville and up into Woodford, we are on the fringes of those plays and as well positioned as any gas gatherer to participate in those shale plays. West Texas, we don't have a significant infrastructure in that shale play at this point, nor do we in the Appalachian play or the Quebec shale play.

But I think of that total that had run through that we are as well positioned as company overall to participate in those. And of course, we've got the expertise in the gathering and processing business. And also, the interstate pipeline opportunities through Alliance and Vector to be a big player in the shale play. So we are very pleased with our position there. We don't get a chance to talk about our gas business that very often. And it's probably the biggest opportunity in all of those in the form of the Rockies Alliance pipeline, which I gave you a brief update on that earlier on.

When you look at some of the emerging shale plays like Haynesville, would you envision that being done solely at EEP or would that be done in some kind of combination depending on the size of the project between EEP and also Enbridge, Inc.?

I think most likely at EEP, but possibly EEP in partnership with other gas processors and gatherers in the area. We touch on the western side of the Haynesville play and are working very aggressively to move that - our infrastructure further east to accommodate Haynesville. But unlikely that Enbridge, Inc. would be a partner there because of the huge focus that we've got on the crude oil development projects, but we would like to guide that out of the EEP office in Houston.

That's great. Thank you.

Thanks, Andrew.

Your next question comes from the line of Bob Hastings of Canaccord. Please proceed.

Hi, thanks. Just a couple of clarifications. On EGD, you had an attractive rate increase back in January, would that have had any sort of meaningful impact in the second quarter?

Bob, no, it's Colin. We accrued those in Q1 and Q2 already.

Okay. And then in Aux Sable, good performance there and you pulled in some of which you expect to get for the year. Your proportion that you captured, is that somewhat similar to what you have done in the second quarter of last year or has that changed in anyway?

Slightly higher proportion in the quarter, but given our full year estimate for '08, we are probably about half way there recorded already.

Okay. And to be clear on the hedge derivative loss, you absolutely expect based on your sales and outlook today to fully capture that by the end of this year and rising oil prices or any other change wouldn't push that into next year, anything like that?

Bob, this is Vern. Based on what we have on our books right now, we would fully recapture that. Should we do more business in the balance of year that crosses the year-end that you might see to mark-to-market but you don't reverse.

Okay. And that's what I was wondering, is whether that would be sort of a natural position when it be to extend it out beyond?

Yes.

Yes, the opportunity is there.

Okay. One last question. Is the corporate expense outlook with - you had a failure that you are spending a lot more money, just do you have any guidance sort of which you are looking for the year now?

Colin?

On the corporate line, Bob, I think it's more of the same - maybe a snick higher than the second quarter, but in that ballpark.

So it's similar to the second quarter levels for each quarter going forward?

A little bit higher, but not as high as it was, say, last year or the year before. So it's a little bit lower now.

Okay, thank you very much.

Thanks, Bob.

And your next question comes from the line of Daniel Shteyn with Desjardins. Please proceed.

Yes, good morning everyone. First I have a question on the potential timeline for Enbridge. I believe this was - someone discussed it before, but I think that with the timeline was revised after the initial announcement of the project to somewhere in 2012, 2014. Now, given the latest - your latest announcement today that you would be looking for file for regulatory approval in 2009, regulatory approvals could take a couple of years and then going into construction, this would probably puts you towards the latter part of the 2012, 2014 time range. Would that be correct?

Yes. I think, as I indicated, Daniel, we are kind of suggesting probably in the 2014 timeframe. And that will be largely dependent on when producers feel they most need this line for the optionality that they are looking to establish around their crude markets and pricing issues, as production increases out of the oil sands and the need to broaden out to markets. But yes, I think it's fair to say that we're kind of looking at 2014 timing at this point.

Right. I guess my concern there is that one of the reasons that you've stated that that your Gulf Coast pipeline may not proceed as planned was that initially shipper support was not quite there due to delays in oil sands and the startup of oil sands operations. Now do you believe that those issues will be resolved and there will be sufficient volumes to fill Gateway, given the fact that there is now another pipeline project by TransCanada that will take a significant amount of crude out of the EECLV ?

Yes. Well, it's a very good question. But let me ask that you think about Gateway as a pricing play. And the fact that - really what producers need to do is, as I indicated in my remarks, create a bid around their crude and have some alternative ex North America in order to create pricing tension around their crude.

And therefore, even though they might not be able to fill the Gateway project on day one, in other words, there may not be so much upstream production driven as pricing optionality driven, Daniel, that that is their expect timing around it. And we've got some flexibility to move one way or the other around by 2014 timing. But it is primarily a pricing play for them and hence that's the timing that we are using.

Sure. I certainly appreciate the need for competitive tension, but in that case, you would still need to go to an open season and get at least some level of shipper commitments prior to proceeding to something like that. So, is there a possibility that you would have an open season where a bunch of shippers would sign up for take or pay agreements and simply - I guess what you are saying is, they will sign up those firm agreements, but may not actually ship.

That's a possibility, yes, but obviously producers are not wanting to have those ongoing commitments. If on the other hand, they feel that the pricing advantage that they get by making the commitment more than compensates for any take or pay commitment, then they will proceed and do that. But that will be a business decision they make at that time. But you are right, we will proceed with an open season and get the shipping commitments required. We won't be going ahead with the projects until we've got those from shipping commitments because of the significant capital at risk.

And that would - the timeline for an open season would be sometime in the 2009, 2010 range or--?

I think it will be later than that to tell you the truth, Daniel.

Okay.

It wouldn't likely occur until we've got regulatory approval. And just to clarify, we obviously would have an open season to satisfy regulatory requirements, but the primary discussion would be with the partners that are currently funding the regulatory approval process. They are the ones that have first call on all of the capacities.

Okay. And kind of related to that, what would be the earliest time that Enbridge would have to start spending or investing a significant CapEx to fund its second wave of expansion projects, because right now, first wave for really kind of the time frame is 2008, 2011? When would be the first significant year of commitments in terms of capital expenditures for the second wave?

Richard, could you address that?

Sure. Well, this first wave and second wave is a bit conceptual, because for the most part, the way we've defined first wave is that which is commercially secured with a little bit of a margin for a few things coming in that aren't yet commercially secured. So most of the second wave would be in service post 2011, starting in 2012. But as those projects kept secured and firmed up a project to be in service in 2012, we would start to see spending of course before that point in time. So we could start to see second wave capital expenditures coming in not likely 2009, but quite possibly as early as 2010.

Okay. And I guess the big question is, how lumpy do you think that could be? Is 2010 CapEx likely to be on the order of what you are experiencing right now, assuming that for the sake of argument that the bulk of the second wave proceeds?

Well, assuming the bulk of the second wave proceeds, that spending would be spread on an order of fairly extended period of time. So I don't think I see 2010 as being particularly untypical year, but we would likely see expenditure levels continuing at the rate that we are currently spending in 2008 and that's becoming more or less of the steady state as we move into phase two.

Daniel, one of the things that we are intending to do at our Investor Day conference in October is to try to lay out for you as best we can the timeline around Wave 2. And the reason why we've chosen that timing is that we've got a number of discussions underway right now where we think we will have a lot better clarity on the likelihood and the timing by the time we get to the early October Investor Day conference. So we should be able to be a little more specific with you at that time.

Okay. Well, that's really good. Right. I guess what I'm taking away from this is that 2008 kind of CapEx levels are almost the new normal in terms of cash flow?

I think they are probably the new normal in terms of opportunity and growth going into the future, yes.

All right. That's fine. Thanks very much.

And by the way, that leads you to a question as to how we finance, but remember that at the same time the CapEx is going up, the cash flow, free cash flow associated with Wave 1 projects really starts to contribute. So we don't have any significant concerns around the financing of Wave 2.

Sure. I understood that. Thanks.

Okay.

Your next question is from the line of Grant Hofer of UBS. Please proceed.

And Pat, this may be a bit of a premature question in light of your recent comments, but with the Texas Access pipeline being pushed back, Gateway likely to be jointly producer owned or shipper owned at least, is that $14 billion to $15 billion of Wave 2 spending still a reasonable number?

Well, when we put forward the $14 billion to $15 billion, we said that that was a gross number and that could include participants. It's hard to decline at this point the extent to which we may have other companies participate. So that is a gross number and it was never intended to be a 100% Enbridge grand.

So, potentially with where things get scaled back to at least the way things look today, I mean, you guys still talked about being able to generate double-digit earnings growth beyond 2012 after Wave 1 is completed and still remain comfortable with that longer term outlook?

Absolutely. And we will be more definitely on that come Investor Day conference as well. Realize that when we talk about Wave 2, those are only the things that we are aware of today as well. And there will be other things that will emerge along the way. So that's why we think that continues to be a reasonable proxy for the capital program.

Okay. Thanks guys.

Thanks, Greg.

And your final question is from the line of Carl Kirst of BMO Capital Markets. Please proceed.

Hi, appreciate the time everybody. I just wanted to quickly follow up on Rockies Alliance Pipeline and talks with Questar, they sort of seem to indicate that producers were perhaps looking for something that went directly into Joliet.

And I guess that the two-prong question here is, one, as we look to firm up support for App is not something where we are also looking at possibly changing rights away. Two, and perhaps maybe even a bigger question, because whatever happens if we do get more gas into the kind of Chicago area, is there possibilities for further expansions of Vector beyond the 100 million a day that's going in right now?

Yes. Good points, Carl. And first of all, the answer to question one is, yes, we will look at regarding options, as I mentioned earlier, because we are getting that kind of feedback from producers that heading directly into Joliet is maybe a little more in tune with their desires in being further upstream but to ensure as we had originally planned.

So we will look at gauging support to hit exactly the right market. And obviously yes, if we put additional volume in Chicago, that bodes well for downstream and for the Vector system. So, yes, yes to both of your questions.

Great. Thank you.

Thank you.

And there are no more questions at this time. I would now like to turn the presentation back over to Mr. Vern Yu for closing remarks.

Operator, were there any media questions?

No, there were not.

Okay. Well, thank you everyone. Colin and I will be available to take any detailed follow-up questions in my office. So I look forward to your calls and thanks for your attention.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a wonderful day.