恩橋 (ENB) 2009 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Enbridge Inc. 2009 first quarter financial results conference call.

I would now like to turn the meeting over to Mr. Vern Yu.

Good morning, and welcome everyone to Enbridge's Q1 2009 earnings call. With me this morning are Pat Daniel, President and Chief Executive Officer; Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development; and Colin Gruending, Vice President and Controller.

Before we begin I'd like to point out that we may refer to forward looking information during the call. By its nature, -- this information applies certain assumptions and expectations about the future, so we remind you it is subject to risks and uncertainties affecting every business including ours. Our slides include a summary of more significant risks and factors that may affect the future outcomes for Enbridge which are also discussed more fulsomely in our public disclosure document available both on SEDAR and Edgar.

I would like to remind everyone this call is webcast and the supporting slides are available on our website, www.enbridge.com/investor. A replay of this call will be available later today and a full transcript will be posted to the website shortly thereafter. The Q&A format will be the same as the past few earnings calls and the initial Q&A will be restricted to the investment analyst community followed by questions from the media. I would also like to remind everyone, Pat Murray and I are available for detailed Q&A after the call. And at this point I would like to turn the call over to Pat.

Great, thanks, Vern. And good morning, everyone. Thank you for joining us for our 2009 first quarter review.

As we reported earlier today our adjusted earnings for the first quarter of 2009 were $269 million. And that is $0.74 per common share and a 13% increase over 2008. We're also pleased to report stronger performance year-over-year in all of our business units. Of course liquids pipelines continues to lead the way as a result of the very robust growth secured through our $12 billion of expansion projects. Sponsored investments also improved due to the distribution increases that were announced at both vehicles in 2008 and also as a result of the increased ownership in Enbridge Energy Partners due to the fourth quarter 2008 equity injection that we made.

These first quarter results are slightly ahead of our expectations. Which put us in great shape to meet our 2009 guidance of, $2.18 to $2.32 per share and also, in terms of our longer term guidance of 10% plus average earnings per share growth through 2012. We're right on target. Richard Bird is going to review the quarterly financial results in more detail in just a moment. This morning, I -- I am going to keep my remarks on the strategic update relatively brief. Because as you know I will be speaking again later today at the annual general meeting. But instead this morning what I would like to do is to use my time to speak to a number of very significant accomplishments that we have had so far this year.

The -- the first quarter was a very busy one and it was very gratifying as we began to place a number of expansion projects into service. These are projects that as you know we have been working on for some time now. On April 1, for example, we placed the final phase of Southern Access expansion into service. This new pipeline between Delavan, Wisconsin and the Flanagan, Illinois hub is the second phase of the Southern Access project. And together phase one which was placed into service last April and phase two, add 400,000 barrels a day of incremental capacity to our main line crude oil system. The new pipeline now also provides substantial low-cost expansion capability simply with the addition of future pumping capacity.

During Q1, we also placed into service our Spearhead pipeline expansion which increases the capacity of this line from 125,000-barrels a day to 193,000 barrels a day. Demand from Western Canadian shippers for access to the Cushing market has been significant and has continued to grow since we first started spearhead a number of years ago.

The line 4 extension, from Edmonton to Hardisty, Alberta was also completed in the first quarter which eliminated a bottleneck in our main line system through that area. I think it is of note that we're very pleased to report that all of these assets were placed into service on time, and within budget. We continue to make good progress on both the Southern Lights project, which will ship 180,000 barrels a day of diluent from Chicago back to Western Canada as well as the largest of our main line expansion projects which is Alberta Clipper to increase main line capacity by another 450,000-barrels a day. Both of these projects are on schedule, and are expected to go into service in mid-to-late 2010.

Recently we have also talked about opportunities for further expansion of our natural gas assets. We recently announced a nonbinding open season on the proposed Lacrosse pipeline which would carry at least a BCF a day of gas from the Carthage, Texas hub to a variety of pipeline interconnections that get that gas into the Florida and the Southeast markets in the U.S. This pipeline is really necessitated by the growing supply out of the Haynesville shale which is one of the most active gas plays and most prolific in the United States. Our proposed Lacrosse pipeline provides what we think is a very creative and flexible solution to relieve marketing constraints that are going to be affecting producers in that booming region.

Turning to the renewable side of the business earlier this quarter we formally opened our 190 megawatt Ontario wind facility which is located on the eastern shores of Lake Huron. Construction on this project was substantially complete at year-end 2008 but it is now in full operation with all 115 wind turbines supplying power to the grid. With the completion of this wind farm, Enbridge's share of power produced from our four wind farms is equivalent to about 35% of the power that we consume on our Canadian crude oil mainline system. So wind power production is becoming a significant part of our story.

In addition, the Enbridge-led 38-member Alberta Saline aquifer project which is known as ASAP announced the completion of the first phase of its work and the start of phase two which includes the construction of a pilot project to actually begin injecting CO2 into a Saline aquifer. We believe while still in the early stages that carbon capture and storage has the potential to transform the environmental footprint of the energy economy and also to significantly help reduce greenhouse gas emissions not only in Canada but throughout North America..

Finally, we were happy to announce the successful sale of our investment in the OCENSA pipeline. With this sale we have really now divested ourselves of our two international ventures and I would like to stress that this is not a change in the Company's strategic direction, in fact, those were very strong performing assets. However the attractiveness of the offers were just too good to pass up given the high quality organic growth projects that we are financing here in North America right now. We still believe, though, that there will be select opportunities where Enbridge can replicate the performance that we have had in both Spain and Colombia in the international marketplace and we will continue to search these out over time. So let me now just pass it on to Richard Bird to review the quarterly financials and the Company's liquidity position and then I will come back and conclude in a couple minutes. Richard?

Okay. Thanks Pat and good morning, everyone. As Pat mentioned we released our first quarter results earlier this morning. And reported net income was $558 million. Or $1.54 per share. That is up from $251 million last year, or $0.70 per share, in 2008. The significant increase in reported earnings, of course is attributable to the $329 million gain on the sale of our investment in OCENSA which Pat just mentioned. That was partially offset by a $15 million mark-to-market loss on derivative financial instruments used to lock in returns within our OCSABLE and energy services business.

Excluding one time and nonoperating factors, our adjusted earnings for the first quarter of 2009 were $269 million, or $0.74 per common share, that is an increase of 13% in adjusted earnings over the first quarter of 2008. But the rate of growth will accelerate as we move through the remaining quarters of the year. Adjusted earnings increased in each of our segments excluding of course international. As Pat mentioned, this increase actually exceeded our expectations, and sets us up very well to meet our 2009 earnings per share guidance range, the midpoint of which represents a 20% increase in earnings per share from 2008.

Diving into the details, starting with liquids pipelines, first quarter adjusted earnings rose $21 million to $97 million in 2009. Most of the increase was due to the recognition of allowance for equity during construction, on Southern Lights. As well as within the Enbridge system on the Alberta Clipper project. Both increased as a result of the capital base growing during their construction periods. Earnings also increased within the Athabasca segment due to the Waupisoo pipeline being placed into service in the second quarter of 2008. These positive impacts were offset partially by higher operating costs within the Enbridge system including pipeline integrity spending.

Gas pipeline results are just slightly higher than 2008. And that is as a result of the stronger U.S. dollar. And as well, the impact of increased demand for the vector transportation corridor. These were offset by depreciating asset base within alliance as well as continuing lost revenue early in the quarter, related to hurricane Gustav and Ike within the off-shore assets. Sponsored investments made an increased contribution.

Adjusted earnings increased $8 million due primarily to the increased ownership within Enbridge energy partners as well as the stronger US dollar. As a result of the $500 million equity injection made in late 2008, our effective ownership increased from 15% to 27%. Of Enbridge energy partners. EEPs adjusted results were lower than the prior year looking at EEPs performance by itself mainly due to weaker performance within the natural gas segment as a result of the lower commodity price environment. Enbridge income funds contribution went up as a result of the two distribution increases announced last year.

Moving to gas distribution ask of services adjusted earnings increased $9 million due mainly to strong performance from our energy services business. Which was able to realize higher margins and volumes from a Contango oil market and low risk transportation arbitrage opportunities. This increase was partially offset decreased earnings within Enbridge gas distribution. That's as a result of a change in our customer billing practice where a larger portion of the customer's bill will be a fixed component and a lesser amount will be variable. As a result earnings at Enbridge gas distribution will be lower in the first quarter and the fourth quarter, but higher in the second and third quarters. And with increased capture of incentive regulation benefits, which is going well, they will be higher for the full-year versus 2008.

As already noted, internationals contribution decreased as a result of the sale of CLH in the second quarter of 2008. As well as the sale of OCENSA on March 17, of this year.

And finally, in corporate, costs are $5 million lower than in 2008. As a result of a number of small factors, including a higher corporate income tax recovery, and some foreign exchange gains as a result of the stronger US dollar.. So that is a review of the earnings drivers and I would now like to spend a moment just updating our financing outlook..

As a quick reminder, I am working off of page 10 now of the slide deck, our investment in OCENSA generated net after tax cash proceeds in Canadian dollars of CAD512 million. And the final gain in Canadian dollars was CAD329 million, reflecting both the favorable exchange rate hedges that we had in place and effective tax planning. This sale substantially reduced our equity needs for our commercially secured projects. As indicated in the funding requirement chart on page 10. And, in fact, it completely eliminated them in 2009. We do continue to explore alternatives to proactively deepen our equity base, in order to accommodate additional investment opportunities, and known alternatives include both asset sales and asset monetizations.

From a liquidity perspective, moving to slide 11 our remaining net funding requirement for 2009 is now $2.4 billion. And that includes the remaining capital expenditures debt maturities and dividends for 2009 less the remaining funds from operations we will generate this year. And we continue to carry a significant amount of unutilized credit facilities. At the end of March committed credit facilities for Enbridge and its subsidiaries totaled $6.7 billion of which $3.2 billion is either drawn or is allocated to backstop commercial paper programs. The remaining $3.5 billion of unutilized capacity is available to provide bridge funding for our capital programs, prior to putting in place permanent financing, or to accommodate additional investment opportunities. As you can see we have a very substantial liquidity surplus, for attractive opportunities, even without accessing capital markets. However -- we are starting to see improvement in long-term debt market pricing in both Canada and the U.S... On that note I will turn it back to Pat for his concluding comments.

Very good, thanks Richard. So the first quarter of 2009 is -- started the year off better than expected. With increased contributions from all operating segments, and placing us now well on our way to achieving our 2009 guidance. And probably even more importantly we're now placing into service, on time and on budget, assets that will enable the Company to have an average earnings per share growth rate through 2012, of 10%-plus. Bringing with that, of course a comparable increase in dividends. So on that note, I think we can move to the Q&A session.

Ladies and gentlemen, today's question-and-answer session will be held in two parts. First, we will take questions from analysts, followed by questions from the media. (Operator Instructions) And your first questions from from the line of Andrew Fairbanks with Banc of America. You pay proceed.

Thank you, good morning, guys.

Good morning,.

Good morning. Just had a question on the financing slide on page 10. So as you look at the total capital expenditures over the period of $12.5 billion, how much of the Fort Hills project is included in that number at this point if anything?

Yes, there is about $2 billion in there for Fort Hills and that is right at the back end of the five-year period. So we're still carrying an assumption of inservice in 2012 pending further guidance from the sponsors.

And I guess as you think about that funding requirement, should Fort Hills slip back to the second part of the decades, would you -- would you think there is a high probability of other projects coming in to absorb that magnitude of capital need or would that just be a funding benefit where there would be just less debt and equity funding requirements in 2010 through 2012?

We're working on a number of other alternatives right now, Andrew, and I think it is fair to say that we would expect, in combination of other oil opportunities or, some of the gas proposals that we're working on, that we would -- we would fill that in. Hard to be very specific with you right now but we do have a number of things on the go.

Well, that's great, thank you.

Thank you.

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

To what extent are you seeing productivity improvement for labor within Alberta and then to what extent is that giving you an ability to come in under budget on some of your projects and then therefore open up some head room on your financing?

Actually Andrew, to a very significant extent we're seeing improvements in productivity. And I will -- I will speak primarily to pipeline construction productivity. I think it is fair to say the general principles that I will refer to are applying to upstream construction as well in the oil sands but we -- to give you a measure of that, we have seen over a three times, three to four times improvement in the well reject rate, associated with pipeline construction which is one of the key measures that we use on productivity and pipeline construction. And that has been very significant, so we're seeing very significant improvements in productivity from a year-ago when we didn't have the kind of tightness that has started to develop in the labor market. So that is the case. And also we're seeing far more competitive bidding from contractors for new projects, and are now able to move away from the time and materials contracts that we were letting to fixed big contracts. So that should result in a significant decrease in cost over time as well. We are very pleased to see those improvements in productivity.

Is there any specific quantification of that benefit and how that translates into your capital program?

Well, -- I can't quantify it other than to say that the construction costs is -- has most recently been about a half of the the cost. So if you -- what portion of that would be impacted by the reject rate on wells, for example, it is hard to say, but we're dealing with, by far, the biggest component of the total cost of laying the pipeline and that is the 50% associated with contractors. So I think you can expect to see some -- some notable decreases in costs but hard to quantify because it's kind of early stage at this point.

And then if I may, just on the intra Alberta market what are your expectations for the bidding process on a Kearl pipeline?

Well, we have put information in front of the sponsor, of the Kearl8 project and would expect at some point over the next six months to find out whether we're in that race or not. And -- but -- it -- it will depend a lot on I am sure the sponsors timing with regard to sanctioning the project and their decision making as to who their pipeline provider will be. We certainly hope to be in the race.

And your next question comes from the line from Linda Ezergailis with TD Newcrest. You may proceed.

My question is more on the operational side. I am wondering, as I look forward to the balance of 2009 and 2010, how I might think of both energy services, outperformance and what I view to be slightly light contribution from the Enbridge system excluding AEDC versus my expectations going forward. So what sort of run-rates might we expect? And you have given us some color on energy services Q1, but maybe on the Enbridge system earnings, if you can give us some color on whether you incurred any penalties under your ITS, or is there a timing consideration, or anything else that we might want to model into our full-year numbers.

Richard, could you respond?

Sure, I will take a stab at that. The Enbridge system in the first quarter, you're seeing, -- you're seeing some drag from higher costs, that is partly employee-related costs. That is probably an ongoing effect, there also were some fairly significant integrity spend in the first quarter. That's in part, I think, something that isn't indicative of the run rate. So I think we will -- we will see better performance on the cost front as we move ahead there. And energy services as I think you already observed, Linda, had a strong quarter, there continues to be some good opportunities, but I wouldn't like to suggest that the first quarter is indicative of the run-rate in that business. It will probably be the best quarter of the year. Perhaps the best quarter for some time. And all of that is -- as we indicated earlier, is rolled up in our -- in our assessment of where we stand with respect to guidance and we're certainly well on track, if not a bit ahead.

Okay, thank you. In terms of the Enbridge system, can you clarify what is going on with the ITS? Like is that integrity spend kind of normal, within the full-year context? Or -- or would that be a higher amount than we would have seen in previous years? And perhaps you can help us quantify what the breakdown was as the -- the ongoing employee costs versus the more one-time integrity spend?

Yes. I don't think we're going to parse it down into too much more detail than that. The integrity spend, with respect to the ITS is as provided for in the ITS and we do have -- we do have an understanding with CAPP with respect to how much we will spend. So I think generally on an annual basis we will be in line with that. But a little -- more heavily weighted towards the first quarter this year.

And your next question comes from the line of Bob Hastings with Canaccord, you may proceed.

Just to clarify on that last point on the Enbridge systems I notice that the equity earnings from -- or AEDC were up very significantly and so -- as I am sure Linda did as well, the -- when you do the calculation, that was up $13 million but Enbridge system is only up $7 million. Is the full difference of that just the two items that you mentioned?

They would be the largest part of that difference, yes.

Okay. And then just to clear up the difference between slide 10 and 11. I notice that, the debt remaining to be funded in slide 10 was $2 billion over the period. But then on slide 11 you're talking about $2.4 billion. Is that because you're -- in the slide 11 you're including some of the other subsidiaries or what is the difference?

Vern, can you?

Yes, on -- Bob, on slide 10, that is the debt to be funded between 2008 and 2012. Slide 11, is just the total funding needs of cap after we take into account funds from operations this year. CapEx, and debt to be refinanced this year. So that -- there is a difference that slide 11 includes refinancings and slide 10 does not.

Did that help, Bob? We lost Bob.

And you have -- your next question is from the line of Robert Kwan with RBC Capital Markets. You may proceed.

Thank you. Just coming back to ITS, is there any progress on the discussions with the upcoming expiration of current agreements?

No, we're still very early stages there, Robert. We haven't really got deeply involved in the renegotiation. As you know it is a pretty active time in the industry both for our customers and for us so -- no, we really don't have anything further in terms of progress from our last report.

Okay and just kind of with the early discussions you're having is it still the case there is nothing you're seeing in terms of issues that would materially change, the outlook for the next ITS versus what you're operating under right now?

I think that is fair to say. I think the spirit under which the original incentive tolling agreement was put in place and then the renewals done over the years is very much the same. One of sharing benefit through cost reduction and productivity improvements and -- and the metrics that we have used for crude quality and scheduling. So certainly the overall spirit of cooperation is very much the same going into those discussions. So, we haven't had any major issues that have come up.

Okay and if I can just turn to the financing down at Enbridge Energy Partners, can you give some extra color there. We have seen a decent pick up in the Enbridge Energy Partners price. I guess just from the Enbridge Inc. perspective, what are the kind of considerations you're looking at and at what point do the economics start to make sense to you, to prefer EEP to look externally for financing?

Well, let me kind of start back at the start as I guess implied by the final part of your question in that our preference always has been for EEP to be a self-financing vehicle. However, with the MLP market being as hard hit as it has been, we have not wanted to be out raising equity in that environment. And as you know, have -- through Enbridge, provided support to EEP as recently as last fall. Obviously much to our benefit as you see from our results as well. So their benefit and ours. So we will continue to monitor the market, we will continue to look at the potential for EEP issuing units if the market strengthens to the point where we think it should. We have also indicated that we could potentially take a further interest in EEP or we could take an interest in a particular project that EEP is working on as ways of providing that kind of financing most effectively to the partnership. Even though the units have strengthened they are still well off their all-time high and hence we have a little ways to go in that market before we feel comfortable in going through the market.

I guess when you mentioned kind of the all-time high that is roughly in the range -- I know you don't want to get into specific numbers but is that kind of in the range where you would feel comfortable in the economics for Enbridge Inc. for EEP to go up for external unit financing?

I would rather not suggest that because there are a lot of other factors that could come into play rather than just one specific number so I would rather not, Robert, but there are a whole lot of things we would have to take into consideration.

(Operator Instructions) And your next question comes from the line of Winfried Fruehauf with Fruehauf Consulting.

Regarding Enbridge's offshore system what were the earnings contribution in the last quarter versus a year-ago? And I have a follow-up question.

I was just looking that up, Win. Bird?

The -- on an adjusted basis, Q1 was $7.4 million. versus $5.4 million in Q1, 2008.

And the follow-up question is, ever since the first investment in this pipeline system, annual earnings have never really reached the target level which I think at this time was about 28 million to $30 million. And I appreciate that there were factors -- many factors beyond Enbridge's field of influence, but in as far as Enbridge can affect these results, what is Enbridge proposing to do this year, next year, to bring these results up?

Win, you're right. As we have indicated before, we probably for the -- one of the first times in Enbridge's history, our timing of an acquisition wasn't great in that we were hit with hurricanes Rita and Katrina the summer after we acquired those assets and then had another hurricane -- bad hurricane year last year in the form of Ike primarily. We -- first of all, there are a number of very encouraging factors in the Gulf of Mexico now. Thunderhorse, for example, is now producing at 200,000 -- yes, 200,000 MMBTUs so it is up and actually, in excess of where I believe they had expected it to be. So it was slow coming on post hurricane Rita, Katrina, but is now exceeding expectation. I think that is one of many indicators that as a lot of this production comes on, we will move back up into the target range that we had initially.

Not only that, as we look at new investments in the Gulf, and there are a number of opportunities for expansions and extensions in the Gulf, we're further refining our model to reduce the risk associated with these investments, such that we have some kind of demand charge, ship for pay commitment and minimum return tied in, and that will gradually bring -- bring these assets back on size in terms of performance level. So we're still very encouraged by the overall geological prospectivity in the Gulf and opportunities to continue to expand. It will be on a more conservative business model than the original assets.

Thanks very much.

Thank you.

And your next question comes from the line of Carl Kirst with BMO Capital Markets. You may proceed.

Good morning, everybody. Most of my questions have been hit but maybe just a follow-up on Lacrosse. If this were a pipeline -- if returns were met, if you will, and it was going to be in service for like 2011, early 2012 when would we actually have to have sanctioning of the project? I mean is this something that could be done in sort of one construction season? Or how long might that take?

Well, we're -- we are in early stages on it, Carl, as you know. We have gone out, we have got an open season running through until the 15, of May, and would expect to get pretty positive response because we think that is the right market to head to and I will come back to that in a minute. But -- we would be looking at construction in 2010 and 2011. As you suggesting on stream in 2011.

Okay. And then, with respect to, Pat you just alluded to the markets you're trying to hit and I understand certainly the wanting to avoid Perryville at this point. But as you guys sort of go down to FGT, is -- are you primarily looking just to bypass Perryville and basically interconnect with the northeast pipes? Or is it fundamentally trying to get that gas down into southeast markets, Florida markets. And in part I am trying to figure out how much of this is producer-push Haynesville-driven versus perhaps tapping into some long term Florida demand?

It is very much the latter of the two alternatives that you suggest. It is not to pick necessarily other interconnect points to get into the US northeast. And I will come back to that in a minute but to hit what we think will be a very strong growth market in the southeast by tying into Florida gas transmission and other points to the southeast. We're -- we -- as we sit looking at this overall shale map in North America, and the large Marcellus shale sitting up in the northeast, we think that longer term that probably this Haynesville gas is going to find the best home and the best market and the best net back for the producer by getting into the southeast market. There are a number of proposals to get from Carthage over to Perryville and we think that hitting the FGT connect is probably the best way to go for producer net back.

Great, thank you.

Thank you. Hello, hello? Yes, go ahead.

Sorry, am I -- I cannot -- I can't hear if I was called.

Go ahead, Steven. It is -- we can hear you fine.

We can hear you, Steven, go ahead.

Thank you, and I am sorry for the confusion. My question is on Spectra joining the alliance and Questar on the Rockies Alliance pipeline. Can you comment on the process that led to bringing in a third party on to the line?

Well, just to kind of step back on -- on Rockies Alliance for a second, the key thing of course is to get as much volume commitment as we can to the pipeline. That is one of the things that made Questar such an attractive partner right from the outset because they do bring volume along with them. We're certainly welcoming Spectra into the mix. And our -- again, a ways to go as a result of some of the slowdown in drilling in the Rockies but hope to build producer support for that line.

Excellent. Thank you.

Operator.

Operator? Do we have any other questions? Hello? Is there anyone out there?

My apologies for the delay. Your next question comes from the line of Sam Kanes with Scotia Capital.

Thank you. Just to explore a little further the progress now you're heading into phase two and eventually phase three now in the large CO2 sequestration project. Obviously you're showing leadership on the issue. I am just curious as to if you have any specific first rights of refusal to the ultimate pipeline build or what pro ration of cost, you're in a more expensive phase. I know there is Federal provincial money but they probably won't cover all of that. Just wondering how that is evolving or shaking out will all 38 partners stay with phase two and phase three, that kind of thing?

Yes, to answer the first part of it, Sam, we do have the exclusive pipeline rights and the sequestering rights on the project. And other partners will look after the upstream capture of the CO2. And -- with regard to the capital associated with phase two, Richard can you help me out on that? Do you know what phase two capital is?

I don't think it is established.

Yes, it is relatively small in that it is pilot project. And you're right. We have tapped into some funding, Sam. We will have to get back to you on a ballpark range on that. Vern has indicated he thinks it is in the range of 150 million to $200 million on phase two.

And that would be to split 38 ways or? Disproportionate to you, that kind of thing?

One-third -- oh, yes, so in terms of -- yes, one-third Federal, one-third provincial and one-third partners and that one-third of the partners is split 38 ways.

Equally, very good. Follow-up you mention your 33%, I guess, hedged if you may, with renewable energy against your energy consumption. Is it a general target or do you have a general target to head towards 100% hedged with respect to your portfolio, or -- or you haven't really defined that yet?

Well, first of all, Sam I don't know that "hedged" is the right word. And what we indicated is that we -- we produce wind -- our share of the wind power that we produce amounts to 35% of the power we use and the crude oil main line system which is one of the biggest areas of power consumption in the Company. So we have got a general guideline that at some point, over the next four to five years, we would like to be generating enough renewable to cover our power requirement in the Company. And that doesn't mean to say that that power is going to go to powering our pump stations, but just as a general offset from a corporate social responsibility point of view we would like to be in that range. So I wouldn't look at it as a hedge. There is no financial connection at all between the power we generate in the wind power business and our power usage. But just generally, the ability to offset our power consumption with a green energy alternative.

Thanks Pat.

Thanks, Sam.

After analysts questions we will be taking questions from the media. (Operator Instructions) And your next question from an analyst comes from Bob Hastings with Canaccord, may proceed.

Thank you. Just a little clarification on your corporate costs. The -- they were down, you said you -- your tax rate recovery went up and I wonder if you maybe could expand on that a little bit and then if you had any guidance sort of where you expect that to be for the year?

I think that is probably seeing our -- corporate tax -- corporate segment tax costs in the first quarter. We're probably going to continue to see that kind of performance for the balance of the year. So a little higher than it has been in the past but consistent on a go-forward basis.

And the SIFT tax, how did that have an impact?

Yes, that is a bit of an anomaly which is why we have -- why we have backed it out in terms of what our run-rate earnings are. There was some legislative changes, clarifying the applicability of the SIFT tax. Previous to that we had thought that some of our internal partnership structures were actually going to be subject to the SIFT tax even though they are not publicly traded entities. We had been providing for the SIFT tax against those entities. Which was at a slightly higher rate than would be applicable in the absence of the SIFT tax. The legislation clarified that those entities wouldn't be caught and so, we have -- we have reflected that change, as a one-time adjustment.

Okay. And the guidance on sort of corporate expenses overall three years s the first quarter an appropriate run-rate?

I think, for the moment, yes. We're generally expecting to be in the 10 to 15 area. So roughly in line.

Okay, thank you very much.

Thanks Bob.

And your next question comes are the line of Andrew Kuske with Credit Suisse. You may proceed.

I just wanted to get a better sense of what your outlook for crude pipeline additions will be post 2012 in part because you have got a tremendous amount of capacity coming on line as does one of your competitors. So when you look out post 2012 with the curtain volumetric production, projected production, what do you think will happen beyond 2012 as far new crude oil pipelines?

Well, I think there are probably two or three areas of opportunity. First of all, you -- as was mentioned earlier that the Kearl project with Imperial Oil seems to be going ahead. And I think, the potential is there for one or two other projects to proceed, and hence, that corridor from Fort McMurray down to Edmonton is going to be an area of opportunity for us whether it is Kearl, whether it is BP Husky on Sunrise, opportunities through that corridor. The second probably, -- or an area of bottleneck maybe the second biggest area of opportunity is going to be from Cushing South. Where we're finding that crude has started to bottleneck in Cushing and there needs to be additional capacity South. Hence our joint venture with BP for look at use of their BP one line to get to Cushing and then a new build from Cushing South. I think that that would probably be the second area of influence.

I would then, in addition to that add the Eastern part of PADD II, to satisfy the Toledo, Detroit area, the expansions that Marathon has underway, and Husky, again, we have to win all of this business. But -- but that will be a further area of opportunity, and then, in -- and I will put this a little bit on the outer end of that, ultimately Gateway. We still have strong support from both producers and refiners to proceed with filing an application on Gateway. And even though from a capacity point of view there -- there will not be a need for ex-Alberta capacity for some time Gateway is becoming more and more a pricing play and an optionality play for producers that could cause it to go before there is actually a shortage in capacity ex the province. Probably in that order, Andrew, I think those would be the areas of focus for us.

And then a somewhat related question just in the context of when you're talking to shippers and prospective shippers about your new pipeline projects, on a return basis, have your thoughts, or your discussions with shippers really been revised around returns with the NEBs recent decision on TQM and their ship to an [Ad Wac] type approach which should buy us up returns over a period of time.

The discussions with shippers, that hasn't really become an issue with regard to a lot of new build opportunities. But certainly it does apply to some existing assets. That we have and the potential for an upward movement in the overall return. And -- and realize that we also have some indexing within existing deals that could move upward as a result of -- of that move.

Okay. That's great, thank you.

It might be worth adding to that Pat, that -- just as an example, Alberta Clipper, which between Canada and the US is over $3 billion worth of capital, does drive its returns off of the multipipeline rate of return. It is multipipeline plus 225 basis points. So to the extent that the TQM decision were ultimately extended to a revision of the generic multipipeline rate of return formula, that would have quite a significant impact on Alberta Clipper and there is probably upwards of another $1 billion of capital in various other projects that are similarly geared off of that number.

It is safe to say that you are going to be filing documents with the NEB on the 25th, or thereabouts of May, with regards to the potential application of the TQM decision to other assets?

Yes, I think we will work with the Board and with the industry to try and work out what is -- what is the logical implication of not just the TQM decision, but the general shift in capital markets that we have seen in the last little while in terms of risk premiums. Of course it is not just the oil pipeline side of the business either that is relevant here although we have an incentive deal in place on the Ontario distribution business. It ultimately has upside potential associated with that as well.

Thank you.

Thank you.

And your next question comes from the line of Petro Panarites with CIBC.

In some of your recent presentation material you have begun to include a more specific chart on gas projects in development. You've included an other category, it amounts to, just eyeballing the chart, about $7 billion. How do we look at that the, in terms of what your fair share of that is and over what timeframe, does it come into service?

Well, yes, I know exactly the chart you're referring to, Petro and basically it is to put beside our original wave 2 of liquids projects a series of opportunities on the gas side that we think could well build in behind or in place of that wave 2. And we specifically haven't specified projects in there because it is a little too early in the development cycle to say. However we're encouraged by the general trends and direction and opportunities that are coming our way, whether it is a combination of Rockies Alliance and the Lacrosse pipeline in the Haynesville, there is some absolutely good and strong opportunities coming out of these shale plays, possible extensions and expansions of Alliance in in the northeast BC area and also the work that we're doing offshore in order to tie in some of the new deepwater discoveries in the off shore Gulf of Mexico. So, we have not been able to be really specific in that, but are just very encouraged by the general level of development in the gas business today. I guess, Petro I could maybe just--. Sorry, go ahead. Do we have another question?

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

Thank you, on the Gateway line a quick question, the producers are fully funding the costs, to get to the permit as you spend them; is that correct?

Yes. It's producers and refiners, Steven, yes.

And -- that arrangement ends when you -- when you complete the -- when you complete the application sometime this year?

It ends when we have an approved application.

Oh, excellent, thank you.

With the caveat that all that is committed at this point is $100 million. So if it took more than that to get to the finish line and that is the budget, but if it took more than that we would have to go back to the producers for further funding.

Thank you.

And your next question comes from the line of Scott Haggett with Reuters, you may proceed.

All right. I just wanted to ask a couple of questions. First, what is your outlook for volumes on Spearhead? Do you see that filling as the season progresses and do you intend to replace the retired capacity at Cushing?

Colin, do you want to respond to that?

I know the capacity goes from 125 up to 190. And -- or to 195. I am not sure exactly what the production outlook is, Richard--?

I can take a stab at that. Spearhead has been quite significantly apportioned for some time. But the expansion isn't just driven by hoping the volumes will come, we conducted an open season and have binding contracts for sufficient of the additional capacity that is being added to provide the expected level of returns on the project. So I would expect we will see throughput mount up over a period of time probably pretty close to the full capacity of the line which is up to now I think 195,000 barrels a day. The one caveat on that as Pat mentioned earlier is that Cushing is going to start to get bottlenecked so there will need to be a solution in the not too far distant future to allow all that crude to flow from Cushing South.

Thanks. And the capacity that you retired or Sagan retired that 500,000 barrels of aging tankage, do you see that being replaced?

Well, we have added a -- an awful lot of tankage at Cushing over the last little while. There is a certain amount that is retired over the normal course so that is older smaller tanks, so I think we already have more than replaced it.

In fact, I think we have had a net add there, Scott.

Okay. Thank you.

This concludes the question-and-answer portion of your conference. I would now like to turn the call over to Mr. Pat Daniel for closing remarks. You may proceed, sir.

I would like to thank everybody for tying in today. I don't think we have any further remarks, Vern, in terms of follow-up.

Yes, I think everyone, if you will just -- the further detailed questions that you need answered, Pat Murray and I are available. I think Pat had sent out an e-mail yesterday with contact numbers that we can be reached out and we look forward to talking to you later..

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