Good morning. My name is April, and I will be your conference operator today. At this time, I would like to welcome everyone to the Spectra Earnings Third Quarter 2011 Earnings Call. [Operator Instructions] Please note that today's call is being recorded. Thank you. Mr. John Arensdorf, you may begin your conference.

Thank you, April, and good morning, everyone welcome to Spectra Energy's Third Quarter 2011 Earnings Review. Again, thanks for joining us today. Leading today's discussion will be Greg Ebel, our President and CEO and Pat Reddy, our Chief Financial Officer. Both Greg and Pat will discuss our quarterly results and provide more color around our strategic plans to enhance the value Spectra Energy delivers to its shareholders. We'll then open the lines for your questions. But before we begin, let me take a moment to remind you that some of the things we will discuss today concern future company performance and include forward-looking statements within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statement. And you should refer to the additional information contained in Spectra Energy's Form 10-K and in our other SEC filings, concerning factors that could cause these results to be different from those contemplated in today's discussion. In addition, today's discussion includes certain non-GAAP financial measures as defined by SEC Reg E. And a reconciliation of those measures to the most directly comparable GAAP measures is available on our investor relations website at spectraenergy.com with that, I'll turn the call over to Greg.

Thanks a lot, John and good morning everybody. As you've seen from our earnings release, Spectra Energy delivered ongoing results of $247 million or $0.38 per share. We continue to deliver value-creating results. We exceeded last year's EPS by 23% well ahead of our expectations year-to-date. All of our businesses continue to perform well and we're growing our earnings from projects placed into service at attractive rates of return. We're realizing the upside of higher NGL prices which as you know is a real driver of return at our field services business. We sell NGL prices 43% higher in the third quarter 2010 and 24% higher than our original assumptions. And as expected, we started to see a pickup in volumes across DCP as we've moved through the year. Incremental Eagle Ford volumes approached 200 million cubic feet per day in Q3. At DCP's new born plant in the DJ Basin, which came on earlier this year, we'd initially expected this to take 2 to 4 years to reach full capacity, but it is indeed now at full volume. We're even seeing growth accelerate in the Mid-continent, something we haven't seen in years. This ramp-up in volumes bodes well for DCP's further expansion plans, which are numerous. With less than 60 days left in the year, a good third quarter behind us and the fourth quarter typically strong for us. We feel very positive that we'll exceed our $1.65 earnings target. That confidence and our visibility on the 2012 earnings led us to a decision to increase our dividend now rather than at year-end. So as our $0.08 annual dividend increased, we've delivered twice the level of dividend growth expected and we delivered it sooner than expected. Last week's dividend increase underscores the soundness and ongoing success of the business…

Well, thank you, Greg. And good morning. As we announced earlier today, Spectra Energy reported third quarter 2011 ongoing earnings of $247 million, compared with $201 million in the third quarter of 2010. Our earnings this quarter surpassed our expectations and equally important, our year-to-date performance reflects solid progress on our capital expansion plans. As Greg mentioned, our core fee-based businesses performed in line with our expectations and we're continuing to realize earnings growth from expansion projects placed into service. Let's look now at EBITDA, which reflects the strong cash generation capacity of our business with every segment delivering solid results. Ongoing EBITDA for the quarter was $785 million compared with $695 million in the third quarter of 2010, an increase of 13% quarter-on-quarter and year-over-year. Now we'll take a look at our performance by business segment beginning with U.S. Transmission. U.S. Transmission reported third quarter EBIT of $235 million compared with $231 million in the third quarter of 2010. As anticipated, the segment benefited from northeast expansion projects placed into service during the fourth quarter of last year primarily TEMAX / TIME III and Algonquin East to West. These benefits were mostly offset by higher operating costs including the expensing of development costs associated with the Marcellus ethane pipeline system. Now let's turn to our distribution operations. Distribution reported third quarter EBIT of $50 million, compared with $63 million last year. This decrease is mainly due to higher operating costs, including higher employee benefit costs, which were partially offset by a stronger Canadian dollar. Let's turn now to Western Canada transmission and processing, which reported third quarter EBIT of $119 million, compared with $90 million in 2010. The segment benefited from improved results in the base gathering and processing business, primarily driven by higher contracted volumes from expansions in…

[Operator Instructions] And your first question comes from the line of Faisel Khan.

It's Faisel from Citi. On your prepared comments, you talked about the 96% renewal rate on the 2 pipelines going to the northeast. Did that include also kind of long-haul capacity as well? Is the long-haul capacity market into the Northeast still pretty strong?

Yes, absolutely that's everything that was up for renewal this year. In fact, that's an improvement from last year. I think it was about 93%, so even a better renewal rate this year, and I think it just underlines the value of those long-haul pipelines and the increments in between as well.

Okay, got you. And then at Kitimat, obviously, there's a -- the project continues to ramp up there in terms of the feed studies. What is your estimate in terms of the timing and when do you have to start working on your end of the equation to make sure that those supplies actually reach that facility?

Yes, I -- a couple of things. One, I think obviously, the processing capacity we put in place both last year end that will come in to service both at Dawson, end of this year and then Fort Nelson, the middle of next year. I mean that ensures that we've got that and the expansion of the pipeline, the header system already in place. So I think we're ready to go from that perspective. The issue is, we're kind of last in the chain in terms of how we'll hook up with producers. For example, the producers received the NEB approvals for export, but they've got to go out and get customers, obviously, foreign customers to backstop that production and then, they would come to us in terms of getting pipeline capacity. So I still think sometime over the next 12, 18 months is when that will all shape up. Obviously, we're in touch with all of the various players, Faisel. As you know, there's probably -- either publicly or privately half a dozen projects that they're all [indiscernible] at Kitimat.

Sure and then what do you have to do to the pipeline to actually -- to get to be able to transport all those volumes to the producers at Kitimat?

Well, we have to build it.

It's an expansion, I think you already have the line partially in place?

Well we do, we're the only folks that -- we have a pipeline that would go down north or south from Northeast British Columbia down to the Washington State border. But what you got to do is then go off from either call it Station 4 or Summit Lake area and then build the pipeline west. So that's the part that doesn't exist, which obviously is a very large build, but a pretty exciting one too.

Okay and then last question for me and I'll jump back in the queue. The $4 billion in projects you talked about, DCP. Do you think you'll still be able to generate the same sort of cash distribution from DCP, are you kind of building out those projects?

Absolutely. See, one of the advantages in I think what we're trying to do, and we've been able to do it so far and there's no reason why we wouldn't expect is that, we've got the MLP that can help fund the equity that may be needed at DCP during these build-outs. Either through additional drop downs at the DPM or through sharing of some of the projects, which -- and obviously they've got their own balance sheet to raise the debt. All of which allows both Spectra and the new downstream business at Conoco to continue receiving the type of dividends we have to date. And I would point out that the new downstream company at Conoco is even more aligned than Conoco in terms of the importance of those dividends. So I think you've got good discipline on both owners. A and b, you've got the good facility in place through DPM to help finance the equity component.

And your next question comes from the line of Monroe Helm.

I just wonder if you could kind of share the board's thoughts on raising the dividend at this kind of rate and the commitment to continue to raise it to $0.08 a year to the next few years. Is that an indication that you think the earnings growth rate is going to pickup here or do you think you need to pay a more competitive dividend given the growth rates for some of the other stocks that you compete against in the marketplace?

Monroe, when we have launched we said we wanted to pay between kind of 60%, 65% and given the earnings growth in the last several years, which has just exceeded what we had expected in the street, we've actually never got up to that rate. So with that and the good visibility going forward, that was really the driver. So, we can easily go and pay and put -- see good visibility to see our way to pay at least $0.08 a year through 2014. On a commodity neutral basis, that still assumes that we're growing at that, call it 7% to 9% EPS growth. So it's really the success we've had in the last few years to be able to move that up. And obviously, I'm not so sure from what other investors are doing or from what other companies are doing as some folks, that would be our peers, haven't had the type of dividend or even dividends at all. I think it's more just -- investors overall are valuing yield as well, and we think we can deliver both. So I think it's just more of a balanced approached and as I said, a monetization on the strategy that we've had to date, and just being able to step forward. If we didn't think we had good visibility on the growth, we probably wouldn't be on that stage, but it looks very good from our perspective.

And your next question comes from the line of Carl Kirst.

Just a couple of questions actually, both of which on Canada here. The first, more from a micro standpoint. Just noticed that in both distribution, which you touched on the higher O&M, we also look like we had a bit of a spike in O&M in Western Canada as well, and it was sort of those 2 areas that were the only thing that we saw that we weren't expecting, and I just want to get a better sense of color. Is this embedded, the higher employee expenses? Or is this somehow temporary, we might see a pullback from that? Just was hoping to get a bit more color there.

Carl, this is Pat. We'll talk about each of the 2 business units. And to your point, it's a little bit of both. But I wanted to just say at the outset, that the higher O&M was certainly anticipated in the EBIT guidance that we gave and for example, for distribution, as we talk about exceeding our $1.65 this year. We're looking for them to come in a little better than the EBIT guidance that we gave earlier in the year. So thinking about distribution, of the $16 million increase year-over-year, about $11 million of that is higher anticipated employee benefits cost and about $6 million is FX. Looking at Western Canada. As you know, they've had a lot of growth in the business. There's a timing piece related to higher maintenance of about $8 million, FX of about $8 million, some taxes that vary from year-to-year related to carbon of about $5 million. Employee benefits are only $3 million of that so, primarily related to operations and FX. But again Western Canada, as you see year-to-date and for the quarter substantially ahead of our EBIT projections.

And then just a second question if I could. Circling back to Faisel's and with respect to Kitimat and how ultimately the pipeline progresses. The purchase last week of PNG and the fact that Apache and EOG have got this sort of Pacific Trails right of way I guess, in their back pocket. How do you expect I guess, this to move forward as far as a potential pipeline, is it going to be basically just all the infrastructure providers putting in a bid for this pipeline to Kitimat or how should we think about this progressing?

Yes, I think you should think it's the same as any other major producing area and new project. I expect the producers to very much look for competitive bids. Of which again, with our header system already there, we feel very good about what we can provide on a full-service basis to those producers. With respect to the commentary on the purchase of PNG, I don't think it changes anything. As you know, they had already sold the pipeline aspect of that to the joint venture. So whoever bought that, it's just an issue of I guess, picking up the opportunity to operate it. But secondly, and perhaps more importantly, that's not a straight right away. That right away veers up north when you really want it to just be going straight out west to Kitimat, which is something that we're looking at. So bottom line, I expect it to be competitive. I expect West Coast Energy's assets that we hold in Spectra to be a competitive advantage vis-à-vis processing and pipelines, and I don't think that the sale of PNG really changes that competitive dynamics.

And your next question comes from the line of Ted Durbin.

Just coming back to the dividend raise here. You'd said I think, in guidance for this year that you were looking for 7% to 9% EPS growth, through 2013. You're now rolling forward to '14. Are you feeling comfortable that the EPS growth is still in that ballpark? And I think that was under a flat commodity price assumption, has that changed at all there?

Yes, no I mean you've got some pluses and minuses along the way, but we still feel comfortable in that range, Ted. Again, our good fortune has been that we've seen growth rates much higher than that because we benefit from the commodity as well. But I think that 7% to 9% type range is the way to look at things through 2014, as you know sometimes it's a little bit lumpy but on average that's what you should get. And hence that what's gives us again that confidence to be able to raise the dividend at least $0.08 a year through that time period.

And then if you can just talk about where you are on contracting on the Sandhills pipeline. Have you actually started construction? Are you kind of, everything sanctioned, you're ready to go and what your sort of producer interest is? What kind of term you're looking for, for contracts and maybe just what kind of returns or EBITDA multiples you're looking for as well?

Yes, I think we're 50% to 70% already contracted and -- well, 50% to 70% is actually DCP's volumes that underwrite that. So we've got additional contracts on top of that. I think we're looking for typical terms that you'd expect from a fixed fee pipeline. We are in execution mode, we are doing it at a couple of phases, as you know, and haven't run into any of the similar challenges that you might see on the interstate pipeline, for example. So we feel good about that. Obviously, both Conoco and Spectra are providing a lot of support to DCP in terms of project management. This is a big project, one that DCP has done historically. And I think that's going to serve us well on both fronts. So full steam ahead on both of that and in the Southern Hills project.

Great and then if I can, just one more. You mentioned challenges on interstate and that you got the draft EIS on New Jersey and New York. I'm wondering if you're seeing anything there that would cause -- whether it's reroutes or changes in the design that might impact the cost there?

I think importantly, that draft, the environmental impact statement said that there were very few concerns and very few impacts. And then it did occur, it could be easily mitigated. And we spent a long time leading up to that draft environmental impact statement, making some adjustments to routes etc., and accommodations. So I think we've done what we need to do to take into account the various concerns. Obviously, we're never going to satisfy everybody, any time you build a pipeline in a congested area. But I think we're good to go in terms of going forward and the FERC will take -- the comment period closed on Monday, Ted. And so I would expect the FERC to diligently move forward. We're trying to get a final environmental impact statement out early in the New Year and after all, there's 5,200 jobs here and probably $200 million to $400 million a year in economic and energy benefits for the folks in New Jersey and New York. So full steam ahead and get it in service at the end of 2013.

And your next question comes from the line of Craig Shere.

I had a quick question about the -- kind of picking up on Carl's question on O&M, but more on the U.S. pipes. Was there much that was occurring in the third quarter beyond the MEPS development cost and were those in-period costs or write off of everything to date?

The write off in the quarter was -- for the quarter, and it was a small write off earlier in the year, but in total, less than $10 million, so fairly modest, overall. But some of the costs that we incurred in the quarter would be ongoing such as pipeline integrity, due to more in-line pipe inspections. But that is only about $4 million of the $19 million in total. So again, it's anticipated and not something that is a significant bump on an ongoing basis.

And Craig, just a little clarification on the MEPS issue, that's everything that -- we've written off the entire cost to date on that front. And obviously, you've seen -- Enterprise made an announcement on their projects that doesn't look like there's a lot of customer support at this time, to move forward with that project, so I wouldn't anticipate any further cost.

Understood. And it looks good on the contract renewals for the long haul pipes. I mean, that's nice to hear. Are you all -- and maybe they're just not in the market because you're out a couple of years on your contracts, but what are you all seeing in terms of the gas storage side on contract renewals?

Yes, we always have some storage coming up and yes there's definite softness there. I think we're seeing the same type of things others are, in terms of -- you might see anywhere from 15% to 30% kind of declines in the rates that they're getting. But as you say, we've got a portfolio that goes out a few years. So obviously, that's not that going to impact you all in one year. Storage represents about 10% of our EBIT going forward. So obviously, that's something that we saw coming at us this year from that perspective. But I think as the market rebalances, as gas power generation comes in, you're going to see the need for that storage. Some of those LNG starts being built you can see need for storage and then you'll see kind of mid-decade, some of those storage margins coming back, which fortunately, would be about the time we bring on our Bobcat Storage facility.

So is it still full steam ahead with the plans on the Bobcat build-out or are we kind of waiting for market indications before we can have -- firmly commit this on the list?

No, we're still building that out. I think we got one cavern that could kind of move a little bit. But we're in the leaching process for the current cavern, and we're still moving ahead. We want to be there when that market comes back '14, '15 timeframe.

And your next question comes from the line of Steven Wayne [ph].

Just following up on the questions on the long haul for Texas Eastern. Can you just indicate on the renewals, how long those contracts are going for now?

Well, they just -- remember they just roll each year...

So this is what? this is year by year?

Yes, that's what happens. You got the original contracts and then you just roll them each year, and that's been going on for -- once the original contract runs out their one-year agreement.

Okay. I didn't know you were extending them even further than one year. On the earnings target growth rate, you said 7% to 9% through '14 now. But I guess, since the last time, you guys originally gave the guidance through '13 at least. The CapEx plan is expanding exponentially that it's greater than $1 billion a year plus, you have all the DCP growth. Should we think that now the earnings growth rate could actually be higher toward the higher end of that target range that you have?

Well, I wouldn't go there quite yet. I mean my view is 7% to 9%, is the number there it was -- we've always said we'll be around $1 billion, in excess of $1 billion. One year you might -- like this year, fortunate enough, Steven, you're right, the number's bigger than $1 billion. It's pushing $1.3 billion, $1.4 billion in terms of expansion capital. But I'm comfortable of that 7% to 9% rate. We'll see how the DCP stuff comes in. As you know, a lot of that is due to go into service kind of '13 timeframe. So those will have a bigger impact, if you will, the '13 through '16 timeframe, as will things like the New York project. The big earnings in New York really don't come in until 2014.

And Steven, one of the questions came up earlier that Greg touched on, and that is that we like the mix that we're getting from these expansions. So when you think about Sandhills and Southern Hills for DCP, those are fee-based projects with about $1 billion investment in each one with mid to high teen returns. So that we -- if we think about paying our dividend just out of the fee based portion of our earnings, we need to think about that contributing to our ability to increase the dividend.

And just a reminder, when you guys talk about the growth rate, you're using the 165 base for this year?

Yes, that's correct.

Okay, and the last question by have is on Kitimat. We have one project with the Encana and the group. But then we saw Shell and you talked about 6 projects total. I'm just curious how many of these terminals do you think that will actually go and get done out of the area?

Well, history is always a pretty good teacher and you will recall Steven, that we probably had 20 if not more projects on LNG import projects along the East Coast and in the Gulf of Mexico on what did we do? 6. So that's a 4:1 hit ratio kind of thing. I would think you'd see the same type of situation here, so that puts that 1 maybe 2. And obviously, that depends on the size. Somebody goes to out to build a 2 BCF facility then I think that's going to be 1. If you -- but could you support or could somebody go out and build call it 3 quarters of the B, then you might have a couple. But I think there's a couple of factors. But I think it's fair to say that there won't be half a dozen.

But Greg, your belief is that the gas that will be supplied for the LNG will be coming from the Horn and not from the Montney?

I think they both -- I think that's -- and that's the nice thing about the Spectra systems where obviously, producers who are located both in the Horn and the Montney, they can make a call whether they want that gas to go east or whether they want that gas to go west, and obviously, they can use both our assets, and the processing and pipeline side in the Montney which is south or in the horn River, which is north.

We have a follow-up question from Monroe Helm.

Just on DCP's opportunities, you said that they have identified another $1 billion of incremental expansion above and beyond the $4 billion that they targeted for 2011, 2013. Can you say how much of that may be driven by what's going on in the Eagle Ford Shale or there are going to be additional opportunities at Eagle Ford that are not in the expansion plans that you have identified so far?

Yes, there some addition, that extra $2 billion that we're looking at. Some of that would in the Eagle Ford. But I think importantly, what has happened by us announcing both Sandhills and Southern Hills is that it's really opened very different producer discussions because we can give them the opportunity not only to process the gas. And as you know, DCP produces twice as many barrels of liquids than any other producer in North America. I think people forget that. So obviously, a huge system and with these pipelines now being able to close the gaps and be able to give people, Mont Belvieu a pricing, it's really opened up our opportunities. So I think we have first mover advantage in places like the Mississippi line. And obviously, it's opened up discussions in places like the Granite Wash and at Woodford, Canada. So it's not just the Eagle Ford. I think it's just opened up. If you took that V if you will, or Y of the pipes that we're building from Conway down to Belvieu and then, the Permian into Belvieu, anything within that zone now becomes a very attractive opportunity for DCP and a very attractive service offering for our customers.

Do you know offhand, how much of the capacity in both these projects is going to taken by ConocoPhillips' own production?

I don't, offhand. I know there's obviously a pretty big position that they have down in the Eagle Ford. But what I can commit to you is that when we come out in early January, we'll have, with our plans for next year, we'll have Tom there to give everybody a little bit more insight on some of the really great opportunities that we see there in the next couple of years.

[Operator Instructions] And you do have a follow-up from Faisel Khan.

What was the contribution in EBIT from Empress in the quarter?

The contribution during the quarter was about $20 million and about $80 million year-to-date.

Okay and what was at the EBIT previous year, that quarter?

In the a quarter, it was a little over $10 million closer to $12 million.

Okay, got you. And then just going back to I think Carl's question on some of the cost, and I think Craig's question on the pipeline cost. I just want to make it clear. There is a $10 million you said maintenance cost in the distribution segment, is that what you said?

No, we had higher benefit costs in the distribution segment of about $11 million and FX of about $6 million and that explains the total increase year-over-year for distribution.

So is that -- those employee benefit cost, did they continue or are they kind of one-time in nature?

It's really timing and when you compare year-over-year, there was an item in last year's quarter that didn't repeat. And so, the third quarter as you know, from an EBIT standpoint, isn't the big quarter for distribution, it's really fourth and first.

Okay, got you. And on the transmission side. What was the number again for the expensing of some of the development cost?

The expensing for the development cost in the quarter was under $10 million, closer to $5 million.

Okay, got you. And then last question for me. In Encana I guess recently kind of discussed kind of the slowing down of some of their drilling activity in kind of that Horn River, Montney area. Any impact to you guys think to you guys in the near term? I know you're still bringing on more processing capacity in the area?

No, I wouldn't expect any impact, Carl. I mean -- or Faisal. The issue as you know, we set up long-term contracts so wouldn't expect any. They had another plant that they were building. I don't know if there's impact on that but for our plant, they're fully contracted and frankly, I fully expect them to be loaded with what Encana has already set up for production.

And you do have another follow-up from Monroe Helm.

Just a follow-up to the last comment where you gave us some numbers for Empress' contribution for the 9 months and 3 months for this year. Do you have the comparable numbers from last year?

For the quarter last year, third quarter, $12 million of EBIT and for year-to-date last year, a little over $50 million compared to a little over $80 million year-to-date in '11. You may recall that when we gave our outlook in January, we had reduced the forecasted contribution from Empress down to about $50 million, and even with much higher extraction premiums this year, the frac spreads had just moved out we've been able to do better there than we anticipated back at the beginning of the year.

And there are no further question at this time.

Okay, if there are no further questions, we'll go ahead and end the call. I'd like to thank everyone for joining us today. And we'd like to remind you that on Tuesday of next week on November 8, we're going to be in Boston for breakfast and then in New York for lunch. We hope that you'll be able to join us at one of those locations. If you haven't already done so, please let us know if you will be able to attend. And if you can't join us in person, I'd like to remind you that the New York luncheon will be webcast. So we look forward to seeing you next week on Tuesday. And as always, if you have additional questions, please feel free to call Roni Cappadonna or me. Thanks.

Thank you for participating today. This concludes today's conference. You may disconnect at this time.